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 0-18398

         Southwest Royalties Institutional Income Fund IX-B, L.P.
                (Exact name of registrant as specified in
                    its limited partnership agreement)

Delaware                                                         75-2274633
(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.

     Net  Profits  Interest.  An agreement whereby  the  owner  receives  a
specified  percentage of the defined net profits from a producing  property
in  exchange for consideration paid.  The net profits interest  owner  will
not otherwise participate in additional costs and expenses of the property.

     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 Royalties Institutional Income Fund IX-B, 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  the  minimum  capital  requirements  on  September  26,  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 royalty or overriding
royalty interests and working interests in oil and gas properties that were
converted into net profits interests or other non-operating interests.  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 and Markets
The  Partnership has acquired and holds royalty, overriding royalty and net
profits  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, 63% of the Partnership's revenues were derived
from  the  sale of oil production and 37% 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 net profits or royalty 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,
Cochran,  Crane, Ector, Gaines, Garza, Howard, Pecos, Reagan, Terry,  Ward,
Winkler  and Yoakum Counties of Texas.  These properties consist of various
interests in approximately 392 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
                    ---------------------    -------    -------
                    ---------------------    -------      ----
                            -----             ----
                    Producing    Nonprod     Undevel     Proved
                                  ucing       oped
                    ---------    -------     -------    -------
                    ---------    -------     -------      ----
                        -          ----       ----
Oil (Bbls)          200,000       -           16,000      216,000
Gas (Mcf)           937,000       -           67,000      1,004,00
                                                        0
Total (BOE)         356,000       -           27,000      383,000
Present  value   of $3,478,0      $    -      $536,000    $4,014,
proved reserves     00                                  000
Standardized
measure          of
discounted
  future  net  cash                                       $3,919,
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                            Percent
             -----------------------             Present      of
             -----------------------                        Present
                   ----------
                              Total     Percen    Value      Value
                               Oil       t of       of        of
              Oil     Gas     Equiva    Total     Proved    Proved
                               lent      Oil
             (Bbls   (Mcf)    (BOE)     Equiva   Reserve    Reserve
               )                         lent       s          s
             -----   -----    ------    ------ -----------  -------
             -----   -----    ------    ------ -----------  -------
              ---      -       ---       ---                  --

             186,0   895,0    335,00    87.5%    3,235,00   80.6%
Phillips/Od  00      00       0                  0
essa
 Other       30,00   109,0    48,000    12.5%    779,000    19.4%
             0       00
             -----   -----    ------    ------   --------   -------
             -----   -----    ------    ------   ------     -------
             -       --                 --                  --
 Total       216,0   1,004    383,00    100.0%   $4,014,    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  $41.81  per
Bbl of oil and natural gas liquids and $5.48 per Mcf of gas, as compared to
$31.37 per Bbl of oil and $5.50 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 589 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
$472,918,  with  $424,668  ($43.41 per unit)  distributed  to  the  limited
partners and $48,250 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.  The following table sets forth
certain information regarding purchases of limited partnership units by the
Managing General Partner during the year of 2004.

                                                      Maximum
                                          Total     Number (or
                                          Number
                                         of Units   Approximat
                                                         e
                                        Purchased    Value) of
                                            as         Units
                                         Part of     that May
                                         Publicly     Yet Be
                Total                   Announced    Purchased
               Number
              of Units       Average     Plans or    Under the
                              Price                    Plans
   Period     Purchase      Paid Per     Programs       or
                  d           Unit                   Programs
------------- --------      --------    ----------  ----------
------------- --------      --------    ----------  ----------
     --           -            --          ---          ---
January 2004       -         $    -         -           (1)
February 2004      -              -         -           (1)
 March 2004        -              -         -           (1)
 April 2004        -              -         -           (1)
  May 2004         -              -         -           (1)
  June 2004        -              -         -           (1)
  July 2004        -              -         -           (1)
 August 2004       -              -         -           (1)
  September        -              -         -           (1)
    2004
October 2004      16          187.50        -           (1)
November 2004      -              -         -           (1)
December 2004      -              -         -           (1)
              -------         -------    -------
                            ---
   TOTALS         16         $187.50        -
                ====         ======        ====

(1) Not determinable.


<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           $ 559,030     474,370   333,264   487,998   635,288

Net income before
cumulative
     effect    of    445,367     359,878   236,451   369,679   547,498
accounting
changes

Net income           445,367     348,033   205,451   369,679   547,498

Partners'   share
of
 net income:

General partners     45,980      36,703    25,845    41,368    56,250

Limited partners     399,387     311,330   179,606   328,311   491,248

Limited partners'
net income
  per unit before
cumulative
     effect    of     40.83
accounting                       32.92     21.53     33.56     50.22
changes

Limited partners'
 net income
 per unit             40.83
                                 31.83     18.36     33.56     50.22

Limited partners'
             cash
distributions
 per unit             43.41
                                 35.77     19.28     49.91     55.26

Total assets       $ 489,848     504,826   367,484   371,261   543,778


<PAGE>
Item 7.   Management's  Discussion and Analysis of Financial Condition  and
          Results of Operations

General
The  Partnership was formed to acquire non-operating interests in producing
oil  and  gas  properties, to produce and market crude oil and natural  gas
produced  from  such  properties and to distribute any  net  proceeds  from
operations  to  the  general  and  limited  partners.   Net  revenues  from
producing  oil  and  gas  properties are not reinvested  in  other  revenue
producing  assets except to the extent that producing facilities and  wells
are  reworked  or  where  methods are employed to improve  or  enable  more
efficient  recovery  of oil and gas reserves.  The  economic  life  of  the
Partnership thus depends on the period over which the Partnership's oil and
gas reserves are economically recoverable.

Increases   or   decreases   in  Partnership   revenues   and,   therefore,
distributions  to partners will depend primarily on changes in  the  prices
received  for  production,  changes in volumes of  production  sold,  lease
operating  expenses, enhanced recovery projects, offset drilling activities
pursuant  to  farm-out arrangements and on the depletion of  wells.   Since
wells  deplete over time, production can generally be expected  to  decline
from year to year.

Well  operating costs and general and administrative costs usually decrease
with   production   declines;  however,  these  costs  may   not   decrease
proportionately.   Net  income available for distribution  to  the  limited
partners  is  therefore expected to 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           13,943    14,800      (6%)
barrels
Gas production in mcf       61,644    75,100     (18%)
Total (BOE)                 24,217    27,317     (11%)
Average price per        $    39.51               34%
barrel of oil                         29.52
Average price per mcf    $     5.29               25%
of gas                                4.22
Income from net profits  $  556,829   450,353     24%
interests
Partnership              $  472,918   388,040     22%
distributions
Limited partner          $  424,668   349,866     21%
distributions
Per unit distribution    $    43.41               21%
to limited partners                   35.77

Number of limited           9,782     9,782
partner units

Income from net profits

The  Partnership's income from net profits interests increased to  $556,829
from $450,353 for the years ended December 31, 2004 and 2003, respectively,
an  increase of 24%.  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 34%, or $9.99 per barrel, resulting in an increase  of
approximately  $139,300 in income from net profits  interests.   Oil  sales
represented  63% of total oil and gas sales during the year ended  December
31, 2004 as compared to 58% 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 $1.07 per mcf, resulting in an  increase
of approximately $66,000 in income from net profits interests.

The  total increase in income from net profits interests due to the  change
in  prices  received from oil and gas production is approximately $205,300.
The  market price for oil and gas has been extremely volatile over the past
decade and management expects a certain amount of volatility to continue in
the foreseeable future.

<PAGE>

Oil  production decreased approximately 857 barrels or 6% during  the  year
ended  December 31, 2004 as compared to the year ended December  31,  2003,
resulting in a decrease of approximately $25,300 in income from net profits
interests.

Gas  production decreased approximately 13,456 mcf or 18% during  the  same
period, resulting in a decrease of approximately $56,800 in income from net
profits interests.

The  total decrease in income from net profits interests due to the  change
in  production  is approximately $82,100.  The decrease in gas  volumes  is
from a gas well with fluids restricting production.

Lease operating costs and production taxes were 6% higher, or approximately
$16,700  more  during the year ended December 31, 2004 as compared  to  the
year ended December 31, 2003.

Costs and Expenses

Total  costs and expenses decreased to $113,663 from $114,492 for the years
ended  December  31, 2004 and 2003, respectively, a decrease  of  1%.   The
decrease  is  a  result of lower accretion expense and  depletion  expense,
partially offset by an increase in general and administrative costs.

General  and  administrative costs consists of independent  accounting  and
engineering fees, computer services, postage, and Managing General  Partner
personnel  costs.   General  and  administrative  costs  increased  5%   or
approximately $4,400 during the year ended December 31, 2004 as compared to
the year ended December 31, 2003.

Depletion expense decreased to $14,427 for the year ended December 31, 2004
from  $19,000 for the same period in 2003.  This represents a  decrease  of
24%.   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 $.60 applied to 24,217 BOE as compared to $.70 applied to 27,317
BOE  for the same period in 2003.  The lower depletion rate in 2004 is  due
to  the upward revision in reserve estimates resulting from higher oil  and
gas prices.

Accretion expense decreased to $12,450 for the year ended December 31, 2004
from  $13,120 for the same period in 2003.  This represents a  decrease  of
5%.



<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           14,800    18,100     (18%)
barrels
Gas production in mcf       75,100    104,400    (28%)
Total (BOE)                 27,317    35,500     (23%)
Average price per        $    29.52               22%
barrel of oil                         24.11
Average price per mcf    $     4.22               63%
of gas                                2.59
Income from net profits  $  450,353   328,189     37%
interests
Partnership              $  388,040   209,138     85%
distributions
Limited partner          $  349,866   188,566     85%
distributions
Per unit distribution    $    35.77               85%
to limited partners                   19.28

Number of limited           9,782     9,782
partner units

Income from net profits

The  Partnership's income from net profits interests increased to  $450,353
from $328,189 for the years ended December 31, 2003 and 2002, respectively,
an  increase of 37%.  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 22%, or $5.41 per barrel, resulting in an increase  of
approximately  $80,100  in income from net profits  interests.   Oil  sales
represented  58% of total oil and gas sales during the year ended  December
31, 2003 as compared to 62% 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 63%, or $1.63 per mcf, resulting in an  increase
of approximately $122,400 in income from net profits interests.

The  total increase in income from net profits interests due to the  change
in  prices  received from oil and gas production is approximately $202,500.
The  market price for oil and gas has been extremely volatile over the past
decade and management expects a certain amount of volatility to continue in
the foreseeable future.

<PAGE>

Oil production decreased approximately 3,300 barrels or 18% during the year
ended  December 31, 2003 as compared to the year ended December  31,  2002,
resulting in a decrease of approximately $79,600 in income from net profits
interests.

Gas  production decreased approximately 29,300 mcf or 28% during  the  same
period, resulting in a decrease of approximately $75,900 in income from net
profits interests.

The  total decrease in income from net profits interests due to the  change
in  production is approximately $155,500.  Oil and gas volumes declined due
to  sale of two leases.  Also contributing to the decline in oil sales were
steep  declines  on  two properties.  Two wells had  steep  gas  production
declines.   One lease had mechanical problems resulting in the decrease  of
oil and gas volumes.

Lease operating costs and production taxes were 20% lower, or approximately
$74,800  less  during the year ended December 31, 2003 as compared  to  the
year ended December 31, 2002.  The decline in lease operating costs is  due
primarily to the sale of one lease in October 2002.

Costs and Expenses

Total  costs and expenses increased to $114,492 from $96,813 for the  years
ended  December 31, 2003 and 2002, respectively, an increase of  18%.   The
increase  is  the  result of the addition of accretion expense  and  higher
general  and  administrative  costs, partially  offset  by  a  decrease  in
depletion expense.

General  and  administrative costs consists of independent  accounting  and
engineering fees, computer services, postage, and Managing General  Partner
personnel  costs.   General  and  administrative  costs  increased  10%  or
approximately $7,600 during the year ended December 31, 2003 as compared to
the year ended December 31, 2002.

Depletion expense decreased to $19,000 for the year ended December 31, 2003
from  $22,000 for the same period in 2002.  This represents a  decrease  of
14%.   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 $.70 applied to 27,317 BOE as compared to $.62 applied to 35,500
BOE for the same period in 2002.

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  $151,827,  a  long  term   liability   of
approximately  $163,672  and  a  loss  of  approximately  $11,845  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 $174,445.  The increase  in  the  balance  from
January 1, 2003 is due to accretion expense of $13,120 plus the addition of
new  wells  for  $653.   The  pro  forma amount  of  the  asset  retirement
obligation  as  of December 31, 2002 was approximately $163,672.   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   $445,367,   $348,033   and   $205,451,   respectively.    Partnership
distributions  for the years ended December 31, 2004, 2003  and  2002  were
$472,918, $388,040 and $209,138.  These differences are indicative  of  the
changes in oil and gas prices, production and properties during 2004,  2003
and 2002.

The  source  for  the  2004  distributions of $472,918  were  oil  and  gas
operations  of  approximately  $474,500,  resulting  in  excess  cash   for
contingencies  or  subsequent  distributions.   The  source  for  the  2003
distributions  of  $388,040  were oil and gas operations  of  approximately
$396,200  and  property  sales of $12,500, resulting  in  excess  cash  for
contingencies  or  subsequent distributions.   The  sources  for  the  2002
distributions  of  $209,138  were oil and gas operations  of  approximately
$229,700  and property sales of approximately $3,400, resulting  in  excess
cash for contingencies or subsequent distributions.

Total  distributions during the year ended December 31, 2004 were  $472,918
of which $424,668 ($43.41 per unit) was distributed to the limited partners
and  $48,250 to the general partners.  Total distributions during the  year
ended  December 31, 2003 were $388,040 of which $349,866 ($35.77 per  unit)
was  distributed  to  the  limited partners  and  $38,174  to  the  general
partners.  Total distributions during the year ended December 31, 2002 were
$209,138 of which $188,566 ($19.28 per unit) was distributed to the limited
partners and $20,572 to the general partners.

Cumulative  cash distributions of $8,066,244 have been made to the  general
and  limited  partners as of December 31, 2004.  As of December  31,  2004,
$7,314,552 or $747.76 per limited partner unit has been distributed to  the
limited partners, representing 150% 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 $474,500  in
2004 compared to $396,200 in 2003 and approximately $229,700 in 2002.

The  Partnership had no cash flows from investing activities in 2004.  Cash
flows  provided by investing activities were approximately $12,500 in  2003
and approximately $3,400 in 2002.

Cash flows used in financing activities were approximately $472,800 in 2004
compared to $388,100 in 2003 and approximately $209,200 in 2002.  The  only
use in financing activities was the distributions to partners.

As  of  December  31, 2004, the Partnership had approximately  $150,900  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                                           25

<PAGE>









                     REPORT OF INDEPENDENT REGISTERED
                          PUBLIC ACCOUNTING FIRM

The Partners
Southwest Royalties Institutional Income Fund IX-B, L.P.
(A Delaware Limited Partnership)


We  have  audited  the  accompanying balance sheets of Southwest  Royalties
Institutional Income Fund IX-B, 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  Royalties
Institutional Income Fund IX-B, 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 Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2004 and 2003

                                   2004      2003
                                  ------    ------
Assets
---------

Current assets:
 Cash and cash equivalents    $  74,177    72,454
  Receivable  from  Managing     76,872    79,145
General Partner
                                 --------  --------
                                 ----      ----
  Total current assets           151,049   151,599
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       3,000,24  3,000,24
                                 7         7
       Less      accumulated
depreciation,
  depletion and amortization     2,661,44  2,647,02
                                 8         1
                                 --------  --------
                                 ----      ----
  Net oil and gas properties     338,799   353,226
                                 --------  --------
                                 ----      ----
                              $  489,848   504,825
                                 =======   =======
Liabilities  and   Partners'
Equity
----------------------------
------------

Current     liability      -  $  188       64
distribution payable
                                 --------  --------
                                 ----      ----
Asset retirement obligation      189,895   177,445
                                 --------  --------
                                 ----      ----
Partners' equity (deficit):
 General partners                (66,090)  (63,820)
 Limited partners                365,855   391,136
                                 --------  --------
                                 ----      ----
  Total partners' equity         299,765   327,316
                                 --------  --------
                                 ----      ----
                              $  489,848   504,825
                                 =======   =======












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

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)
                         Statements of Operations
              Years ended December 31, 20044, 2003 and 2002

                                     2004      2003      2002
                                     ----      ----      ----
Revenues
-------------
   Income   from  net  profits  $  556,829   450,353   328,189
interests
 Interest from operations          653       723       549
 Other                             1,548     23,294    4,526
                                   --------  --------  --------
                                   --        --        --
                                   559,030   474,370   333,264
                                   --------  --------  --------
                                   --        --        --
Expenses
------------
  Depreciation, depletion  and     14,427    19,000    22,000
amortization
 Accretion expense                 12,450    13,120    -
 General and administrative        86,786    82,372    74,813
                                   --------  --------  --------
                                   --        --        --
                                   113,663   114,492   96,813
                                   --------  --------  --------
                                   --        --        --
Net  income  before cumulative
effects
 of accounting changes             445,367   359,878   236,451

Cumulative effect of change in
accounting
 principle - SFAS No. 143 -        -         (11,845)  -
See Note 3
Cumulative effect of change in
accounting principle
 - change in depletion method      -         -         (31,000)
- See Note 4
                                   --------  --------  --------
                                   --        --        --
Net income                      $  445,367   348,033   205,451
                                   ======    ======    ======
Net income allocated to:
 Managing General Partner       $  41,382    33,033    23,261
                                   ======    ======    ======
 General Partner                $  4,598     3,670     2,584
                                   ======    ======    ======
 Limited partners               $  399,387   311,330   179,606
                                   ======    ======    ======
   Per  limited  partner  unit  $    40.83
before cumulative effects                    32.92     21.53
     Cumulative   effect   per     -          (1.09)    (3.17)
limited partner unit
                                   --------  --------  --------
                                   --        --        --
  Per limited partner unit      $    40.83
                                             31.83     18.36
                                   ======    ======    ======





                  The accompanying notes are an integral
                   part of these financial statements.
<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, 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  $  (67,622)  438,632   371,010

 Net income                      25,845    179,606   205,451

 Distributions                   (20,572)  (188,566  (209,138
                                           )         )
                                 --------  --------  --------
                                 --        ---       --
Balance at December 31, 2002     (62,349)  429,672   367,323

 Net income                      36,703    311,330   348,033

 Distributions                   (38,174)  (349,866  (388,040
                                           )         )
                                 --------  --------  --------
                                 --        ---       ---
Balance at December 31, 2003     (63,820)  391,136   327,316

 Net income                      45,980    399,387   445,367

 Distributions                   (48,250)  (424,668  (472,918
                                           )         )
                                 --------  --------  --------
                                 --        ---       ---
Balance at December 31, 2004  $  (66,090)  365,855   299,765
                                 ======    ======    ======


























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

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, 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   net  $  556,541   454,706   309,459
profits interests
  Cash paid for administrative
fees and general
  and administrative overhead      (84,225)  (82,478)  (84,881)
 Interest received                 653       723       549
 Other                             1,548     23,294    4,526
                                   --------  --------  --------
                                   ----      --        ---
    Net   cash   provided   by     474,517   396,245   229,653
operating activities
                                   --------  --------  --------
                                   ----      --        ---
Cash    flows   provided    by
investing activities:
   Sale   of   oil   and   gas     -         12,476    3,422
properties
                                   --------  --------  --------
                                   ----      --        ---
Cash  flows used in  financing
activities:
 Distributions to partners         (472,794  (388,137  (209,228
                                   )         )         )
                                   --------  --------  --------
                                   ----      ---       ---
Net  increase in cash and cash     1,723     20,584    23,847
equivalents

Beginning of year                  72,454    51,870    28,023
                                   --------  --------  --------
                                   ----      --        ---
End of year                     $  74,177    72,454    51,870
                                   =======   ======    ======
Reconciliation of  net  income
to net cash
    provided    by   operating
activities:

Net income                      $  445,367   348,033   205,451

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

  Depreciation, depletion  and     14,427    19,000    22,000
amortization
 Accretion expense                 12,450    13,120    -
  Cumulative effect of  change     -         11,845    31,000
in accounting principle
    (Increase)   decrease   in     (288)     4,353     (18,730)
receivables
    Increase   (decrease)   in     2,561     (106)     (10,068)
payables
                                   --------  --------  --------
                                   ----      --        ---
Net cash provided by operating  $  474,517   396,245   229,653
activities
                                   =======   ======    ======
Noncash investing and
financing activities:

 Increase in oil and gas
properties - Adoption
  of SFAS No. 143               $  -         151,827   -
                                   =======   ======    ======
 Increase in oil and gas
properties SFAS No. 143
  Additional wells due to       $  -         653       -
farmout arrangement
                                   =======   ======    ======

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

                      Notes to Financial Statements

1.   Organization
     Southwest Royalties Institutional Income Fund IX-B, 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
                              --------  --------
Oil and gas sales             90%       10%
Interest  income on  capital  100%      -
contributions
All other revenues            90%       10%
Organization  and   offering  100%      -
costs (1)
Syndication costs             100%      -
Amortization of organization  100%      -
costs
Property acquisition costs    100%      -
Gain/loss    on     property  90%       10%
disposition
Operating and administrative  90%       10%
costs (2)
Depreciation, depletion  and
amortization
 of oil and 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.

     The  Partnership's interest in oil and gas properties consists of  net
     profits  interests in proved properties located within the continental
     United States.  A net profits interest is created when the owner of  a
     working  interest  in a property enters into an arrangement  providing
     that  the  net profits interest owner will receive a stated percentage
     of  the net profit from the property.  The net profits interest  owner
     will not otherwise participate in additional costs and expenses of the
     property.

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies -continued

     Oil and Gas Properties - continued
     The Partnership recognizes income from its net profits interest in oil
     and  gas  property  on  an  accrual basis, while  the  quarterly  cash
     distributions  of the net profits interest are based on a  calculation
     of  actual  cash  received from oil and gas  sales,  net  of  expenses
     incurred  during  that quarterly period. If the net  profits  interest
     calculation  results in expenses incurred exceeding the  oil  and  gas
     income  received during a quarter, no cash distribution is due to  the
     Partnership's net profits interest until the deficit is recovered from
     future  net profits.  The Partnership accrues a quarterly loss on  its
     net profits interest provided there is a cumulative net amount due for
     accrued  revenue  as of the balance sheet date.  As  of  December  31,
     2004,  there were no timing differences, which resulted in  a  deficit
     net profit interest.

     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.

     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 364 mcf of gas, respectively.

     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 $(66,068) and $84,441, respectively, more (less)
     than  that shown on the accompanying Balance Sheets in accordance with
     generally accepted accounting principles.

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

     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, there were  9,782  limited
     partner units outstanding held by 589, 595 and 610 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.

     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)

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

3.   Cumulative effect of change in accounting principle - SFAS No. 143
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  Adoption of SFAS No. 143  is  required
     for  all  companies with fiscal years beginning after June  15,  2002.
     The new standard requires the Partnership to recognize a liability for
     the  present  value  of  all  legal obligations  associated  with  the
     retirement  of tangible long-lived assets and to capitalize  an  equal
     amount as a cost of the asset and depreciate the additional cost  over
     the  estimated  useful  life of the asset.  On January  1,  2003,  the
     Partnership    recorded   additional   costs,   net   of   accumulated
     depreciation,  of  approximately $151,827, a long  term  liability  of
     approximately  $163,672 and a loss of approximately  $11,845  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 $189,895.  The increase
     in  the  balance from January 1, 2004 is due to accretion  expense  of
     $12,450.   The pro forma amount of the asset retirement obligation  as
     of  December  31,  2002  was approximately $163,672.   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  $  224,405
method
                                   ======
   Per  limited  partner  unit  $    20.42
(9,782.0 units)
                                   ======
 Net income                     $  193,405
                                   ======
   Per  limited  partner  unit  $    17.25
(9,782.0 units)
                                   ======

4.    Cumulative  effect  of 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 $31,000 effective as of  January
     1, 2002.  The Partnership's depletion for years subsequent to 2001 has
     been calculated using the units-of-production.

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

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 is not  aware
     of  any  unasserted  violations, which would have a  material  adverse
     effect upon capital expenditures, earnings or the competitive position
     in  the  oil and gas industry.  However, the Managing General  Partner
     does  recognize  by  the very nature of its business,  material  costs
     could be incurred in the near term to bring the Partnership into total
     compliance.    The   amount  of  such  future  expenditures   is   not
     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  $51,400,
     $56,700  and $68,400 for the years ended December 31, 2004,  2003  and
     2002,   respectively.    The   amounts  for  administrative   overhead
     attributable  to  operating the partnership have  been  deducted  from
     gross  oil  and  gas  revenues  in the  determination  of  net  profit
     interest.   In  addition,  the Managing General  Partner  and  certain
     officers  and employees may have an interest in some of the properties
     that the Partnership also participates.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $68,400  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 $76,900 and $79,100 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2004 and 2003, respectively.


<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, 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               188,000   784,000

   Revisions   of   previous  18,000    188,000
estimates
 Production                   (18,000)  (104,000
                                        )
                              --------  --------
                              ----      ----
December 31, 2002             188,000   868,000

 Sales of reserves in place   (2,000)   (3,000)
   Revisions   of   previous  38,000    210,000
estimates
 Production                   (15,000)  (75,000)
                              --------  --------
                              ----      ----
December 31, 2003             209,000   1,000,00
                                        0

   Revisions   of   previous  21,000    66,000
estimates
 Production                   (14,000)  (62,000)
                              --------  --------
                              ----      ----
December 31, 2004             216,000   1,004,00
                                        0
                              =======   =======
Proved developed reserves -
December 31, 2002             185,000   762,000
                              =======   =======
December 31, 2003             205,000   951,000
                              =======   =======
December 31, 2004             200,000   937,000
                              =======   =======


<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, 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 $41.81, $31.37 and $29.25 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 $5.48,  $5.50
     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 Royalties Institutional Income Fund IX-B, 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           $  14,533,0  12,067,0  9,226,00
                                 00        00        0
Production, development and
 abandonment costs               5,814,00  4,956,00  3,960,00
                                 0         0         0
                                 --------  --------  --------
                                 ------    -----     ----
Future net cash flows            8,719,00  7,111,00  5,266,00
                                 0         0         0
10% annual discount for
  estimated timing  of  cash     4,800,00  3,689,00  2,244,00
flows                            0         0         0
                                 --------  --------  --------
                                 ------    ----      ----
Standardized measure of
  discounted future net cash  $  3,919,00  3,422,00  3,022,00
flows                            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  (450,000  (328,000
                                 )         )         )
Changes   in   prices    and     646,000   466,000   1,277,00
production costs                                     0
Changes of production rates
 (timing) and others             (261,000  (554,000  (86,000)
                                 )         )
Sales of minerals in place       -         (28,000)  -
Revisions of previous
 quantities estimates            327,000   664,000   448,000
Accretion of discount            342,000   302,000   156,000
Discounted future net
 cash flows -
Beginning of year                3,422,00  3,022,00  1,555,00
                                 0         0         0
                                 --------  --------  --------
                                 ----      ----      ----
End of year                   $  3,919,00  3,422,00  3,022,00
                                 0         0         0
                                 =======   =======   =======


<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

8.   Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2004:
 Total revenues             $ 124,709   131,259   138,161   164,901
 Total expenses               28,506    31,386    28,833    24,938
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 96,203    99,873    109,328   139,963
                              =======   =======   =======   =======

  Net  income per  limited  $   8.81
partners unit                           9.15      10.02     12.85
                              =======   =======   =======   =======

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2003:
 Total revenues             $ 167,679   84,230    99,673    122,788
 Total expenses               27,798    35,030    29,061    22,603
                              --------  --------  --------  --------
                              ----      ----      ----      ----
    Net    income   before
cumulative effect of
   a  change in accounting    139,881   49,200    70,612    100,185
principle
 Cumulative effect of SFAS    (11,845)  -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 128,036   49,200    70,612    100,185
                              =======   =======   =======   =======
  Income before cumulative
effect of a
    change  in  accounting  $  12.81
principle                               4.48      6.45      9.18
 Cumulative effect of SFAS    (1.09)         -         -         -
No. 143
                              --------  --------  --------  --------
                              ----      ----      ----      ----
  Net  income per  limited  $  11.72
partners unit                           4.48      6.45      9.18
                              =======   =======   =======   =======



<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
$68,400  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 435.0 limited partner units, a 4.0% limited partner interest.
The  Managing General Partner's total percentage interest ownership in  the
Partnership is 14.0%.

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 $68,400 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  net  profits  interest.   Certain  properties  in  which  the
Partnership  has an interest are operated by the Managing General  Partner,
who was paid approximately $51,400 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, 2003 and 2002 and fees billed for  other
services rendered by KPMG during those periods.

 For the Year Ended December     2004      2003
             31,
                                ------    ------
Audit Fees                     $12,865   $
                                         8,958
Audit Related Fees                  -         -
Tax Fees                            -
                                         -
All Other Fees                      -
                                         -
                                 ------
                               --        --------
    TOTAL                      $12,865   $
                                         8,958
                                =====
                                         =====

The  Audit  Committee of 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 Royalties Institutional
                          Income  Fund  IX-B, 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 Royalties Institutional
                          Income Fund IX-B, L.P. dated September 26,  1989.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1989.)

                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 Royalties Institutional Income
                          Fund IX-B, 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 Royalties
Institutional Income Fund IX-B, 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 Royalties Institutional Income
Fund IX-B, 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 Royalties
Institutional Income Fund IX-B, 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 Royalties Institutional Income
Fund IX-B, 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  Royalties
Institutional  Income  Fund  IX-B, 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  Royalties Institutional
                                   Income Fund IX-B, 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  Royalties Institutional
                                   Income Fund IX-B, L.P.

                                   March 31, 2005