Unassociated Document

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

¨ 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 0-19585

Southwest Oil & Gas Income Fund X-B, L.P.

(Exact name of registrant as specified in

its limited partnership agreement)

Delaware		75-2332176
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)

6 Desta Drive, Suite 6500, Midland, Texas		79705
(Address of principal executive office)		(Zip Code)

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

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

None

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

limited partnership interests

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.	¨ Yes	x No

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

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

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

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

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

¨ Yes

x No

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.

Table of Contents

		Page
Part I
Item 1.	Business	3

Item 1A.	Risk Factors	6

Item 1B.	Unresolved Staff Comments	7

Item 2.	Properties	8

Item 3.	Legal Proceedings	9

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

Part II
Item 5.	Market for Registrant's Common Equity, Related
	Stockholder Matters and Issuer Purchases of Equity Securities	10

Item 6.	Selected Financial Data	11

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

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	14

Item 8.	Financial Statements and Supplementary Data	15

Item 9.	Changes in and Disagreements with Accountants
	on Accounting and Financial Disclosure	28

Item 9A.	Controls and Procedures	28

Item 9B.	Other Information	28

Part III
Item 10.	Directors, Executive Officers and Corporate Governance	29

Item 11.	Executive Compensation	29

Item 12.	Security Ownership of Certain Beneficial Owners and Management and
	Related Stockholder Matters	30

Item 13.	Certain Relationships and Related Transactions, and Director Independence	30

Item 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

Part I

Item 1. Business

General

Southwest Oil & Gas Income Fund X-B, L.P. (the "Partnership" or "Registrant") was organized as a Delaware limited partnership on November 27, 1990. The offering of limited partnership interests began December 1, 1990 as part of a shelf offering registered under the name Southwest Oil & Gas 1990-91 Income Program (the "Program"). Minimum capital requirements for the Partnership were met on March 1, 1991, with the offering of limited partnership interests concluding September 30, 1991. 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 working interests in oil and gas properties. 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, Marketing and Distribution

The Partnership has acquired and holds working interests in oil and gas properties located in Arkansas, New Mexico and Texas. During 2006, 75% of the Partnership’s revenues were derived from the sale of oil production and 25% were derived from gas production. All activities of the Partnership are confined to the continental United States. All oil and gas produced from these properties is sold to unrelated third parties in the oil and gas business. The 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 interests in producing oil and gas properties, it is not subject to competition from other oil and gas property purchasers. See Item 2, Properties.

Factors that may adversely affect the Partnership include delays in completing arrangements for the sale of production, availability of a market for production, rising operating costs of producing oil and gas and complying with applicable water and air pollution control statutes, increasing costs and difficulties of transportation, and marketing of competitive fuels. Moreover, domestic oil and gas must compete with imported oil and gas and with coal, atomic energy, hydroelectric power and other forms of energy.

Regulation

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

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

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

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

Environmental Matters

The Partnership’s operations pertaining to oil and gas production and related activities are subject to numerous and constantly changing federal, state and local laws governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may require the acquisition of certain permits prior to or in connection with 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.

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.

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 10.4 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.

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.

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.

Item 2. Properties

As of December 31, 2006, the Partnership possessed an interest in oil and gas properties located in Columbia County of Arkansas; Eddy and Lea Counties of New Mexico; and Duval, Midland, Schleicher, Ward and Winkler Counties of Texas. These properties consist of various interests in approximately 164 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		Total
	Producing		Nonproducing		Undeveloped		Proved
Oil (Bbls)		118,000		-		27,000		145,000
Gas (Mcf)		199,000		-		107,000		306,000
Total (BOE)		151,000		-		45,000		196,000

Standardized measure of discounted
future net cash flows							$	3,108,000

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 Reserves
					Total Oil		Percent of
	Oil		Gas		Equivalent		Total Oil
	(Bbls)		(Mcf)		(BOE)		Equivalent
Vacuum		74,000		49,000		82,000		41.8	%
Malaga		12,000		138,000		35,000		17.9	%
Petrox		34,000		1,000		34,000		17.3	%
Jalmat		16,000		60,000		26,000		13.3	%
Other		9,000		58,000		19,000		9.7	%
Total		145,000		306,000		196,000		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 $58.42 per Bbl of oil and natural gas liquids and $4.66 per Mcf of gas, as compared to $59.75 per Bbl of oil and $9.91 per Mcf of gas as of December 31, 2005.

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.

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 517 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 $636,698, with $573,104 ($52.63 per unit) distributed to the limited partners and $63,594 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		20	$	96.93
February 2006		-		-
March 2006		-		-
April 2006		12		106.20
May 2006		-		-
June 2006		-		-
July 2006		-		-
August 2006		-		-
September 2006		-		-
October 2006		-		-
November 2006		-		-
December 2006		6		134.05
TOTALS		38	$	105.72

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	$	1,040,125	$	1,058,893	$	801,189		$	553,838		$	444,206

Income (loss) from continuing
operations		543,105		523,823		351,069			(100,970	)		107,112

Results from discontinued operations		-		-		(27,318	)		796,422			(14,242	)

Income before cumulative
effect of accounting change		543,105		523,823		323,751			695,452			92,870

Net income		543,105		523,823		323,751			118,160			85,870

Partners' share of net income:

General partners		57,202		55,028		35,494			16,816			12,987

Limited partners		485,903		468,795		288,257			101,344			72,883

Limited partners' income (loss)
per unit before discontinued
operations and cumulative effect
of accounting change		44.62		43.05		28.73			(8.61	)		8.67

Discontinued operations per
limited partner unit		-		-		(2.26	)		65.63			(1.33	)

Limited partners’
net income per unit		44.62		43.05		26.47			9.31			6.69

Limited partners'
cash distributions per unit		52.63		38.85		29.98			9.78			5.14

Total assets	$	619,464	$	589,341	$	506,878		$	531,839		$	386,903

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

General

The Partnership was formed to acquire 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.

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		12,138		12,642		12,904
Gas production in mcf		40,609		49,967		49,147
Total (BOE)		18,906		20,970		21,095
Average price per barrel of oil	$	63.94	$	54.76	$	39.95
Average price per mcf of gas	$	6.36	$	7.32	$	5.79
Partnership distributions	$	636,698	$	470,000	$	355,541
Limited partner distributions	$	573,104	$	423,000	$	326,499
Per unit distribution to limited partners	$	52.63	$	38.85	$	29.98
Number of limited partner units		10,889		10,889		10,889

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.

Oil and gas operating results

Oil and gas prices remained high compared to the previous two years. Comparing 2006 to 2005, oil and gas sales decreased $23,300, of which price variances accounted for a $72,800 increase and production variances accounted for a $96,100 decrease. Comparing 2005 to 2004, oil and gas sales increased $257,800, of which price variances accounted for a $263,500 increase and production variances accounted for a $5,700 decrease.

Production in 2006 (on a BOE basis) was 10% lower than 2005 and 10% lower than 2004. Our oil production was 4% lower in 2006 than 2005 due primarily to normal production decline. Our gas production was 19% lower in 2006 than 2005 due primarily to a steep production decline on a gas well.

In 2006, our realized oil price was 17% higher than 2005 and 60% higher than 2004, while our realized gas price was 13% lower than 2005 and 10% 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 decreased from $19.67 per BOE in 2005 and increased from $15.32 per BOE in 2004 to $19.03 per BOE in 2006. The decrease in operating costs in 2006 was due primarily to lower expenditures on properties subject to a farm-out agreement in 2006.

Depletion on a BOE basis increased 21% from 2005 and 3% from 2004. Comparing 2006 to 2005, depletion expense increased $2,500, of which rate variances accounted for a $5,100 increase and production variances accounted for a $2,600 decrease. Comparing 2005 to 2004, depletion expense decreased $4,700, of which rate variances accounted for a $4,500 decrease and production variances accounted for a $200 decrease. 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 7% higher than 2005 and 5% higher than 2004 primarily due 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. Although House Bill 3 states that the Texas Margin Tax is not an income tax, the Partnership believes that Statement of Financial Accounting Standards No. 109 “Accounting for Income Taxes” (“SFAS 109”) applies to the Texas Margin Tax. However the Partnership believes, based on its interpretation, that the Texas Margin Tax does not apply to the Partnership because it qualifies under the passive entity exclusion.

Liquidity and Capital Resources

Partnership distributions during the year ended December 31, 2006 were $636,698, of which $573,104 was distributed to the limited partners and $63,594 to the general partners. Cumulative cash distributions of $7,064,817 have been made to the general and limited partners as of December 31, 2006. As of December 31, 2006, $6,398,878 or $587.65 per limited partner unit has been distributed to the limited partners, representing 118% 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 2006 was 13% higher than 2005 due to the combined effects of several drivers. A 2% decrease in oil and gas sales were offset by decreases in production costs. Our only use in financing activities is the distribution to partners which was 35% higher than 2005.

As of December 31, 2006, the Partnership had approximately $147,100 in working capital. The Managing General Partner knows of no unusual contractual commitments. Although the Partnership held many long-lived properties at inception, because of the restrictions on property development imposed by the partnership agreement, the Partnership cannot develop its non-producing properties, if any. Without continued development, the producing reserves continue to deplete. Accordingly, as the Partnership’s properties have matured and depleted, the net cash flows from operations for the Partnership have 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.

Discontinued Operations - Sale of oil and gas leases

During 2003, the Partnership sold its interest in certain oil wells for $239,402 sales proceeds and retired $605,481 of asset retirement obligation associated with the properties. The Partnership recognized a gain of $784,359 on the sale. Pursuant to the requirements of SFAS No. 144, the historical operating results from these properties have been reported as discontinued operations in the accompanying statements of operations. The following table summarizes certain historical operating information related to the discontinued operations:

	2004
Revenues	$	-
Operating expenses		27,318
Gain on sale		-
Income (loss) from
discontinued operations	$	(27,318	)

Sales of oil and gas properties, whether or not being amortized currently, shall be accounted for as adjustments of capitalized costs, with no gain or loss recognized, unless such adjustments would significantly alter the relationship between capitalized cost and proved oil and gas reserves. It was determined that the sale of a certain oil lease, which encompasses several wells, would significantly alter the relationship between capitalized costs and the proved reserves. Therefore, the Partnership calculated and recorded a gain on sale of the oil lease in the amount of $784,359. Net capitalized costs were allocated to the gain on sale based on the percentage of the reserves for the wells sold to the total reserves before the sale. In addition, the asset retirement obligation associated with the wells was taken to the gain on sale.

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.

Item 8. Financial Statements and Supplementary Data

Index to Financial Statements

		Page
Report of Independent Registered Public Accounting Firm		16

Balance Sheets		17

Statements of Operations		18

Statements of Changes in Partners' Equity		19

Statements of Cash Flows		20

Notes to Financial Statements		21

REPORT OF INDEPENDENT REGISTERED

PUBLIC ACCOUNTING FIRM

The Partners

Southwest Oil & Gas Income Fund X-B, L.P.

(A Delaware Limited Partnership)

We have audited the accompanying balance sheets of Southwest Oil & Gas Income Fund X-B, L.P. (the “Partnership”) as of December 31, 2006 and 2005, and the related statements of operations, changes in partners’ equity, and cash flows for each of the years in the three-year period ended December 31, 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 Oil & Gas Income Fund X-B, 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

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Balance Sheets

	December 31,
	2006		2005
Assets

Current assets:
Cash and cash equivalents	$	8,465	$	73,431
Receivable from Managing General Partner		98,896		106,828
New Mexico income tax deposit		39,767		19,631
Total current assets		147,128		199,890

Oil and gas properties - using the full-
cost method of accounting		4,303,837		4,192,041
Less accumulated depreciation,
depletion and amortization		3,831,501		3,802,590
Net oil and gas properties		472,336		389,451

	$	619,464	$	589,341

Liabilities and Partners' Equity

Current liability - distributions payable	$	-	$	481


Asset retirement obligation		296,255		172,058

Partners' equity:
General partners		21,952		28,344
Limited partners		301,257		388,458
Total partners' equity		323,209		416,802

	$	619,464	$	589,341

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Statements of Operations

	Years ended December 31,
	2006		2005		2004
Revenues
Oil and gas income	$	1,034,627	$	1,057,936	$	800,150
Interest income		2,042		957		408
Other income		3,456		-		631
		1,040,125		1,058,893		801,189

Expenses
Production		359,863		412,459		323,161
Depreciation, depletion and amortization		28,911		26,452		31,190
Accretion expense		14,926		8,756		6,899
General and administrative		93,320		87,403		88,870
		497,020		535,070		450,120

Income from continuing operations		543,105		523,823		351,069

Results from discontinued operations -
sale of oil and gas leases - See Note 4		-		-		(27,318	)

Net income	$	543,105	$	523,823	$	323,751

Net income allocated to:
Managing General Partner	$	51,482	$	49,525	$	31,945

General Partner	$	5,720	$	5,503	$	3,549

Limited partners	$	485,903	$	468,795	$	288,257

Per limited partner unit before discontinued
operations and cumulative effect	$	44.62	$	43.05	$	28.73
Discontinued operations per limited partner unit		-		-		(2.26	)

Per limited partner unit	$	44.62	$	43.05	$	26.47

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Statements of Changes in Partners' Equity

Years ended December 31, 2006, 2005 and 2004

	General			Limited
	Partners			Partners			Total
Balance at December 31, 2003	$	13,864		$	380,905		$	394,769

Net income		35,494			288,257			323,751

Distributions		(29,042	)		(326,499	)		(355,541	)

Balance at December 31, 2004		20,316			342,663			362,979

Net income		55,028			468,795			523,823

Distributions		(47,000	)		(423,000	)		(470,000	)

Balance at December 31, 2005		28,344			388,458			416,802

Net income		57,202			485,903			543,105

Distributions		(63,594	)		(573,104	)		(636,698	)

Balance at December 31, 2006	$	21,952		$	301,257		$	323,209

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund X-B, 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 oil and gas sales	$	1,025,879		$	1,012,193		$	838,879
Cash paid for production expense, administrative
fees and general and administrative overhead		(453,439	)		(502,999	)		(412,031	)
Cash used in discontinued operations		-			-			(27,318	)
Interest received		2,042			957			408
Other income		-			-			631

Net cash provided by operating activities		574,482			510,151			400,569

Cash flows used in investing activities:
Additions to oil and gas properties		(2,269	)		(2,479	)		(29,291	)

Cash flows from financing activities:
Distributions to partners		(636,698	)		(470,000	)		(355,541	)
Decrease in distributions payable		(481	)		(89	)		(14	)

Net cash used in financing activities		(637,179	)		(470,089	)		(355,555	)

Net (decrease) increase in cash and cash equivalents		(64,966	)		37,583			15,723

Beginning of period		73,431			35,848			20,125

End of period	$	8,465		$	73,431		$	35,848

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

Net income	$	543,105		$	523,823		$	323,751

Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, depletion and amortization		28,911			26,452			31,190
Accretion expense		14,926			8,756			6,899
Settlement of asset retirement obligations
for plugged and abandoned wells		(256	)		(3,137	)		-
(Increase) decrease in receivables and deposits		(12,204	)		(45,743	)		38,729

Net cash provided by operating activities	$	574,482		$	510,151		$	400,569

Increase (decrease) in oil and gas properties -
SFAS No. 143	$	109,527		$	23,110		$	(56	)

The accompanying notes are an integral

part of these financial statements.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

1.	Organization

Southwest Oil & Gas Income Fund X-B, L.P. was organized under the laws of the state of Delaware on November 27, 1990 for the purpose of acquiring producing oil and gas properties and to produce and market crude oil and natural gas produced from such properties for a term of 50 years, unless terminated at an earlier date as provided for in the Partnership Agreement. The Partnership sells its oil and gas production to a variety of purchasers with the prices it receives being dependent upon the oil and gas economy. Southwest Royalties, Inc., a wholly owned subsidiary of Clayton Williams Energy, Inc., serves as the Managing General Partner. Revenues, costs and expenses are allocated as follows:

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

(1)

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

(2)

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

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.

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.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

2.	Summary of Significant Accounting Policies- continued

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 $412,769 and $266,542 less than that shown on the accompanying Balance Sheets in accordance with generally accepted accounting principles.

Cash and Cash Equivalents

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

Number of per Limited Partner Units

As of December 31, 2006, 2005 and 2004, there were 10,889 limited partner units outstanding held by 517, 520 and 521 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.

Fair Value of Financial Instruments

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

Net Income (loss) per limited partnership unit

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

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

2.	Summary of Significant Accounting Policies- continued

Recent Accounting Pronouncements

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	$	172,058		$	143,329
Additional abandonment obligations from new wells		255			-
Reduction of obligations due to wells plugged and abandoned		(256	)		(3,137	)
Reduction of obligations due to farm-outs		(1,481	)		-
Accretion expense		14,926			8,756
Revisions of previous estimates		110,753			23,110
End of year	$	296,255		$	172,058

4.	Discontinued Operations - Sale of oil and gas leases

During 2003, the Partnership sold its interest in certain oil wells for $239,402 of sales proceeds and retired $605,481 of asset retirement obligations associated with the properties. The Partnership recognized a gain of $784,359 on the sale. Pursuant to the requirements of SFAS No. 144, the historical operating results from these properties have been reported as discontinued operations in the accompanying statements of operations. The following table summarizes certain historical operating information related to the discontinued operations:

	2004
Revenues		-
Operating expenses	$	27,318
Gain on sale		-
Income (loss) from
discontinued operations	$	(27,318	)

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

5.	Commitments and Contingent Liabilities

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

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

As of December 31, 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 reliably 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.

6.	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 $54,600, $53,400 and $50,300 for the years ended December 31, 2006, 2005 and 2004, respectively. In addition, the Managing General Partner and certain officers and employees may have an interest in some of the properties that the Partnership also participates.

Southwest Royalties, Inc., the Managing General Partner, was paid $72,000 during 2006, 2005 and 2004, as an administrative fee for reimbursement of 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 $98,900 and $106,800 are from oil and gas production, net of lease operating costs and production taxes, as of December 31, 2006 and 2005, respectively.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

7.	Oil and Gas Reserves Information (unaudited)

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

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

	Oil (bbls)			Gas (mcf)
Total Proved -
January 1, 2004		141,000			521,000

Revisions of estimates in place		60,000			30,000
Production from continuing operations		(13,000	)		(49,000	)

December 31, 2004		188,000			502,000

Revisions of estimates in place		3,000			16,000
Production from continuing operations		(13,000	)		(50,000	)

December 31, 2005		178,000			468,000

Revisions of estimates in place		(21,000	)		(121,000	)
Production from continuing operations		(12,000	)		(41,000	)

December 31, 2006		145,000			306,000

Proved developed reserves -
December 31, 2004		161,000			393,000
December 31, 2005		151,000			355,000
December 31, 2006		118,000			199,000

Net revisions of 41,000 BOE in 2006 consisted of approximately 15,000 BOE of downward revisions attributable to the effects of lower product prices on the estimated quantities of proved reserves, and downward revisions of approximately 26,000 BOE attributable to well performance primarily from properties in the Malaga field of New Mexico. Net revisions of 6,000 BOE in 2005 consisted of approximately 20,000 BOE of upward revisions attributable to the effects of higher product prices on the estimated quantities of proved reserves, net of downward revisions of approximately 14,000 BOE attributable to well performance primarily from properties in the Petrox 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 $58.42, $59.75 and $41.99 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 $4.66, $9.91 and $5.25 per Mcf.

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

7.	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.

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	$	9,653,000	$	15,302,000	$	10,516,000
Production, development and abandonment costs		4,218,000		5,303,000		4,904,000
Future net cash flows		5,435,000		9,999,000		5,612,000
10% annual discount for estimated
timing of cash flows		2,327,000		5,091,000		2,695,000
Standardized measure of discounted
future net cash flows	$	3,108,000	$	4,908,000	$	2,917,000

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	$	(675,000	)	$	(645,000	)	$	(450,000	)
Changes in prices and production costs		(1,554,000	)		2,363,000			316,000
Changes of production rates (timing) and others		591,000			(128,000	)		(327,000	)
Revisions of previous quantities estimates		(653,000	)		109,000			698,000
Accretion of discount		491,000			292,000			244,000
Discounted future net cash flows -
Beginning of year		4,908,000			2,917,000			2,436,000
End of year	$	3,108,000		$	4,908,000		$	2,917,000

Southwest Oil & Gas Income Fund X-B, L.P.

(a Delaware limited partnership)

Notes to Financial Statements

8. Selected Quarterly Financial Results - (unaudited)

	Quarter
	First		Second		Third		Fourth
2006:
Total revenues	$	269,021	$	287,286	$	261,562	$	222,256
Total expenses		103,208		131,876		133,569		128,367
Net income	$	165,813	$	155,410	$	127,993	$	93,889

Net income per limited partners unit	$	13.64	$	12.79	$	10.52	$	7.67

	Quarter
	First		Second		Third		Fourth
2005:
Total revenues	$	224,876	$	240,585	$	318,058	$	275,374
Total expenses		120,720		156,245		129,182		128,923
Net income	$	104,156	$	84,340	$	188,876	$	146,451

Net income per limited partners unit	$	8.55	$	6.91	$	15.54	$	12.05

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.

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, as an administrative fee, $72,000 during 2006, 2005 and 2004. 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.

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 472.5 limited partner units, a 3.9% limited partner interest. The Managing General Partner's total percentage interest ownership in the Partnership is 13.9%.

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 $72,000 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 working interest. Certain properties in which the Partnership has an interest are operated by the Managing General Partner, who was paid approximately $54,600 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	$	13,303
Audit 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.

Part IV

Item 15. Exhibits and Financial Statement Schedules

(a)	(1)	Financial Statements:

		Included in Part II of this report

		Report of Independent Registered Public Accounting Firm
		Balance Sheets
		Statements of Operations
		Statements of Changes in Partners' Equity
		Statements of Cash Flows
		Notes to Financial Statements

	(2)	Schedules required by Article 12 of Regulation S-X are either omitted because they are not applicable or because the required information is shown in the financial statements or the notes thereto.

	(3)	Exhibits:

4	(a)	Certificate of Limited Partnership of Southwest Oil & Gas Income Fund X-B, L.P., dated November 27, 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 Oil & Gas Income Fund X-B, L.P. dated November 27, 1990. (Incorporated by reference from Partnership's Form 10-K for the fiscal year ended December 31, 1991.)

	31.1	Rule 13a-14(a)/15d-14(a) Certification
	31.2	Rule 13a-14(a)/15d-14(a) Certification
	32.1	Certification of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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.

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.

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.

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 Oil & Gas Income Fund X-B, L.P.,
	a Delaware limited partnership

By:	Southwest Royalties, Inc., Managing
	General Partner


By:	/s/ L. Paul Latham
	L. Paul Latham
	President and Chief Executive Officer

Date:	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 Latham
Clayton W. Williams, Chairman of the Board		L. Paul Latham, President and a Director
and a Director

Date: April 5, 2007		Date: April 5, 2007




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

Date: April 5, 2007

Date: April 5, 2007	/s/ Mel G. Riggs
	Mel G. Riggs
	Vice President and Chief Financial Officer of
	Southwest Royalties, Inc., the
	Managing General Partner of
	Southwest Oil & Gas Income Fund X-B, L.P.