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 [Fee Required]

For the fiscal year ended December 31, 2001

                                    OR

[ ]    Transition  report pursuant to Section 13 or 15(d) of the Securities
       Exchange Act of 1934 [No Fee Required]

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.)

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

Registrant's telephone number, including area code  (915) 686-9927

       Securities registered pursuant to Section 12(b) of the Act:

                                   None

       Securities registered pursuant to Section 12(g) of the Act:

                      limited partnership interests

Indicate by check mark whether registrant (1) has filed reports required to
be  filed  by  Section 13 or 15(d) of the Securities Exchange Act  of  1934
during  the  preceding  12  months (or for such  shorter  period  that  the
registrant was required to file such reports), and (2) has been subject  to
such filing requirements for the past 90 days:     Yes   x    No

Indicate by check mark if disclosure of delinquent filers pursuant to  Item
405  of  Regulation S-K (229.405 of this chapter) is not contained  herein,
and  will  not  be  contained,  to the best of registrant's  knowledge,  in
definitive  proxy or information statements incorporated  by  reference  in
Part III of this Form 10-K or any amendment to this Form 10-K.     [x]

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

The  total  number of pages contained in this report is 39.   There  is  no
exhibit index.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          6

 3.  Legal Proceedings                                                   7

 4.  Submission of Matters to a Vote of Security Holders                 7

                                 Part II

 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                 8

 6.  Selected Financial Data                                             9

 7.  Management's Discussion and Analysis of
     Financial Condition and Results of Operations                      10

 8.  Financial Statements and Supplementary Data                        18

 9.  Changes in and Disagreements with Accountants
     on Accounting and Financial Disclosure                             33

                                 Part III

10.  Directors and Executive Officers of the Registrant                 34

11.  Executive Compensation                                             35

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         35

13.  Certain Relationships and Related Transactions                     37

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        38

     Signatures                                                         39

<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  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 nonoperating interests.  The
Partnership  purchased  either all or part of the  rights  and  obligations
under various oil and gas leases.

The  principal executive offices of the Partnership are located at  407  N.
Big Spring, Suite 300, Midland, Texas, 79701.  The Managing General Partner
of  the  Partnership,  Southwest Royalties,  Inc.  (the  "Managing  General
Partner")   and  its  staff  of  89  individuals,  together  with   certain
independent  consultants  used  on an "as needed"  basis,  perform  various
services on behalf of the Partnership, including the selection of  oil  and
gas properties and the marketing of production from such properties.  H. H.
Wommack,  III,  a  stockholder, director, President and  Treasurer  of  the
Managing  General Partner, is also a general partner.  The Partnership  has
no employees.

Principal Products, Marketing and Distribution
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.  All oil and gas produced from these properties is sold  to
unrelated third parties in the oil and gas business.

The  revenues  generated from the Partnership's oil and gas activities  are
dependent upon the current market for oil and gas.  The prices received  by
the Partnership for its oil and gas production depend upon numerous factors
beyond   the   Partnership's  control,  including  competition,   economic,
political  and regulatory developments and competitive energy sources,  and
make it particularly difficult to estimate future prices of oil and natural
gas.

<PAGE>
For  nearly nine months, despite the fears of a global recession, crude oil
prices  held steady between $26 and $28 per barrel due in part to a  series
of  OPEC  and  non-OPEC production cuts.  Then, following what  has  become
known  simply  as  "9-11",  crude prices plunged  immediately  to  $22  and
gradually  fell  to below $18 per barrel.  Slower demand  across  the  U.S.
caused by the threat of recession and warmer than expected weather also led
to  declining prices in the latter half of 2001.  However, the  oil  cartel
and other non-member countries agreed for the fourth time since February to
curb  output in an effort to stabilize prices.  Crude oil contracts trading
on the NYMEX closed the year at approximately $20 per barrel.

Spot  prices in 2001 climbed to their highest levels ever, with the  yearly
average  price  nationwide reaching $4.14/MMBtu, up  9.77%  from  the  2000
average  of $3.77/MMBtu.  Prices reached their zenith in the first  quarter
of  2001 before beginning a steady decline throughout the remainder of  the
year.   The  terrorist  attacks  of  September  11  knocked  the  New  York
Mercantile Exchange out of the market for several days and shook  the  spot
marketplace into a maintenance mode.  As companies measured the  impact  of
the  attacks on the U.S. economy, spot prices deteriorated further.  In the
fourth  quarter,  prices  bottomed out for the year  with  the  three-month
average  falling to $2.31/MMBtu.  As for 2002, record-high  storage  levels
and  the  expectation of a flat economy through the first half of the  year
are  leading  industry  experts to predict prices to  average  $2.05/MMBtu,
remaining above the $2.00 per MMBtu level for a 5th consecutive year.

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

                                  Oil          Gas

                    2001          56%          44%
                    2000          56%          44%
                    1999          58%          42%

As  the table indicates, the Partnership's revenue is almost evenly divided
between its oil and gas production, the Partnership revenues will be highly
dependent upon the future prices and demands for oil and gas.

Seasonality of Business
Although the demand for natural gas is highly seasonal, with higher  demand
in  the colder winter months and in very hot summer months, the Partnership
has  been able to sell all of its natural gas, either through contracts  in
place or on the spot market at the then prevailing spot market price.  As a
result,  the volumes sold by the Partnership have not fluctuated materially
with the change of season.

Customer Dependence
No  material portion of the Partnership's business is dependent on a single
purchaser,  or  a  very few purchasers, where the loss of  one  would  have
material  adverse impact on the Partnership.  Two purchasers accounted  for
63% of the Partnership's total oil and gas production during 2001: Phillips
66  Company for 48% and Duke Energy Field Services for 15%.  One  purchaser
accounted for 69% of the Partnership's total oil and gas production  during
2000:   Phillips 66 Company 69%.  One purchaser accounted for  62%  of  the
Partnership's  total  oil  and gas production  during  1999:   Phillips  66
Company for 62%.

All  purchasers of the Partnership's oil and gas production  are  unrelated
third  parties.   In the event any of these purchasers were to  discontinue
purchasing  the  Partnership's  production, the  Managing  General  Partner
believes that a substitute purchaser or purchasers could be located without
undue  delay.   No  other purchaser accounted for an  amount  equal  to  or
greater than 10% of the Partnership's sales of oil and gas production.


<PAGE>
Competition
Because  the  Partnership has utilized all of its funds available  for  the
acquisition  of 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

Oil  and Gas Production - The production and sale of oil and gas is subject
to  federal and state governmental regulation in several respects, such  as
existing price controls on natural gas and possible price controls on crude
oil,  regulation of oil and gas production by state and local  governmental
agencies, pollution and environmental controls and various other direct and
indirect   regulation.    Many  jurisdictions  have  periodically   imposed
limitations on oil and gas production by restricting the rate of  flow  for
oil  and  gas wells below their actual capacity to produce and by  imposing
acreage limitations for the drilling of wells.  The federal government  has
the  power  to  permit increases in the amount of oil imported  from  other
countries and to impose pollution control measures.

Various  aspects of the Partnership's oil and gas activities are  regulated
by  administrative agencies under statutory provisions of the states  where
such  activities  are  conducted and by certain  agencies  of  the  federal
government for operations on Federal leases.  Moreover, certain  prices  at
which the Partnership may sell its natural gas production are controlled by
the  Natural Gas Policy Act of 1978, the Natural Gas Wellhead Decontrol Act
of  1989  and the regulations promulgated by the Federal Energy  Regulatory
Commission.

Environmental  - The Partnership's oil and gas activities  are  subject  to
extensive  federal,  state  and local laws and  regulations  governing  the
generation,  storage, handling, emission, transportation and  discharge  of
materials into the environment.  Governmental authorities have the power to
enforce compliance with their regulations, and violations carry substantial
penalties.   This  regulatory burden on the oil and gas industry  increases
its cost of doing business and consequently affects its profitability.  The
Managing  General  Partner  is  unable to  predict  what,  if  any,  effect
compliance will have on the Partnership.

Industry  Regulations  and  Guidelines - Certain industry  regulations  and
guidelines  apply to the registration, qualification and operation  of  oil
and  gas programs in the form of limited partnerships.  The Partnership  is
subject  to  these  guidelines  which regulate  and  restrict  transactions
between the Managing General Partner and the Partnership.

The  Partnership  complies with these guidelines and the  Managing  General
Partner  does not anticipate that continued compliance will have a material
adverse effect on Partnership operations.

Partnership Employees
The Partnership has no employees; however, the Managing General Partner has
a  staff of geologists, engineers, accountants, landmen and clerical  staff
who  engage in Partnership activities and operations and perform additional
services  for  the  Partnership as needed.  In  addition  to  the  Managing
General  Partner's  staff, the Partnership engages independent  consultants
such  as petroleum engineers and geologists as needed.  As of December  31,
2001,  there were 89 individuals directly employed by the Managing  General
Partner in various capacities.

<PAGE>
Item 2.   Properties

In  determining whether an interest in a particular producing property  was
to  be  acquired, the Managing General Partner considered such criteria  as
estimated  oil  and  gas reserves, estimated cash flow  from  the  sale  of
production,  present  and  future prices of oil  and  gas,  the  extent  of
undeveloped  and  unproved reserves, the potential for secondary,  tertiary
and other enhanced recovery projects and the availability of markets.

As  of December 31, 2001, 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,  Midland,  Pecos,  Reagan,
Terry,  Ward,  Winkler  and  Yoakum Counties of  Texas.   These  properties
consist of various interests in approximately 309 wells and units.

Due  to  the  Partnership's  objective of  maintaining  current  operations
without engaging in the drilling of any developmental or exploratory wells,
or  additional acquisitions of producing properties, there has not been any
significant changes in properties during 2001, 2000 and 1999.

There  were  no  property sales during 2001 and 2000.   During  1999,  four
leases were sold for approximately $210,000.

Significant Properties
The  following  table  reflects the significant  properties  in  which  the
Partnership has an interest:

                        Date
                     Purchased          No. of           Proved Reserves*
Name and Location   and Interest        Wells        Oil (bbls)  Gas (mcf)
-----------------   ------------       -------       ----------  ----------

Phillips/Odessa       1/90 at 6%         45           174,000     586,000
Properties,           to 48% net
16 counties in        profits
Texas, 2 counties     interests
in New Mexico

*Ryder  Scott  Petroleum Engineers prepared the reserve and  present  value
data for the Partnership's existing properties as of January 1, 2002.   The
reserve  estimates were made in accordance with guidelines  established  by
the  Securities  and  Exchange  Commission  pursuant  to  Rule  4-10(a)  of
Regulation  S-X.   Such guidelines require oil and gas reserve  reports  be
prepared  under  existing  economic  and  operating  conditions   with   no
provisions   for   price   and  cost  escalation  except   by   contractual
arrangements.

Oil  price  adjustments were made in the individual evaluations to  reflect
oil quality, gathering and transportation costs. The results of the reserve
report as of January 1, 2002 are an average price of $18.29 per barrel.

Gas  price  adjustments were made in the individual evaluations to  reflect
BTU  content,  gathering and transportation costs and  gas  processing  and
shrinkage.  The results of the reserve report as of January 1, 2002 are  an
average price of $2.26 per Mcf.

As  also discussed in Part II, Item 7, Management's Discussion and Analysis
of  Financial Condition and Results of Operations, oil and gas prices  were
subject to frequent changes in 2001.

<PAGE>
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
producing 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,  or  receives
cash.

The  Partnership or the owners of properties in which the Partnership  owns
an  interest  can  engage  in workover projects or  supplementary  recovery
projects, for example, to extract behind the pipe reserves which qualify as
proved developed non-producing reserves.  See Part II, Item 7, Management's
Discussion and Analysis of Financial Condition and Results of Operations.

Item 3.   Legal Proceedings

There are no material pending legal proceedings to which the Partnership is
a party.

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

No  matter  was submitted to a vote of security holders during  the  fourth
quarter of 2001 through the solicitation of proxies or otherwise.

<PAGE>
                                 Part II


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

Market Information
Limited  partnership interests, or units, in the Partnership were initially
offered and sold for a price of $500.  Limited partner units are not traded
on  any  exchange  and there is no public or organized trading  market  for
them.  The Managing General Partner has become aware of certain limited and
sporadic transfers of units between limited partners and third parties, but
has no verifiable information regarding the prices at which such units have
been  transferred.   Further,  a transferee may  not  become  a  substitute
limited partner without the consent of the Managing General Partner.

The  Managing  General Partner has the right, but not  the  obligation,  to
purchase limited partnership units should an investor desire to sell.   The
value  of  the unit is determined  by adding the sum of (1) current  assets
less  liabilities  and  (2) the present value of the  future  net  revenues
attributable to proved reserves and by discounting the future net  revenues
at  a rate not in excess of the prime rate charged by NationsBank, N.A.  of
Midland, Texas plus one percent (1%), which value shall be further  reduced
by  a risk factor discount of no more than one-third (1/3) to be determined
by  the  Managing General Partner in its sole and absolute discretion.   In
2001,  40  limited  partner units were tendered to  and  purchased  by  the
Managing General Partner at an average base price of $153.43 per unit.   In
2000,  68  limited  partner units were tendered to  and  purchased  by  the
Managing General Partner at an average base price of $102.44 per unit.   In
1999,  76  limited  partner units were tendered to  and  purchased  by  the
Managing General Partner at an average base price of $69.49 per unit.

Number of Limited Partner Interest Holders
As of December 31, 2001, there were 610 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."

<PAGE>
During  2001,  quarterly  distributions were made totaling  $542,447,  with
$488,202  distributed to the limited partners and $54,245  to  the  general
partners.   For the year ended December 31, 2001, distributions  of  $49.91
per  limited partner unit were made, based upon 9,782 limited partner units
outstanding.   During  2000,  quarterly distributions  were  made  totaling
$588,780, with $540,523 distributed to the limited partners and $48,257  to
the  general partners.  For the year ended December 31, 2000, distributions
of  $55.26  per  limited partner unit were made, based upon  9,782  limited
partner  units outstanding.  Distributions for 2000 increased significantly
due to the record high oil and gas prices received during the year.  During
1999,  distributions were made totaling $274,382, with $251,382 distributed
to  the limited partners and $23,000 to the general partners.  For the year
ended  December 31, 1999, distributions of $25.70 per limited partner  unit
were made, based upon 9,782 limited partner units outstanding.

Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
2001,  2000,  1999,  1998 and 1997 should be read in conjunction  with  the
financial statements included in Item 8:

                                     Years ended December 31,
                    ---------------------------------------------------------
                        2001        2000      1999        1998       1997
                        ----        ----      ----        ----       ----
Revenues           $   487,998    635,288    327,462    199,905    444,601

Net income             369,679    547,498    228,523      3,941    249,950

Partners' share of
 net income (loss):

  General partners      41,368     56,250     25,352     11,294     36,795

  Limited partners     328,311    491,248    203,171    (7,353)    213,155

Limited partners'
 net income (loss)
  per unit               33.56      50.22      20.77      (.75)      21.79

Limited partners'
 cash distributions
  per unit               49.91      55.26      25.70      27.76      38.32

Total assets       $   371,261    543,778    585,060    631,451    926,056

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

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

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

Well  operating costs and general and administrative costs usually decrease
with   production   declines;  however,  these  costs  may   not   decrease
proportionately.   Net  income available for distribution  to  the  limited
partners  is therefore expected to fluctuate in later years based on  these
factors.

Based  on  current conditions, management anticipates performing  workovers
during 2002 to enhance production.  The partnership may have an increase in
production  volumes for the years 2002 and 2003, otherwise, the partnership
will   most   likely  experience  the  historical  production  decline   of
approximately 9% per year.

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

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

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

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

<PAGE>
The  Partnership's policy for depreciation, depletion and  amortization  of
oil  and  gas  properties is computed under the units  of  revenue  method.
Under the units of revenue method, depreciation, depletion and amortization
is  computed  on  the  basis of current gross revenues from  production  in
relation  to future gross revenues, based on current prices, from estimated
production of proved oil and gas reserves.

Results of Operations

A.  General Comparison of the Years Ended December 31, 2001 and 2000

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2001 and 2000:

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                2001      2000   (Decrease)
                                                ----      ----   ---------
Average price per barrel of oil            $   23.40    28.76    (19%)
Average price per mcf of gas               $    3.40     3.48     (2%)
Oil production in barrels                     20,900   20,000       5%
Gas production in mcf                        115,000  129,900    (11%)
Income from net profits interests          $ 484,452  628,194    (23%)
Partnership distributions                  $ 542,447  588,780     (8%)
Limited partner distributions              $ 488,202  540,523    (10%)
Per unit distribution to limited partners  $   49.91    55.26    (10%)
Number of limited partner units                9,782    9,782

Revenues

The  Partnership's income from net profits interests decreased to  $484,452
from $628,194 for the years ended December 31, 2001 and 2000, respectively,
a  decrease of 23%.  The principal factors affecting the comparison of  the
years ended December 31, 2001 and 2000 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 2001 as compared  to  the
    year ended December 31, 2000 by 19%, or $5.36 per barrel, resulting  in
    a  decrease  of  approximately $112,000  in  income  from  net  profits
    interests.  Oil sales represented 56% of total oil and gas sales during
    the  year  ended December 31, 2001 as compared to 56% during  the  year
    ended December 31, 2000.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 2%, or $.08 per mcf, resulting in a
    decrease of approximately $9,200 in income from net profits interests.

    The  total  decrease in income from net profits interests  due  to  the
    change  in prices received from oil and gas production is approximately
    $121,200.  The market price for oil and gas has been extremely volatile
    over  the  past  decade  and management expects  a  certain  amount  of
    volatility to continue in the foreseeable future.

<PAGE>

2.  Oil  production increased approximately 900 barrels or  5%  during  the
    year ended December 31, 2001 as compared to the year ended December 31,
    2000, resulting in an increase of approximately $25,900 in income  from
    net profits interests.

    Gas  production  decreased approximately 14,900 mcf or 11%  during  the
    same period, resulting in a decrease of approximately $51,900 in income
    from net profits interests.

    The  net total decrease in income from net profits interests due to the
    change in production is approximately $26,000.

3.  Lease   operating  costs  and  production  taxes  were  1%  lower,   or
    approximately $3,400 less during the year ended December  31,  2001  as
    compared to the year ended December 31, 2000.

Costs and Expenses

Total  costs and expenses increased to $118,319 from $87,790 for the  years
ended  December 31, 2001 and 2000, respectively, an increase of  35%.   The
increase  is  the  result  of higher general and administrative  costs  and
depletion expense.

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

2.   Depletion expense increased to $44,000 for the year ended December 31,
   2001 from $15,000 for the same period in 2000.  This represents an increase
   of  193%.  Depletion is calculated using the units of revenue method  of
   amortization based on a percentage of current period gross  revenues  to
   total future gross oil and gas revenues, as estimated by the Partnership's
   independent petroleum consultants.

   The  major  factor  to  the increase in depletion  expense  between  the
   comparative  periods was the decrease in the price of oil and  gas  used
   to  determine the Partnership's reserves for January 1, 2002 as compared
   to  2001,  and  the  decrease in oil and gas revenues  received  by  the
   Partnership  during 2001 as compared to 2000, and the  decrease  in  oil
   and gas revenues received by the Partnership during 2001 as compared  to
   2000.   Revisions of previous estimates can be attributed to the changes
   in  production performance, oil and gas price and production costs.  The
   impact   of   the  revision  would  have  increased  depletion   expense
   approximately $20,000 as of December 31, 2000.

<PAGE>

Results of Operations

B.  General Comparison of the Years Ended December 31, 2000 and 1999

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 2000 and 1999:

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                2000      1999   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   28.76    16.98      69%
Average price per mcf of gas               $    3.48     1.97      77%
Oil production in barrels                     20,000   21,770     (8%)
Gas production in mcf                        129,900  135,640     (4%)
Income from net profits interests          $ 628,194  322,555      95%
Partnership distributions                  $ 588,780  274,382     115%
Limited partner distributions              $ 540,523  251,382     115%
Per unit distribution to limited partners  $   55.26    25.70     115%
Number of limited partner units                9,782    9,782

Revenues

The  Partnership's income from net profits interests increased to  $628,194
from $322,555 for the years ended December 31, 2000 and 1999, respectively,
an  increase of 95%.  The principal factors affecting the comparison of the
years ended December 31, 2000 and 1999 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 2000 as compared  to  the
    year ended December 31, 1999 by 69%, or $11.78 per barrel, resulting in
    an  increase  of  approximately $235,600 in  income  from  net  profits
    interests.  Oil sales represented 56% of total oil and gas sales during
    the  year  ended December 31, 2000 as compared to 58% during  the  year
    ended December 31, 1999.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 77%, or $1.51 per mcf, resulting in
    an  increase  of  approximately $196,200 in  income  from  net  profits
    interests.

    The  total  increase in income from net profits interests  due  to  the
    change  in prices received from oil and gas production is approximately
    $431,800.  The market price for oil and gas has been extremely volatile
    over  the  past  decade  and management expects  a  certain  amount  of
    volatility to continue in the foreseeable future.

<PAGE>

2.  Oil  production decreased approximately 1,770 barrels or 8% during  the
    year ended December 31, 2000 as compared to the year ended December 31,
    1999,  resulting in a decrease of approximately $30,100 in income  from
    net profits interests.

    Gas  production decreased approximately 5,740 mcf or 4% during the same
    period, resulting in a decrease of approximately $11,300 in income from
    net profits interests.

    The  total  decrease in income from net profits interests  due  to  the
    change in production is approximately $41,400.

3.  Lease  operating  costs  and  production  taxes  were  27%  higher,  or
    approximately $84,400 more during the year ended December 31,  2000  as
    compared  to the year ended December 31, 1999.  The increase  in  lease
    operating  costs and production taxes is due in part to an increase  in
    major  repairs  and  maintenance, such as pulling expenses  on  several
    leases, and in part to the rise in production taxes directly associated
    with the rise in oil and gas price received during the past year.   The
    rise  in  oil  and gas prices for 2000 has allowed the  Partnership  to
    perform  these  repairs  and maintenance in  the  hopes  of  increasing
    production, thereby increasing revenues.

Costs and Expenses

Total  costs and expenses decreased to $87,790 from $98,939 for  the  years
ended  December 31, 2000 and 1999, respectively, a decrease  of  11%.   The
decrease  is  the  result  of lower general and  administrative  costs  and
depletion expense.

1.  General and administrative costs consists of independent accounting and
    engineering  fees,  computer services, postage,  and  Managing  General
    Partner personnel costs.  General and administrative costs decreased 2%
    or  approximately  $1,100 during the year ended December  31,  2000  as
    compared to the year ended December 31, 1999.

3.   Depletion expense decreased to $15,000 for the year ended December 31,
   2000 from $25,000 for the same period in 1999.  This represents a decrease
   of  40%.   Depletion is calculated using the units of revenue method  of
   amortization based on a percentage of current period gross  revenues  to
   total future gross oil and gas revenues, as estimated by the Partnership's
   independent petroleum consultants.

   The  major  factor  to  the decrease in depletion  expense  between  the
   comparative  periods was the increase in the price of oil and  gas  used
   to  determine the Partnership's reserves for January 1, 2001 as compared
   to  2000.   Another  contributing  factor  was  due  to  the  impact  of
   revisions  of  previous  estimates on reserves.  Revisions  of  previous
   estimates  can  be attributed to the changes in production  performance,
   oil  and  gas  price and production costs.  The impact of  the  revision
   would  have  decreased  depletion expense  approximately  $1,000  as  of
   December 31, 1999.

<PAGE>

C.  Revenue and Distribution Comparison

Partnership net income for the years ended December 31, 2001, 2000 and 1999
was  $369,679, $547,498 and $228,523, respectively.  Excluding the  effects
of depreciation, depletion and amortization, net income for the years ended
December  31,  2001, 2000 and 1999 would have been $413,679,  $562,498  and
$253,523, respectively.  Correspondingly, Partnership distributions for the
years  ended  December 31, 2001, 2000 and 1999 were $542,447, $588,780  and
$274,382.  These differences are indicative of the changes in oil  and  gas
prices, production and properties during 2001, 2000 and 1999.

The  source  for  the  2001  distributions of $542,447  were  oil  and  gas
operations  of  approximately  $488,700 and  the  change  in  oil  and  gas
properties of approximately $700, with the balance from available  cash  on
hand at the beginning of the period.  The source for the 2000 distributions
of $588,780 were oil and gas operations of approximately $525,700, with the
balance  from available cash on hand at the beginning of the  period.   The
sources  for the 1999 distributions of $274,382 were oil and gas operations
of  approximately  $192,219 and property sales of  approximately  $213,100,
resulting in excess cash for contingencies or subsequent distributions.

Total  distributions during the year ended December 31, 2001 were  $542,447
of  which  $488,202 was distributed to the limited partners and $54,245  to
the general partners.  The per unit distribution to limited partners during
the  same  period was $49.91.  Total distributions during  the  year  ended
December  31, 2000 were $588,780 of which $540,523 was distributed  to  the
limited  partners  and  $48,257  to the general  partners.   The  per  unit
distribution to limited partners during the same period was $55.26.   Total
distributions  during  the year ended December 31, 1999  were  $274,382  of
which  $251,382 was distributed to the limited partners and $23,000 to  the
general partners.  The per unit distribution to limited partners during the
same period was $25.70.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $6,996,148  have been made to the partners.  As of December  31,  2001,
$6,351,452 or $649.30 per limited partner unit, has been distributed to the
limited partners, representing a 130% return of the capital contributed.

<PAGE>

Liquidity and Capital Resources
The  primary source of cash is from operations, the receipt of income  from
interests in oil and gas properties.  The Partnership knows of no  material
change, nor does it anticipate any such change in 2001.

Cash flows provided by operating activities were approximately $488,700  in
2001 compared to $525,700 in 2000 and approximately $192,200 in 1999.   The
primary  sources  of  the  2001 cash flow from  operating  activities  were
profitable operations.

Cash  flows  provided  by investing activities were approximately  $700  in
2001.   The  Partnership had no cash flow from investing activities  during
2000.   Cash  flows  provided  by investing activities  were  approximately
$213,100  in 1999.  The principal use of the 2001 cash flows from investing
activities was term assignment proceeds.

Cash flows used in financing activities were approximately $542,200 in 2001
compared to $588,700 in 2000 and approximately $275,000 in 1999.  The  only
use in financing activities was the distributions to partners.

As  of  December  31,  2001, the Partnership had approximately  $82,400  in
working  capital.   The  Managing  General  Partner  knows  of  no  unusual
contractual commitments and believes the revenues generated from operations
are adequate to meet the needs of the Partnership.

Liquidity - Managing General Partner

The  Managing General Partner has a highly leveraged capital structure with
$50.0  million and $123.7 million of principal due in August  of  2003  and
October  of  2004, respectively.  The Managing General Partner  will  incur
approximately  $17.6  million in interest payments  in  2002  on  its  debt
obligations. Due to the depressed commodity prices experienced  during  the
last  quarter  of  2001,  the  Managing  General  Partner  is  experiencing
difficulty  in generating sufficient cash flow to meet its obligations  and
sustain its operations.  The Managing General Partner is currently  in  the
process  of  renegotiating the terms of its various  obligations  with  its
creditors  and/or  attempting  to seek new  lenders  or  equity  investors.
Additionally,  the  Managing General Partner would  consider  disposing  of
certain assets in order to meet its obligations.

There  can  be  no  assurance  that  the Managing  General  Partner's  debt
restructuring efforts will be successful or that the lenders will agree  to
a   course   of  action  consistent  with  the  Managing  General  Partners
requirements  in restructuring the obligations.  Even if such agreement  is
reached,  it  may  require approval of additional  lenders,  which  is  not
assured.   Furthermore, there can be no assurance that the sales of  assets
can  be  successfully  accomplished on terms  acceptable  to  the  Managing
General   Partner.   Under  current  circumstances,  the  Managing  General
Partner's  ability to continue as a going concern depends upon its  ability
to  (1)  successfully  restructure  its obligations  or  obtain  additional
financing  as  may  be  required, (2) maintain  compliance  with  all  debt
covenants, (3) generate sufficient cash flow to meet its obligations  on  a
timely  basis, and (4) achieve satisfactory levels of future earnings.   If
the  Managing  General Partner is unsuccessful in its efforts,  it  may  be
unable to meet its obligations making it necessary to undertake such  other
actions  as  may  be  appropriate  to  preserve  asset  values.   Upon  the
occurrence of any event of dissolution by the Managing General Partner, the
holders  of  a  majority of limited partnership interests may,  by  written
agreement,  elect  to  continue the business  of  the  Partnership  in  the
Partnership's   name,  with  Partnership  property,  in   a   reconstituted
partnership under the terms of the partnership agreement and to designate a
successor Managing General Partner.

<PAGE>

Recent Accounting Pronouncements
In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No.133, "Accounting
for Derivative Instruments and Hedging Activities."  SFAS No. 133, as
amended by SFAS No. 138, establishes accounting and reporting standards for
derivative instruments, including certain derivative instruments embedded
in other contracts and for hedging activities.  Assessment by the Managing
General Partner revealed this pronouncement to have no impact on the
partnerships.

The FASB has issued Statement No. 143 "Accounting for Asset Retirement
Obligations" which establishes requirements for the accounting of removal-
type costs associated with asset retirements.  The standard is effective
for fiscal years beginning after June 15, 2002, with earlier application
encouraged.  The Managing General Partner is currently assessing the impact
on the partnerships financial statements.

On  October 3, 2001, the FASB issued Statements No. 144 "Accounting for the
Impairment   or   Disposal  of  Long-Lived  Assets."   This   pronouncement
supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets  and
for  Long-Lived  Assets to Be Disposed" and eliminates the  requirement  of
Statement  121 to allocate goodwill to long-lived assets to be  tested  for
impairment.   The provisions of this statement are effective for  financial
statements issued for fiscal years beginning after December 15,  2001,  and
interim periods within those fiscal years.  The Managing General Partner is
currently assessing the impact to the partnerships 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

Independent Auditors Report                                             19

Balance Sheets                                                          20

Statements of Operations                                                21

Statement of Changes in Partners' Equity                                22

Statements of Cash Flows                                                23

Notes to Financial Statements                                           25

<PAGE>









                        INDEPENDENT AUDITORS REPORT

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,
2001  and  2000,  and  the  related statements of  operations,  changes  in
partners'  equity and cash flows for each of the years in  the  three  year
period  ended  December  31,  2001.  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 auditing standards  generally
accepted in the Untied States of America.  Those standards require that  we
plan and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement.  An audit  includes
examining, on a test basis, evidence supporting the amounts and disclosures
in  the  financial  statements.   An  audit  also  includes  assessing  the
accounting principles used and significant estimates made by management, as
well  as  evaluating  the  overall financial  statement  presentation.   We
believe that our audits provide a reasonable basis for our opinion.

In  our opinion, the financial statements referred to above present fairly,
in  all  material  respects, the financial position of Southwest  Royalties
Institutional Income Fund IX-B, L.P. as of December 31, 2001 and  2000  and
the  results of its operations and its cash flows for each of the years  in
the three year period ended December 31, 2001 in conformity with accounting
principles generally accepted in the United States of America.








                                                  KPMG LLP



Midland, Texas
March 10, 2002

<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 2001 and 2000


                                                      2001          2000
                                                      ----          ----

  Assets
  ------

Current assets:
 Cash and cash equivalents                   $        28,023       80,803
 Receivable from Managing General Partner             54,594      129,611

---------                                    ---------
                                                 Total    current    assets
82,617                                       210,414

---------                                    ---------
Oil and gas properties - using the full-
 cost method of accounting                         2,955,644    2,956,364
  Less accumulated depreciation,
                                               depletion  and  amortization
2,667,000                                    2,623,000

---------                                    ---------
                                              Net  oil  and gas  properties
288,644                                      333,364

---------                                    ---------
                                                                          $
371,261                                      543,778

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

Current liability - distribution payable     $           251            -

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

Partners' equity:
 General partners                                   (67,622)     (54,745)
 Limited partners                                    438,632      598,523

---------                                    ---------
                                                Total    partners'   equity
371,010                                      543,778

---------                                    ---------
                                                                          $
371,261                                      543,778

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




















                  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, 2001, 2000 and 1999


                                                 2001      2000     1999
                                                 ----      ----     ----
  Revenues
  --------

Income from net profits interests         $    484,452   628,194  322,555
Interest                                         3,546     7,094    3,511
Miscellaneous                                        -         -    1,396
                                                                    -------
-------                                   -------
                                                                    487,998
635,288                                   327,462
                                                                    -------
-------                                   -------
  Expenses
  --------

General and administrative                      74,319    72,790   73,939
Depreciation, depletion and amortization        44,000    15,000   25,000
                                                                    -------
-------                                   -------
                                                                    118,319
87,790                                    98,939
                                                                    -------
-------                                   -------
Net income                                $    369,679   547,498  228,523
                                                                    =======
=======                                   =======

Net income allocated to:

 Managing General Partner                 $     37,231    50,625   22,817
                                                                    =======
=======                                   =======
 General Partner                          $      4,137     5,625    2,535
                                                                    =======
=======                                   =======
 Limited partners                         $    328,311   491,248  203,171
                                                                    =======
=======                                   =======
  Per limited partner unit                $      33.56     50.22    20.77
                                                                    =======
=======                                   =======























                  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, 2001, 2000 and 1999


                                              General   Limited
                                              Partners  Partners   Total
                                              --------  --------   -----
Balance at December 31, 1998            $   (65,090)    696,009   630,919

 Net income                                   25,352    203,171   228,523

 Distributions                              (23,000)  (251,382) (274,382)
                                                                    -------
---------                               ---------
Balance at December 31, 1999                (62,738)    647,798   585,060

 Net income                                   56,250    491,248   547,498

 Distributions                              (48,257)  (540,523) (588,780)
                                                                    -------
---------                               ---------
Balance at December 31, 2000                (54,745)    598,523   543,778

 Net income                                   41,368    328,311   369,679

 Distributions                              (54,245)  (488,202) (542,447)
                                                                    -------
---------                               ---------
Balance at December 31, 2001            $   (67,622)    438,632   371,010
                                                                    =======
=========                               =========
































                  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, 2001, 2000 and 1999


                                                 2001      2000      1999
                                                 ----      ----      ----

Cash flows from operating activities:

 Cash received from net profits interests $    574,333   574,941  260,510
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(89,182)                                  (56,316)(71,802)
 Interest received                               3,546     7,094    3,511
                                                                   --------
--------                                  --------
   Net  cash provided by operating activities              488,697  525,719
192,219
                                                                   --------
--------                                  --------
Cash flows provided by investing activities:

 Sale of oil and gas properties                    720         -  213,097
                                                                   --------
--------                                  --------
Cash flows used in financing activities:

 Distributions to partners                   (542,197) (588,734)(274,960)
                                                                   --------
--------                                  --------
Net (decrease) increase in cash and
 cash equivalents                             (52,780)  (63,015)  130,356

 Beginning of year                              80,803   143,818   13,462
                                                                   --------
--------                                  --------
 End of year                              $     28,023    80,803  143,818
                                                                   ========
========                                  ========


(continued)

























                  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, continued
               Years ended December 31, 2001, 2000 and 1999


                                                 2001      2000     1999
                                                 ----      ----     ----

Reconciliation of net income to net cash
 provided by operating activities:

Net income                                $    369,679   547,498  228,523

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

   Depreciation, depletion and amortization                44,000    15,000
25,000
  Decrease (increase) in receivables            89,881  (53,252) (63,441)
  (Decrease) increase in payables             (14,863)    16,473    2,137
                                                                    -------
-------                                   -------
Net cash provided by operating activities $    488,697   525,719  192,219
                                                                    =======
=======                                   =======






































                  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. serves as the Managing General Partner and H. H. Wommack, III, as
     the  individual  general partner.  Revenues, costs  and  expenses  are
     allocated as follows:

                                                     Limited      General
                                                     Partners     Partners
                                                     --------     --------
     Oil and gas sales                                90%          10%
     Interest income on capital contributions        100%           -
     All other revenues                               90%          10%
     Organization and offering costs (1)             100%           -
     Syndication costs                               100%           -
     Amortization of organization costs              100%           -
     Property acquisition costs                      100%           -
     Gain/loss on property disposition                90%          10%
     Operating and administrative costs (2)           90%          10%
     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.

     The  Partnership's policy for depreciation, depletion and amortization
     of  oil  and  gas  properties is computed under the units  of  revenue
     method.   Under  the units of revenue method, depreciation,  depletion
     and  amortization is computed on the basis of current  gross  revenues
     from production in relation to future gross revenues, based on current
     prices, from estimated production of proved oil and gas reserves.

     Under  the  units  of  revenue method, the  Partnership  computes  the
     provision  by multiplying the total unamortized cost of  oil  and  gas
     properties by an overall rate determined by dividing (a) oil  and  gas
     revenues during the period by (b) the total future gross oil  and  gas
     revenues  as  estimated  by  the Partnership's  independent  petroleum
     consultants.   It  is  reasonably possible  that  those  estimates  of
     anticipated  future  gross revenues, the remaining estimated  economic
     life  of  the product, or both could be changed significantly  in  the
     near  term  due to the potential fluctuation of oil and gas prices  or
     production.   The  depletion estimate would also be affected  by  this
     change.


<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
     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, 2001, 2000 and  1999,
     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.

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

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

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

     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,  2001  the
     Partnership  was  overproduced by 364 mcf of gas. As of  December  31,
     2000,  the  Partnership was overproduced by 364  mcf  of  gas.  As  of
     December 31, 1999, 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,  2001  and 2000 is $134,867 and $128,061, respectively, more  than
     that  shown  on  the  accompanying Balance Sheets in  accordance  with
     generally accepted accounting principles.

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

                      Notes to Financial Statements

2.   Summary of Significant Accounting Policies - continued

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

     Number of Limited Partner Units
     As  of  December  31,  2001, 2000 and 1999, there were  9,782  limited
     partner units outstanding held by 610, 602 and 612 partners.

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

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

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

     Recent Accounting Pronouncements
     In June 1998, the Financial Accounting Standards Board ("FASB") issued
     Statement   of   Financial  Accounting  Standards   ("SFAS")   No.133,
     "Accounting for Derivative Instruments and Hedging Activities."   SFAS
     No.  133,  as  amended  by  SFAS No. 138, establishes  accounting  and
     reporting  standards  for  derivative instruments,  including  certain
     derivative  instruments embedded in other contracts  and  for  hedging
     activities.  Assessment by the Managing General Partner revealed  this
     pronouncement to have no impact on the partnerships.

     The FASB has issued Statement No. 143 "Accounting for Asset Retirement
     Obligations"  which  establishes requirements for  the  accounting  of
     removal-type costs associated with asset retirements.  The standard is
     effective for fiscal years beginning after June 15, 2002, with earlier
     application  encouraged.  The Managing General  Partner  is  currently
     assessing the impact on the partnerships financial statements.

     On October 3, 2001, the FASB issued Statements No. 144 "Accounting for
     the  Impairment or Disposal of Long-Lived Assets."  This pronouncement
     supercedes FAS 121 "Accounting for the Impairment of Long-Lived Assets
     and   for  Long-Lived  Assets  to  Be  Disposed"  and  eliminates  the
     requirement of Statement 121 to allocate goodwill to long-lived assets
     to  be  tested  for impairment.  The provisions of this statement  are
     effective  for financial statements issued for fiscal years  beginning
     after  December  15,  2001, and interim periods  within  those  fiscal
     years.  The Managing General Partner is currently assessing the impact
     to the partnerships financial statements.

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

                      Notes to Financial Statements

3.   Liquidity - Managing General Partner

     The  Managing General Partner has a highly leveraged capital structure
     with  $50.0 million and $123.7 million of principal due in  August  of
     2003  and October of 2004, respectively.  The Managing General Partner
     will incur approximately $17.6 million in interest payments in 2002 on
     its   debt   obligations.  Due  to  the  depressed  commodity   prices
     experienced  during  the last quarter of 2001,  the  Managing  General
     Partner is experiencing difficulty in generating sufficient cash  flow
     to  meet  its  obligations and sustain its operations.   The  Managing
     General Partner is currently in the process of renegotiating the terms
     of  its  various obligations with its creditors and/or  attempting  to
     seek  new  lenders  or equity investors.  Additionally,  the  Managing
     General Partner would consider disposing of certain assets in order to
     meet its obligations.

     There  can  be  no assurance that the Managing General Partner's  debt
     restructuring  efforts  will be successful or that  the  lenders  will
     agree  to  a  course  of action consistent with the  Managing  General
     Partners requirements in restructuring the obligations.  Even if  such
     agreement  is reached, it may require approval of additional  lenders,
     which is not assured.  Furthermore, there can be no assurance that the
     sales  of  assets can be successfully accomplished on terms acceptable
     to  the  Managing  General Partner.  Under current circumstances,  the
     Managing  General  Partner's ability to continue as  a  going  concern
     depends   upon  its  ability  to  (1)  successfully  restructure   its
     obligations  or  obtain additional financing as may be  required,  (2)
     maintain  compliance with all debt covenants, (3) generate  sufficient
     cash  flow to meet its obligations on a timely basis, and (4)  achieve
     satisfactory  levels  of  future earnings.  If  the  Managing  General
     Partner  is unsuccessful in its efforts, it may be unable to meet  its
     obligations making it necessary to undertake such other actions as may
     be  appropriate to preserve asset values.  Upon the occurrence of  any
     event of dissolution by the Managing General Partner, the holders of a
     majority  of limited partnership interests may, by written  agreement,
     elect to continue the business of the Partnership in the Partnership's
     name,  with Partnership property, in a reconstituted partnership under
     the  terms  of the partnership agreement and to designate a  successor
     Managing General Partner.

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
     NationsBank, N.A. of Midland, Texas plus one percent (1%), which value
     shall be further reduced by a risk factor discount of no more than 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.

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

                      Notes to Financial Statements

4.   Commitments and Contingent Liabilities - continued
     As  of December 31, 2001, 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 operated by and purchased  from  the
     Managing  General Partner.  As provided for in the operating agreement
     for  each respective oil and gas property in which the Partnership has
     an  interest,  the  operator  is  paid an  amount  for  administrative
     overhead attributable to operating such properties, with such  amounts
     to  Southwest  Royalties,  Inc.  as  operator  approximating  $69,300,
     $65,500  and $86,500 for the years ended December 31, 2001,  2000  and
     1999,  respectively.   In addition, the Managing General  Partner  and
     certain  officers and employees may have an interest in  some  of  the
     properties that the Partnership also participates.

     Certain  subsidiaries  or affiliates of the Managing  General  Partner
     perform  various  oilfield  services  for  properties  in  which   the
     Partnership  owns an interest.  Such services aggregated approximately
     $15,000,  $22,400 and $18,000 for the years ended December  31,  2001,
     2000 and 1999, respectively.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $68,400  during  2001,  2000  and 1999 as an  administrative  fee  for
     indirect general and administrative overhead expenses.

     Receivables  from  Southwest  Royalties, Inc.,  the  Managing  General
     Partner,  of approximately $54,600 and $129,600 are from oil  and  gas
     production, net of lease operating costs and production taxes,  as  of
     December 31, 2001 and 2000, respectively.

     In addition, a director and officer of the Managing General Partner is
     a  partner  in a law firm, with such firm providing legal services  to
     the  Partnership.  There were no legal services provided for the  year
     ended December 31, 2001, 2000 and 1999.


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

                      Notes to Financial Statements


6.   Major Customers
     No  material portion of the Partnership's business is dependent  on  a
     single  purchaser, or a very few purchasers, where  the  loss  of  one
     would  have material adverse impact on the Partnership. Two purchasers
     accounted  for  63% of the Partnership's total oil and gas  production
     during  2001:   Phillips  66 Company for 48%  and  Duke  Energy  Field
     Services   for  15%.   One  purchaser  accounted  for   69%   of   the
     Partnership's total oil and gas production during 2000:   Phillips  66
     Company  69%.   One  purchaser accounted for 62% of the  Partnership's
     total  oil  and gas production during 1999:  Phillips 66  Company  for
     62%.   All purchasers of the Partnership's oil and gas production  are
     unrelated third parties.  In the event any of these purchasers were to
     discontinue  purchasing  the Partnership's  production,  the  Managing
     General  Partner  believes that a substitute purchaser  or  purchasers
     could  be  located without undue delay.  No other purchaser  accounted
     for  an amount equal to or greater than 10% of the Partnership's sales
     of oil and gas production.

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

                                                    Oil (bbls)   Gas (mcf)
                                                    ----------   ---------
     Proved developed and undeveloped reserves -

     January 1, 1999                                 172,000       984,000

       Revisions of previous estimates               134,000       350,000
       Production                                   (22,000)     (136,000)
       Sale of minerals in place                     (5,000)      (42,000)
                                                     -------     ---------
     December 31, 1999                               279,000     1,156,000

       Revisions of previous estimates                50,000       614,000
       Production                                   (20,000)     (130,000)
                                                     -------     ---------
     December 31, 2000                               309,000     1,640,000

       Revisions of previous estimates             (100,000)     (741,000)
       Production                                   (21,000)     (115,000)
                                                     -------     ---------
     December 31, 2001                               188,000       784,000
                                                     =======     =========

     Proved developed reserves -

     December 31, 1999                               252,000     1,066,000
                                                     =======     =========
     December 31, 2000                               293,000     1,564,000
                                                     =======     =========
     December 31, 2001                               183,000       686,000
                                                     =======     =========

     All  of  the Partnership's reserves are located within the continental
     United States.

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

                      Notes to Financial Statements

7.   Estimated Oil and Gas Reserves (unaudited) - continued
     *Ryder  Scott  Petroleum Engineers prepared the  reserve  and  present
     value data for the Partnership's existing properties as of January  1,
     2002.   The  reserve estimates were made in accordance with guidelines
     established by the Securities and Exchange Commission pursuant to Rule
     4-10(a)  of  Regulation  S-X.  Such guidelines  require  oil  and  gas
     reserve  reports  be  prepared under existing economic  and  operating
     conditions with no provisions for price and cost escalation except  by
     contractual arrangements.

     Oil  price  adjustments  were made in the  individual  evaluations  to
     reflect  oil quality, gathering and transportation costs. The  results
     of  the  reserve report as of January 1, 2002 are an average price  of
     $18.29 per barrel.

     Gas  price  adjustments  were made in the  individual  evaluations  to
     reflect  BTU  content,  gathering and  transportation  costs  and  gas
     processing  and shrinkage.  The results of the reserve  report  as  of
     January 1, 2002 are an average price of $2.26 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
     producing  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,
     or receives cash.

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

                      Notes to Financial Statements

7.   Estimated Oil & Gas Reserves (unaudited) - continued
     The  standardized measure of discounted future net cash flows relating
     to  proved oil and gas reserves at December 31, 2001, 2000 and 1999 is
     presented below:

                                              2001       2000        1999
                                              ----       ----        ----

     Future cash inflows, net of
       production and development
      costs                             $  2,618,000 15,466,000  4,794,000
     10% annual discount for
       estimated timing of cash
      flows                                1,063,000  7,508,000  2,172,000
                                           ---------  ---------  ---------
     Standardized measure of
       discounted future net cash
      flows                             $  1,555,000  7,958,000  2,622,000
                                           =========  =========  =========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     2001, 2000 and 1999 are as follows:

                                              2001        2000        1999
                                              ----        ----        ----

     Sales of oil and gas produced,
       net of production costs          $  (484,000)  (628,000)  (323,000)
      Changes in prices and production costs         (6,196,000)  3,793,000
1,011,000
     Changes of production rates
       (timing) and others                   572,000  (172,000)  (121,000)
     Sales of minerals in place                    -          -   (70,000)
     Revisions of previous
       quantities estimates              (1,091,000)  2,081,000  1,062,000
     Accretion of discount                   796,000    262,000     97,000
     Discounted future net
       cash flows -
      Beginning of year                    7,958,000  2,622,000    966,000
                                           ---------  ---------  ---------
      End of year                       $  1,555,000  7,958,000  2,622,000
                                           =========  =========  =========

     Future  net cash flows were computed using year-end prices  and  costs
     that  related  to existing proved oil and gas reserves  in  which  the
     Partnership has mineral interests.
<PAGE>
         Southwest Royalties Institutional Income Fund IX-B, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements

8.  Selected Quarterly Financial Results - (unaudited)

                                                 Quarter
                              ----------------------------------------------
                                 First       Second    Third       Fourth
                                 ------     -------    ------      ------
  2001:
     Total revenues           $  211,858    128,863    91,878      55,399
     Total expenses               25,257     31,026    35,274      26,762
     Net income                  186,601     97,837    56,604      28,637
     Net income per limited
      partners unit                17.10       8.88      5.03        2.55

  2000:
     Total revenues           $  137,733    170,833   177,805     148,917
     Total expenses               25,519     21,637    23,433      17,201
     Net income                  112,214    149,196   154,372     131,716
     Net income per limited
      partners unit                10.25      13.70     14.15       12.12

Item 9.   Changes  in and Disagreements With Accountants on Accounting  and
          Financial Disclosure
None

<PAGE>
                                 Part III

Item 10.  Directors and Executive Officers of the Registrant

Management of the Partnership is provided by Southwest Royalties, Inc.,  as
Managing  General Partner.  The names, ages, offices, positions and  length
of  service of the directors and executive officers of Southwest Royalties,
Inc. are set forth below.  Each director and executive officer serves for a
term  of  one year.  The present directors of the Managing General  Partner
have served in their capacity since the Company's formation in 1983.

     Name                   Age                       Position
--------------------        ---         -----------------------------------
-------
H. H. Wommack, III                      46     Chairman   of   the   Board,
                                        President,
                                        Chief Executive Officer, Treasurer
                                        and Director

H. Allen Corey              45          Secretary and Director

Bill E. Coggin                          47     Vice  President  and   Chief
                                        Financial Officer

J. Steven Person            43          Vice President, Marketing

Paul L. Morris              60          Director

H.  H.  Wommack, III, is Chairman of the Board, President, Chief  Executive
Officer,  Treasurer, principal stockholder and a director of  the  Managing
General  Partner,  and  has  served as its President  since  the  Company's
organization  in August, 1983.  Prior to the formation of the Company,  Mr.
Wommack  was  a  self-employed  independent oil  producer  engaged  in  the
purchase  and sale of royalty and working interests in oil and gas  leases,
and  the drilling of exploratory and developmental oil and gas wells.   Mr.
Wommack  holds  a J.D. degree from the University of Texas  from  which  he
graduated  in  1980, and a B.A. from the University of  North  Carolina  in
1977.

H.  Allen  Corey, a founder of the Managing General Partner, has served  as
the   Managing  General  Partner's  secretary  and  a  director  since  its
inception.   Mr. Corey is President of Trolley Barn Brewery, Inc.,  a  brew
pub restaurant chain based in the Southeast.  Prior to his involvement with
Trolley Barn, Mr. Corey was a partner at the law firm of Miller & Martin in
Chattanooga,  Tennessee.  He is currently of counsel to  the  law  firm  of
Baker,  Donelson,  Bearman  & Caldwell, with the  offices  in  Chattanooga,
Tennessee.  Mr. Corey received a J.D. degree from the Vanderbilt University
Law  School and B.A. degree from the University of North Carolina at Chapel
Hill.

Bill  E. Coggin, Vice President and Chief Financial Officer, has been  with
the Managing General Partner since 1985.  Mr. Coggin was Controller for Rod
Ric  Corporation of Midland, Texas, an oil and gas drilling company, during
the latter part of 1984.  He was Controller for C.F. Lawrence & Associates,
Inc., an independent oil and gas operator also of Midland, Texas during the
early  part of 1984.  Mr. Coggin taught public school for four years  prior
to his business experience.  Mr. Coggin received a B.S. in Education and  a
B.B.A. in Accounting from Angelo State University.

J.  Steven  Person, Vice President, Marketing assumed his  responsibilities
with  the Managing General Partner as National Marketing Director in  1989.
Prior  to joining the Managing General Partner, Mr. Person served  as  Vice
President  of  Marketing  for CRI, Inc., and was  associated  with  Capital
Financial  Group and Dean Witter (1983).  He received a B.B.A. from  Baylor
University in 1982 and an M.B.A. from Houston Baptist University in 1987.

Paul  L.  Morris has served as a Director of Southwest Royalties  Holdings,
Inc.  since August 1998 and Southwest Royalties, Inc. since September 1998.
Mr. Morris is President and CEO of Wagner & Brown, Ltd., one of the largest
independently owned oil and gas companies in the United States.   Prior  to
his  position with Wagner & Brown, Mr. Morris served as President of Banner
Energy  and  in various managerial positions with the Columbia Gas  System,
Inc.


<PAGE>
Key Employees

Jon  P. Tate, Vice President, Land and Assistant Secretary, age 44, assumed
his  responsibilities with the Managing General Partner in 1989.  Prior  to
joining  the  Managing  General Partner, Mr.  Tate  was  employed  by  C.F.
Lawrence  & Associates, Inc., an independent oil and gas company,  as  Land
Manager from 1981 through 1989.  Mr. Tate is a member of the Permian  Basin
Landman's  Association and American Association of Petroleum Landmen.   Mr.
Tate received his B.B.S. degree from Hardin-Simmons University.

R.  Douglas  Keathley,  Vice President, Operations,  age  46,  assumed  his
responsibilities with the Managing General Partner as a Production Engineer
in  October,  1992.   Prior to joining the Managing  General  Partner,  Mr.
Keathley  was  employed for four (4) years by ARCO Oil  &  Gas  Company  as
senior  drilling  engineer working in all phases of well production  (1988-
1992),  eight  (8)  years by Reading & Bates Petroleum  Company  as  senior
petroleum  engineer responsible for drilling (1980-1988) and two (2)  years
by  Tenneco Oil Company as drilling engineer responsible for all phases  of
drilling   (1978-1980).   Mr.  Keathley  received  his  B.S.  in  Petroleum
Engineering in 1977 from the University of Oklahoma.

In certain instances, the Managing General Partner will engage professional
petroleum   consultants   and  other  independent  contractors,   including
engineers   and   geologists  in  connection  with  property  acquisitions,
geological  and  geophysical  analysis,  and  reservoir  engineering.   The
Managing  General Partner believes that, in addition to its own  "in-house"
staff,  the utilization of such consultants and independent contractors  in
specific  instances  and  on  an  "as-needed"  basis  allows  for   greater
flexibility  and greater opportunity to perform its oil and gas  activities
more economically and effectively.

Item 11.  Executive Compensation

The  Partnership  does not have any directors or executive  officers.   The
executive officers of the Managing General Partner do not receive any  cash
compensation,  bonuses, deferred compensation or compensation  pursuant  to
any  type  of  plan,  from the Partnership.  The Managing  General  Partner
received $68,400 during 2001, 2000 and 1999 as an annual administrative fee
for indirect general and administrative overhead expense.

Item 12.  Security Ownership of Certain Beneficial Owners and Management

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

The  Managing  General Partner owns a nine percent interest  as  a  general
partner.   Through prior purchases, the Managing General Partner also  owns
318.0  limited  partner  units, or a 3.3% limited  partner  interest.   The
Managing  General  Partner  total  percentage  interest  ownership  in  the
Partnership is 11.9%.

No  officer or director of the Managing General Partner owns Units  in  the
Partnership.  H. H. Wommack, III, as the individual general partner of  the
Partnership,  owns  a  one  percent interest as  a  general  partner.   The
officers  and  directors  of the Managing General  Partner  are  considered
beneficial  owners of the limited partner units acquired  by  the  Managing
General  Partner by virtue of their status as such.  A list  of  beneficial
owners  of limited partner units, acquired by the Managing General Partner,
is as follows:

<PAGE>
                                                   Amount and
                                                   Nature of      Percent
                     Name and Address of           Beneficial        of
 Title of Class        Beneficial Owner            Ownership       Class
-------------------  ---------------------------  ---------------  -------
Limited Partnership  Southwest Royalties, Inc.    Directly Owns    3.3%
 Interest            Managing General Partner     318.0 Units
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. H. Wommack, III           Indirectly Owns  3.3%
 Interest            Chairman of the Board,       318.0 Units
                     President, CEO, Treasurer
                     and Director of Southwest
                     Royalties, Inc., the
                     Managing General Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. Allen Corey               Indirectly Owns  3.3%
 Interest            Secretary and Director of    318.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     633 Chestnut Street
                     Chattanooga, TN  37450-1800

Limited Partnership  Bill E. Coggin               Indirectly Owns  3.3%
 Interest            Vice President and CFO of    318.0 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  J. Steven Person             Indirectly Owns  3.3%
 Interest            Vice President, Marketing    318.0 Units
                     of Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  Paul L. Morris               Indirectly Owns  3.3%
 Interest            Director, of Southwest       318.0 Units
                     Royalties, Inc., the
                     Managing General Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

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

<PAGE>
Item 13.  Certain Relationships and Related Transactions

In 2001, 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 certain  officers  and
employees  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 $69,300  for  administrative
overhead attributable to operating such properties during 2001.

Certain  subsidiaries or affiliates of the Managing General Partner perform
various  oilfield services for properties in which the Partnership owns  an
interest.   Such  services aggregated approximately $15,100  for  the  year
ended December 31, 2001.

In  the  opinion  of  management, the terms of the above  transactions  are
similar to ones with unaffiliated third parties.

<PAGE>
                                 Part IV

Item 14.  Exhibits, Financial Statement Schedules and Reports on Form 8-K

          (a)(1)  Financial Statements:

                  Included in Part II of this report --

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

                     (2)  Schedules required by Article 12 of Regulation 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.)

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on  Form  8-K  during  the
              quarter ended December 31, 2001.

<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/ H. H. Wommack, III
                                 -----------------------------
                                           H. H. Wommack, III, President


                          Date:  March 29, 2002


Pursuant  to the requirements of the Securities Exchange Act of 1934,  this
report  has  been signed below by the following persons on  behalf  of  the
Partnership and in the capacities and on the dates indicated.


By:    /s/ H. H. Wommack, III
       -----------------------------------
       H. H. Wommack, III, Chairman of the
       Board, President, Chief Executive
       Officer, Treasurer and Director


Date:  March 29, 2002


By:    /s/ H. Allen Corey
       -----------------------------
       H. Allen Corey, Secretary and
       Director


Date:  March 29, 2002

<PAGE>