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, 2005

                                    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 if the registrant is a well-known seasoned  issuer,
as defined in Rule 405 of the Securities Act.       Yes     No  X

Indicate  by  check mark if the registrant is not required to file  reports
pursuant to Section 13 or Section 15(d) of the Act.   Yes     No  X

Indicate  by  check mark whether the registrant (1) has filed  all  reports
required to be filed by Section 13 or 15(d) of the Securities Exchange  Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject  to
such filing requirements for the past 90 days.     Yes 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 a large accelerated filer,
an  accelerated  filer,  or  a non-accelerated filer.   See  definition  of
"accelerated  filer  and large accelerated filer"  in  Rule  12b-2  of  the
Exchange Act.

 Large  accelerated filer [   ]      Accelerated  filer   [    ]       Non-
 accelerated filer  [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

1B.  Unresolved Staff Comments                                           7

 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         15

 8.  Financial Statements and Supplementary Data                        16

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             30

9A.  Controls and Procedures                                            30

9B.  Other Information                                                  30

                                 Part III

10.  Directors and Executive Officers of the Registrant                 31

11.  Executive Compensation                                             31

12.  Security Ownership of Certain Beneficial Owners and Management     32

13.  Certain Relationships and Related Transactions                     32

14.  Principal Accountant Fees and Services                             32

                                 Part IV

15.  Exhibits and Financial Statement Schedules                         33

     Signatures                                                         34

<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.

     Standardized  measure  of discounted future net  cash  flows.  Present
value  of  proved reserves, as adjusted to give effect to estimated  future
abandonment costs, net of the estimated salvage value of related equipment.

<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 2005, 62% of the Partnership's revenues were derived
from  the  sale of oil production and 38% 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 2006.  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.

Item 1B.  Unresolved Staff Comments

     Not applicable.

<PAGE>

Item 2.   Properties

As  of December 31, 2005, 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 417 wells and units.

Reserves

The  following table sets forth certain information as of December 31, 2005
with  respect  to the Partnership's estimated proved oil and  gas  reserves
pursuant  to  SEC guidelines and standardized measure of discounted  future
net cash flows.

                      Proved Developed       Proved      Total
                    ---------------------    -------    -------
                    ---------------------    -------      ----
                            -----             ----
                    Producing    Nonprod     Undevel     Proved
                                  ucing       oped
                    ---------    -------     -------    -------
                    ---------    -------     -------      ----
                        -          ----       ----
Oil (Bbls)          180,000       -           6,000       186,000
Gas (Mcf)           799,000       -           51,000      850,000
Total (BOE)         313,000       -           15,000      328,000

Standardized
measure          of
discounted
  future  net  cash                                       $5,709,
flows                                                   000

The  following table sets forth certain information as of December 31, 2005
regarding  the  Partnership's  proved oil  and  gas  reserves  for  certain
significant fields.

                 Proved Reserves
             -----------------------
             -----------------------
                   ----------
                              Total     Percen
                               Oil       t of
              Oil     Gas     Equiva    Total
                               lent      Oil
             (Bbls   (Mcf)    (BOE)     Equiva
               )                         lent
             -----   -----    ------    ------
             -----   -----    ------    ------
              ---      -       ---       ---

 Big Spring  87,00   53,00    96,000    29.3%
             0       0
 Henshaw     13,00   166,0    41,000    12.5%
             0       00
 Sombrero    4,000   229,0    42,000    12.8%
                     00
    Puckett  2,000   143,0    26,000    7.9%
East/Hockit          00
 Other       80,00   259,0    123,00    37.5%
             0       00       0
             -----   -----    ------    ------
             -----   -----    ------    ------
             -       --                 --
 Total       186,0   850,0    328,00    100.0%
             00      00       0
             =====   =====    ======    ======
             =       ==       =         ==

The  estimates of proved reserves at December 31, 2005 and the standardized
measure  of  discounted future net cash flows 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.

In  accordance with applicable financial accounting and reporting standards
of  the  SEC,  the estimates of the Partnership's proved reserves  and  the
standardized  measure of discounted future net cash flows 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  standardized measure of discounted future net cash  flows  as  of
December  31, 2005 were $59.03 per Bbl of oil and natural gas  liquids  and
$10.51  per Mcf of gas, as compared to $41.81 per Bbl of oil and $5.48  per
Mcf of gas as of December 31, 2004.

<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  standardized measure 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 2005 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, 2005, there were 570 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 2005, distributions were made  totaling
$600,000,  with  $540,000  ($55.20 per unit)  distributed  to  the  limited
partners and $60,000 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 2005.

                Total
               Number
              of Units       Average
                              Price
   Period     Purchase      Paid Per
                  d           Unit
------------- --------      --------
------------- --------      --------
     --           -            --
January 2005      74         $108.03
February 2005      -              -
 March 2005        -              -
 April 2005       45         117.14
  May 2005         -              -
  June 2005        -              -
  July 2005       59          77.66
 August 2005       -              -
  September        -              -
    2005
October 2005
November 2005      -              -
December 2005      -              -
              -------         -------
                            ---
   TOTALS        178         $100.27
                ====         ======


<PAGE>
Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2005,  2004,  2003,  2002 and 2001 should be read in conjunction  with  the
financial statements included in Item 8:

                                  Years ended December 31,
                     -------------------------------------------------
                                          --------
                        2005       2004      2003      2002      2001
                       -----       ----      ----      ----      ----
Revenues           $ 667,326     559,030   474,370   333,264   487,998

Net income before
cumulative
     effect    of    559,694     445,367   359,878   236,451   369,679
accounting change

Net income           559,694     445,367   348,033   205,451   369,679

Partners'   share
of
 net income:

General partners     57,293      45,980    36,703    25,845    41,368

Limited partners     502,401     399,387   311,330   179,606   328,311

Limited partners'
net income
  per unit before
cumulative
     effect    of     51.36      40.83
accounting change                          32.92     21.53     33.56

Limited partners'
 net income
 per unit             51.36      40.83
                                           31.83     18.36     33.56

Limited partners'
             cash
distributions
 per unit             55.20      43.41
                                           35.77     19.28     49.91

Total assets       $ 506,858     489,848   504,826   367,484   371,261


<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>
Supplemental Information
The following unaudited information is intended to supplement the financial
statements  included  in  this Form 10-K with  data  that  is  not  readily
available from those statements.

                               Years Ended December 31,
                               2005      2004      2003
                              ------    ------   --------
                                                   -----
Oil production in            11,681    13,943    14,800
barrels
Gas production in mcf        54,549    61,644    75,100
Total (BOE)                  20,773    24,217    27,317
Average price per barrel  $    52.27     39.51
of oil                                           29.52
Average price per mcf of  $     6.78      5.29
gas                                              4.22
Partnership               $  600,000   472,918   388,040
distributions
Limited partner           $  540,000   424,668   349,866
distributions
Per unit distribution to  $    55.20     43.41
limited partners                                 35.77
Number of limited            9,782     9,782     9,782
partner units

Operating Results
The  following discussion compares our results for the year ended  December
31,  2005 to the two previous years.  All references to 2005, 2004 and 2003
within this section refer to the respective annual periods.

Income from net profits
Oil  and  gas  prices continued to climb to record levels compared  to  the
previous  two  years.  Comparing 2005 to 2004, oil and gas sales  increased
$103,400,  of  which price variances accounted for a $230,300 increase  and
production variances accounted for a $126,900 decrease.  Comparing 2004  to
2003,  oil  and  gas  sales increased $123,100, of  which  price  variances
accounted for a $205,200 increase and production variances accounted for  a
$82,100 decrease.

Production in 2005 (on a BOE basis) was 14% lower than 2004 and  24%  lower
than 2003.  Our oil production was 16% lower and our gas production was 12%
lower in 2005 than 2004 due primarily to normal production declines.

In  2005,  our realized oil price was 32% higher than 2004 and  77%  higher
than  2003, while our realized gas price was 28% higher than 2004  and  61%
higher  than  2003.  Historically, the markets for oil and  gas  have  been
volatile,  and they are likely to continue to be volatile.   We  have  very
little  control  over  the  prices we receive for  our  production  at  the
wellhead  since  most  of our physical marketing arrangements  are  market-
sensitive.

Oil  and gas production costs on a BOE basis increased from $13.23 per  BOE
in 2004 and $11.11 per BOE in 2003 to $15.15 per BOE in 2005.  The increase
in  oil  and  gas  production costs in 2005 was  due  primarily  to  higher
oilfield service costs and an increase in activities. Also contributing  to
the  increase  was  higher production tax costs related to  higher  product
prices.  It  is  likely that these factors will continue to  contribute  to
higher production costs in future periods.

Expenses
Depletion  on a BOE basis increased 7% from 2004 and decreased by  8%  from
2003.  Comparing 2005 to 2004, depletion expense decreased $1,200, of which
rate  variances  accounted  for a $900 increase  and  production  variances
accounted for a $2,100 decrease.  Comparing 2004 to 2003, depletion expense
decreased  $4,600, of which rate variances accounted for a $2,400  decrease
and  production variances accounted for a $2,200 decrease.  Depletion rates
are  a  function of net capitalized costs and estimated reserve quantities.
The rates for 2006 are expected to be similar to the 2005 rates.

General and administrative ("G&A") expenses were 7% lower than 2004 and  2%
lower  than  2003 due primarily to lower engineering fees and lower  annual
report printing costs.

Liquidity and Capital Resources
Partnership  distributions during the year ended  December  31,  2005  were
$600,000,  of  which $540,000 was distributed to the limited  partners  and
$60,000  to  the  general  partners.   Cumulative  cash  distributions   of
$8,666,244  have  been  made  to the general and  limited  partners  as  of
December  31,  2005.  As of December 31, 2005, $7,854,552  or  $802.96  per
limited  partner  unit  has  been  distributed  to  the  limited  partners,
representing 161% of contributed capital.

<PAGE>
Our  primary  source of cash from operating activities is our oil  and  gas
sales, net of production costs.  Cash flow provided by operating activities
for  2005  was 22% higher than 2004 due to the combined effects of  several
drivers.   The  positive benefits of a 12% increase in oil and  gas  sales,
driven  primarily  by higher oil and gas prices, were combined  with  lower
production costs.  Our only use in financing activities is the distribution
to partners which was 27% higher than 2004.

As  of  December  31, 2005, the Partnership had approximately  $137,100  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 adopted this
statement  in the third quarter of 2005, and it did not have an  effect  on
the financial statements.

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 are 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 implementation of SAB 106 did not 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                 17

Balance Sheets                                                          18

Statements of Operations                                                19

Statement of Changes in Partners' Equity                                20

Statements of Cash Flows                                                21

Notes to Financial Statements                                           22

<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,
2005  and 2004, and the related statements of operations, partners' equity,
and  cash  flows  for  each  of the years in the  three-year  period  ended
December  31,  2005.  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, 2005 and 2004,  and
the  results of its operations and its cash flows for each of the years  in
the  three-year  period ended December 31, 2005, in  conformity  with  U.S.
generally accepted accounting principles.

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 30, 2006


<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2005 and 2004

                                   2005      2004
                                  ------    ------
Assets
---------

Current assets:
 Cash and cash equivalents    $  54,791    74,177
  Receivable  from  Managing     73,089    76,872
General Partner
 Other                           9,369
                                 --------  --------
                                 ----      ----
  Total current assets           137,249   151,049
                                 --------  --------
                                 ----      ----
Oil  and  gas  properties  -
using the full-
 cost method of accounting       3,044,29  3,000,24
                                 2         7
       Less      accumulated
depreciation,
  depletion and amortization     2,674,68  2,661,44
                                 3         8
                                 --------  --------
                                 ----      ----
  Net oil and gas properties     369,609   338,799
                                 --------  --------
                                 ----      ----
                              $  506,858   489,848
                                 =======   =======
Liabilities  and   Partners'
Equity
----------------------------
------------

Current     liability      -  $  113       188
distribution payable
                                 --------  --------
                                 ----      ----
Asset retirement obligation      247,286   189,895
                                 --------  --------
                                 ----      ----
Partners' equity (deficit):
 General partners                (68,797)  (66,090)
 Limited partners                328,256   365,855
                                 --------  --------
                                 ----      ----
  Total partners' equity         259,459   299,765
                                 --------  --------
                                 ----      ----
                              $  506,858   489,848
                                 =======   =======












                  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, 2005, 2004 and 2003

                                     2005      2004      2003
                                     ----      ----      ----
Revenues
-------------
   Income   from  net  profits  $  665,923   556,829   450,353
interests
 Interest income                   1,403     653       723
 Other                             -         1,548     23,294
                                   --------  --------  --------
                                   --        --        --
                                   667,326   559,030   474,370
                                   --------  --------  --------
                                   --        --        --
Expenses
------------
  Depreciation, depletion  and     13,235    14,427    19,000
amortization
 Accretion expense                 13,346    12,450    13,120
 General and administrative        81,051    86,786    82,372
                                   --------  --------  --------
                                   --        --        --
                                   107,632   113,663   114,492
                                   --------  --------  --------
                                   --        --        --
Net  income  before cumulative
effect
 of accounting change              559,694   445,367   359,878

Cumulative effect of change in
accounting
 principle - SFAS No. 143 -        -         -         (11,845)
See Note 3
                                   --------  --------  --------
                                   --        --        --
Net income                      $  559,694   445,367   348,033
                                   ======    ======    ======
Net income allocated to:
 Managing General Partner       $  51,564    41,382    33,033
                                   ======    ======    ======
 General Partner                $  5,729     4,598     3,670
                                   ======    ======    ======
 Limited partners               $  502,401   399,387   311,330
                                   ======    ======    ======
   Per  limited  partner  unit  $    51.36     40.83
before cumulative effect                               32.92
     Cumulative   effect   per     -         -          (1.09)
limited partner unit
                                   --------  --------  --------
                                   --        --        --
  Per limited partner unit      $    51.36     40.83
                                                       31.83
                                   ======    ======    ======





                  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, 2005, 2004 and 2003

                                 General   Limited
                                 Partners  Partners   Total
                                 --------  --------   -----

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

 Net income                      57,293    502,401   559,694

 Distributions                   (60,000)  (540,000  (600,000
                                           )         )
                                 --------  --------  --------
                                 --        ---       --
Balance at December 31, 2005  $  (68,797)  328,256   259,459
                                 ======    ======    ======


























                  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, 2005, 2004 and 2003

                                     2005      2004      2003
                                    ------    ------    ------
Cash   flows  from   operating
activities:
   Cash   received  from   net  $  660,337   559,102   454,600
profits interests
  Cash paid for administrative
fees and general
  and administrative overhead      (81,051)  (86,786)  (82,372)
 Interest received                 1,403     653       723
 Other                             -         1,548     23,294
                                   --------  --------  --------
                                   ----      ----      --
    Net   cash   provided   by     580,689   474,517   396,245
operating activities
                                   --------  --------  --------
                                   ----      ----      --
Cash   flows  from   investing
activities:
   Sale   of   oil   and   gas     -         -         12,476
properties
                                   --------  --------  --------
                                   ----      ----      --
Cash   flows  from   financing
activities:
 Distributions to partners         (600,000  (472,918  (388,040
                                   )         )         )
    (Decrease)   increase   in     (75)      124       (97)
distribution payable
                                   --------  --------  --------
                                   ----      ----      ---
    Net  cash  flows  used  in     (600,075  (472,794  (388,137
financing activities               )         )         )
                                   --------  --------  --------
                                   ----      ----      ---
Net  (decrease)  increase   in     (19,386)  1,723     20,584
cash and cash equivalents

Beginning of year                  74,177    72,454    51,870
                                   --------  --------  --------
                                   ----      ----      --
End of year                     $  54,791    74,177    72,454
                                   =======   =======   ======
Reconciliation of  net  income
to net cash
    provided    by   operating
activities:

Net income                      $  559,694   445,367   348,033

Adjustments  to reconcile  net
income to net
  cash  provided by  operating
activities:
  Depreciation, depletion  and     13,235    14,427    19,000
amortization
 Accretion expense                 13,346    12,450    13,120
  Cumulative effect of  change     -         -         11,845
in accounting principle
    (Increase)   decrease   in     (5,586)   2,273     4,247
receivables
                                   --------  --------  --------
                                   ----      ----      --
Net cash provided by operating  $  580,689   474,517   396,245
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                  $  44,045    -         653
                                   =======   =======   ======




                  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, 2005, 2004 and  2003,
     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,
     2005, 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
     The  Partnership  recognizes 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, 2005 and 2004  the
     Partnership was overproduced by 364 mcf of gas.

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

     In   accordance  with  the  requirements  of  Statement  of  Financial
     Accounting  Standards  No.  109, "Accounting  for  Income  Taxes"  the
     Partnership's tax basis in its net oil and gas properties at  December
     31,  2005  and 2004 is $112,824 and $66,068, respectively,  less  than
     that  shown  on  the  accompanying Balance Sheets in  accordance  with
     generally accepted accounting principles.

     Cash and Cash Equivalents
     For purposes of the statement of cash flows, the Partnership considers
     all  highly liquid debt instruments purchased with a maturity of three
     months or less to be cash equivalents.  The Partnership maintains  its
     cash at one financial institution.

<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

     Number of Limited Partner Units
     As  of  December  31,  2005, 2004 and 2003, there were  9,782  limited
     partner units outstanding held by 570, 589 and 595 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 per limited partnership unit
     The net income 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 adopted this statement in the third quarter  of
     2005, and it did not have an effect on the financial statements.

     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 are 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
     implementation  of  SAB  106 did not have a  material  impact  on  our
     financial statements.

3.   Asset Retirement Obligations
     On  January  1, 2003, the Partnership adopted Statement  of  Financial
     Accounting   Standards  No.  143,  Accounting  for  Asset   Retirement
     Obligations  ("SFAS No. 143").  The 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 $151,827, a long term liability of
     $163,672  and  a  loss  of  $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.

     Changes in abandonment obligations for 2005 and 2004 are as follows:

                                        2005     2004
                                       -------  -------
Beginning of year                   $  189,895  177,445
Accretion expense                      13,346   12,450
Revisions of previous estimates        44,045   -
                                       -------  -------
                                       -------  -----
End of year                         $  247,286  189,895
                                       =======  =======
                                       =

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

                      Notes to Financial Statements

4.   Commitments and Contingent Liabilities
     The Managing General Partner has the right, but not the obligation, to
     purchase limited partnership units should an investor desire to  sell.
     The  value of the unit is determined by adding the sum of (1)  current
     assets  less liabilities and (2) the present value of the  future  net
     revenues attributable to proved reserves and by discounting the future
     net revenues at a rate not in excess of the prime rate charged by 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, 2005, 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.

5.   Related Party Transactions
     A  significant  portion  of the oil and gas properties  in  which  the
     Partnership  has  an interest are purchased from and operated  by  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  $51,900,
     $51,400  and $56,700 for the years ended December 31, 2005,  2004  and
     2003,   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  2005,  2004  and 2003 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 $73,100 and $76,900 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2005 and 2004, respectively.


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

                      Notes to Financial Statements

6.   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, 2003               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

   Revisions   of   previous  (18,000)  (99,000)
estimates
 Production                   (12,000)  (55,000)
                              --------  --------
                              ----      ----
December 31, 2005             186,000   850,000
                              =======   =======
Proved developed reserves -
December 31, 2003             205,000   951,000
                              =======   =======
December 31, 2004             200,000   937,000
                              =======   =======
December 31, 2005             180,000   799,000
                              =======   =======


     Net  revisions of 35,000 BOE in 2005 consisted of approximately 28,000
     BOE  of upward revisions attributable to the effects of higher product
     prices on the estimated quantities of proved reserves, net of downward
     revisions of approximately 63,000 BOE attributable to well performance
     primarily from properties in the Henshaw field of New Mexico.

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

                      Notes to Financial Statements

6.   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
     standardized  measure as of December 31, 2005, 2004 and 2003  reflects
     an average oil price of $59.03, $41.81 and $31.37 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 standardized measure as of December 31,
     2005,  2004 and 2003 reflects an average natural gas price of  $10.51,
     $5.48 and $5.50 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

6.   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, 2005, 2004 and 2003 is
     presented below:

                                   2005      2004      2003
                                  -----     -----     -----
Future cash inflows           $  19,922,0  14,533,0  12,067,0
                                 00        00        00
Production, development and
 abandonment costs               6,716,00  5,814,00  4,956,00
                                 0         0         0
                                 --------  --------  --------
                                 ------    ------    -----
Future net cash flows            13,206,0  8,719,00  7,111,00
                                 00        0         0
10% annual discount for
  estimated timing  of  cash     7,497,00  4,800,00  3,689,00
flows                            0         0         0
                                 --------  --------  --------
                                 ------    ------    ----
Standardized measure of
  discounted future net cash  $  5,709,00  3,919,00  3,422,00
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,
     2005, 2004 and 2003 are as follows:

                                   2005      2004      2003
                                  -----     -----     -----
Sales   of   oil   and   gas
produced,
 net of production costs      $  (666,000  (557,000  (450,000
                                 )         )         )
Changes   in   prices    and     2,821,00  646,000   466,000
production costs                 0
Changes of production rates
 (timing) and others             (156,000  (261,000  (554,000
                                 )         )         )
Sales of minerals in place       -         -         (28,000)
Revisions of previous
 quantities estimates            (601,000  327,000   664,000
                                 )
Accretion of discount            392,000   342,000   302,000
Discounted future net
 cash flows -
Beginning of year                3,919,00  3,422,00  3,022,00
                                 0         0         0
                                 --------  --------  --------
                                 ----      ----      ----
End of year                   $  5,709,00  3,919,00  3,422,00
                                 0         0         0
                                 =======   =======   =======


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

                      Notes to Financial Statements

7.   Selected Quarterly Financial Results - (unaudited)

                                             Quarter
                              --------------------------------------
                              --------------------------------------
                                                -
                               First     Second    Third     Fourth
                               ------   --------  -------   --------
                                          ---                  -
2005:
 Total revenues             $ 158,391   170,933   185,699   152,303
 Total expenses               28,152    28,180    24,387    26,913
                              --------  --------  --------  --------
                              ----      ----      ----      ----
 Net income                 $ 130,239   142,753   161,312   125,390
                              =======   =======   =======   =======

  Net  income per  limited  $  11.95
partners unit                           13.10     14.81     11.50
                              =======   =======   =======   =======


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




<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,
2005  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 74, 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  54,  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 51, 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.

RANDY  HOWARD, age 50, is Vice President - of the Managing General Partner,
having served in this capacity since March 2006.

ROBERT C. LYON, age 69, 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 49, 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.

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 2005, 2004 and 2003 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  613 limited partner units, a 5.6% limited partner  interest.
The  Managing General Partner's total percentage interest ownership in  the
Partnership is 15.6%.

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 2005, 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 $51,900 for administrative overhead attributable
to operating such properties during 2005.

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 Accountant 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, 2005 and 2004 and fees billed for  other
services rendered by KPMG during those periods.

 For the Year Ended December     2005      2004
             31,
                                ------    ------
Audit Fees                     $13,303   $
                                         12,865
Audit Related Fees                  -         -
Tax Fees                            -
                                         -
All Other Fees                      -
                                         -
                                 ------
                               --        --------
    TOTAL                      $13,303   $
                                         12,865
                                =====
                                         =====

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 30, 2006

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 30, 2006                     Date:     March 30, 2006




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

Date:     March 30, 2006




<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 30, 2006              /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 30, 2006               /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, 2005 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 30, 2006


                                   /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 30, 2006