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, 1999

                                    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   0-18997

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

Delaware                                                     75-2310852
(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 40 .  There  is  no
exhibit index.

<PAGE>
                            Table of Contents

Item                                                                   Page

                                  Part I

 1.  Business                                                            3

 2.  Properties                                                          6

 3.  Legal Proceedings                                                   9

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

                                 Part II

 5.  Market for Registrant's Common Equity and Related
     Stockholder Matters                                                10

 6.  Selected Financial Data                                            11

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

 8.  Financial Statements and Supplementary Data                        19

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

                                 Part III

10.  Directors and Executive Officers of the Registrant                 35

11.  Executive Compensation                                             36

12.  Security Ownership of Certain Beneficial Owners and
     Management                                                         36

13.  Certain Relationships and Related Transactions                     38

                                 Part IV

14.  Exhibits, Financial Statement Schedules, and Reports
     on Form 8-K                                                        39

     Signatures                                                         40

<PAGE>
                                  Part I

Item 1.   Business

General
Southwest  Royalties Institutional Income Fund X-A, L.P. (the "Partnership"
or "Registrant") was organized as a Delaware limited partnership on January
29, 1990.  The offering of limited partnership interests began May 11, 1990
as  part  of a shelf offering registered under the name Southwest Royalties
Institutional 1990-91 Income Program.  Minimum capital requirements for the
Partnership  were  met  on  July 30, 1990, with  the  offering  of  limited
partnership interests concluding on November 30, 1990.  The Partnership has
no subsidiaries.

The Partnership has acquired interests in producing oil and gas properties,
and  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  97  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
profit 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>
Oil prices experienced a year of recovery during 1999.  After seeing prices
languish  near  $10  per barrel in December 1998, a rebound  occurred  that
would briefly push NYMEX pricing over $27 in late November 1999.  Crude oil
prices reached $20 per barrel in mid-July and would not fall below $21  the
rest of the year.  There were drastic improvements to the main factors that
gave  rise  to  the worst price depression in history.  These  improvements
provoked a spike in crude oil prices to levels not seen since the Gulf War.
First, OPEC has done a remarkable job of adhering to production cuts agreed
to  in  March, despite the temptation to cheat given current  pricing.   As
prices  have  risen  over  the last twelve months,  OPEC  has  consistently
maintained a compliance rate above 90 percent.  Also, most foreign  markets
are well on their way to recovery, greatly increasing the demand for energy
in   those  countries.   These  and  other  factors  have  eliminated   the
"oversupply"  of  crude oil that we experienced in 1998.   The  near  month
contract for crude oil settled at $25.60 per barrel on December 30, 1999.

In  1999  natural  gas  prices rose 10% to an average of  $2.18/MMBtu,  18 cents
higher  than  the  $2.00/MMBtu average seen in 1998.  Despite  warmer-than-
normal  heating seasons at both ends of the year, 1999 was the fourth  year
in  a  row that prices averaged $2.00/MMBtu or above.  Citing lower storage
levels and a rising demand for natural gas, industry experts are predicting
a "healthy jump" in prices for 2000.  Although higher prices in 1999 fueled
an  increase in production, end of year gas in storage nationwide  is  only
75% of capacity as compared to 87% at the end of 1998.  Further, gas demand
is expected to continue to increase at a faster pace than the amount of gas
being replaced.  A record breaking 70% of single-family homes built in 1999
were equipped with natural gas services ranging from traditional heating to
water   heating,   cooking  and  grilling.   Based  on  these   encouraging
statistics,  we  remain optimistic in our expectation  of  slightly  higher
natural  gas  prices in the coming year, hopefully seeing an average  above
the $2.20/MMBtu level.

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

                                  Oil          Gas

                    1999          74%          26%
                    1998          79%          21%
                    1997          80%          20%

As  the table indicates, the majority of the Partnership's revenue is  from
its   oil  production;  therefore,  Partnership  revenues  will  be  highly
dependent upon the future prices and demands for oil.

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.

<PAGE>
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  a
material adverse impact on the Partnership.  Four purchasers accounted  for
69% of the Partnership's total oil and gas production during 1999: Scurlock
Permian  LLC  for  24%,  Navajo Refining Company Inc.  for  20%,  Eaglewing
Trading  Inc. for 15% and Phillips 66 for 10%.  Three purchasers  accounted
for  57%  of  the Partnership's total oil and gas production  during  1998:
Scurlock  Permian  LLC for 28%, Navajo Refining Company Inc.  for  18%  and
Eaglewing Trading Inc. for 11%.  Three purchasers accounted for 56% of  the
Partnership's  total oil and gas production during 1997:  Scurlock  Permian
Corporation  for  29%,  Navajo Refining Company  Inc.  for  16%  and  Mobil
Corporation  for  11%.   All purchasers of the Partnership's  oil  and  gas
production  are  unrelated third parties.  In the  event  either  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.

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.

<PAGE>
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 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,
1999,  there were 97 individuals directly employed by the Managing  General
Partner in various capacities.

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.

<PAGE>
As  of December 31, 1999, the Partnership possessed an interest in oil  and
gas  properties  located in Eddy and Lea Counties of New  Mexico;  Andrews,
Cherokee,  Duval,  Glasscock,  Hockley,  Howard,  Midland,  Panola,  Pecos,
Reagan,  Runnels,  Upton,  Ward  and  Yoakum  Counties  of  Texas.    These
properties  consist  of various interests in approximately  408  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 have not been any
significant changes in properties during 1999, 1998 and 1997.

During 1999, nine leases were sold for $42,772.  During 1998, eleven leases
were sold for $71,500.  During 1997, two leases were sold for $2,500.

Significant Property

The  following  table  reflects  the  significant  property  in  which  the
Partnership has an interest:

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

Cline Estate          1/91 at .3%         144         62,000       48,000
Andrews, Cherokee,    to 100%
Glasscock, Howard,    net profits
Panola, Reagan, Upton interests
and Yoakum Counties,
Texas

Texas Crude           12/90* at 17.5%       8         98,000       43,000
Acquisition           to 50%
Gaines, Hockley       net profits
and Terry Counties,   interests
Texas and Lea County,
New Mexico

*Per  the  terms of the purchase, the Partnership received production  runs
from a period prior to the date of purchase.


<PAGE>
*Donald  R.  Creamer,  P.E., an Independent Registered  Petroleum  Engineer
prepared  the reserve and present value data for the Partnership's existing
properties  as  of  January 1, 2000.  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.

The  New York Mercantile Exchange price at December 31, 1999 of $25.60  was
used  as the beginning basis for the oil price.  Oil price adjustments from
$25.60  per  barrel were made in the individual evaluations to reflect  oil
quality,  gathering and transportation costs. The results  are  an  average
price received at the lease of $22.85 per barrel in the preparation of  the
reserve report as of January 1, 2000.

In  the  determination of the gas price, the New York  Mercantile  Exchange
price  at December 31, 1999 of $2.33 was used as the beginning basis.   Gas
price   adjustments  from  $2.33  per  Mcf  were  made  in  the  individual
evaluations to reflect BTU content, gathering and transportation costs  and
gas processing and shrinkage.  The results are an average price received at
the  lease of $2.18 per Mcf in the preparation of the reserve report as  of
January 1, 2000.

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 1999.

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.

<PAGE>
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, proved developed non-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 1999 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
1999,  24  limited  partner units were tendered to  and  purchased  by  the
Managing  General Partner at an average base price of $20.80 per unit.   In
1998,  44  limited  partner units were tendered to  and  purchased  by  the
Managing  General Partner at an average base price of $24.74 per unit.   In
1997,  10  limited  partner units were tendered to  and  purchased  by  the
Managing General Partner at an average base price of $47.70 per unit.

Number of Limited Partner Interest Holders
As  of December 31, 1999 there were 580 holders of limited partner units in
the Partnership.

Distributions
Pursuant to Article III, Section 3.05 of the Partnership's Certificate  and
Agreement  of  Limited Partnership "Net Cash Flow" is  distributed  to  the
partners  on  a  monthly 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>
There  were  no distributions during the twelve months ended  December  31,
1999.   During 1998, distributions were made totaling $50,000, with $45,000
distributed  to  the limited partners and $5,000 to the  general  partners.
For  the  year ended December 31, 1998, distributions of $3.98 per  limited
partner   unit   were  made,  based  upon  11,316  limited  partner   units
outstanding.  During 1997, twelve monthly distributions were made  totaling
$230,000, with $207,000 distributed to the limited partners and $23,000  to
the  general partners.  For the year ended December 31, 1997, distributions
of  $18.29  per  limited partner unit were made, based upon 11,316  limited
partner units outstanding.

Item 6.   Selected Financial Data

The  following  selected financial data for the years  ended  December  31,
1999,  1998,  1997,  1996 and 1995 should be read in conjunction  with  the
financial statements included in Item 8:

                                    Years ended December 31,
                    --------------------------------------------------------
                        1999        1998      1997        1996      1995
                        ----        ----      ----        ----      ----
Revenues            $  133,271   (14,648)    268,242    380,073    130,883

Net income (loss)       24,636  (283,067)     87,080    209,089   (68,065)

Partners' share
 of net income
  (loss):

  General
   partners              3,764   (12,192)     17,008     28,109      2,962

  Limited
   partners             20,872  (270,875)     70,072    180,980   (71,027)

Limited partners'
 net income (loss)
  per unit                1.84    (23.94)       6.19      15.99     (6.28)

Limited partners'
 cash distributions
  per unit                   -       3.98      18.29      17.97      11.12

Total assets        $  268,541    261,844    576,834    719,605    736,647

<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  a  few
workovers during 2000 to enhance production.  The partnership may  have  an
increase   in  production  volumes  for  the  year  2001,  otherwise,   the
partnership  will most likely experience the historical production  decline
of approximately 7% per year.


<PAGE>
Results of Operations

A.  General Comparison of the Years Ended December 31, 1999 and 1998

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 1999 and 1998:

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                1999      1998   (Decrease)
                                                ----      ----   ---------
Average price per barrel of oil            $   16.36    11.60      41%
Average price per mcf of gas               $    2.51     1.97      27%
Oil production in barrels                     16,830   23,700    (29%)
Gas production in mcf                         38,830   38,150       2%
Income from net profits interests          $ 133,177 (14,752)   1,003%
Partnership distributions                  $       -   50,000   (100%)
Limited partner distributions              $       -   45,000   (100%)
Per unit distribution to limited partners  $       -     3.98   (100%)
Number of limited partner units               11,316   11,316

Revenues

The  Partnership's income from net profits interests increased to  $133,177
from   $(14,752)  for  the  years  ended  December  31,  1999   and   1998,
respectively,  an increase of 1,003%.  The principal factors affecting  the
comparison of the years ended December 31, 1999 and 1998 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    increased  during the year ended December 31, 1999 as compared  to  the
    year ended December 31, 1998 by 41%, or $4.76 per barrel, resulting  in
    an  increase  of  approximately $112,800 in  income  from  net  profits
    interests.  Oil sales represented 74% of total oil and gas sales during
    the  year  ended December 31, 1999 as compared to 79 % during the  year
    ended December 31, 1998.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    increased during the same period by 27%, or $.54 per mcf, resulting  in
    an  increase  of  approximately $20,600  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
    $133,400.  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 6,870 barrels or 29% during the
    year ended December 31, 1999 as compared to the year ended December 31,
    1998, resulting in a decrease of approximately $112,400 in income  from
    net profits interests.

    Gas  production increased approximately 680 mcf or 2% during  the  same
    period, resulting in an increase of approximately $1,700 in income from
    net profits interests.

    The  net total decrease in income from net profits interests due to the
    change  in production is approximately $110,700.  The decrease  in  oil
    production is due primarily to property sales during 1999 and 1998.

3.  Lease  operating  costs  and  production  taxes  were  34%  lower,   or
    approximately $125,200 less during the year ended December 31, 1999  as
    compared  to the year ended December 31, 1998.  The decrease  in  lease
    operating  costs  is due primarily to property sales  during  1999  and
    1998.

Costs and Expenses

Total  costs and expenses decreased to $108,635 from $268,419 for the years
ended  December 31, 1999 and 1998, respectively, a decrease  of  60%.   The
decrease is the result of lower depletion expense, provision for impairment
and general and administrative costs.

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
    11% or approximately $11,600 during the year ended December 31, 1999 as
    compared to the year ended December 31, 1998.

2.   Depletion expense decreased to $13,000 for the year ended December 31,
   1999 from $125,000 for the same period in 1998.  This represents a decrease
   of  90%.   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.

    A  contributing 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, 2000 as compared
    to  1999.   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  $86,000  as  of
    December 31, 1998.

3.  The  Partnership  reduced the net capitalized  costs  of  oil  and  gas
    properties  during 1998 by $36,143. This provision for  impairment  had
    the  effect  of reducing net income, but did not affect  cash  flow  or
    partner  distributions.  See Summary of Significant Accounting Policies
    - Oil and Gas Properties.


<PAGE>

Results of Operations

B.  General Comparison of the Years Ended December 31, 1998 and 1997

The  following  table  provides certain information  regarding  performance
factors for the years ended December 31, 1998 and 1997:

                                                  Year Ended     Percentage
                                                 December 31,     Increase
                                                1998      1997   (Decrease)
                                                ----      ----   ---------

Average price per barrel of oil            $   11.60    18.06    (36%)
Average price per mcf of gas               $    1.97     2.60    (24%)
Oil production in barrels                     23,700   29,400    (19%)
Gas production in mcf                         38,150   49,800    (23%)
Income from net profits interests          $(14,752)  258,854   (106%)
Partnership distributions                  $  50,000  230,000    (78%)
Limited partner distributions              $  45,000  207,000    (78%)
Per unit distribution to limited partners  $    3.98    18.29    (78%)
Number of limited partner units               11,316   11,316

Revenues

The  Partnership's income from net profits interests decreased to $(14,752)
from $258,854 for the years ended December 31, 1998 and 1997, respectively,
a  decrease of 106%.  The principal factors affecting the comparison of the
years ended December 31, 1998 and 1997 are as follows:

1.  The  average  price  for a barrel of oil received  by  the  Partnership
    decreased  during the year ended December 31, 1998 as compared  to  the
    year ended December 31, 1997 by 36%, or $6.46 per barrel, resulting  in
    a  decrease  of  approximately $190,000  in  income  from  net  profits
    interests.  Oil sales represented 79% of total oil and gas sales during
    the  year  ended December 31, 1998 as compared to 80 % during the  year
    ended December 31, 1997.

    The  average  price  for  an  mcf of gas received  by  the  Partnership
    decreased during the same period by 24%, or $.63 per mcf, resulting  in
    a  decrease  of  approximately  $31,400  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
    $221,400.  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 5,700 barrels or 19% during the
    year ended December 31, 1998 as compared to the year ended December 31,
    1997,  resulting in a decrease of approximately $66,100 in income  from
    net profits interests.

    Gas  production  decreased approximately 11,700 mcf or 23%  during  the
    same period, resulting in a decrease of approximately $23,000 in income
    from net profits interests.

    The  total  decrease in income from net profits interests  due  to  the
    change in production is approximately $89,100.  Decrease in oil and gas
    production  due primarily to property sales, downtime and  shut-ins  on
    wells uneconomical to repair.

3.  Lease   operating  costs  and  production  taxes  were  9%  lower,   or
    approximately $36,700 less during the year ended December 31,  1998  as
    compared to the year ended December 31, 1997.

Costs and Expenses

Total  costs and expenses increased to $268,419 from $181,162 for the years
ended  December 31, 1998 and 1997, respectively, an increase of  48%.   The
increase  is  the  result  of  higher  depletion  expense,  provision   for
impairment and general and administrative costs.

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 9%
    or  approximately  $9,100 during the year ended December  31,  1998  as
    compared to the year ended December 31, 1997.

3.    Depletion  expense increased to $125,000 for the year ended  December
   31,  1998 from $83,000 for the same period in 1997.  This represents  an
   increase of 51%.  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.

    A  contributing 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, 1999 as compared
    to  1998.   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  increased depletion expense approximately  $58,000  as  of
    December 31, 1997.

3.  The  Partnership  reduced the net capitalized  costs  of  oil  and  gas
    properties by $36,143.  This provision for impairment had the effect of
    reducing  net  income,  but  did  not  affect  cash  flow  or   partner
    distributions.   See Summary of Significant Accounting Policies  -  Oil
    and Gas Properties.


<PAGE>

C.  Revenue and Distribution Comparison

Partnership income (loss) for the years ended December 31, 1999,  1998  and
1997  was  $24,636,  $(283,067) and $87,080, respectively.   Excluding  the
effects   of  depreciation,  depletion,  amortization  and  provision   for
impairment,  net income (loss) would have been $37,636 in 1999,  $(121,924)
in  1998  and $170,080 in 1997.  Correspondingly, Partnership distributions
for the years ended December 31, 1999, 1998 and 1997 were none, $50,000 and
$230,000, respectively.  These differences are indicative of the changes in
oil and gas prices, production and property sales.

There  were no distributions for the twelve months ended December 31, 1999.
The  sources  for  the  1998  distributions of $50,000  were  oil  and  gas
operations  of  approximately $(45,955) and  the  change  in  oil  and  gas
properties  of  approximately  $100,300,  resulting  in  excess  cash   for
contingencies  or  subsequent distributions.   The  sources  for  the  1997
distributions  of  $230,000  were oil and gas operations  of  approximately
$226,900 and the change in oil and gas properties of approximately  $2,500,
with  the  balance  from available cash on hand at  the  beginning  of  the
period.

There  were no distributions for the twelve months ended December 31, 1999.
Total distributions during the year ended December 31, 1998 were $50,000 of
which  $45,000  was distributed to the limited partners and $5,000  to  the
general partners.  The per unit distribution to limited partners during the
same  period was $3.98.  Total distributions during the year ended December
31,  1997  were $230,000 of which $207,000 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 $18.29.

Since  inception of the Partnership, cumulative monthly cash  distributions
of  $3,033,122  have been made to the partners.  As of December  31,  1999,
$2,778,161 or $245.51 per limited partner unit, has been distributed to the
limited partners, representing a 49% return of the capital contributed.

<PAGE>
Liquidity and Capital Resources

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

Cash flows provided by or (used in) operating activities were approximately
$(23,429) in 1999 compared to $(45,955) in 1998 and approximately  $226,900
in  1997.   The primary use of the 1999 cash flow from operating activities
was for operations.

Cash  flows provided by investing activities were approximately $44,900  in
1999  compared to $100,300 in 1998 and approximately $2,500 in  1997.   The
principal  source of the 1999 cash flow from investing activities  was  the
sale of oil and gas properties.

Cash  flows  provided by (used in) financing activities were  approximately
$139 in 1999 compared to $(50,000) in 1998 and approximately $(229,900)  in
1997.

As  of  December  31,  1999, the Partnership had approximately  $74,800  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
over  $35.1  million principal and $17.5 million interest payments  due  in
2000  on  its  debt  obligations. Due to the severely  depressed  commodity
prices  experienced  during the last quarter of 1997, throughout  1998  and
continuing through the second quarter of 1999 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.

Information Systems for the Year 2000

The  year  2000  issue  referred to the risk of disruptions  of  operations
caused  by  the  failure of computer-controlled systems, including  systems
used  by  third  parties, to properly recognize date sensitive  information
when  the  year changed from 1999 to 2000.  During the year ended  December
31, 1999, the Managing General Partners data processing subsidiary, Midland
Southwest  Software, Inc., installed new software as part  of  an  on-going
project  to upgrade its financial and management information systems.   The
cost  of  upgrading the software occurred in the normal course  of  Midland
Southwest  Software's  business and was not  material  to  the  results  of
operations or financial condition of the Partnership.

The  Partnership  has not experienced any significant business  disruptions
due  to  year  2000 issues causing processing errors in its systems,  or  a
third  party's  systems, during the period of operations after  January  1,
2000 until the filing of the 10-K.


<PAGE>
Item 8.   Financial Statements and Supplementary Data

                      Index to Financial Statements

                                                                       Page

Independent Auditors Report                                             20

Balance Sheets                                                          21

Statements of Operations                                                22

Statement of Changes in Partners' Equity                                23

Statements of Cash Flows                                                24

Notes to Financial Statements                                           26

<PAGE>









                        INDEPENDENT AUDITORS REPORT

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

We  have  audited  the  accompanying balance sheets of Southwest  Royalties
Institutional Income Fund X-A, L.P. (the "Partnership") as of December  31,
1999  and  1998,  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,  1999.  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 generally  accepted  auditing
standards.  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 X-A, L.P. as of December 31, 1999  and  1998  and
the  results of its operations and its cash flows for each of the years  in
the  three-year period ended December 31, 1999 in conformity with generally
accepted accounting principles.








                                                  KPMG LLP



Midland, Texas
March 10, 2000

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)
                              Balance Sheets
                        December 31, 1999 and 1998


                                                      1999          1998
                                                      ----          ----

  Assets

Current assets:
 Cash and cash equivalents                $           32,212       10,631
 Receivable from Managing General Partner             42,987            -

---------                                 ---------
                                               Total     current     assets
75,199                                    10,631

---------                                 ---------
Oil and gas properties - using the full-
 cost method of accounting                         4,239,485    4,284,356
  Less accumulated depreciation,
                                             depletion   and   amortization
4,046,143                                 4,033,143

---------                                 ---------
                                            Net   oil  and  gas  properties
193,342                                   251,213

---------                                 ---------
                                                                          $
268,541                                   261,844

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

Current liabilities
 Distribution payable                     $              429          290
 Payable to Managing General Partner                       -       18,078

---------                                 ---------
                                             Total    current   liabilities
429                                       18,368

---------                                 ---------
Partners' equity:
 General Partner                                    (18,727)     (22,491)
 Limited partners                                    286,839      265,967

---------                                 ---------
                                              Total     partners'    equity
268,112                                   243,476

---------                                 ---------
                                                                          $
268,541                                   261,844

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


















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

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Operations
               Years ended December 31, 1999, 1998 and 1997


                                                 1999      1998      1997
                                                 ----      ----      ----

  Revenues

Income from net profits interests         $    133,177  (14,752)  258,854
Interest                                            94       104    1,735
Miscellaneous income                                 -         -    7,653
                                                                    -------
-------                                   -------
                                                                    133,271
(14,648)                                  268,242
                                                                    -------
-------                                   -------
  Expenses

General and administrative                      95,635   107,276   98,162
Depreciation, depletion and amortization        13,000   125,000   83,000
Provision for impairment of oil and gas
 properties                                          -    36,143        -
                                                                    -------
-------                                   -------
                                                                    108,635
268,419                                   181,162
                                                                    -------
-------                                   -------
Net income (loss)                         $     24,636 (283,067)   87,080
                                                                    =======
=======                                   =======
Net income (loss) allocated to:

  Managing General Partner                $      3,388  (10,973)   15,307
                                                                    =======
=======                                   =======
  General Partner                         $        376   (1,219)    1,701
                                                                    =======
=======                                   =======
  Limited partners                        $     20,872 (270,875)   70,072
                                                                    =======
=======                                   =======
                                           Per limited partner unit       $
1.84                                      (23.94) 6.19
                                                                    =======
=======                                   =======























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

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)
                 Statement of Changes in Partners' Equity
               Years ended December 31, 1999, 1998 and 1997


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

Balance at December 31, 1996              $        693   718,770  719,463

 Net income                                     17,008    70,072   87,080

 Distributions                                (23,000) (207,000)(230,000)
                                                                    -------
--------                                  --------
Balance at December 31, 1997                   (5,299)   581,842  576,543

 Net income (loss)                            (12,192) (270,875)(283,067)

 Distributions                                 (5,000)  (45,000) (50,000)
                                                                    -------
--------                                  --------
Balance at December 31, 1998                  (22,491)   265,967  243,476

 Net income                                      3,764    20,872   24,636

 Distributions                                       -         -        -
                                                                    -------
--------                                  --------
Balance at December 31, 1999              $   (18,727)   286,839  268,112
                                                                    =======
========                                  ========































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

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)
                         Statements of Cash Flows
               Years ended December 31, 1999, 1998 and 1997


                                                 1999      1998     1997
                                                 ----      ----     ----

Cash flows from operating activities:

 Cash received from net profits interests $     72,643    54,952  323,343
 Cash paid to Managing General Partner
  for administrative fees and general
                                            and   administrative   overhead
(96,166)                                  (101,011)(98,162)
 Interest received                                  94       104    1,735
                                                                   --------
--------                                  --------
  Net cash (used in) provided by operating
                                           activities    (23,429)  (45,955)
226,916
                                                                   --------
--------                                  --------
Cash flows from investing activities:

 Sale of oil and gas properties                 44,871   100,286    2,500
                                                                   --------
--------                                  --------
Cash flows provided by (used in) financing
 activities:

 Distributions to partners                         139  (50,001)(229,851)
                                                                   --------
--------                                  --------
Net increase (decrease) in cash and
 cash equivalents                               21,581     4,330    (435)

 Beginning of year                              10,631     6,301    6,736
                                                                   --------
--------                                  --------
 End of year                              $     32,212    10,631    6,301
                                                                   ========
========                                  ========


(continued)























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

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)
                   Statements of Cash Flows, continued
               Years ended December 31, 1999, 1998 and 1997


                                                 1999      1998      1997
                                                 ----      ----      ----

Reconciliation of net income (loss) to net
 cash (used in) provided by operating activities:

Net income (loss)                         $     24,636 (283,067)   87,080

Adjustments to reconcile net income (loss) to
 net cash (used in) provided by operating
 activities:

   Depreciation, depletion and amortization                13,000   125,000
83,000
  Provision for impairment of oil and gas
                                           properties           -    36,143
-
  Decrease (Increase) in receivables          (60,534)    69,704   56,836
  (Decrease)Increase in payables                 (531)     6,265        -
                                                          -------   -------
-------
Net cash (used in) provided by operating
 activities                               $   (23,429)  (45,955)  226,916
                                                          =======   =======
=======


































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

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

                      Notes to Financial Statements


1.   Organization
     Southwest Oil & Gas Income Fund X-B, L.P. was organized under the laws
     of  the  state  of Delaware on November 27, 1990 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
                                                     --------     --------

     Interest income on capital contributions        100%            -
     Oil and gas sales                                90%           10%
     All other revenues                               90%           10%
     Organization and offering costs (1)             100%            -
     Amortization or 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.

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

                      Notes to Financial Statements


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.

     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, 1999 and 1997 the  net
     capitalized  costs did not exceed the estimated present value  of  oil
     and  gas reserves.  As of December 31, 1998, the net capitalized  cost
     exceeded the estimated present value of oil and gas reserves, thus  an
     adjustment of $36,143 was made to the financial statement.

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


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

                      Notes to Financial Statements


2.   Summary of Significant Accounting Policies - continued

     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.  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,  1999,  1998  and
     1997, there were no significant amounts of imbalance in terms of units
     and value.

     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,  1999  and 1998 is $601,951 and $961,127, respectively, more  than
     that  shown  on  the  accompanying Balance Sheets in  accordance  with
     generally accepted accounting principles.

<PAGE>
         Southwest Royalties Institutional Income Fund X-A, 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, 1999, 1998 and 1997, there were  11,316  limited
     partner units outstanding held by 580, 585 and 585 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.

3.   Liquidity - Managing General Partner
     The  Managing General Partner has a highly leveraged capital structure
     with  over $35.1 million principal and $17.5 million interest payments
     due  in  2000 on its debt obligations.  Due to the severely  depressed
     commodity  prices  experienced  during  the  last  quarter  of   1997,
     throughout 1998 and continuing through the second quarter of 1999  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.

<PAGE>

         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements


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

     As  of December 31, 1999, 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.

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

                      Notes to Financial Statements


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 is usual in the industry and as provided
     for  in  the  operating  agreement for each  respective  oil  and  gas
     property  in  which the Partnership has an interest, the  operator  is
     paid  an  amount for administrative overhead attributable to operating
     such  properties,  with such amounts to Southwest Royalties,  Inc.  as
     operator  approximating $60,300, $77,400 and  $69,000  for  the  years
     ended  December 31, 1999, 1998, and 1997, 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
     $8,900, $6,800 and $1,600 for the years ended December 31, 1999, 1998,
     and 1997, respectively, and the Managing General Partner believes that
     these  costs are comparable to similar charges paid by the Partnership
     to unrelated third parties.

     Southwest  Royalties,  Inc., the Managing General  Partner,  was  paid
     $90,000  during  1999,  1998 and 1997, as an administrative  fee,  for
     indirect general and administrative overhead expenses.

     Receivables  (Payable)  from  (to)  Southwest  Royalties,  Inc.,   the
     Managing  General Partner, of approximately $42,987 and $(18,078)  are
     from  oil  and  gas  production,  net of  lease  operating  costs  and
     production taxes, as of December 31, 1999 and 1998, 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
     ending December 31, 1999, 1998 and 1997.

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  a  material  adverse impact  on  the  Partnership.   Four
     purchasers  accounted for 69% of the Partnership's total oil  and  gas
     production  during 1999: Scurlock Permian Corporation for 24%,  Navajo
     Refining  Company  Inc. for 20%, Eaglewing Trading Inc.  for  15%  and
     Phillips  66  for  10%.  Three purchasers accounted  for  57%  of  the
     Partnership's  total  oil  and gas production  during  1998:  Scurlock
     Permian Corporation for 28%, Navajo Refining Company Inc. for 18%  and
     Eaglewing Trading Inc. for 11%.  Three purchasers accounted for 56% of
     the  Partnership's total oil and gas production during 1997:  Scurlock
     Permian Corporation for 29%, Navajo Refining Company Inc. for 16%  and
     Mobil  Corporation  for 11%.  All purchasers of the Partnership's  oil
     and  gas production are unrelated third parties.  In the event  either
     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>
         Southwest Royalties Institutional Income Fund X-A, L.P.
                     (a Delaware limited partnership)

                      Notes to Financial Statements


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, 1997                                 339,000       421,000

       Revisions of previous estimates             (112,000)         7,000
       Production                                   (29,000)      (50,000)
                                                     -------       -------
     December 31, 1997                               198,000       378,000

       Sales of reserves in place                    (7,000)      (19,000)
       Revisions of previous estimates             (121,000)      (98,000)
       Production                                   (24,000)      (38,000)
                                                     -------       -------
     December 31, 1998                                46,000       223,000

       Revisions of previous estimates               185,000        94,000
       Production                                   (17,000)      (39,000)
                                                     -------       -------
     December 31, 1999                               214,000       278,000
                                                     =======       =======
     Proved developed reserves -

     December 31, 1997                               198,000       373,000
                                                     =======       =======
     December 31, 1998                                45,000       215,000
                                                     =======       =======
     December 31, 1999                               213,000       270,000
                                                     =======       =======

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

     *Donald R. Creamer, P.E., an Independent Registered Petroleum Engineer
     prepared  the  reserve  and present value data for  the  Partnership's
     existing properties as of January 1, 2000.  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.

     The  New York Mercantile Exchange price at December 31, 1999 of $25.60
     was  used  as  the  beginning basis for  the  oil  price.   Oil  price
     adjustments  from  $25.60  per  barrel were  made  in  the  individual
     evaluations  to  reflect  oil  quality, gathering  and  transportation
     costs.   The  results are an average price received at  the  lease  of
     $22.85  per  barrel  in the preparation of the reserve  report  as  of
     January 1, 2000.

     In  the  determination  of  the gas price,  the  New  York  Mercantile
     Exchange price at December 31, 1999 of $2.33 was used as the beginning
     basis.   Gas  price adjustments from $2.33 per Mcf were  made  in  the
     individual   evaluations  to  reflect  BTU  content,   gathering   and
     transportation  costs and gas processing and shrinkage.   The  results
     are  an  average price received at the lease of $2.18 per Mcf  in  the
     preparation of the reserve report as of January 1, 2000.

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

                      Notes to Financial Statements


7.   Estimated Oil and Gas Reserves (unaudited) - continued
     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, proved developed non-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 X-A, 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, 1999, 1998 and 1997 is
     presented below:

                                              1999       1998        1997
                                              ----       ----        ----

     Future cash inflows, net of
       production and development
      costs                             $  3,095,000    374,000  1,653,000
     10% annual discount for
       estimated timing of cash
      flows                                1,435,000    123,000    601,000
                                           ---------  ---------  ---------
     Standardized measure of
       discounted future net cash
      flows                             $  1,660,000    251,000  1,052,000
                                           =========  =========  =========

     The  principal  sources  of  change in  the  standardized  measure  of
     discounted  future  net cash flows for the years  ended  December  31,
     1999, 1998 and 1997 are as follows:

                                              1999       1998         1997
                                              ----       ----         ----

     Sales of oil and gas produced,
       net of production costs          $  (133,000)     15,000  (259,000)
      Changes in prices and production costs             307,000  (535,000)
(1,312,000)
     Changes of production rates
       (timing) and others                  (69,000)     66,000   (42,000)
     Sales of minerals in place                    -   (38,000)          -
     Revisions of previous
       quantities estimates                1,279,000  (414,000)  (445,000)
     Accretion of discount                    25,000    105,000    283,000
     Discounted future net
       cash flows -
      Beginning of year                      251,000  1,052,000  2,827,000
                                           ---------  ---------  ---------
      End of year                       $  1,660,000    251,000  1,052,000
                                           =========  =========  =========

     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.

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                      44     Chairman   of   the   Board,
                                        President,
                                        Chief Executive Officer, Treasurer
                                        and Director

H. Allen Corey              43          Secretary and Director

Bill E. Coggin                          45     Vice  President  and   Chief
                                        Financial Officer

J. Steven Person            41          Vice President, Marketing

Paul L. Morris              58          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.D.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 Columbia Gas System, Inc.


<PAGE>
Key Employees

Jon  P. Tate, Vice President, Land and Assistant Secretary, age 42, 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 received his B.B.S. degree  from  Hardin-Simmons
University.

R.  Douglas  Keathley,  Vice President, Operations,  age  44,  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  $90,000 during 1999, 1998 and 1997, respectively,  as  an  annual
administrative fee.

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  repurchases  of limited  partner  units,  the  Managing
General Partner also owns 152 limited partner units, a 1.3% limited partner
interest.  The Managing General Partner total percentage interest ownership
in the Partnership is 9.7%.

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    1.3%
 Interest            Managing General Partner     152 Units
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  H. H. Wommack, III           Indirectly Owns  1.3%
 Interest            Chairman of the Board,       152 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  1.3%
 Interest            Secretary and Director of    152 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     633 Chestnut Street
                     Chattanooga, TN  37450-1800

Limited Partnership  Bill E. Coggin               Indirectly Owns  1.3%
 Interest            Vice President and CFO of    152 Units
                     Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  J. Steven Person             Indirectly Owns  1.3%
 Interest            Vice President, Marketing    152 Units
                     of Southwest Royalties, Inc.,
                     the Managing General
                     Partner
                     407 N. Big Spring Street
                     Midland, TX  79701

Limited Partnership  Paul L. Morris               Indirectly Owns  1.3%
 Interest            Director of Southwest        152 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  1999, the Managing General Partner received approximately $90,000 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 $60,300  for  administrative
overhead attributable to operating such properties during 1999.

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 $8,900 for the year ended
December 31, 1999.

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 X-A, L.P., dated January  29,  1990.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1990.)

                                            (b)    Agreement   of   Limited
                          Partnership  of Southwest Royalties Institutional
                          Income  Fund  X-A, L.P. dated January  29,  1990.
                          (Incorporated  by  reference  from  Partnership's
                          Form 10-K for the fiscal year ended December  31,
                          1990.)

                  27 Financial Data Schedule

          (b)     Reports on Form 8-K

                  There  were  no  reports filed on  Form  8-K  during  the
              quarter ended December 31, 1999.

<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 X-A, 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 31, 2000


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 31, 2000


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


Date:  March 31, 2000

<PAGE>