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

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

For the fiscal year ended December 31, 2004

                                    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 0-18397

                Southwest Oil & Gas Income Fund IX-A, L.P.
                (Exact name of registrant as specified in
                    its limited partnership agreement)

Delaware                                                    75-2274632
(State or other jurisdiction                             (I.R.S. Employer
of incorporation or organization)                       Identification No.)

6 Desta Drive, Suite 6500, Midland, Texas                     79705
(Address of principal executive office)                     (Zip Code)

Registrant's telephone number, including area code  (432) 682-6324

       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 X  No

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

Indicate  by check mark whether the registrant is an accelerated filer  (as
defined in Exchange Act Rule 12b-2).     Yes     No  X

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


<PAGE>
                            Table of Contents

Item                                                                   Page

     Glossary of Oil and Gas Terms                                       3

                                  Part I

1.   Business                                                            5

 2.  Properties                                                          8

 3.  Legal Proceedings                                                   9

 4.  Submission of Matters to a Vote of Security Holders                 9

                                 Part II

 5.  Market for Registrant's Common Equity, Related
     Stockholder Matters and Issuer Purchases of Equity Securities      10

 6.  Selected Financial Data                                            11

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      12

7A.  Quantitative and Qualitative Disclosures About Market Risk         18

 8.  Financial Statements and Supplementary Data                        19

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             34

9A.  Controls and Procedures                                            34

9B.  Other Information                                                  34

                                 Part III

10.  Directors and Executive Officers of the Registrant                 35

11.  Executive Compensation                                             35

12.  Security Ownership of Certain Beneficial Owners and Management     36

13.  Certain Relationships and Related Transactions                     36

14.  Principal Accounting Fees and Services                             36

                                 Part IV

15.  Exhibits and Financial Statement Schedules                         37

     Signatures                                                         38

<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.

     BOE.   Equivalent  barrels of oil, with natural gas converted  to  oil
equivalents based on a ratio of six Mcf of natural gas to one Bbl of oil.

     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.  Proved oil and  gas  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. Proved Oil and gas  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  IX-A,  L.P.  (the  "Partnership"   or
"Registrant") was organized as a Delaware limited partnership on  March  9,
1989.   The  offering of limited partnership interests began May 11,  1989,
reached  minimum  capital requirements on October 25,  1989  and  concluded
March 31, 1990.  The Partnership has no subsidiaries.  The Managing General
Partner  of  the  Partnership is Southwest Royalties, Inc.  (the  "Managing
General Partner"), a Delaware corporation.

The  Partnership  has  expended  its  capital  and  acquired  interests  in
producing oil and gas properties.  After such acquisitions, the Partnership
has  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,  with an occasional purchase  of  a  royalty  or
overriding royalty interest.  The Partnership purchased either all or  part
of the rights and obligations under various oil and gas leases.

During  2004, the Managing General Partner was acquired by Clayton Williams
Energy,  Inc.  ("CWEI"), a Delaware corporation, and is now a wholly  owned
subsidiary  of  CWEI.   CWEI is an oil and gas company  based  in  Midland,
Texas, and its common stock is traded on the Nasdaq Stock Market's National
Market  under  the  symbol  "CWEI".  All of  the  directors  and  executive
officers  of  the  Managing General Partner are employees  of  CWEI.   CWEI
maintains an internet website at www.claytonwilliams.com from which  public
information about CWEI may be obtained.

The  principal executive offices of the Partnership are located at 6  Desta
Drive, Suite 6500, Midland, Texas, 79705.  The Managing General Partner and
its  staff, 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.  The Partnership has no employees.

Operations

The business objective of the Partnership is to maximize the production and
related  net  cash  flow  from the properties  it  currently  owns  without
engaging  in  the drilling of any development or exploratory  wells  except
through  farm-out  arrangements.  If additional drilling  is  necessary  to
fully  develop a Partnership property, the Partnership will  enter  into  a
farmout agreement with the Managing General Partner to assign a portion  of
the  Partnership's interest in the property to the Managing General Partner
in  exchange for retaining an interest in the one or more new wells  at  no
cost  to  the Partnership.  The Managing General Partner obtains a fairness
opinion  from an unaffiliated petroleum engineer with respect to the  terms
of each farmout agreement with the Partnership.

Principal Products, Marketing and Distribution
The  Partnership has acquired and holds working interests in  oil  and  gas
properties  located  in  Texas  and New  Mexico.   All  activities  of  the
Partnership  are confined to the continental United States.   During  2004,
66%  of  the  Partnership's revenues were derived  from  the  sale  of  oil
production  and  34% were derived from gas production.   All  oil  and  gas
produced  from these properties is sold to unrelated third parties  in  the
oil and gas business.  The Partnership believes that the loss of any of its
purchasers  would  not have a material adverse affect  on  its  results  of
operations due to the availability of other purchasers.

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.   The
Partnership  is  unable  to accurately predict future  prices  of  oil  and
natural gas.

<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

The Partnership's oil and gas production and related operations are subject
to  extensive rules and regulations promulgated by federal, state and local
agencies.  Failure to comply with such rules and regulations can result  in
substantial  penalties. The regulatory burden on the oil and  gas  industry
increases  the  Partnership's  cost  of  doing  business  and  affects  the
Partnership's  profitability.  Because  such  rules  and  regulations   are
frequently  amended or reinterpreted, the Partnership is unable to  predict
the future cost or impact of complying with such laws.

All  of  the  states  in which the Partnership conducts business  generally
require  permits  for  drilling  operations,  drilling  bonds  and  reports
concerning  operations  and  impose  other  requirements  relating  to  the
exploration  and production of oil and gas. Such states also have  statutes
or  regulations  addressing conservation matters, including provisions  for
the unitization or pooling of oil and gas properties, the establishment  of
maximum  rates  of  production from oil and  gas  wells  and  the  spacing,
plugging  and  abandonment of such wells. The statutes and  regulations  of
certain  states  also limit the rate at which oil and gas can  be  produced
from the Partnership's properties.

The  Federal  Energy  Regulatory Commission ("FERC")  regulates  interstate
natural  gas transportation rates and service conditions, which affect  the
marketing  of gas produced by the Partnership, as well as the revenues  the
Partnership  receives for sales of such production.  Since  the  mid-1980s,
the  FERC  has  issued various orders that have significantly  altered  the
marketing  and  transportation  of  gas.   These  orders  resulted   in   a
fundamental  restructuring of interstate pipeline sales and  transportation
services,  including the unbundling by interstate pipelines of  the  sales,
transportation,  storage  and  other  components  of  the  city-gate  sales
services  such  pipelines previously performed.  These  FERC  actions  were
designed  to  increase competition within all phases of the  gas  industry.
The  interstate regulatory framework may enhance the Partnership's  ability
to  market and transport its gas, although this framework may also  subject
the  Partnership  to  competition  and to  the  more  restrictive  pipeline
imbalance tolerances and greater associated penalties for violation of such
tolerances.

The  Partnership's sales of oil production are not presently regulated  and
are  made  at market prices.  The price the Partnership receives  from  the
sale of those products is affected by the cost of transporting the products
to  market.  The FERC has implemented regulations establishing an  indexing
system for transportation rates for oil pipelines, which, generally,  would
index   such  rates  to  inflation,  subject  to  certain  conditions   and
limitations.   The  Partnership is not able to predict with  any  certainty
what  effect, if any, these regulations will have on the Partnership,  but,
other factors being equal, the regulations may, over time, tend to increase
transportation costs which may have the effect of reducing wellhead  prices
for oil and natural gas liquids.

Environmental Matters

The  Partnership's  operations pertaining to oil  and  gas  production  and
related activities are subject to numerous and constantly changing federal,
state  and  local  laws  governing  the discharge  of  materials  into  the
environment or otherwise relating to environmental protection.  These  laws
and regulations may require the acquisition of certain permits prior to  or
in  connection  with drilling activities, restrict or prohibit  the  types,
quantities  and concentration of substances that can be released  into  the
environment  in  connection  with  drilling  and  production,  restrict  or
prohibit  drilling  activities that could impact  wetlands,  endangered  or
threatened  species or other protected areas or natural resources,  require
some   degree  of  remedial  action  to  mitigate  pollution  from   former
operations, such as pit cleanups and plugging abandoned wells,  and  impose
substantial  liabilities  for pollution resulting  from  the  Partnership's
operations.  Such laws and regulations may substantially increase the  cost
of developing, producing or processing oil and gas and may prevent or delay
the  commencement  or continuation of a given project  and  thus  generally
could  have a material adverse effect upon the Partnership's cash flow  and
earnings.   The  Partnership believes that it is in substantial  compliance
with current applicable environmental laws and regulations, and the cost of
compliance with such laws and regulations has not been material and is  not
expected  to  be material during 2005.  Nevertheless, changes  in  existing
environmental laws and regulations or in the interpretations thereof  could
have  a significant impact on the Partnership's operations, as well as  the
oil  and  gas  industry  in general.  For instance,  legislation  has  been
proposed  in  Congress from time to time that would reclassify certain  oil
and  gas  production  wastes as "hazardous wastes," which  reclassification
would make exploration and production wastes subject to much more stringent
handling, disposal and clean-up requirements.  State initiatives to further
regulate  the  disposal  of  oil  and gas wastes  and  naturally  occurring
radioactive  materials,  if adopted, could have a  similar  impact  on  the
Partnership.
<PAGE>
The  United  States  Oil  Pollution Act of 1990 ("OPA  `90"),  and  similar
legislation enacted in Texas, Louisiana and other coastal states, addresses
oil  spill  prevention  and  control and  significantly  expands  liability
exposure across all segments of the oil and gas industry. OPA `90 and  such
similar  legislation and related regulations impose  on  us  a  variety  of
obligations  related  to  the prevention of oil spills  and  liability  for
damages  resulting  from  such spills.  OPA `90 imposes  strict  and,  with
limited  exceptions,  joint and several liabilities upon  each  responsible
party for oil removal costs and a variety of public and private damages.

The  Comprehensive Environmental Response, Compensation, and Liability  Act
("CERCLA"),  also known as the "Superfund" law, imposes liability,  without
regard to fault or the legality of the original conduct, on certain classes
of  persons  that are considered to have contributed to the  release  of  a
"hazardous  substance"  into the environment.  These  persons  include  the
owner  or  operator  of  the disposal site or the site  where  the  release
occurred  and companies that disposed or arranged for the disposal  of  the
hazardous substances at the site where the release occurred.  Under CERCLA,
such persons may be subject to joint and several liability for the costs of
cleaning  up  the  hazardous substances that have been  released  into  the
environment  and for damages to natural resources, and it is  not  uncommon
for  neighboring  landowners and other third parties  to  file  claims  for
personal  injury  and  property damage allegedly caused  by  the  hazardous
substances released into the environment.  The failure of an operator of  a
property  owned by the Partnership to comply with applicable  environmental
regulations   may,   in  certain  circumstances,  be  attributed   to   the
Partnership.  The Partnership does not believe that it will be required  to
incur  any  material  expenditures to comply  with  existing  environmental
requirements.

The  Resource  Conservation and Recovery Act ("RCRA"), and analogous  state
laws govern the handling and disposal of hazardous and solid wastes. Wastes
that  are  classified  as  hazardous under RCRA are  subject  to  stringent
handling,   recordkeeping,  disposal  and  reporting   requirements.   RCRA
specifically  excludes  from the definition of  hazardous  waste  "drilling
fluids,  produced waters, and other wastes associated with the exploration,
development, or production of crude oil, natural gas or geothermal energy."
However,  these  wastes may be regulated by the EPA or  state  agencies  as
solid  waste.  Moreover, many ordinary industrial  wastes,  such  as  paint
wastes,  waste solvents, laboratory wastes and waste compressor  oils,  are
regulated  as  hazardous wastes. Although the costs of  managing  hazardous
waste  may  be  significant, the Partnership does not expect to  experience
more burdensome costs than similarly situated companies

State  water  discharge regulations and federal waste discharge  permitting
requirements  adopted pursuant to the Federal Water Pollution  Control  Act
prohibit  or  are  expected  in the future to  prohibit  the  discharge  of
produced  water and sand and some other substances related to the  oil  and
gas  industry, into coastal waters.  Although the costs to comply with such
mandates under state or federal law may be significant, the entire industry
will  experience similar costs, and the Partnership does not  believe  that
these  costs will have a material adverse impact on its financial condition
and operations.

The   Partnership  maintains  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 the Partnership's investment  in
the associated site.

Partnership Employees
The  Partnership has no employees; however the Managing General Partner and
CWEI  have  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,
the Partnership engages independent consultants such as petroleum engineers
and geologists as needed.


<PAGE>
Item 2.   Properties

As  of December 31, 2004, the Partnership possessed an interest in oil  and
gas  properties  located in Eddy and Lea Counties of  New  Mexico  Andrews,
Crane, Ector, Garza, Howard, Pecos, Stonewall, Ward and Winkler Counties of
Texas.   These properties consist of various interests in approximately  93
wells and units.

Reserves

The  following table sets forth certain information as of December 31, 2004
with  respect  to the Partnership's estimated proved oil and  gas  reserves
pursuant   to  SEC  guidelines,  present  value  of  proved  reserves   and
standardized measure of discounted future net cash flows.

                       Proved Developed      Proved      Total
                      -------------------    -------    -------
                      -------------------    -------     ----
                           ---------          ----
                      Produci    Nonprod     Undevel    Proved
                         ng       ucing       oped
                      -------    -------     -------    -------
                      -------    -------     -------     ----
                       -----       ----       ----
Oil (Bbls)            225,000     -           13,000      238,000
Gas (Mcf)             990,000     -           52,000      1,042,0
                                                        00
Total (BOE)           390,000     -           22,000      412,000
Present   value    of $3,662,     $    -      $377,000    $4,039,
proved reserves       000                               000
Standardized  measure
of discounted
   future  net   cash                                     $3,942,
flows                                                   000

The  following table sets forth certain information as of December 31, 2004
regarding  the  Partnership's  proved oil  and  gas  reserves  for  certain
significant properties.

                 Proved Reserves                             Percen
                                                               t
             -----------------------             Present       of
             -----------------------                         Presen
                   ----------                                  t
                              Total     Percen   Value of    Value
                               Oil       t of                  of
              Oil     Gas     Equiva    Total     Proved     Proved
                               lent      Oil
             (Bbls   (Mcf)    (BOE)     Equiva   Reserves    Reserv
               )                         lent                  es
             -----   -----    ------    ------ ------------  ------
             -----   -----    ------    ------  ----------   ------
              ---      -       ---       ---                  ---

  Phillips-  201,0   969,0    363,00    88.1%    3,508,00    86.9%
Odessa       00      00       0                  0
 Other       37,00   73,00    49,000    11.9%    531,000     13.1%
             0       0
             -----   -----    ------    ------   --------    ------
             -----   -----    ------    ------   ------      ------
             -       --                 -                    ---
 Total       238,0   1,042    412,00    100.0%   $4,039,     100.0%
             00      ,000     0                  000
             =====   =====    ======    ======   ========    ======
             =       ==       =         ==                   ===

The estimates of proved reserves at December 31, 2004 and the present value
of  proved  reserves  were derived from a report prepared  by  Ryder  Scott
Company,  L.P.,  petroleum consultants.  These calculations  were  prepared
using standard geological and engineering methods generally accepted by the
petroleum  industry  and  in accordance with SEC financial  accounting  and
reporting  standards.  The estimated present value of proved reserves  does
not  give  effect  to indirect expenses such as general and  administrative
expenses,   debt   service  (if  any)  and  depletion,   depreciation   and
amortization.

In  accordance with applicable financial accounting and reporting standards
of  the  SEC,  the estimates of the Partnership's proved reserves  and  the
present  value of proved reserves set forth herein are made using  oil  and
gas  sales prices estimated to be in effect as of the date of such  reserve
estimates  and  are  held constant throughout the life of  the  properties.
Estimated  quantities  of  proved reserves  and  their  present  value  are
affected by changes in oil and gas prices.  The average prices utilized for
the  purposes  of  estimating the Partnership's  proved  reserves  and  the
present  value of proved reserves as of December 31, 2004 were  $41.85  per
Bbl of oil and natural gas liquids and $5.47 per Mcf of gas, as compared to
$31.42 per Bbl of oil and $5.51 per Mcf of gas as of December 31, 2003.

<PAGE>
The  reserve  information shown is estimated.  The accuracy of any  reserve
estimate is a function of the quality of available geological, geophysical,
engineering  and  economic  data,  the precision  of  the  engineering  and
geological interpretation and judgment.  The estimates of reserves,  future
cash  flows  and present value are based on various assumptions,  including
those  prescribed by the SEC, and are inherently imprecise.   Although  the
Partnership   believes  these  estimates  are  reasonable,  actual   future
production, cash flows, taxes, development expenditures, operating expenses
and  quantities  of  recoverable  oil and natural  gas  reserves  may  vary
substantially from these estimates.  Also, the use of a 10% discount factor
for  reporting purposes may not necessarily represent the most  appropriate
discount  factor,  given  actual interest rates  and  risks  to  which  our
business or the oil and natural gas industry in general are subject.

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.

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 2004 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II

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

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.

Number of Limited Partner Interest Holders
As of December 31, 2004, there were 565 holders of limited partner units in
the Partnership.

Distributions
Pursuant  to Article IV, Section 4.01 of the Partnership's Certificate  and
Agreement  of  Limited Partnership "Net Cash Flow" is  distributed  to  the
partners  on  a quarterly basis.  "Net Cash Flow" is defined as  "the  cash
generated  by  the  Partnership's 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."  During 2004, distributions were made  totaling
$468,980,  with  $422,059  ($40.38 per unit)  distributed  to  the  limited
partners and $46,921 to the general partners.

Issuer Purchases of Equity Securities
The  Managing  General  Partner has the right, but not  the  obligation  in
accordance with the obligations set forth in the partnership agreement,  to
purchase limited partnership units should an investor desire to sell.   The
value  of  the  unit is determined by adding the sum of (1) current  assets
less  liabilities  and  (2) the present value of the  future  net  revenues
attributable to proved reserves and by discounting the future net  revenues
at  a  rate not in excess of the prime rate charged by Bank One, a division
of  JP Morgan Chase Bank, N.A. plus one percent (1%), which value shall  be
further  reduced by a risk factor discount of no more than one-third  (1/3)
to  be  determined by the Managing General Partner in its sole and absolute
discretion  under the partnership agreement.  In 2004, no  limited  partner
units were purchased by the Managing General Partner.


<PAGE>
Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2004,  2003,  2002,  2001 and 2000 should be read in conjunction  with  the
financial statements included in Item 8:

                                     Years ended December 31,
                         ------------------------------------------------
                                            ---------
                           2004      2003      2002      2001      2000
                          ------    ------    ------    ------    ------
Revenues              $  1,026,69  947,397   832,356   1,014,35  1,217,37
                         3                             6         3

Net income before
  cumulative  effect
of
 accounting changes      437,846   390,532   263,294   401,609   658,754

Net income               437,846   382,748   193,294   401,609   658,754

Partners' share
 of net income:

General partners         45,318    40,375    28,629    45,461    67,876

Limited partners         392,528   342,373   164,665   356,148   590,878

Limited    partners'
net income per
     unit     before
cumulative effect
    of    accounting     37.55
changes                            33.42     22.45     34.07     56.53

Limited partners'
 net income per unit               32.75
                         37.55               15.75     34.07     56.53

Limited partners'
 cash distributions
  per unit               40.38
                                   38.16     18.81     55.63     54.00

Total assets          $  527,624   544,386   402,165   427,412   671,235


<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  has fluctuated over the past couple of years and is  expected  to
decline in later years based on these factors.

Critical Accounting Policies
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 depletion, depreciation, and amortization
("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.

<PAGE>
Results of Operations

General Comparison of the Years Ended December 31, 2004 and 2003

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2004 and 2003:

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2004      2003    (Decreas
                                                   e)
                             ------    ------   --------
                                                -------
Oil production in           17,461    19,500     (10%)
barrels
Gas production in mcf       65,438    79,900     (18%)
Total (BOE)                 28,367    32,817     (14%)
Average price per        $    38.87               30%
barrel of oil                         29.85
Average price per mcf    $     5.28               25%
of gas                                4.23
Oil and gas revenue      $  1,024,33  920,073     11%
                            4
Production expense       $  467,794   433,045      8%
Partnership              $  468,980   442,773      6%
distributions
Limited partner          $  422,059   398,892      6%
distributions
Per unit distribution    $    40.38                6%
to limited partners                   38.16

Number of limited           10,453    10,453
partner units


Revenues

The  Partnership's  oil  and  gas revenues  increased  to  $1,024,334  from
$920,073  for the years ended December 31, 2004 and 2003, respectively,  an
increase  of  11%.  The principal factors affecting the comparison  of  the
years ended December 31, 2004 and 2003 are as follows:

The average price for a barrel of oil received by the Partnership increased
during  the  year  ended December 31, 2004 as compared to  the  year  ended
December 31, 2003 by 30%, or $9.02 per barrel, resulting in an increase  of
approximately $157,500 in revenues. Oil sales represented 66% of total  oil
and  gas sales during the year ended December 31, 2004 as compared  to  63%
during the year ended December 31, 2003.

The  average price for an mcf of gas received by the Partnership  increased
during  the same period by 25%, or $1.05 per mcf, resulting in an  increase
of approximately $68,700 in revenues.

The  total  increase in revenues due to the change in prices received  from
oil and gas production is approximately $226,200.  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>
Oil production decreased approximately 2,039 barrels or 10% during the year
ended  December 31, 2004 as compared to the year ended December  31,  2003,
resulting in a decrease of approximately $60,900 in revenues.

Gas  production decreased approximately 14,462 mcf or 18% during  the  same
period, resulting in a decrease of approximately $61,200 in revenues.

The  total  decrease  in  revenues  due to  the  change  in  production  is
approximately $122,100.  The decrease in oil volumes is from down time on a
well  for  mechanical subsurface problems.  The decrease in gas volumes  is
from a gas well with fluids restricting production.

Costs and Expenses

Total  costs and expenses increased to $588,847 from $556,865 for the years
ended  December 31, 2004 and 2003, respectively, an increase  of  6%.   The
increase  is  the  result of higher lease operating costs and  general  and
administrative  costs, partially offset by a decrease in accretion  expense
and depletion expense.

Lease operating costs and production taxes were 8% higher, or approximately
$34,700  more  during the year ended December 31, 2004 as compared  to  the
year ended December 31, 2003.

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  5%   or
approximately $4,000 during the year ended December 31, 2004 as compared to
the year ended December 31, 2003.

Depletion expense decreased to $15,339 for the year ended December 31, 2004
from  $21,000 for the same period in 2003.  This represents a  decrease  of
27%.   The contributing factor to the decrease in depletion expense  is  in
relation  to the BOE depletion rate for the year ended December  30,  2004,
which  was $.54 applied to 28,367 BOE as compared to $.64 applied to 32,817
BOE for the same period in 2003.  The lower depletion in 2004 is due to the
upward  revision  in reserve estimates resulting from higher  oil  and  gas
prices.

Accretion expense decreased to $13,878 for the year ended December 31, 2004
from  $14,971 for the same period in 2003.  This represents a  decrease  of
7%.



<PAGE>

Results of Operations

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

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

                                Year Ended      Percenta
                                                   ge
                               December 31,     Increase
                              2003      2002    (Decreas
                                                   e)
                             ------    ------   --------
                                                -------
Oil production in           19,500    22,100     (12%)
barrels
Gas production in mcf       79,900    110,800    (28%)
Total (BOE)                 32,817    40,567     (19%)
Average price per        $    29.85               23%
barrel of oil                         24.30
Average price per mcf    $     4.23               64%
of gas                                2.58
Oil and gas revenue      $  920,073   822,546     12%
Production expense       $  433,045   466,318     (7%)
Partnership              $  442,773   218,523     103%
distributions
Limited partner          $  398,892   196,671     103%
distributions
Per unit distribution    $    38.16               103%
to limited partners                   18.81

Number of limited           10,453    10,453
partner units


Revenues

The  Partnership's oil and gas revenues increased to $920,073 from $822,546
for  the  years ended December 31, 2003 and 2002, respectively, an increase
of  12%.  The principal factors affecting the comparison of the years ended
December 31, 2003 and 2002 are as follows:

The average price for a barrel of oil received by the Partnership increased
during  the  year  ended December 31, 2003 as compared to  the  year  ended
December 31, 2002 by 23%, or $5.55 per barrel, resulting in an increase  of
approximately $108,200 in revenues. Oil sales represented 63% of total  oil
and  gas sales during the year ended December 31, 2003 as compared  to  65%
during the year ended December 31, 2002.

The  average price for an mcf of gas received by the Partnership  increased
during  the same period by 64%, or $1.65 per mcf, resulting in an  increase
of approximately $131,800 in revenues.

The  total  increase in revenues due to the change in prices received  from
oil and gas production is approximately $240,000.  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>
Oil production decreased approximately 2,600 barrels or 12% during the year
ended  December 31, 2003 as compared to the year ended December  31,  2002,
resulting in a decrease of approximately $63,200 in revenues.

Gas  production decreased approximately 30,900 mcf or 28% during  the  same
period, resulting in a decrease of approximately $79,700 in revenues.

The  total  decrease  in  revenues  due to  the  change  in  production  is
approximately $142,900.  Oil and gas volumes declined due to  the  sale  of
four  leases.  Also  contributing to the decline in oil  sales  were  steep
declines  on  two properties.  The gas volume decline also  included  steep
decline  on two wells and mechanical problems with surface equipment  on  a
lease.

Costs and Expenses

Total  costs and expenses decreased to $556,865 from $569,062 for the years
ended  December  31, 2003 and 2002, respectively, a decrease  of  2%.   The
decrease  is  the  result  of  lower lease operating  costs  and  depletion
expense,  partially  offset by the addition of  accretion  expense  and  an
increase in general and administrative costs.

Lease  operating costs and production taxes were 7% lower, or approximately
$33,300  less  during the year ended December 31, 2003 as compared  to  the
year ended December 31, 2002.

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  10%  or
approximately $8,100 during the year ended December 31, 2003 as compared to
the year ended December 31, 2002.

Depletion expense decreased to $21,000 for the year ended December 31, 2003
from  $23,000 for the same period in 2002.  This represents a  decrease  of
9%.   The  contributing factor to the decrease in depletion expense  is  in
relation  to the BOE depletion rate for the year ended December  30,  2003,
which  was $.64 applied to 32,817 BOE as compared to $.57 applied to 40,567
BOE for the same period in 2002.

Cumulative effect of change in accounting principle
On  January  1,  2003,  the  Partnership  adopted  Statement  of  Financial
Accounting  Standards No. 143, Accounting for Asset Retirement  Obligations
("SFAS  No. 143").  Adoption of SFAS No. 143 is required for all  companies
with fiscal years beginning after June 15, 2002.  The new standard requires
the Partnership to recognize a liability for the present value of all legal
obligations  associated with the retirement of tangible  long-lived  assets
and to capitalize an equal amount as a cost of the asset and depreciate the
additional cost over the estimated useful life of the asset.  On January 1,
2003,  the  Partnership  recorded  additional  costs,  net  of  accumulated
depreciation,  of  approximately  $179,335,  a  long  term   liability   of
approximately  $187,119  and  a  loss  of  approximately  $7,784  for   the
cumulative  effect  on depreciation of the additional costs  and  accretion
expense  on the liability related to expected abandonment costs of its  oil
and  natural  gas  producing properties.  At December 31, 2003,  the  asset
retirement  obligation  was $202,113.  The increase  in  the  balance  from
January 1, 2003 is due to accretion expense of $14,971 plus addition of new
well  for  $576, offset by the sale of a property for $553.  The pro  forma
amount  of  the  asset retirement obligation as of December  31,  2002  was
approximately  $187,119.   The pro forma amounts of  the  asset  retirement
obligation were measured using information, assumptions and interest  rates
as of the adoption date of January 1, 2003.



<PAGE>



Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2004, 2003 and 2002
was   $437,846,   $382,748   and   $193,294,   respectively.    Partnership
distributions  for the years ended December 31, 2004, 2003  and  2002  were
$468,980,   $442,773  and  $218,523,  respectively.   These   changes   are
indicative  of the changes in oil and gas prices, production and properties
during 2004, 2003 and 2002.

The  sources  for  the  2004 distributions of $468,980  were  oil  and  gas
operations  of  approximately  $434,500 and  the  change  in  oil  and  gas
properties of approximately $(13,000), with the balance from available cash
on  hand  at  the  beginning  of the period.   The  sources  for  the  2003
distributions  of  $442,773  were oil and gas operations  of  approximately
$474,000 and the change in oil and gas properties of approximately  $8,400,
resulting in excess cash for contingencies or subsequent distributions.

Total  distributions during the year ended December 31, 2004 were  $468,980
of which $422,059 ($40.38 per unit) was distributed to the limited partners
and  $46,921 to the general partners.  Total distributions during the  year
ended  December 31, 2003 were $442,773 of which $398,892 ($38.16 per  unit)
was  distributed  to  the  limited partners  and  $43,881  to  the  general
partners.  Total distributions during the year ended December 31, 2002 were
$218,523 of which $196,671 ($18.81 per unit) was distributed to the limited
partners and $21,852 to the general partners.

Cumulative  cash distributions of $8,571,203 have been made to the  general
and  limited  partners as of December 31, 2004.  As of December  31,  2004,
$7,783,322 or $744.60 per limited partner unit has been distributed to  the
limited partners, representing 149% of contributed capital.

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 $434,500  in
2004 compared to $474,000 in 2003 and approximately $244,200 in 2002.

Cash  flows  provided by (used in) investing activities were  approximately
$(13,000) in 2004 compared to $8,400 in 2003 and approximately $(5,600)  in
2002.   The  principal use of the 2004 cash flow from investing  activities
was the addition of oil and gas properties.

Cash flows used in financing activities were approximately $468,300 in 2004
compared to $442,600 in 2003 and approximately $218,500 in 2002.  The  only
use in financing activities was the distributions to partners.

As  of  December  31, 2004, the Partnership had approximately  $138,000  in
working  capital.   The  Managing  General  Partner  knows  of  no  unusual
contractual  commitments.  Although the Partnership  held  many  long-lived
properties   at  inception,  because  of  the  restrictions   on   property
development  imposed by the partnership agreement, the  Partnership  cannot
develop   its   non-producing  properties,  if  any.    Without   continued
development,  the producing reserves continue to deplete.  Accordingly,  as
the  Partnership's properties have matured and depleted, the net cash flows
from  operations  for  the  Partnership has steadily  declined,  except  in
periods  of  substantially  increased commodity  pricing.   Maintenance  of
properties  and administrative expenses for the Partnership are  increasing
relative to production.  As the properties continue to deplete, maintenance
of  properties  and administrative costs as a percentage of production  are
expected to continue to increase.




<PAGE>
Recent Accounting Pronouncements

In  December 2004, the Financial Accounting Standards Board ("FASB") issued
Statement   of  Financial  Accounting  Standards  No.  153  "Exchanges   of
Nonmonetary  Assets,  an amendment of APB Opinion  No.  29"  ("SFAS  153").
SFAS  153  specifies  the criteria required to record a  nonmonetary  asset
exchange  using  carryover  basis.  SFAS 153 is effective  for  nonmonetary
asset  exchanges occurring after July 1, 2005.  The Partnership will  adopt
this statement in the third quarter of 2005, and it is not expected to have
a material effect on the financial statements when adopted.

In  September  2004,  the Securities and Exchange Commission  issued  Staff
Accounting Bulletin No. 106 ("SAB 106"). SAB 106 expresses the SEC  staff's
views  regarding SFAS No. 143 and its impact on both the full-cost  ceiling
test and the calculation of depletion expense.  In accordance with SAB 106,
beginning in the first quarter of 2005, undiscounted abandonment costs  for
wells  to  be  drilled in the future to develop proved reserves  should  be
included in the unamortized cost of oil and gas properties, net of  related
salvage  value,  for  purposes  of computing  depreciation,  depletion  and
amortization  ("DD&A").  The effect of including  undiscounted  abandonment
costs  of  future wells to the undiscounted cost of oil and gas  properties
may  increase  DD&A  expense in future periods,  however,  the  Partnership
currently  does  not  believe SAB 106 will have a material  impact  on  our
financial statements.

Item 7A.  Quantitative and Qualitative Disclosures About Market Risk

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


<PAGE>
Item 8.   Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Report of Independent Registered Public Accounting Firm                 20

Balance Sheets                                                          21

Statements of Operations                                                22

Statement of Changes in Partners' Equity                                23

Statements of Cash Flows                                                24

Notes to Financial Statements                                           26

<PAGE>









                     REPORT OF INDEPENDENT REGISTERED
                          PUBLIC ACCOUNTING FIRM

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


We  have  audited the accompanying balance sheets of Southwest  Oil  &  Gas
Income  Fund  IX-A, L.P. (the "Partnership") as of December  31,  2004  and
2003, and the related statements of operations, partners' equity, and  cash
flows  for  each of the years in the three-year period ended  December  31,
2004.    These   financial  statements  are  the  responsibility   of   the
Partnership's management.  Our responsibility is to express an  opinion  on
these financial statements based on our audits.

We  conducted  our audits in accordance with the standards  of  the  Public
Company  Accounting  Oversight  Board  (United  States).   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 IX-A, L.P. as of December 31, 2004 and 2003, and the results of
its  operations and its cash flows for each of the years in the  three-year
period  ended December 31, 2004, in conformity with U.S. generally accepted
accounting principles.

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






KPMG LLP
Dallas, Texas
March 26, 2005


<PAGE>
                Southwest Oil & Gas Income Fund IX-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2004 and 2003


                                   2004      2003
                                  ------    ------

Assets
----------

Current assets:
 Cash and cash equivalents    $  62,336    109,200
  Receivable  from  Managing     77,125    44,518
General Partner
                                 --------  --------
                                 -----     -----
   Total current assets          139,461   153,718
                                 --------  --------
                                 -----     -----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       3,197,99  3,185,16
                                 5         0
       Less      accumulated
depreciation,
         depletion       and     2,809,83  2,794,49
amortization                     2         2
                                 --------  --------
                                 -----     -----
      Net   oil   and    gas     388,163   390,668
properties
                                 --------  --------
                                 -----     -----
                              $  527,624   544,386
                                 =======   =======
Liabilities  and   Partners'
Equity
----------------------------
------------

Current     liability      -  $  1,509     851
distributions payable
                                 --------  --------
                                 -----     -----

Asset retirement obligation      215,827   202,113
                                 --------  --------
                                 -----     -----
Partners' equity (deficit):
 General partners                (63,413)  (61,810)
 Limited partners                373,701   403,232
                                 --------  --------
                                 -----     -----
   Total partners' equity        310,288   341,422
                                 --------  --------
                                 -----     -----
                              $  527,624   544,386
                                 =======   =======













                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
                Southwest Oil & Gas Income Fund IX-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Operations
               Years ended December 31, 2004, 2003 and 2002

                                     2004      2003      2002
                                    ------    ------    ------
Revenues
-------------
 Oil and gas                    $  1,024,33  920,073   822,546
                                   4
 Interest from operations          654       971       647
 Other                             1,705     26,353    9,163
                                   --------  --------  --------
                                   ----      ----      ----
                                   1,026,69  947,397   832,356
                                   3
                                   --------  --------  --------
                                   ----      ----      ----
Expenses
------------
 Production                        467,794   433,045   466,318
  Depreciation, depletion  and     15,339    21,000    23,000
amortization
 Accretion expense                 13,878    14,971    -
 General and administrative        91,836    87,849    79,744
                                   --------  --------  --------
                                   ----      ----      ----
                                   588,847   556,865   569,062
                                   --------  --------  --------
                                   ----      ----      ----
Net  income  before cumulative
effects
 of accounting changes             437,846   390,532   263,294

Cumulative effect of change in
accounting
  principle - SFAS No.  143  -     -         (7,784)   -
See Note 3
Cumulative effect of change in
accounting principle
  - change in depletion method     -         -         (70,000)
- See Note 4
                                   --------  --------  --------
                                   ----      ----      ----
Net income                      $  437,846   382,748   193,294
                                   =======   =======   =======
Net income allocated to:
 Managing General Partner       $  40,786    36,337    25,766
                                   =======   =======   =======
 General Partner                $  4,532     4,038     2,863
                                   =======   =======   =======
 Limited partners               $  392,528   342,373   164,665
                                   =======   =======   =======
   Per  limited  partner  unit  $    37.55
before cumulative effect                     33.42     22.45
    Cumulative   effects   per     -           (.67)
limited partner unit                                   (6.70)
                                   --------  --------  --------
                                   ----      ----      ----
  Per limited partner unit      $    37.55
                                             32.75     15.75
                                   =======   =======   =======










                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
                Southwest Oil & Gas Income Fund IX-A, L.P.
                     (a Delaware limited partnership)
                 Statement of Changes in Partners' Equity
               Years ended December 31, 2004, 2003 and 2002

                                 General   Limited
                                 Partners  Partners   Total
                                 --------  --------   -----
Balance at December 31, 2001  $  (65,081)  491,757   426,676

 Net income                      28,629    164,665   193,294

 Distributions                   (21,852)  (196,671  (218,523
                                           )         )
                                 --------  --------  --------
                                 --        --        --
Balance at December 31, 2002     (58,304)  459,751   401,447

 Net income                      40,375    342,373   382,748

 Distributions                   (43,881)  (398,892  (442,773
                                           )         )
                                 --------  --------  --------
                                 --        --        --
Balance at December 31, 2003     (61,810)  403,232   341,422

 Net income                      45,318    392,528   437,846

 Distributions                   (46,921)  (422,059  (468,980
                                           )         )
                                 --------  --------  --------
                                 --        --        --
Balance at December 31, 2004  $  (63,413)  373,701   310,288
                                 ======    ======    ======




























                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
                Southwest Oil & Gas Income Fund IX-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Cash Flows
               Years ended December 31, 2004, 2003 and 2002

                                     2004      2003      2002
                                    ------    ------    ------
Cash   flows  from   operating
activities:

  Cash  received from oil  and  $  1,024,10  915,049   800,557
gas sales                          2
   Cash  paid  for  production
expense, administrative
    fees   and   general   and     (592,004  (468,408  (566,121
administrative overhead            )         )         )
 Interest received                 654       971       647
 Other                             1,705     26,353    9,163
                                   --------  --------  --------
                                   -----     -----     -----
    Net   cash   provided   by     434,457   473,965   244,246
operating activities
                                   --------  --------  --------
                                   -----     -----     -----
Cash   flows  from   investing
activities:

  Additions  to  oil  and  gas     (12,999)  (4,132)   (535)
properties
   Sale   of   oil   and   gas     -         12,501    6,183
properties
                                   --------  --------  --------
                                   -----     -----     -----
   Net cash (used in) provided     (12,999)  8,369     5,648
by investing activities
                                   --------  --------  --------
                                   -----     -----     -----
Cash  flows used in  financing
activities:

 Distributions to partners         (468,322  (442,640  (218,541
                                   )         )         )
                                   --------  --------  --------
                                   -----     -----     -----

Net  (decrease)  increase   in     (46,864)  39,694    31,353
cash and cash equivalents

Beginning of year                  109,200   69,506    38,153
                                   --------  --------  --------
                                   -----     -----     -----
End of year                     $  62,336    109,200   69,506
                                   =======   =======   =======
                                                       (continu
                                                       ed)




















<PAGE>
                Southwest Oil & Gas Income Fund IX-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Cash Flows
         Years ended December 31, 2004, 2003 and 2002 (continued)

                                     2004      2003      2002
                                    ------    ------    ------
Reconciliation of  net  income
to net cash
    provided    by   operating
activities:

Net income                      $  437,846   382,748   193,294

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

  Depreciation, depletion  and     15,339    21,000    23,000
amortization
 Accretion expense                 13,878    14,971    -
  Cumulative effects of change     -         7,784     70,000
in accounting principle
 Increase in receivables           (232)     (5,024)   (21,989)
    (Decrease)   increase   in     (32,374)  52,486    (20,059)
payables
                                   --------  --------  --------
                                   -----     -----     -----
Net cash provided by operating  $  434,457   473,965   244,246
activities
                                   =======   =======   =======
Noncash investing and
financing activities:
 Increase in oil and gas
properties - Adoption
  of SFAS No. 143               $  -         179,335   -
                                   =======   =======   =======
 Increase in oil and gas
properties - SFAS No. 143
  Additional well due to farm-  $  -         576       -
out arrangement
                                   =======   =======   =======
 Decrease in oil and gas
properties - SFAS No. 143
  Sale of property              $  -         (553)     -
                                   =======   =======   =======
 Decrease in oil and gas
properties - SFAS No. 143
  Plug and abandoned wells      $  164       -         -
                                   =======   =======   =======




















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

                      Notes to Financial Statements

1.   Organization
     Southwest  Oil  & Gas Income Fund IX-A, L.P. was organized  under  the
     laws  of  the state of Delaware on March 9, 1989, 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.,  a  wholly  owned subsidiary of Clayton Williams  Energy,  Inc.,
     serves  as the Managing 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)
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 gas 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.  As of December 31, 2004, 2003  and  2002
     the  net capitalized costs did not exceed the estimated present  value
     of oil and gas reserves.

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

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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  gas-
     balancing  arrangements.  Under this method the Partnership recognizes
     sales  revenue on all gas sold. As of December 31, 2004 and  2003  the
     Partnership was overproduced by 403 mcf of gas.

     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,  2004  and  2003 is $188,942 and $181,816 less than, respectively,
     than  that shown on the accompanying Balance Sheet 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, 2004, 2003 and 2002 and there were 10,453 limited
     partner units outstanding held by 565, 566 and 562 partners.

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

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

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

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     Recent Accounting Pronouncements
     In  December  2004, the Financial Accounting Standards Board  ("FASB")
     issued  Statement of Financial Accounting Standards No. 153 "Exchanges
     of   Nonmonetary  Assets,  an  amendment  of  APB  Opinion   No.   29"
     ("SFAS  153").  SFAS 153 specifies the criteria required to  record  a
     nonmonetary  asset  exchange  using  carryover  basis.   SFAS  153  is
     effective  for  nonmonetary asset exchanges occurring  after  July  1,
     2005.   The Partnership will adopt this statement in the third quarter
     of  2005,  and  it is not expected to have a material  effect  on  the
     financial statements when adopted.

     In September 2004, the Securities and Exchange Commission issued Staff
     Accounting  Bulletin No. 106 ("SAB 106"). SAB 106  expresses  the  SEC
     staff's views regarding SFAS No. 143 and its impact on both the  full-
     cost  ceiling  test  and  the calculation of  depletion  expense.   In
     accordance  with  SAB  106, beginning in the first  quarter  of  2005,
     undiscounted abandonment costs for wells to be drilled in  the  future
     to  develop proved reserves should be included in the unamortized cost
     of  oil and gas properties, net of related salvage value, for purposes
     of  computing  depreciation, depletion and amortization ("DD&A").  The
     effect of including undiscounted abandonment costs of future wells  to
     the  undiscounted  cost of oil and gas properties  may  increase  DD&A
     expense in future periods, however, the Partnership currently does not
     believe  SAB  106  will  have  a  material  impact  on  our  financial
     statements.

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

3.   Cumulative effect of change in accounting principle - SFAS No. 143
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  Adoption of SFAS No. 143  is  required
     for  all  companies with fiscal years beginning after June  15,  2002.
     The new standard requires the Partnership to recognize a liability for
     the  present  value  of  all  legal obligations  associated  with  the
     retirement  of tangible long-lived assets and to capitalize  an  equal
     amount as a cost of the asset and depreciate the additional cost  over
     the  estimated  useful  life of the asset.  On January  1,  2003,  the
     Partnership    recorded   additional   costs,   net   of   accumulated
     depreciation,  of  approximately $179,335, a long  term  liability  of
     approximately  $187,119  and a loss of approximately  $7,784  for  the
     cumulative  effect  on  depreciation  of  the  additional  costs   and
     accretion  expense  on  the liability related to expected  abandonment
     costs  of  its oil and natural gas producing properties.  At  December
     31,  2004, the asset retirement obligation was $215,827.  The increase
     in  the  balance from January 1, 2004 is due to accretion  expense  of
     $13,878  less  $164 for wells plugged and abandoned.   The  pro  forma
     amount of the asset retirement obligation as of December 31, 2002  was
     approximately $187,119.  The pro forma amounts of the asset retirement
     obligation  were measured using information, assumptions and  interest
     rates  as  of  the adoption date of January 1, 2003.   The  pro  forma
     amounts  for  the  year ended December 31, 2002,  which  is  presented
     below, reflect the effect of retroactive application of SFAS No. 143.

                                     2002
                                    ------
Pro   forma  amounts  assuming
change is applied
 retroactively:
  Net income before cumulative
effect
    for  change  in  depletion  $  249,522
method
                                   =======
   Per  limited  partner  unit  $    21.26
(10,453.0 units)
                                   =======
 Net income                     $  179,522
                                   =======
   Per  limited  partner  unit  $    14.57
(10,453.0 units)
                                   =======

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

                      Notes to Financial Statements

4.    Cumulative  effect of a change in accounting principle  -  change  in
depletion method
     In  2002,  the Partnership changed methods of accounting for depletion
     of capitalized costs from the units-of-revenue method to the units-of-
     production   method.   The  newly  adopted  accounting  principle   is
     preferable in the circumstances because the units-of-production method
     results  in  a better matching of the costs of oil and gas  production
     against the related revenue received in periods of volatile prices for
     production  as have been experienced in recent periods.  Additionally,
     the  units-of-production method is the predominant method used by full
     cost  companies in the oil and gas industry, accordingly,  the  change
     improves  the comparability of the Partnership's financial  statements
     with  its peer group.  The Partnership adopted the units-of-production
     method  through the recording of a cumulative effect of  a  change  in
     accounting principle in the amount of $70,000 effective as of  January
     1, 2002.  The Partnership's depletion for the years subsequent to 2001
     has been calculated using the units-of-production method.

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 Bank
     One,  a division of JP Morgan Chase Bank, N.A. plus one percent  (1%),
     which  value shall be further reduced by a risk factor discount of  no
     more  than  one-third (1/3) to be determined by the  Managing  General
     Partner in its sole and absolute discretion.

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

     As  of December 31, 2004, the Partnership has not been fined, cited or
     notified of any environmental violations and management was 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
     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.

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  $60,800,
     $66,300  and $79,200 for the years ended December 31, 2004,  2003  and
     2002,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $73,200  during  2004,  2003  and 2002 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.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of  approximately $77,100 and $44,500 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2004 and 2003, respectively.



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

                      Notes to Financial Statements

7.   Oil and Gas Reserves Information (unaudited)
     The  estimates  of  proved  oil  and  gas  reserves  utilized  in  the
     preparation  of the financial statements were prepared by  independent
     petroleum engineers.  Such estimates are in accordance with guidelines
     established  by  the  Securities  and  Exchange  Commission  and   the
     Financial  Accounting  Standards Board,  which  require  that  reserve
     reports  be prepared under economic and operating conditions  existing
     at  the  registrant's year end with no provision for  price  and  cost
     escalations  except by contractual arrangements.  Future cash  inflows
     were  computed by applying year-end prices to the year-end  quantities
     of  proved  reserves.  Future development, abandonment and  production
     costs  were computed by estimating the expenditures to be incurred  in
     developing,  producing, and abandoning proved oil and gas reserves  at
     the   end  of  the  year,  based  on  year-end  costs.   All  of   the
     Partnership's  reserves  are  located  in  the  United  States.    For
     information about the Partnership's results of operations from oil and
     gas   producing   activities,  see  the  accompanying  statements   of
     operations.

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

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

January 1, 2002               209,000   839,000

Revisions    of     previous  28,000    190,000
estimates
Production                    (22,000)  (111,000
                                        )
                              --------  --------
                              ----      ----
December 31, 2002             215,000   918,000

Sales of reserves in place    (2,000)   (3,000)
Revisions    of     previous  58,000    211,000
estimates
Production                    (20,000)  (80,000)
                              --------  --------
                              ----      ----
December 31, 2003             251,000   1,046,00
                                        0

Revisions    of     previous  4,000     61,000
estimates
Production                    (17,000)  (65,000)
                              --------  --------
                              ----      ----
December 31, 2004             238,000   1,042,00
                                        0
                              =======   =======
Proved developed reserves -

December 31, 2002             202,000   797,000
                              =======   =======
December 31, 2003             238,000   994,000
                              =======   =======
December 31, 2004             225,000   990,000
                              =======   =======



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

                      Notes to Financial Statements

7.   Oil and Gas Reserves Information (unaudited) - continued
     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 December 31, 2004, 2003 and 2002 are  an
     average price of $41.85, $31.42 and $29.28 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
     December 31, 2004, 2003 and 2002 are an average price of $5.47,  $5.51
     and $4.30 per Mcf.

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

     Unanticipated  depletion, if it occurs, will result in lower  reserves
     than  previously estimated; thus an ultimately lower  return  for  the
     Partnership.  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 is 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.

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

                      Notes to Financial Statements

7.   Oil and Gas Reserves Information (unaudited) - continued
     The  standardized measure of discounted future net cash flows relating
     to  proved oil and gas reserves at December 31, 2004, 2003 and 2002 is
     presented below:

                                   2004      2003      2002
                                  ------    ------    ------

Future cash inflows           $  15,665,0  13,646,0  10,248,0
                                 00        00        00
Production, development and
 abandonment costs               6,747,00  5,915,00  4,482,00
                                 0         0         0
                                 --------  --------  --------
                                 ------    ------    -----
Future net cash flows            8,918,00  7,731,00  5,766,00
                                 0         0         0
10%   annual  discount   for
estimated
 timing of cash flows            4,976,00  3,945,00  2,406,00
                                 0         0         0
                                 --------  --------  --------
                                 -----     ------    -----
Standardized   measure    of
discounted
 future net cash flows        $  3,942,00  3,786,00  3,360,00
                                 0         0         0
                                 =======   ========  =======

     Changes  in  the  standardized measure of discounted future  net  cash
     flows  relating  to proved reserves for the years ended  December  31,
     2004, 2003 and 2002 are as follows:

                                   2004      2003      2002
                                  ------    ------    ------

Sales   of   oil   and   gas
produced,
     net of production costs  $  (557,000  (487,000  (356,000
                                 )         )         )
Changes   in   prices    and     636,000   404,000   1,375,00
production costs                                     0
Changes of production rates
     (timing) and others         (437,000  (628,000  (84,000)
                                 )         )
Sales of minerals in place       -         (28,000)  -
Revisions of previous
     quantities estimates        135,000   829,000   545,000
Accretion of discount            379,000   336,000   171,000
Discounted future net
     cash flows -
Beginning of year                3,786,00  3,360,00  1,709,00
                                 0         0         0
                                 --------  --------  --------
                                 ----      ----      ----
End of year                   $  3,942,00  3,786,00  3,360,00
                                 0         0         0
                                 =======   =======   =======


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

                      Notes to Financial Statements

8.   Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2004:
 Total revenues             $ 237,077   234,204   267,911   287,501
 Total expenses               151,090   122,003   155,085   160,669
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 85,987    112,201   112,826   126,832
                              =======   =======   =======   =======

  Net  income per  limited  $   7.37
partners unit                           9.62      9.68      10.88
                              =======   =======   =======   =======

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2003:
 Total revenues             $ 280,508   218,525   223,733   224,631
 Total expenses               124,302   153,519   131,352   147,692
                              --------  --------  --------  --------
                              ----      ----      ----      ----
    Net    income   before
cumulative effect of
   a  change in accounting    156,206   65,006    92,381    76,939
principle
 Cumulative effect of SFAS    (7,784)   -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 148,422   65,006    92,381    76,939
                              =======   =======   =======   =======
  Per limited partner unit
amounts:
  Income before cumulative
effect of a
    change  in  accounting  $  13.39
principle                               5.54      7.91      6.58
 Cumulative effect of SFAS     (.67)    -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
  Net  income per  limited  $  12.72
partners unit                           5.54      7.91      6.58
                              =======   =======   =======   =======

<PAGE>

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

None

Item 9A.  Controls and Procedures

The  Managing  General  Partner  has established  disclosure  controls  and
procedures   that  are  adequate  to  provide  reasonable  assurance   that
management will be able to collect, process and disclose both financial and
non-financial information, on a timely basis, in the Partnership's  reports
to  the  SEC.   Disclosure controls and procedures  include  all  processes
necessary  to  ensure  that material information  is  recorded,  processed,
summarized  and  reported within the time periods specified  in  the  SEC's
rules  and  forms,  and  is  accumulated and  communicated  to  management,
including our chief executive and chief financial officers, to allow timely
decisions regarding required disclosures.

     With respect to these disclosure controls and procedures:

          management  has  evaluated the effectiveness  of  the  disclosure
          controls  and procedures as of the end of the period  covered  by
          this report;

          this evaluation was conducted under the supervision and with  the
          participation  of management, including the chief  executive  and
          chief financial officers of the Managing General Partner; and

          it  is  the  conclusion of chief executive  and  chief  financial
          officers  of  the Managing General Partner that these  disclosure
          controls   and   procedures  are  effective  in   ensuring   that
          information  that is required to be disclosed by the  Partnership
          in   reports  filed  or  submitted  with  the  SEC  is  recorded,
          processed,  summarized  and  reported  within  the  time  periods
          specified in the rules and forms established by the SEC.

Internal Control Over Financial Reporting
There  has  not been any change in the Partnership's internal control  over
financial  reporting that occurred during the quarter  ended  December  31,
2004  that  has materially affected, or is reasonably likely to  materially
affect, its internal control over financial reporting.

Item 9B.  Other Information

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.  Since the Managing General Partner is a  wholly
owned subsidiary of CWEI, the directors of the Managing General Partner are
elected  by management of CWEI.  Each director the Managing General Partner
serves for a term of one year.  Following is certain information concerning
each  of  the  directors  and executive officers of  the  Managing  General
Partner.

CLAYTON W. WILLIAMS, age 73, is Chairman of the Board and a director of the
Managing  General Partner, having served in this capacity since  May  2004.
Mr.  Williams  also  serves  as  Chairman of the  Board,  President,  Chief
Executive Officer and a director of CWEI.

L.  PAUL  LATHAM,  age  53,  is President, Chief Executive  Officer  and  a
director  of  the Managing General Partner, having served in this  capacity
since  May 2004.  Mr. Latham also serves as Executive Vice President, Chief
Operating Officer and a director of CWEI.

MEL G. RIGGS, age 50, is Vice President, Chief Financial Officer, Treasurer
and  a  director  of the Managing General Partner, having  served  in  this
capacity  since  May 2004.  Mr. Riggs also serves as Senior Vice  President
and Chief Financial Officer of CWEI.

JERRY  F. GRONER, age 42, is Vice President - Land and Lease Administration
of  the Managing General Partner, having served in this capacity since  May
2004.   Mr.  Groner  also  serves  as  Vice  President  -  Land  and  Lease
Administration of CWEI.

D.  GREGORY BENTON, age 43, is Vice President - Engineering of the Managing
General Partner, having served in this capacity since May 2004.  Mr. Benton
also serves as Exploitation Manager of CWEI.

ROBERT C. LYON, age 68, is Vice President - Gas Gathering and Marketing  of
the  Managing  General Partner, having served in this  capacity  since  May
2004.  Mr. Lyon also serves as Vice President - Gas Gathering and Marketing
of CWEI.

T.  MARK  TISDALE, age 48, is Vice President and Secretary of the  Managing
General  Partner,  having  served in this capacity  since  May  2004.   Mr.
Tisdale also serves as Vice President and General Counsel of CWEI.

There  are no family relationships among the directors and officers of  the
Managing  General Partner except that Mr. Groner is the son-in-law  of  Mr.
Williams.

Code of Ethics

As  a  wholly  owned  subsidiary of CWEI, the Managing General  Partner  is
subject  to  a  Code  of Conduct and Ethics ("Code") that  applies  to  all
directors,  executive  officers and employees  of  CWEI  and  the  Managing
General Partner.  This Code assists employees in complying with the law, in
resolving  ethical  issues that may arise, and in complying  with  policies
established  by CWEI.  This Code is also designed to promote,  among  other
things, ethical handling of actual or apparent conflicts of interest; full,
fair,  accurate  and timely disclosure in filings with the SEC;  compliance
with  law;  and prompt internal reporting of violations of the Code.   This
Code  is available on the website of CWEI at www.claytonwilliams.com  under
"Investor Relations/Documents".

Item 11.  Executive Compensation

The  Partnership  does  not  employ any directors,  executive  officers  or
employees.  The Managing General Partner receives an administrative fee for
the  management of the Partnership.  The Managing General Partner  received
$73,200  during 2004, 2003 and 2002 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.

<PAGE>
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,  other  than  the  Managing
General Partner.

Through  repurchase  offers to the limited partners, the  Managing  General
Partner  owns 498.5 limited partner units, a 4.3% limited partner interest.
The  Managing General Partner's total percentage interest ownership in  the
Partnership is 14.3%.

No  officer or director of the Managing General Partner directly owns units
in  the  Partnership. CWEI is considered to be a beneficial  owner  of  the
limited partner units acquired by the Managing General Partner by virtue of
its  ownership  of  the Managing General Partner. 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.

Item 13.  Certain Relationships and Related Transactions

In 2004, the Managing General Partner received $73,200 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 its affiliates  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 $60,800 for administrative overhead attributable to operating
such properties during 2004.

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

Item 14.  Principal Accounting Fees and Services

The  following table presents fees for professional audit services rendered
by  KPMG LLP for the audit of the Partnership's annual financial statements
for  the  years ended December 31, 2004 and 2003 and fees billed for  other
services rendered by KPMG during those periods.

 For the Year Ended December     2004      2003
             31,
                               -------    ------
Audit Fees                     $12,865   $
                                         8,434
Audit Related Fees                  -
                                         -
Tax Fees                            -
                                         -
All Other Fees                      -
                                         -
                                 ------    ------
                               -----     -----
    TOTAL                      $12,865   $
                                         8,434
                                ======
                                         ======

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



<PAGE>
                                 Part IV


Item 15.  Exhibits and Financial Statement Schedules

          (a)(1)  Financial Statements:

                  Included in Part II of this report --

                  Report of Independent Registered Public Accounting Firm
                  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 S-
                  X  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 IX-
                          A,  L.P., dated March 9, 1989.  (Incorporated  by
                          reference  from Partnership's Form 10-K  for  the
                          fiscal year ended December 31, 1989.)

                                            (b)    Agreement   of   Limited
                          Partnership of Southwest Oil & Gas Income Fund IX-
                          A, L.P. dated October 25, 1989.  (Incorporated by
                          reference  from Partnership's Form 10-K  for  the
                          fiscal year ended December 31, 1987.)

                                          (c)  Certificate of Amendment  of
                          Limited Partnership of Southwest Oil & Gas Income
                          Fund   IX-A,   L.P.,   dated   July   21,   1987.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1987.)

                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  and
Chief Financial Officer
                           Pursuant  to 18 U.S.C. Section 1350, as  adopted
                    Pursuant to Section
                          906 of the Sarbanes-Oxley Act of 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 IX-A, L.P., a
                          Delaware limited partnership

                                        By:    Southwest  Royalties,  Inc.,
                                 Managing
                                 General Partner


                          By:    /s/ L. Paul Latham
                                 L. Paul Latham
                                 President and Chief Executive Officer


                          Date:  March 31, 2005


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


/s/ Clayton W Williams                       /s/ L. Paul Latham
Clayton     W.    Williams,                  L.      Paul     Latham,
Chairman of the Board                        President and a Director
and a Director

Date:     March 31, 2005                     Date:     March 31, 2005




/s/ Mel G. Riggs
Mel    G.    Riggs,    Vice
President - Finance,
Treasurer and a Director

Date:     March 31, 2005



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.1


I, L. Paul Latham, certify that:

1.   I have reviewed this annual report on Form 10-K of Southwest Oil & Gas
Income Fund IX-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  15d-15(e))  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)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

  c)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  control  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
     control over financial reporting.


Date:  March 31, 2005              /s/ L. Paul Latham
                                   L. Paul Latham
                                   President and Chief Executive Officer
                                   of Southwest Royalties, Inc., the
                                   Managing General Partner of
                                    Southwest  Oil & Gas Income Fund  IX-A,
L.P.



<PAGE>
                    SECTION 302 CERTIFICATION                Exhibit 31.2


I, Mel G. Riggs, certify that:

1.   I have reviewed this annual report on Form 10-K of Southwest Oil & Gas
Income Fund IX-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  15d-15(e))  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)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

  c)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  control  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
     control over financial reporting.


Date:  March 31, 2005              /s/ Mel G. Riggs
                                   Mel G. Riggs
                                     Vice  President  and  Chief  Financial
Officer of
                                   Southwest Royalties, Inc., the
                                   Managing General Partner of
                                    Southwest  Oil & Gas Income Fund  IX-A,
L.P.


<PAGE>

                                                               Exhibit 32.1

               CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND
                          CHIEF FINANCIAL OFFICER

Pursuant to 18 U.S.C.  1350 and in connection with the accompanying  report
on  Form  10-K for the period ended December 31, 2004 that is  being  filed
concurrently with the Securities and Exchange Commission on the date hereof
(the  "Report"), each of the undersigned officers of Southwest  Oil  &  Gas
Income Fund IX-A, L.P. (the "Company"), hereby certifies 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.


                                   /s/ L. Paul Latham
                                   L. Paul Latham
                                   President and Chief Executive Officer
                                        of Southwest Royalties, Inc., the
                                        Managing General Partner of
                                        Southwest Oil & Gas Income Fund IX-
                                   A, L.P.

                                   March 31, 2005


                                   /s/ Mel G. Riggs
                                   Mel G. Riggs
                                   Vice   President  and  Chief   Financial
                                   Officer of
                                        Southwest Royalties, Inc., the
                                        Managing General Partner of
                                        Southwest Oil & Gas Income Fund IX-
                                   A, L.P.

                                   March 31, 2005



<PAGE>