UNITED
      STATES


SECURITIES
      AND EXCHANGE COMMISSION


WASHINGTON,
      D.C. 20549





FORM
      10-K


(Mark
      One)


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





For
      the
      fiscal year ended December 31, 2006





OR





 ̈  Transition
      report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934





For
      the
      transition period from  to





Commission
      File Number 0-18997





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.
                Employerof
                incorporation or organization)
            
            Identification
                No.)6
                Desta Drive, Suite 6500, Midland, Texas
            
            79705(Address
                of principal executive office)
            
            (Zip
                Code)





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





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


None





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


limited
      partnership interests





Indicate
                by check mark if the registrant is a well-known seasoned issuer,
                as
                defined in Rule 405 of the Securities Act.
             ̈Yes
            xNoIndicate
                by check mark if the registrant is not required to file reports pursuant
                to Section 13 or Section 15(d) of the Act.
             ̈Yes
            xNoIndicate
                by check mark whether the registrant (1) has filed all reports required
                to
                be filed by Section 13 or 15(d) of the Securities Exchange Act of
                1934
                during the preceding 12 months (or for such shorter period that the
                registrant was required to file such reports), and (2) has been subject
                to
                such filing requirements for the past 90 days.
            xYes
             ̈No





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





Indicate
                by check mark whether the registrant is a large accelerated filer,
                an
                accelerated filer, or a non-accelerated filer. See definition of
                “accelerated filer and large accelerated filer” in Rule 12b-2 of the
                Exchange Act.Large
                accelerated filer ̈
            
            Accelerated
                filer ̈
            
            Non-accelerated
                filerx





Indicate
                by check mark whether the registrant is a shell company (as defined
                in
                Rule 12b-2 of the Act).
             ̈Yes
            xNo





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.







1


**Table
      of Contents**





**Page****Part
                I**Item
                1.
            Business
            3Item
                1A.
            Risk
                Factors
            6Item
                1B.
            Unresolved
                Staff Comments
            7Item
                2.
            Properties
            8Item
                3.
            Legal
                Proceedings
            9Item
                4.
            Submission
                of Matters to a Vote of Security
                Holders
            9**Part
                II**Item
                5.
            Market
                for Registrant's Common Equity,
                RelatedStockholder
                Matters and Issuer Purchases of Equity
                Securities
            10Item
                6.
            Selected
                Financial Data
            11Item
                7.
            Management's
                Discussion and Analysis ofFinancial
                Condition and Results of
                Operations
            12Item
                7A.
            Quantitative
                and Qualitative Disclosures About Market
                Risk
            14Item
                8.
            Financial
                Statements and Supplementary
                Data
            15Item
                9.
            Changes
                in and Disagreements with
                Accountantson
                Accounting and Financial Disclosure
            28Item
                9A.
            Controls
                and Procedures
            28Item
                9B.
            Other
                Information
            28**Part
                III**Item
                10.
            Directors,
                Executive Officers and Corporate
                Governance
            29Item
                11.
            Executive
                Compensation
            29Item
                12.
            Security
                Ownership of Certain Beneficial Owners and
                Management andRelated
                Stockholder Matters
            30Item
                13.
            Certain
                Relationships and Related Transactions, and
                Director Independence
            30Item
                14.
            Principal
                Accounting Fees and Services
            30**Part
                IV**Item
                15.
            Exhibits
                and Financial Statement
                Schedules
            31**Glossary
                of Oil and Gas
                Terms**
            32**Signatures**
            34





2


**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
      Managing General Partner of the Partnership is Southwest Royalties, Inc. (the
      “Managing General Partner”), a Delaware corporation.





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 non-operating interests. The
      Partnership purchased either all or part of the rights and obligations under
      various oil and gas leases.




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





The
      principal executive offices of the Partnership are located at 6 Desta Drive,
      Suite 6500, Midland, Texas, 79705. The Managing General Partner and its staff,
      together with certain independent consultants used on an "as needed" basis,
      perform various services on behalf of the Partnership, including the selection
      of oil and gas properties and the marketing of production from such properties.
      The Partnership has no employees.





**Operations**


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





During
      2006, the Partnership entered into a farm-out agreement with the Managing
      General Partner through which the Managing General Partner agreed to drill
      four
      wells and perform workovers on 15 wells on the State A A/C 1 and State A A/C
      2
      leases . The partnership retained 75% of its original interest and paid none
      of
      the cost to drill and complete or workover these wells.





**Principal
      Products and Markets**


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.
      During 2006, 74% of the Partnership’s revenues were derived from the sale of oil
      production and 26% were derived from gas production. All oil and gas produced
      from these properties is sold to unrelated third parties in the oil and gas
      business. The Partnership believes that the loss of any of its purchasers would
      not have a material adverse affect on its results of operations due to the
      availability of other purchasers.





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





**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.


3


**Regulation**


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





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





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





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





**Environmental
      Matters**


The
      Partnership’s operations pertaining to oil and gas production and related
      activities are subject to numerous and constantly changing federal, state and
      local laws governing the discharge of materials into the environment or
      otherwise relating to environmental protection. These laws and regulations
      may
      require the acquisition of certain permits prior to or in connection with the
      Partnership’s operations, restrict or prohibit the types, quantities and
      concentration of substances that can be released into the environment, restrict
      or prohibit activities that could impact wetlands, endangered or threatened
      species or other protected areas or natural resources, require some degree
      of
      remedial action to mitigate pollution from former operations, such as pit
      cleanups and plugging abandoned wells, and impose substantial liabilities for
      pollution resulting from the Partnership’s operations. Such laws and regulations
      may substantially increase the cost of the Partnership’s operations and may
      prevent or delay the commencement or continuation of a given project and thus
      generally could have a material adverse effect upon the Partnership’s financial
      condition and operations. Violation of these laws and regulations could result
      in significant fines or penalties. The Partnership may experience accidental
      spills, leaks and other discharges of contaminants, or the Partnership may
      be
      held responsible for past or ongoing contamination in acquired properties.
      The
      Partnership maintains insurance against "sudden and accidental" occurrences,
      which may cover some, but not all, of the environmental risks described above.
      Most significantly, the insurance the Partnership maintains will not cover
      the
      risks described above which occur over a sustained period of time. Further,
      there can be no assurance that such insurance will continue to be available
      to
      cover all such costs or that such insurance will be available at premium levels
      that justify its purchase. The occurrence of a significant event not fully
      insured or indemnified against could have a material adverse effect on the
      Partnership’s financial condition and operations.





The
      Partnership believes that it is in substantial compliance with current
      applicable environmental laws and regulations, and the cost of compliance with
      such laws and regulations has not been material and is not expected to be
      material during 2007. The Partnership does not believe that it will be required
      to incur any material capital expenditures to comply with existing environmental
      requirements. Nevertheless, changes in existing environmental laws and
      regulations or in the interpretations thereof could have a significant impact
      on
      the Partnership’s operations, as well as the oil and gas industry in general.
      For instance, any changes in environmental laws and regulations that result
      in
      more stringent and costly waste handling, storage, transport, disposal or
      clean-up requirements could have a material adverse impact on the Partnership’s
      operations.




4


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





The
      Resource Conservation and Recovery Act (“RCRA”), and analogous state laws,
      impose detailed requirements for the handling, storage, treatment and disposal
      of hazardous and solid wastes. RCRA specifically excludes drilling fluids,
      produced waters, and other wastes associated with the exploration, development,
      or production of crude oil, natural gas or geothermal energy from regulation
      as
      hazardous wastes. However, these wastes may be regulated by the U.S.
      Environmental Protection Agency (“EPA”) or state agencies as solid waste.
      Moreover, many ordinary industrial wastes, such as paint wastes, waste solvents,
      laboratory wastes and waste compressor oils, are regulated as hazardous wastes.
      Although the costs of managing hazardous waste may be significant, the
      Partnership does not expect to experience more burdensome costs than similarly
      situated companies.





The
      Federal Water Pollution Control Act (“Clean Water Act”), and analogous state
      laws, impose restrictions and strict controls with respect to the discharge
      of
      pollutants, including spills and leaks of oil and other substances, into waters
      of the United States. The discharge of pollutants into regulated waters is
      prohibited, except in accordance with the terms of a permit issued by the EPA
      or
      an analogous state agency. Federal and state regulatory agencies can impose
      administrative, civil and criminal penalties for non-compliance with discharge
      permits or other requirements of the Clean Water Act and analogous state laws
      and regulations. The United States Oil Pollution Act of 1990 (“OPA”), and
      similar legislation enacted in Texas, Louisiana and other coastal states,
      addresses oil spill prevention and control and significantly expands liability
      exposure across all segments of the oil and gas industry. OPA and such similar
      legislation and related regulations impose on the Partnership a variety of
      obligations related to the prevention of oil spills and liability for damages
      resulting from such spills. OPA and such similar legislation and related
      regulations impose strict and, with limited exceptions, joint and several
      liabilities upon each responsible party for oil removal costs and a variety
      of
      public and private damages.


Recent
      studies have suggested that emissions of certain gases may be contributing
      to a
      warming of the Earth’s atmosphere. In response to these studies, many nations
      have agreed to limit emissions of “greenhouse gases”, pursuant to the United
      Nations Framework Convention of Climate Change, also known as the “Kyoto
      Protocol”. Methane, a primary component of natural gas, and carbon dioxide, a
      byproduct of the burning of natural gas and oil, and refined petroleum products,
      are “greenhouse gases” regulated by the Kyoto Protocol. Although the United
      States is not participating in the Kyoto Protocol, the current session of
      Congress is considering climate change legislation, with multiple bills having
      been introduced in the Senate that propose to restrict greenhouse gas emissions.
      Several states have already adopted legislation, regulations and/or regulatory
      initiatives to reduce emissions of greenhouse gases. For instance, California
      adopted the “California Global Warming Solutions Act of 2006”, which requires
      the California Air Resources Board to achieve a 25% reduction in emissions
      of
      greenhouse gases from sources in California by 2020. Additionally, on November
      29, 2006, the U.S. Supreme Court heard arguments on and has since begun
      reviewing a decision made by the U.S. Circuit Court of Appeals for the District
      of Columbia in Massachusetts, et al v. EPA, a case in which the appellate court
      held that the EPA had discretion under the Clean Air Act to refuse to regulate
      carbon dioxide emissions from mobile sources. Passage of climate change
      legislation by Congress or a Supreme Court reversal of the appellate decision
      could result in federal regulation of carbon dioxide emissions and other
      greenhouse gases. At this time, it is not possible to accurately estimate how
      potential future laws or regulations addressing greenhouse gas emissions would
      impact the Partnership’s operations or financial condition.





Limited
      partners should be aware that the assessment of liability associated with
      environmental liabilities is not always correlated to the value of a particular
      project. Accordingly, liability associated with the environment under local,
      state, or federal regulations, particularly clean-ups under CERCLA, can exceed
      the value of the Partnership’s investment in the associated site.





**Partnership
      Employees**


The
      Partnership has no employees; however the Managing General Partner and CWEI
      have
      a staff of geologists, engineers, accountants, landmen and clerical staff who
      engage in Partnership activities and operations and perform additional services
      for the Partnership as needed. In addition, the Partnership engages independent
      consultants such as petroleum engineers and geologists as needed.





5


**Item
      1A.** **Risk
      Factors**





There
      are
      many factors that affect the Partnership’s business, some of which are beyond
      the Partnership’s control. The Partnership’s business, financial condition and
      results of operations could be materially adversely affected by any of these
      risks. The risks described below are not the only ones facing the Partnership.
      Additional risks not presently known to the Partnership or that the Partnership
      currently deems immaterial individually or in the aggregate may also impair
      the
      Partnership’s business operations.





**The
      Partnership’s oil and gas reserves will decline as they are produced.**


In
      general, the volume of production from an oil and gas property declines as
      reserves related to that property are depleted. The decline rates depend upon
      reservoir characteristics. The implied life of the Partnership’s proved reserves
      at December 31, 2006 is approximately 9.0 years, based on 2006 production
      levels.





**Volatility
      of oil and gas prices significantly affects the Partnership’s cash flow and
      ability to produce oil and gas economically.**


Historically,
      the markets for oil and gas have been volatile, and the Partnership believes
      that they are likely to continue to be volatile. Significant changes in oil
      and
      gas prices may result from relatively minor changes in the supply of and demand
      for oil and natural gas, market uncertainty and other factors that are beyond
      the Partnership’s control. The Partnership cannot predict, with any degree of
      certainty, future oil and natural gas prices. Changes in oil and natural gas
      prices significantly affect the Partnership’s revenues, operating results,
      profitability and the value of the Partnership’s oil and gas reserves. Those
      prices also affect the amount of cash flow available for distribution to
      partners and the amount of oil and natural gas that the Partnership can produce
      economically.





Changes
      in oil and gas prices impact both the Partnership’s estimated future net revenue
      and the estimated quantity of proved reserves. Price increases may permit
      additional quantities of reserves to be produced economically, and price
      decreases may render uneconomic the production of reserves previously classified
      as proved. Thus, the Partnership may experience material increases and decreases
      in reserve quantities solely as a result of price changes and not as a result
      of
      well performance.





**Information
      concerning the Partnership’s reserves and future net revenues estimates is
      inherently uncertain.**


The
      estimated proved reserve information is based upon reserve reports prepared
      by
      independent engineers. The accuracy of proved reserves estimates and estimated
      future net revenues from such reserves is a function of the quality of available
      geological, geophysical, engineering and economic data and is subject to various
      assumptions, including assumptions required by the SEC relating to oil and
      gas
      prices, drilling and operating expenses, and other matters. Although the
      Partnership believes that the Partnership’s estimated proved reserves represent
      reserves that the Partnership is reasonably certain to recover, actual future
      production, oil and gas prices, revenues, taxes, development expenditures,
      operating expenses and quantities of recoverable oil and gas reserves will
      most
      likely vary from the assumptions and estimates used to determine proved
      reserves. Any significant variance could materially affect the estimated
      quantities and value of the Partnership’s oil and gas reserves, which in turn
      could adversely affect the Partnership’s cash flow and results of operations. In
      addition, the Partnership may adjust estimates of proved reserves to reflect
      production history, results of development, prevailing oil and gas prices and
      other factors, many of which are beyond the Partnership’s control. Downward
      adjustments to the Partnership’s estimated proved reserves could require the
      Partnership to write down the carrying value of the Partnership’s oil and gas
      properties, which would reduce the Partnership’s earnings and partners'
      equity.





The
      present value of proved reserves will not necessarily equal the current fair
      market value of the Partnership’s estimated oil and gas reserves. In accordance
      with the reserve reporting requirements of the SEC, the estimated discounted
      future net cash flows from proved reserves are generally based on prices and
      costs as of the date of the estimate. Actual future prices and costs may be
      materially higher or lower than those as of the date of the estimate. The timing
      of both the production and the expenses with respect to the development and
      production of oil and gas properties will affect the timing of future net cash
      flows from proved reserves and their present value.





**The
      Partnership may not be insured against all of the operating hazards to which
      the
      Partnership’s business is exposed.**


The
      Partnership’s operations are subject to the usual hazards incident to the
      production of oil and gas, such as windstorms, blowouts, cratering, explosions,
      uncontrollable flows of oil, gas or well fluids, fires, severe weather and
      pollution and other environmental risks. These hazards can cause personal injury
      and loss of life, severe damage to and destruction of property and equipment,
      pollution or environmental damage, clean-up responsibilities, regulatory
      investigation and penalties, and suspension of operations which could result
      in
      substantial loss. The Partnership maintains insurance against some, but not
      all,
      of the risks described above. Such insurance may not be adequate to cover losses
      or liabilities. Also, the Partnership cannot be assured of the continued
      availability of insurance at premium levels that justify its
      purchase.





6


**The
      Partnership’s business depends on oil and natural gas transportation facilities,
      most of which are owned by others.**


The
      marketability of the Partnership’s oil and natural gas production depends in
      large part on the availability, proximity and capacity of pipeline systems
      owned
      by third parties. The unavailability of or lack of available capacity on these
      systems and facilities could result in the shut-in of producing wells. Although
      the Partnership has some contractual control over the transportation of the
      Partnership’s product, material changes in these business relationships could
      materially affect the Partnership’s operations. Federal and state regulation of
      oil and natural gas production and transportation, tax and energy policies,
      changes in supply and demand, pipeline pressures, damage to or destruction
      of
      pipelines and general economic conditions could adversely affect the
      Partnership’s ability to produce, gather and transport oil and natural
      gas.





**The
      Partnership’s industry is highly competitive.**


The
      oil
      and gas industry as a whole competes with other industries in supplying the
      energy and fuel requirements of industrial, commercial and individual consumers.
      The price and availability of alternative energy sources could adversely affect
      the Partnership’s revenue.





The
      market for the Partnership’s oil, gas and natural gas liquids production depends
      on factors beyond the Partnership’s control, including domestic and foreign
      political conditions, the overall level of supply of and demand for oil, gas
      and
      natural gas liquids, the price of imports of oil and gas, weather conditions,
      the price and availability of alternative fuels, the proximity and capacity
      of
      gas pipelines and other transportation facilities and overall economic
      conditions.





**Compliance
      with environmental and other government regulations could be costly and could
      negatively impact production.**


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





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





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





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





**Item
      1B.** **Unresolved
      Staff Comments**





Not
      applicable.





7


**Item
      2.** **Properties**





As
      of
      December 31, 2006, the Partnership possessed an interest in oil and gas
      properties located in Eddy and Lea Counties of New Mexico; Andrews, Cherokee,
      Duval, Hockley, Howard, Midland, Panola, Reagan, Upton, Ward and Yoakum Counties
      of Texas. These properties consist of various interests in approximately 476
      wells and units.





**Reserves**


The
      following table sets forth certain information as of December 31, 2006 with
      respect to the Partnership’s estimated proved oil and gas reserves pursuant to
      SEC guidelines and standardized measure of discounted future net cash
      flows.





Proved
                Developed
            
            Proved
            
            TotalProducing
            
            Nonproducing
            
            Undeveloped
            
            ProvedOil
                (Bbls)
            
            
            88,000
            
            
            -
            
            
            -
            
            
            88,000Gas
                (Mcf)
            
            
            226,000
            
            
            -
            
            
            1,000
            
            
            227,000Total
                (BOE)
            
            
            126,000
            
            
            -
            
            
            -
            
            
            126,000Standardized
                measure of discountedfuture
                net cash flows
            
            
            
            
            
            
            
            
            
            
            $
            1,647,000





The
      following table sets forth certain information as of December 31, 2006 regarding
      the Partnership’s proved oil and gas reserves for certain significant
      fields.





Proved
                ReservesTotal
                Oil
            
            Percent
                ofOil
            
            Gas
            
            Equivalent
            
            Total
                Oil(Bbls)
            
            (Mcf)
            
            (BOE)
            
            EquivalentSlaughter
            
            
            48,000
            
            
            -
            
            
            48,000
            
            
            38.1
            %Rhoda
                Walker
            
            
            5,000
            
            
            92,000
            
            
            20,000
            
            
            15.9
            %Jalmat
            
            
            8,000
            
            
            29,000
            
            
            13,000
            
            
            10.3
            %Other
            
            
            27,000
            
            
            106,000
            
            
            45,000
            
            
            35.7
            %Total
            
            
            88,000
            
            
            227,000
            
            
            126,000
            
            
            100.0
            %





The
      estimates of proved reserves at December 31, 2006 and the standardized measure
      of discounted future net cash flows were derived from a report prepared by
      Ryder
      Scott Company, L.P., petroleum consultants. These calculations were prepared
      using standard geological and engineering methods generally accepted by the
      petroleum industry and in accordance with SEC financial accounting and reporting
      standards.





In
      accordance with applicable financial accounting and reporting standards of
      the
      SEC, the estimates of the Partnership’s proved reserves and the standardized
      measure of discounted future net cash flows set forth herein are made using
      oil
      and gas sales prices estimated to be in effect as of the date of such reserve
      estimates and are held constant throughout the life of the properties. Estimated
      quantities of proved reserves and their present value are affected by changes
      in
      oil and gas prices. The average prices utilized for the purposes of estimating
      the Partnership’s proved reserves and the standardized measure of discounted
      future net cash flows as of December 31, 2006 were $53.23 per Bbl of oil
      and natural gas liquids and $5.23 per Mcf of gas, as compared to $56.64 per
      Bbl
      of oil and $10.98 per Mcf of gas as of December 31, 2005.













8


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





Unanticipated
      depletion, if it occurs, will result in lower reserves than previously
      estimated; thus an ultimately lower return for the Partnership. Basic changes
      in
      past reserve estimates occur annually. As new data is gathered during the
      subsequent year, the engineer must revise his earlier estimates. A year of
      new
      information, which is pertinent to the estimation of future recoverable volumes,
      is available during the subsequent year evaluation. In applying industry
      standards and procedures, the new data may cause the previous estimates to
      be
      revised. This revision may increase or decrease the earlier estimated volumes.
      Pertinent information gathered during the year may include actual production
      and
      decline rates, production from offset wells drilled to the same geologic
      formation, increased or decreased water production, workovers, and changes
      in
      lifting costs, among others. Accordingly, reserve estimates are often different
      from the quantities of oil and gas that are ultimately recovered.





**Item
      3.**  **Legal
      Proceedings**





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





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





No
      matter
      was submitted to a vote of security holders during the fourth quarter of 2006
      through the solicitation of proxies or otherwise.







9


**Part
      II**





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





**Market
      Information**


Limited
      partnership interests, or units, in the Partnership were initially offered
      and
      sold for a price of $500. Limited partner units are not traded on any exchange
      and there is no public or organized trading market for them.





**Number
      of Limited Partner Interest Holders**


As
      of
      December 31, 2006 there were 533 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
      quarterly basis. "Net Cash Flow" is defined as "the cash generated by the
      Partnership's investments in producing oil and gas properties, less (i) General
      and Administrative Costs, (ii) Operating Costs, and (iii) any reserves necessary
      to meet current and anticipated needs of the Partnership, as determined in
      the
      sole discretion of the Managing General Partner." During
      2006, distributions were made totaling $331,623, with $298,161 ($26.35 per
      unit)
      distributed to the limited partners and $33,462 to the general
      partners.





**Issuer
      Purchases of Equity Securities**


The
      Managing General Partner has the right, but not the obligation in accordance
      with the obligations set forth in the partnership agreement, to purchase limited
      partnership units should an investor desire to sell. The value of the unit
      is
      determined by adding the sum of (1) current assets less liabilities and (2)
      the
      present value of the future net revenues attributable to proved reserves and
      by
      discounting the future net revenues at a rate not in excess of the prime rate
      charged by Bank One, a division of JP Morgan Chase Bank, N.A. plus one percent
      (1%), which value shall be further reduced by a risk factor discount of no
      more
      than one-third (1/3) to be determined by the Managing General Partner in its
      sole and absolute discretion under the partnership agreement. The following
      table sets forth certain information regarding purchases of limited partnership
      units by the Managing General Partner during the year of 2006.





**Total
                Number****of
                Units**
            
            **Average
                Price****Period**
            
            **Purchased**
            
            **Paid
                Per Unit**January
                2006
            
            
            83
            
            $
            67.55February
                2006
            
            
            -
            
            
            -March
                2006
            
            
            -
            
            
            -April
                2006
            
            
            80
            
            
            76.50May
                2006
            
            
            -
            
            
            -June
                2006
            
            
            -
            
            
            -July
                2006
            
            
            16
            
            
            86.43August
                2006
            
            
            -
            
            
            -September
                2006
            
            
            -
            
            
            -October
                2006
            
            
            -
            
            
            -November
                2006
            
            
            -
            
            
            -December
                2006
            
            
            62
            
            
            81.46TOTALS
            
            
            241
            
            $
            75.35
















10


**Item
      6.**  **Selected
      Financial Data**





The
      following selected financial data for the years ended December 31, 2006,
      2005, 2004, 2003 and 2002 should be read in conjunction with the financial
      statements included in Item 8:





**Years
                ended December 31,****2006**
            
            **2005**
            
            **2004**
            
            **2003**
            
            **2002**Revenues
            
            $
            412,625
            
            $
            459,406
            
            $
            275,491
            
            $
            218,987
            
            $
            110,024Income
                before cumulativeeffect
                of accounting change
            
            
            271,735
            
            
            334,787
            
            
            145,577
            
            
            86,100
            
            
            1,727Net
                income (loss)
            
            
            271,735
            
            
            334,787
            
            
            145,577
            
            
            103,735
            
            
            (273
            )Partners'
                share of net income(loss):General
                partners
            
            
            28,688
            
            
            34,570
            
            
            15,807
            
            
            11,873
            
            
            1,373Limited
                partners
            
            
            243,047
            
            
            300,217
            
            
            129,770
            
            
            91,862
            
            
            (1,646
            )Limited
                partners' income perunit
                before cumulative effectof
                accounting change
            
            
            21.48
            
            
            26.53
            
            
            11.47
            
            
            6.72
            
            
            .03Limited
                partners'net
                income (loss) per unit
            
            
            21.48
            
            
            26.53
            
            
            11.47
            
            
            8.12
            
            
            (.15
            )Limited
                partners'cash
                distributions per unit
            
            
            26.35
            
            
            27.04
            
            
            11.97
            
            
            4.01
            
            
            -Total
                assets
            
            $
            426,228
            
            $
            417,337
            
            $
            407,709
            
            $
            405,882
            
            $
            204,052





11


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





**General**


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





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





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





**Critical
      Accounting Policies**


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





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





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





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







12


**Supplemental
      Information**


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





**Year
                Ended December 31,****2006**
            
            **2005**
            
            **2004**Oil
                production in barrels
            
            
            9,068
            
            
            10,509
            
            
            10,350Gas
                production in mcf
            
            
            29,075
            
            
            29,455
            
            
            29,819Total
                (BOE)
            
            
            13,914
            
            
            15,418
            
            
            15,320Average
                price per barrel of oil
            
            $
            61.88
            
            $
            52.51
            
            $
            38.01Average
                price per mcf of gas
            
            $
            6.78
            
            $
            7.61
            
            $
            6.10Partnership
                distributions
            
            $
            331,623
            
            $
            340,000
            
            $
            150,759Limited
                partner distributions
            
            $
            298,161
            
            $
            306,000
            
            $
            135,488Per
                unit distribution to limited partners
            
            $
            26.35
            
            $
            27.04
            
            $
            11.97Number
                of limited partner units
            
            
            11,316
            
            
            11,316
            
            
            11,316





**Operating
      Results**


The
      following discussion compares our results for the year ended December 31, 2006
      to the two previous years. All references to 2006, 2005 and 2004 within this
      section refer to the respective annual periods.





**Income
      from net profits**


Oil
      and
      gas prices remained high compared to the previous two years. Comparing 2006
      to
      2005, oil and gas sales from net profits interests decreased $17,800, of which
      price variances accounted for a $60,800 increase and production variances
      accounted for a $78,600 decrease. Comparing 2005 to 2004, oil and gas sales
      from
      net profits interests increased $200,800, of which price variances accounted
      for
      a $197,000 increase and production variances accounted for a $3,800
      increase.





Production
      in 2006 (on a BOE basis) was 10% lower than 2005 and 9% lower than 2004. Our
      oil
      production was 14% lower in 2006 than 2005 due primarily to the production
      decline on one property. Our gas production was 1% lower in 2006 than 2005
      due
      primarily to normal production declines.





In
      2006,
      our realized oil price was 18% higher than 2005 and 63% higher than 2004, while
      our realized gas price was 11% lower than 2005 and 11% higher than 2004.
      Historically, the markets for oil and gas have been volatile, and they are
      likely to continue to be volatile. We have very little control over the prices
      we receive for our production at the wellhead since most of our physical
      marketing arrangements are market-sensitive.





Oil
      and
      gas production costs on a BOE basis increased from $20.54 per BOE in 2005 and
      $19.62 per BOE in 2004 to $24.87 per BOE in 2006. The increase in oil and gas
      production costs in 2006 was primarily due to the cost to plug and abandon
      four
      wells that exceeded the asset retirement obligation for those
      wells.





**Expenses**


Depletion
      on a BOE basis increased 54% from 2005 and 34% from 2004. Comparing 2006 to
      2005, depletion expense increased $4,200, of which rate variances accounted
      for
      a $5,300 increase and production variances accounted for a $1,100 decrease.
      Comparing 2005 to 2004, depletion expense decreased $1,600, of which rate
      variances accounted for a $1,700 decrease and production variances accounted
      for
      a $100 increase. Depletion rates are a function of net capitalized costs and
      estimated reserve quantities. The rates for 2007 are expected to be similar
      to
      the 2006 rates.





General
      and administrative (“G&A”) expenses were 10% higher in 2006 than 2005 and 5%
      higher than 2004 due primarily to higher
      professional fees for audit and tax services .





**Texas
      Margin Taxes**


In
      May
      2006, the State of Texas adopted House Bill 3, which modified the state’s
      franchise tax structure, replacing the previous tax based on capital or earned
      surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax
      reports filed on or after January 1, 2008. The Texas margin Tax is computed
      by
      applying the applicable tax rate (1% for the Partnership’s business) to the
      profit margin, which is generally determined by total revenue less either cost
      of goods sold or compensation as applicable. However the Partnership believes,
      based on its interpretation, that the Texas Margin Tax does not apply to the
      Partnership since substantially all of its income is derived from a net profits
      interest.





13


**Liquidity
      and Capital Resources**


Partnership
      distributions during the year ended December 31, 2006 were $331,623, of which
      $298,191 was distributed to the limited partners and $33,462 to the general
      partners. Cumulative cash distributions of $4,261,325 have been made to the
      general and limited partners as of December 31, 2006. As of December 31,
      2006, $3,892,499 or $343.98 per limited partner unit has been distributed to
      the
      limited partners, representing 69% of contributed capital.





Our
      primary source of cash from operating activities is our oil and gas sales,
      net
      of production costs. Cash flow provided by operating activities for
      200 6
      was 22%
      lower than 2005 due to the combined effects of several drivers. A 2% decrease
      in
      oil and gas sales were combined with an increase in production costs. Our only
      use in financing activities is the distribution to partners which was 2% lower
      than 2005.





As
      of
      December 31, 2006,
      the
      Partnership had approximately $85,300 in working capital. The Managing General
      Partner knows of no unusual contractual commitments. Although the Partnership
      held many long-lived properties at inception, because of the restrictions on
      property development imposed by the partnership agreement, the Partnership
      cannot develop its non-producing properties, if any. Without continued
      development, the producing reserves continue to deplete. Accordingly, as the
      Partnership’s properties have matured and depleted, the net cash flows from
      operations for the Partnership has steadily declined, except in periods of
      substantially increased commodity pricing. Maintenance of properties and
      administrative expenses for the Partnership are increasing relative to
      production. As the properties continue to deplete, maintenance of properties
      and
      administrative costs as a percentage of production are expected to continue
      to
      increase.





**Recent
      Accounting Pronouncements**


In
      June
      2006, the Financial Accounting Standards Board (“FASB”) issued FASB
      Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN48”) to
      clarify the manner in which enterprises account for uncertainties in their
      provisions for income taxes. Generally, the standard presented by FIN 48 is
      a
“more likely than not” standard and is intended to enhance the relevancy and
      comparability of financial reporting by companies. FIN 48 is effective for
      fiscal years beginning after December 31, 2006. The adoption of FIN 48 is not
      expected to have an impact on the Partnership’s financial
      statements.





**Item
      7A.** **Quantitative
      and Qualitative Disclosures About Market Risk**





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










14


**Item
      8.** **Financial
      Statements and Supplementary Data**





**Index
      to Financial Statements**





**Page**Report
                of Independent Registered Public Accounting
                Firm
            
            16Balance
                Sheets
            
            17Statements
                of
                Operations
            
            18Statements
                of Changes in Partners' Equity
                (Deficit)
            
            19Statements
                of Cash Flows
            
            20Notes
                to Financial Statements
            
            21











15





























**REPORT
      OF INDEPENDENT REGISTERED**


**PUBLIC
      ACCOUNTING FIRM**





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, 2006 and 2005, and the related statements of
      operations, changes in partners’ equity (deficit), and cash flows for each of
      the years in the three-year period ended December 31, 2006. These financial
      statements are the responsibility of the Partnership’s management. Our
      responsibility is to express an opinion on these financial statements based
      on
      our audits.





We
      conducted our audits  in
      accordance with the standards of the Public Company Accounting Oversight Board
      (United States). Those standards require that we plan and perform the audit
      to
      obtain reasonable assurance about whether the financial statements are free
      of
      material misstatement. An audit includes examining, on a test basis, evidence
      supporting the amounts and disclosures in the financial statements. An audit
      also includes assessing the accounting principles used and significant estimates
      made by management, as well as evaluating the overall financial statement
      presentation. We believe that our audits provide a reasonable basis for our
      opinion.





In
      our
      opinion, the financial statements  referred
      to above present fairly, in all material respects, the financial position of Southwest
      Royalties Institutional Income Fund X-A, L.P. as
      of
      December 31, 2006 and 2005, and the results of its operations and its cash
      flows
      for each of the years in the three-year period ended December 31, 2006, in
      conformity with U.S. generally accepted accounting principles.














KPMG
      LLP


Dallas,
      Texas


April
      5,
      2007







16


**Southwest
      Royalties InstitutionalIncome Fund X-A,
      L.P.**


**(a
      Delaware limited partnership)**


**Balance
      Sheets**








**December
                31,****2006**
            
            **2005****Assets**Current
                assets:Cash
                and cash equivalents
            
            $
            18,571
            
            $
            71,661Receivable
                from Managing General Partner
            
            
            55,021
            
            
            59,321New
                Mexico income tax deposits
            
            
            11,674
            
            
            7,539Other
            
            
            -
            
            
            103Total
                current assets
            
            
            85,266
            
            
            138,624Oil
                and gas properties - using the full-cost
                method of accounting
            
            
            4,377,076
            
            
            4,299,680Less
                accumulated depreciation,depletion
                and amortization
            
            
            4,036,114
            
            
            4,020,967Net
                oil and gas properties
            
            
            340,962
            
            
            278,713$
            426,228
            
            $
            417,337**Liabilities
                and Partners' Equity (Deficit)**Asset
                retirement obligation
            
            $
            239,842
            
            $
            171,063Partners'
                equity (deficit):General
                Partner
            
            
            (8,190
            )
            
            (3,416
            )Limited
                partners
            
            
            194,576
            
            
            249,690Total
                partners' equity
            
            
            186,386
            
            
            246,274$
            426,228
            
            $
            417,337

































































The
      accompanying notes are an integral


part
      of
      these financial statements.


17


**Southwest
      Royalties Institutional Income Fund X-A,L.P.**


**(a
      Delaware limited partnership)**


**Statements
      of Operations**








**Years
                ended December 31,****2006**
            
            **2005**
            
            **2004****Revenues**Income
                from net profits interests
            
            $
            412,262
            
            $
            459,406
            
            $
            274,552Other
            
            
            363
            
            
            -
            
            
            939412,625
            
            
            459,406
            
            
            275,491**Expenses**Depreciation,
                depletion and amortization
            
            
            15,147
            
            
            10,915
            
            
            12,486Accretion
                expense
            
            
            13,926
            
            
            11,749
            
            
            10,438General
                and administrative
            
            
            111,817
            
            
            101,955
            
            
            106,990140,890
            
            
            124,619
            
            
            129,914Net
                income
            
            $
            271,735
            
            $
            334,787
            
            $
            145,577Net
                income allocated to:Managing
                General Partner
            
            $
            25,819
            
            $
            31,113
            
            $
            14,226General
                Partner
            
            $
            2,869
            
            $
            3,457
            
            $
            1,581Limited
                partners
            
            $
            243,047
            
            $
            300,217
            
            $
            129,770Per
                limited partner unit
            
            $
            21.48
            
            $
            26.53
            
            $
            11.47













































































The
      accompanying notes are an integral


part
      of
      these financial statements.


18


**Southwest
      Royalties Institutional Income FundX-A,
      L.P.**


**(a
      Delaware limited partnership)**


**Statements
      of Changes in Partners' Equity (Deficit)**


**Years
      ended December 31, 2006, 2005 and 2004**








**General**
            
            **Limited****Partners**
            
            **Partners**
            
            **Total**Balance
                at December 31, 2003
            
            $
            (4,522
            )
            $
            261,191
            
            $
            256,669Net
                income
            
            
            15,807
            
            
            129,770
            
            
            145,577Distributions
            
            
            (15,271
            )
            
            (135,488
            )
            
            (150,759
            )Balance
                at December 31, 2004
            
            
            (3,986
            )
            
            255,473
            
            
            251,487Net
                income
            
            
            34,570
            
            
            300,217
            
            
            334,787Distributions
            
            
            (34,000
            )
            
            (306,000
            )
            
            (340,000
            )Balance
                at December 31, 2005
            
            
            (3,416
            )
            
            249,690
            
            
            246,274Net
                income
            
            
            28,688
            
            
            243,047
            
            
            271,735Distributions
            
            
            (33,462
            )
            
            (298,161
            )
            
            (331,623
            )Balance
                at December 31, 2006
            
            $
            (8,190
            )
            $
            194,576
            
            $
            186,386

























































































The
      accompanying notes are an integral


part
      of
      these financial statements.


19


**Southwest
      Royalties InstitutionalIncome Fund X-A,
      L.P.**


**(a
      Delaware limited partnership)**


**Statements
      of Cash Flows**








**Years
                ended December 31,****2006**
            
            **2005**
            
            **2004**Cash
                flows from operating activities:Cash
                received from net profits interests
            
            $
            389,987
            
            $
            458,045
            
            $
            241,478Cash
                paid for administrative fees and generaland
                administrative overhead
            
            
            (111,817
            )
            
            (101,955
            )
            
            (106,990
            )Interest
                received
            
            
            363
            
            
            -
            
            
            -Other
            
            
            -
            
            
            -
            
            
            939Net
                cash provided by operating activities
            
            
            278,533
            
            
            356,090
            
            
            135,427Cash
                flows from financing activities:Distributions
                to partners
            
            
            (331,623
            )
            
            (340,000
            )
            
            (150,759
            )Decrease
                in distributions payable
            
            
            -
            
            
            (115
            )
            
            -Net
                cash used in financing activities
            
            
            (331,623
            )
            
            (340,115
            )
            
            (150,759
            )Net
                (decrease) increase in cash and cash equivalents
            
            
            (53,090
            )
            
            15,975
            
            
            (15,332
            )Beginning
                of year
            
            
            71,661
            
            
            55,686
            
            
            71,018End
                of year
            
            $
            18,571
            
            $
            71,661
            
            $
            55,686Reconciliation
                of net income to net cashprovided
                by operating activities:Net
                income
            
            $
            271,735
            
            $
            334,787
            
            $
            145,577Adjustments
                to reconcile net income tonet
                cash provided by operating activities:Depreciation,
                depletion and amortization
            
            
            15,147
            
            
            10,915
            
            
            12,486Accretion
                expense
            
            
            13,926
            
            
            11,749
            
            
            10,438Settlement
                of asset retirement obligationsfor
                plugged and abandoned wells
            
            
            (22,543
            )
            
            (6,772
            )
            
            (3,465
            )Decrease
                (increase) in receivables and deposits
            
            
            268
            
            
            5,411
            
            
            (29,609
            )Net
                cash provided by operating activities
            
            $
            278,533
            
            $
            356,090
            
            $
            135,427Noncash
                investing and financing activities:Increase
                in oil and gas properties -SFAS
                No. 143
            
            $
            77,396
            
            $
            9,979
            
            $
            36
































The
      accompanying notes are an integral


part
      of
      these financial statements.


20


**SouthwestRoyalties Institutional Income FundX-A,
      L.P.**


**(a
      Delaware limited partnership)**





**Notes
      to Financial Statements**





**1.**
            **Organization**


Southwest
      Royalties Institutional Income Fund X-A, 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., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as
      the
      Managing General Partner. Revenues, costs and expenses are allocated as
      follows:





Limited
            
            GeneralPartners
            
            PartnersInterest
                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 amortizationof
                oil and gas properties
            100%
            
            -All
                other costs
            90%
            
            10%




(1)
            All
                organization costs in excess of 3% of initial capital contributions
                will
                be paid by the Managing General Partner and will be treated as a
                capital
                contribution. The Partnership paid the Managing General Partner an
                amount
                equal to 3% of initial capital contributions for such organization
                costs.





(2)
            Administrative
                costs in any year, which exceed 2% of capital contributions shall
                be paid
                by the Managing General Partner and will be treated as a capital
                contribution.





**2.**
            **Summary
                of Significant Accounting
                Policies**





*Oil
      and Gas Properties*


Oil
      and
      gas properties are accounted for at cost under the full-cost method. Under
      this
      method, all productive and nonproductive costs incurred in connection with
      the
      acquisition, exploration and development of oil and gas reserves are
      capitalized. Gain or loss on the sale of oil and gas properties is not
      recognized unless significant oil and gas reserves are involved.





Should
      the net capitalized costs exceed the estimated present value of oil and gas
      reserves, discounted at 10%, such excess costs would be charged to current
      expense. As of December 31, 2006, 2005 and 2004 the net capitalized costs did
      not exceed the estimated present value of oil and gas reserves.





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





The
      Partnership recognizes income from its net profits interest in oil and gas
      property on an accrual basis, while the quarterly cash distributions of the
      net
      profits interest are based on a calculation of actual cash received from oil
      and
      gas sales, net of expenses incurred during that quarterly period. If the net
      profits interest calculation results in expenses incurred exceeding the oil
      and
      gas income received during a quarter, no cash distribution is due to the
      Partnership's net profits interest until the deficit is recovered from future
      net profits. The Partnership accrues a quarterly loss on its net profits
      interest provided there is a cumulative net amount due for accrued revenue
      as of
      the balance sheet date. As of December 31, 2006, there were no timing
      differences which resulted in a deficit net profit interest.




21


**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.
      The
      Partnership’s depletion calculation and full-cost ceiling test for oil and gas
      properties uses oil and gas reserves estimates, which are inherently imprecise.
      Actual results could differ from those estimates.





*Syndication
      Costs*


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





*Environmental
      Costs*


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





*Revenue
      Recognition*


The
      Partnership recognizes oil and gas sales when delivery to the purchaser has
      occurred and title has transferred. This occurs when production has been
      delivered to a pipeline or transport vehicle.





*Gas
      Balancing*


The
      Partnership utilizes the sales method of accounting for gas-balancing
      arrangements. Under this method the Partnership recognizes sales revenue on
      all
      gas sold. As of December 31, 2006 and 2005, there were no significant amounts
      of
      imbalance in terms of units or 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, 2006 and 2005 is $21,456 less than and
      $225,446 more than, respectively that shown on the accompanying Balance Sheets
      in accordance with generally accepted accounting principles.





*Cash
      and Cash Equivalents*


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





*Number
      of Limited Partner Units*


As
      of
      December 31, 2006, 2005 and 2004, there were 11,316 limited partner units
      outstanding held by 533, 548 and 564 partners.





*Concentrations
      of Credit Risk*


The
      Partnership is subject to credit risk for amounts due from its customers.
      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.




22


**Southwest
      Royalties Institutional Income Fund X-A, L.P.**


**(a
      Delaware limited partnership)**





**Notes
      to Financial Statements**





**2.**
            **Summary
                of Significant Accounting Policies -
                continued**





*Fair
      Value of Financial Instruments*


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





*Net
      Income per limited partnership unit*


The
      net
      income per limited partnership unit is calculated by using the number of
      outstanding limited partnership units.





*Recent
      Accounting Pronouncements*


In
      June
      2006, the Financial Accounting Standards Board (“FASB”) issued FASB
      Interpretation No. 48 “Accounting for Uncertainty in Income Taxes” (“FIN48”) to
      clarify the manner in which enterprises account for uncertainties in their
      provisions for income taxes. Generally, the standard presented by FIN 48 is
      a
“more likely than not” standard and is intended to enhance the relevancy and
      comparability of financial reporting by companies. FIN 48 is effective for
      fiscal years beginning after December 31, 2006. The adoption of FIN 48 is not
      expected to have an impact on the Partnership’s financial
      statements.





**3.** **Abandonment
      Obligations**


The
      Partnership follows the provisions of Statement of Financial Accounting
      Standards No. 143 “Accounting for Asset Retirement Obligations” (“SFAS 143”), as
      amended.  SFAS 143 requires the Partnership to recognize a liability for
      the present value of all legal obligations associated with the retirement of
      tangible, long-lived assets and capitalize an equal amount as a cost of the
      asset.  The cost associated with the abandonment obligations, along with
      any estimated salvage value, is included in the computation of depreciation,
      depletion and amortization.





Changes
      in abandonment obligations for 2006 and 2005 are as follows:





**2006**
            
            **2005**Beginning
                of year
            
            $
            171,063
            
            $
            156,107Additional
                abandonment obligations from new wells
            
            
            123
            
            
            -Reduction
                of obligations due to farm-outs
            
            
            (710
            )
            
            -Reduction
                of obligations due to wells plugged and abandoned
            
            
            (22,543
            )
            
            (6,772
            )Accretion
                expense
            
            
            13,926
            
            
            11,749Revisions
                of previous estimates
            
            
            77,983
            
            
            9,979End
                of year
            
            $
            239,842
            
            $
            171,063







23


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





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





As
      of
      December 31, 2006, 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 the Partnership’s
      financial condition and operations. 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 the Partnership's properties.





In
      May
      2006, the State of Texas adopted House Bill 3, which modified the state’s
      franchise tax structure, replacing the previous tax based on capital or earned
      surplus with a margin tax (the “Texas Margin Tax”) effective with franchise tax
      reports filed on or after January 1, 2008. The Texas margin Tax is computed
      by
      applying the applicable tax rate (1% for the Partnership’s business) to the
      profit margin, which is generally determined by total revenue less either cost
      of goods sold or compensation as applicable. However the Partnership believes,
      based on its interpretation, that the Texas Margin Tax does not apply to the
      Partnership since substantially all of its income is derived from a net profits
      interest.





**5.**
            **Related
                Party Transactions**


A
      significant portion of the oil and gas properties in which the Partnership
      has
      an interest are purchased from and operated by the Managing General Partner.
      As
      provided for in the operating agreement for each respective oil and gas property
      in which the Partnership has an interest, the operator is paid an amount for
      administrative overhead attributable to operating such properties, with such
      amounts to Southwest Royalties, Inc. as operator approximating $47,100, $43,300
      and $39,500 for the years ended December 31, 2006, 2005, and 2004, respectively.
      The amounts for administrative overhead attributable to operating the
      partnership properties have been deducted from gross oil and gas revenues in
      the
      determination of net profit interest. In addition, the Managing General Partner
      and certain officers and employees may have an interest in some of the
      properties that the Partnership also participates.





Southwest
      Royalties, Inc., the Managing General Partner, was paid $90,000 during 2006,
      2005 and 2004, as an administrative fee, for indirect general and administrative
      overhead expenses. The administrative fees are included in general and
      administrative expense on the statement of operations.





Receivables
      from Southwest Royalties, Inc., the Managing General Partner, of approximately
      $55,000 and $59,300 are from oil and gas production, net of lease operating
      costs and production taxes, as of December 31, 2006 and 2005,
      respectively.










24


**Southwest
      Royalties Institutional Income Fund X-A, L.P.**


**(a
      Delaware limited partnership)**





**Notes
      to Financial Statements**





**6.**
            **Oil
                and Gas Reserves Information
                (unaudited)**


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





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





Oil
                (bbls)
            
            Gas
                (mcf)**Total
                Proved -**January
                1, 2004
            
            
            117,000
            
            
            255,000Revisions
                of previous estimates
            
            
            1,000
            
            
            85,000Production
            
            
            (10,000
            )
            
            (30,000
            )December
                31, 2004
            
            
            108,000
            
            
            310,000Revisions
                of previous estimates
            
            
            58,000
            
            
            (34,000
            )Production
            
            
            (11,000
            )
            
            (29,000
            )December
                31, 2005
            
            
            155,000
            
            
            247,000Revisions
                of previous estimates
            
            
            (58,000
            )
            
            9,000Production
            
            
            (9,000
            )
            
            (29,000
            )December
                31, 2006
            
            
            88,000
            
            
            227,000**Proved
                developed reserves -**December
                31, 2004
            
            
            108,000
            
            
            310,000December
                31, 2005
            
            
            155,000
            
            
            247,000December
                31, 2006
            
            
            88,000
            
            
            226,000





Net
      revisions of 56,000 BOE in 2006 consisted of approximately 18,000 BOE of
      downward revisions attributable to the effects of lower product prices on the
      estimated quantities of proved reserves, and downward revisions of approximately
      38,000 BOE attributable to well performance primarily from properties in Petrox
      field of West Texas. Net revisions of 52,000 BOE in 2005 consisted of
      approximately 29,000 BOE of upward revisions attributable to the effects of
      higher product prices on the estimated quantities of proved reserves, and upward
      revisions of approximately 23,000 BOE attributable to well performance primarily
      from properties in Anita field of West Texas.





Oil
      price
      adjustments were made in the individual evaluations to reflect oil quality,
      gathering and transportation costs. The standardized measure as of December
      31,
      2006, 2005 and 2004 reflects an average oil price of $53.23, $56.64 and $39.99
      per barrel.





Gas
      price
      adjustments were made in the individual evaluations to reflect BTU content,
      gathering and transportation costs and gas processing and shrinkage. The
      standardized measure as of December 31, 2006, 2005 and 2004 reflects an average
      natural gas price of $5.23, $10.98 and $5.71 per Mcf.




25


**Southwest
      Royalties Institutional Income Fund X-A, L.P.**


**(a
      Delaware limited partnership)**





**Notes
      to Financial Statements**





**6.**
            **Oil
                and Gas Reserves Information (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 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.





The
      standardized measure of discounted future net cash flows relating to proved
      oil
      and gas reserves at December 31, 2006, 2005 and 2004 is presented
      below:





**2006**
            
            **2005**
            
            **2004**Future
                cash inflows
            
            $
            5,795,000
            
            $
            11,540,000
            
            $
            6,068,000Production,
                development and abandonment costs
            
            
            2,731,000
            
            
            4,744,000
            
            
            2,950,000Future
                net cash flows
            
            
            3,064,000
            
            
            6,796,000
            
            
            3,118,00010%
                annual discount forestimated
                timing of cash flows
            
            
            1,417,000
            
            
            3,532,000
            
            
            1,596,000Standardized
                measure ofdiscounted
                future net cash flows
            
            $
            1,647,000
            
            $
            3,264,000
            
            $
            1,522,000





Changes
      in the standardized measure of discounted future net cash flows relating to
      proved reserves for the years ended December 31, 2006, 2005 and 2004 are as
      follows:





**2006**
            
            **2005**
            
            **2004**Sales
                of oil and gas produced, net of production costs
            
            $
            (412,000
            )
            $
            (459,000
            )
            $
            (275,000
            )Changes
                in prices and production costs
            
            
            (1,029,000
            )
            
            1,127,000
            
            
            178,000Changes
                of production rates (timing) and others
            
            
            237,000
            
            
            51,000
            
            
            (58,000
            )Revisions
                of previous quantities estimates
            
            
            (739,000
            )
            
            871,000
            
            
            145,000Accretion
                of discount
            
            
            326,000
            
            
            152,000
            
            
            139,000Discounted
                future net cash flows -Beginning
                of year
            
            
            3,264,000
            
            
            1,522,000
            
            
            1,393,000End
                of year
            
            $
            1,647,000
            
            $
            3,264,000
            
            $
            1,522,000










26


**Southwest
      Royalties Institutional Income Fund X-A, L.P.**


**(a
      Delaware limited partnership)**





**Notes
      to Financial Statements**





**7.**
            **Selected
                Quarterly Financial Results -
                (unaudited)**





**Quarter****First**
            
            **Second**
            
            **Third**
            
            **Fourth**2006:Total
                revenues
            
            $
            132,756
            
            $
            131,796
            
            $
            86,300
            
            $
            61,773Total
                expenses
            
            
            33,714
            
            
            39,159
            
            
            33,263
            
            
            34,754Net
                income
            
            $
            99,042
            
            $
            92,637
            
            $
            53,037
            
            $
            27,019Net
                income per limited partners unit
            
            $
            7.85
            
            $
            7.34
            
            $
            4.20
            
            $
            2.09





**Quarter****First**
            
            **Second**
            
            **Third**
            
            **Fourth**2005:Total
                revenues
            
            $
            82,014
            
            $
            107,511
            
            $
            133,615
            
            $
            136,266Total
                expenses
            
            
            31,823
            
            
            32,682
            
            
            29,672
            
            
            30,442Net
                income
            
            $
            50,191
            
            $
            74,829
            
            $
            103,943
            
            $
            105,824Net
                income per limited partners unit
            
            $
            3.97
            
            $
            5.93
            
            $
            8.24
            
            $
            8.39






















27


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





None





**Item
      9A.** **Controls
      and Procedures**





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





With
      respect to these disclosure controls and procedures:





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





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





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





*Internal
      Control Over Financial Reporting*


There
      has
      not been any change in the Partnership’s internal control over financial
      reporting that occurred during the quarter ended December 31, 2006 that has
      materially affected, or is reasonably likely to materially affect, its internal
      control over financial reporting.





**Item
      9B.** **Other
      Information**





None.







28


**Part
      III**





**Item
      10.** **Directors,
      Executive Officers and Corporate Governance**





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





CLAYTON
      W. WILLIAMS, age 75, is Chairman of the Board and a director of the Managing
      General Partner, having served in this capacity since May 2004. Mr. Williams
      also serves as Chairman of the Board, President, Chief Executive Officer and
      a
      director of CWEI.





L.
      PAUL
      LATHAM, age 55, is President, Chief Executive Officer and a director of the
      Managing General Partner, having served in this capacity since May 2004. Mr.
      Latham also serves as Executive Vice President, Chief Operating Officer and
      a
      director of CWEI.





MEL
      G.
      RIGGS, age 52, is Vice President, Chief Financial Officer, Treasurer and a
      director of the Managing General Partner, having served in this capacity since
      May 2004. Mr. Riggs also serves as Senior Vice President and Chief Financial
      Officer of CWEI.





RANDY
      HOWARD, age 51, is Vice President - of the Managing General Partner, having
      served in this capacity since March 2006.





ROBERT
      C.
      LYON, age 70, is Vice President - Gas Gathering and Marketing of the Managing
      General Partner, having served in this capacity since May 2004. Mr. Lyon also
      serves as Vice President - Gas Gathering and Marketing of CWEI.





T.
      MARK
      TISDALE, age 50, is Vice President and Secretary of the Managing General
      Partner, having served in this capacity since May 2004. Mr. Tisdale also serves
      as Vice President and General Counsel of CWEI.





**Code
      of Ethics**





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





**Item
      11.** **Executive
      Compensation**





The
      Partnership does not employ any directors, executive officers or employees.
      The
      Managing General Partner receives an administrative fee for the management
      of
      the Partnership. The Managing General Partner received $90,000 during 2006,
      2005
      and 2004 as an annual administrative fee. The executive officers of the Managing
      General Partner do not receive any form of compensation, from the Partnership;
      instead, their compensation is paid solely by Southwest. The executive officers,
      however, may occasionally perform administrative duties for the Partnership
      but
      receive no additional compensation for this work.





29


**Item
      12.** **Security
      Ownership of Certain Beneficial Owners and Management and Related Stockholder
      Matters**





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





Through
      repurchase offers to the limited partners, the Managing General Partner owns
      982
      limited partner units, a 7.8% limited partner interest. The Managing General
      Partner's total percentage interest ownership in the Partnership is
      17.8%.





No
      officer or director of the Managing General Partner directly owns units in
      the
      Partnership. CWEI is considered to be a beneficial owner of the limited partner
      units acquired by the Managing General Partner by virtue of its ownership of
      the
      Managing General Partner. Beneficial ownership is determined in accordance
      with
      the rules of the Securities and Exchange Commission and includes voting or
      investment power with respect to the limited partner units.





**Item
      13.** **Certain
      Relationships and Related Transactions, and Director
      Independence**





In
      2006,
      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 its affiliates may be working
      interest owners in an oil and gas property in which the Partnership also has
      a
      net profits interest. Certain properties in which the Partnership has an
      interest are operated by the Managing General Partner, who was paid
      approximately $47,100 for administrative overhead attributable to operating
      such
      properties during 2006.





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





**Item
      14.** **Principal
      Accounting Fees and Services**





The
      following table presents fees for professional audit services rendered by KPMG
      LLP for the audit of the Partnership’s annual financial statements for the years
      ended December 31, 2006 and 2005 and fees billed for other services rendered
      by
      KPMG during those periods.





**For
                the Year Ended December 31,**
            
            **2006**
            
            **2005**Audit
                Fees
            
            $
            15,084
            
            $
            13,303Audit
                Related Fees
            
            
            -
            
            
            -Tax
                Fees
            
            
            -
            
            
            -All
                Other Fees
            
            
            -
            
            
            -TOTAL
            
            $
            15,084
            
            $
            13,303





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











30


**Part
      IV**








**Item
      15.** **Exhibits
      and Financial Statement Schedules**





(a)
            (1)
            Financial
                Statements:Included
                in Part II of this reportReport
                of Independent Registered Public Accounting FirmBalance
                SheetsStatements
                of OperationsStatements
                of Changes in Partners' Equity (Deficit)Statements
                of Cash FlowsNotes
                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.)31.1
            Rule
                13a-14(a)/15d-14(a) Certification31.2
            Rule
                13a-14(a)/15d-14(a) Certification32.1
            Certification
                of Chief Executive Officer and Chief Financial Officer Pursuant to
                18
                U.S.C. Section 1350, as adopted Pursuant to Section 906 of the
                Sarbanes-Oxley Act of 2002


31


**Glossary
      of Oil and Gas Terms**


The
      following are abbreviations and definitions of terms commonly used in the oil
      and gas industry that are used in this filing. All volumes of natural gas
      referred to herein are stated at the legal pressure base to the state or area
      where the reserves exit and at 60 degrees Fahrenheit and in most instances
      are
      rounded to the nearest major multiple.





*Bbl.* One
      stock
      tank barrel, or 42 United States gallons liquid volume.





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





*Developmental
      well.* A
      well
      drilled within the proved area of an oil or natural gas reservoir to the depth
      of a stratigraphic horizon known to be productive.





*Exploratory
      well.* A
      well
      drilled to find and produce oil or gas in an unproved area to find a new
      reservoir in a field previously found to be productive of oil or natural gas
      in
      another reservoir or to extend a known reservoir.





*Farm-out
      arrangement.* An
      agreement whereby the owner of a leasehold or working interest agrees to assign
      his interest in certain specific acreage to an assignee, retaining some
      interest, such as an overriding royalty interest, subject to the drilling of
      one
      (1) or more wells or other specified performance by the assignee.





*Field.* An
      area
      consisting of a single reservoir or multiple reservoirs all grouped on or
      related to the same individual geological structural feature and/or
      stratigraphic condition.





*Mcf.* One
      thousand cubic feet.





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





*Oil.* Crude
      oil, condensate and natural gas liquids.





*Overriding
      royalty interest* .
      Interests that are carved out of a working interest, and their duration is
      limited by the term of the lease under which they are created.





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










32


*Production
      costs.* Costs
      incurred to operate and maintain wells and related equipment and facilities,
      including depreciation and applicable operating costs of support equipment
      and
      facilities and other costs of operating and maintaining those wells and related
      equipment and facilities.





*Proved
      Area* .
      The
      part of a property to which proved reserves have been specifically
      attributed.





*Proved
      developed oil and gas reserves* .
      Proved
      oil and gas reserves that can be expected to be recovered from existing wells
      with existing equipment and operating methods.





*Proved
      properties* .
      Properties with proved reserves.





*Proved
      oil and gas reserves.* The
      estimated quantities of crude oil, natural gas, and natural gas liquids with
      geological and engineering data that demonstrate with reasonable certainty
      to be
      recoverable in future years from known reservoirs under existing economic and
      operating conditions, i.e., prices and costs as of the date the estimate is
      made.





*Proved
      undeveloped reserves.* Proved
      oil and gas reserves that are expected to be recovered from new wells on
      undrilled acreage, or from existing wells where a relatively major expenditure
      is required for recompletion.





*Reservoir.* A
      porous
      and permeable underground formation containing a natural accumulation of
      producible oil or gas that is confined by impermeable rock or water barriers
      and
      is individual and separate from other reservoirs.





*Royalty
      interest.* An
      interest in an oil and natural gas property entitling the owner to a share
      of
      oil or natural gas production free of costs of production.





*Working
      interest.* The
      operating interest that gives the owner the right to drill, produce and conduct
      operating activities on the property and a share of production.





*Workover.* Operations
      on a producing well to restore or increase production.










33


**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 FundX-A,
                L.P., a Delaware limited partnershipBy:
            Southwest
                Royalties, Inc., ManagingGeneral
                PartnerBy:
            /s/
                L. Paul LathamL.
                Paul LathamPresident
                and Chief Executive OfficerDate:
            April
                5, 2007





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





/s/
                Clayton W Williams
            
            /s/
                L. Paul LathamClayton
                W. Williams, Chairman of the Board
            
            L.
                Paul Latham, President and a Directorand
                a DirectorDate:April
                5, 2007
            
            Date:April
                5, 2007/s/
                Mel G. RiggsMel
                G. Riggs, Vice President - Finance,Treasurer
                and a DirectorDate:April
                5, 2007