exv13

EXHIBIT 13

ANNUAL REPORT TO SHAREHOLDERS

[COVER PAGE]

[PERMIAN BASIN ROYALTY TRUST LOGO]

PERMIAN BASIN ROYALTY TRUST ANNUAL REPORT & FORM 10-K 2008

[MAP OF COUNTIES IN TEXAS]

TEXAS ROYALTY PROPERTIES ARE LOCATED IN 35 TEXAS COUNTIES.
WADDELL RANCH PROPERTIES ARE LOCATED IN CRANE COUNTY.

The Trust

The Permian Basin Royalty Trust’s (the “Trust”) principal assets are comprised of a 75% net overriding royalty interest carved out by Southland Royalty Company (“Southland”) from its fee mineral interest in the Waddell Ranch properties in Crane County, Texas (“Waddell Ranch properties”), and a 95% net overriding royalty interest carved out by Southland from its major producing royalty properties in Texas (“Texas Royalty properties”). The interests out of which the Trust’s net overriding royalty interests were carved were in all cases less than 100%. The Trust’s net overriding royalty interests represent burdens against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved. The net overriding royalties above are collectively referred to as the “Royalties.” The properties and interests from which the Royalties were carved and which the Royalties now burden are collectively referred to as the “Underlying Properties.”

The Trust has been advised that effective January 1, 1996, Southland was merged with and into Meridian Oil Inc. (“Meridian”), a Delaware corporation, with Meridian being the surviving corporation. Meridian succeeded to the ownership of all the assets, has the rights, powers, and privileges, and assumed all of the liabilities and obligations of Southland. Effective July 11, 1996, Meridian changed its name to Burlington Resources Oil & Gas Company, now Burlington Resources Oil & Gas Company LP (“BROG”). Any reference to BROG hereafter for periods prior to the occurrence of the aforementioned name change or merger should, as applicable, be construed to be a reference to Meridian or Southland. Further, BROG notified the Trust that, on February 14, 1997, the Texas Royalty properties that are subject to the Net Overriding Royalty Conveyance dated November 1, 1980 (“Texas Royalty Conveyance”), were sold to Riverhill Energy Corporation (“Riverhill Energy”) of Midland, Texas. Effective March 31, 2006, ConocoPhillips acquired BRI pursuant to a merger between BRI and a wholly-owned subsidiary of ConocoPhillips. As a result of this acquisition, BRI and BROG are both wholly-owned subsidiaries of ConocoPhillips.

Units of Beneficial Interest

Units of Beneficial Interest (“Units”) of the Trust are traded on the New York Stock Exchange with the symbol PBT. Quarterly high and low sales prices and the aggregate amount of monthly distributions paid each quarter during the Trust’s two most recent years were as follows:


	Sales Price				Distributions
2008	High		Low		Paid
First Quarter	$	23.15	$	15.25	$	.560051
Second Quarter		27.80		20.75		.577627
Third Quarter		27.40		20.05		.760315
Fourth Quarter		23.89		12.47		.493363

Total for 2008					$	2.391356


	Sales Price				Distributions
2007	High		Low		Paid
First Quarter	$	16.14	$	11.35	$	.291984
Second Quarter		14.85		12.95		.281583
Third Quarter		15.50		12.90		.384680
Fourth Quarter		16.12		14.33		.492530

Total for 2007					$	1.450777

Approximately 1,434 Unit holders of record held the 46,608,796 Units of the Trust at December 31, 2008.

The Trust has no equity compensation plans and has not repurchased any Units during the period covered by this report.

To Unit Holders

We are pleased to present the twenty-eighth Annual Report of the Trust. The report includes a copy of the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the year ended December 31, 2008, without exhibits. Both the report and accompanying Form 10-K contain important information concerning the Trust’s properties, including the oil and gas reserves attributable to the Royalties owned by the Trust. Production figures, drilling activity and certain other information included in this report have been provided to the Trust by BROG (formerly Meridian and Southland) and Riverhill Energy.

As more particularly explained in the Notes to the Financial Statements appearing in this report and in Item 1 of the accompanying Form 10-K, Bank of America, N.A., as Trustee, has the primary function under the Trust Indenture of collecting the monthly net proceeds attributable to the Royalties and making monthly distributions to the Unit holders, after deducting Trust administrative expenses and any amounts necessary for cash reserves.

Royalty income received by the Trustee for the year ended December 31, 2008, was $112,341,696 and interest income earned for the same period was $90,572. General and administrative expenses amounted to $973,761. A total of $111,458,507 or 2.391356 per Unit, was distributed to Unit holders during 2008. A discussion of factors affecting the distributions for 2008 may be found in the Trustee’s Discussion and Analysis section of this report and the accompanying Form 10-K.

As of December 31, 2008, the Trust’s proved reserves were estimated at 5,860,000 Bbls of oil and 20,664,000 Mcf of gas. The estimated future net revenues from proved reserves at December 31, 2008 amount to $321,888,000 or $6.91 per Unit. The present value of estimated future net revenues discounted at 10% at December 31, 2008 was $178,727,000 or $3.83 per Unit. The computation of future net revenues is made following guidelines prescribed by the Financial Accounting Standards Board (explained in Item 2 of the accompanying Form 10-K) based on year-end prices and costs.

As has been previously reported, Southland advised the Trust that it became operator of record of the Waddell Ranch properties on May 1, 1991. Meridian, as successor by merger, became the operator of record effective January 1, 1996. Meridian changed its name to Burlington Resources Oil & Gas Company in 1996 and again to Burlington Resources Oil & Gas Company LP in 2000. All field, technical and accounting operations, however, have been carried out by Schlumberger Technology Corporation (“STC”) under the direction of BROG, and by Riverhill Capital Corporation (“Riverhill Capital”).

As was previously reported, in February 1997, BROG sold its interest in the Texas Royalty properties that are subject to the Texas Royalty Conveyance to Riverhill Energy, which at the time was a wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (“CMC”). Subsequently, the Trustee was advised that STC acquired all of the shares of Riverhill Capital. The Trustee has been advised that, as part of this transaction, ownership of Riverhill Energy’s interests in the Texas Royalty properties referenced above remain in Riverhill Energy, which was owned by the former shareholders of Riverhill Capital. All accounting operations pertaining to the Texas Royalty properties are performed by Riverhill Energy.

Percentage depletion is allowed on proven properties acquired after October 11, 1990. For Units acquired after such date, Unit holders would normally compute both percentage depletion and cost depletion from each property, and claim the larger amount as a deduction on their income tax returns. The Trustee and its accountants have estimated the cost depletion for January through December 2008, and it appears that percentage depletion will exceed cost depletion for some of the Unit holders.

Royalty income is generally considered portfolio income under the passive loss rules. Therefore, in general, it appears that Unit holders should not consider the taxable income from the Trust to be passive income in determining net passive income or loss. Unit holders should consult their tax advisors for further information.

Unit holders of record will continue to receive an individualized tax information letter for each of the quarters ending March 31, June 30 and September 30, 2009, and for the year ending December 31, 2009. Unit holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request.


	Bank of America, N.A., Trustee
	By:	/s/ Ron E. Hooper
		Ron E. Hooper
		Senior Vice President

Description of the Properties

The net overriding royalty interests held by the Trust are carved out of high-quality producing oil and gas properties located primarily in West Texas. A production index for oil and gas properties is the number of years derived by dividing remaining reserves by current production. The production index for the Trust properties based on the reserve report prepared by independent petroleum engineers as of December 31, 2008, is approximately 6.8 years.

The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the Trust. The mineral interests in the Waddell Ranch, from which such net royalty interests are carved vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross acres and 34,205 net acres, containing 859 gross (396 net) productive oil wells, 170 gross (76 net) productive gas wells and 292 gross (131 net) injection wells.

Six major fields on the Waddell Ranch properties account for more than 90% of the total production. In the six fields, there are 12 producing zones ranging in depth from 2,800 to 10,600 feet. Most prolific of these zones are the Grayburg and San Andres, which produce from depths between 2,800 and 3,400 feet. Productive from the San Andres are the Sand Hills (Judkins) gas field and the Sand Hills (McKnight) oil field, the Dune (Grayburg/San Andreas) oil field, and the Waddell (Grayburg/San Andreas) oil field.

The Dune and Waddell oil fields are productive from both the Grayburg and San Andres formations. The Sand Hills (Tubb) oil fields produce from the Tubb formation at depths averaging 4,300 feet, and the University Waddell (Devonian) oil field is productive from the Devonian formation between 8,400 and 9,200 feet.

All of the major oil fields on the Waddell Ranch properties are currently being water flooded. Engineering studies and 3-D seismic evaluations on these fields indicate the potential for increased production through infill drilling, modifications of existing water flood techniques and installation of larger capacity pumping equipment. Capital expenditures for remedial and maintenance activities during 2008 totaled approximately $24.1 million.

The Texas Royalty properties, out of which the other net overriding royalty was carved, are located in 33 counties across Texas. The Texas Royalty properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (51,000 net) producing acres. Approximately 41% of the future net revenues discounted at 10% attributable to Texas Royalty properties are located in the Wasson and Yates fields.

BROG has informed the Trustee that the 2009 capital expenditures budget with regard to the Waddell Ranch properties should total approximately $37.7 million gross of which $21.1 million gross is attributable to drilling, $16.1 million gross to workovers and recompletions, and $0.5 million gross to facilities.

Computation of Royalty Income Received by the Trust

The Trust’s royalty income is computed as a percentage of the net profit from the operation of the properties in which the Trust owns net overriding royalty interests. The percentages of net profits are 75% and 95% in the cases of the Waddell Ranch properties and the Texas Royalty properties, respectively. Royalty income received by the Trust for the five years ended December 31, 2008, was computed as shown in the table on the next page.


	Year Ended December 31,
	2008						2007						2006						2005						2004
	Waddell			Texas			Waddell			Texas			Waddell			Texas			Waddell			Texas			Waddell			Texas
	Ranch			Royalty			Ranch			Royalty			Ranch			Royalty			Ranch			Royalty			Ranch			Royalty
	Properties			Properties			Properties			Properties			Properties			Properties			Properties			Properties			Properties			Properties
Gross Proceeds of Sales
From the Underlying Properties:
Oil Proceeds	$	78,716,086		$	34,112,890		$	51,897,859		$	20,651,675		$	51,185,185		$	21,301,642		$	43,967,934		$	17,415,261		$	32,078,721		$	12,296,982
Gas Proceeds		54,694,736			7,831,734			41,997,463			5,275,253			40,386,375			5,780,321			37,531,266			5,050,206			28,746,318			3,970,231


Total		133,410,822			41,944,624			93,895,322			25,926,928			91,571,560			27,081,963			81,499,200			22,465,467			60,825,039			16,267,213

Less:
Severance Tax
Oil		3,365,962			1,301,428			2,241,791			779,513			2,219,552			760,043			1,806,281			675,609			1,366,942			457,308
Gas		3,172,496			511,315			2,474,922			337,861			2,587,606			378,513			2,319,699			325,044			1,702,937			262,673
Other		290,737			0			169,151			159,926			42,695			-0-			42,505			—			42,763			252,906
Lease Operating Expense and Property Tax
Oil and Gas		16,766,553			1,352,645			15,854,987			1,579,946			13,932,289			1,454,993			12,191,168			963,563			9,391,083			894,383

Capital Expenditures		9,146,511			—			11,198,975			—			15,265,143			—			7,151,598			—			6,539,015			—


Total		32,742,259			3,165,388			31,939,826			2,857,246			34,047,285			2,593,549			23,511,251			1,964,216			19,042,740			1,867,270


Net Profits		100,668,563			38,779,236			61,955,496			23,069,682			57,524,275			24,488,414			57,987,949			20,501,251			41,782,299			14,399,943
Net Overriding Royalty Interest		75	%		95	%		75	%		95	%		75	%		95	%		75	%		95	%		75	%		95	%

Royalty Income		75,501,422			36,840,274			46,466,622			21,916,198			43,143,206			23,263,993			43,490,961			19,476,189			31,336,724			13,679,946
Total Royalty Income for Distribution		75,501,422			36,840,274			46,466,622			21,916,198		$	43,143,206		$	23,263,993		$	43,490,961		$	19,476,189		$	31,336,724		$	13,679,946

Discussion and Analysis

Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 2008

Critical Accounting Policies and Estimates

The trust’s financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical judgment areas in the application of accounting policies that currently affect the Trust’s financial condition and results of operations.

1. Revenue Recognition

Revenues from Royalty Interests are recognized in the period in which amounts are received by the Trust. Royalty income received by the Trust in a given calendar year will generally reflect the proceeds from natural gas produced for the twelve-month period ended October 31^st in that calendar year.

2. Reserve Recognition

Independent petroleum engineers estimate the net proved reserves attributable to the Royalty Interests. In accordance with Statement of Financial Standards No. 69, “Disclosures About Oil and Gas Producing Activities,” estimates of future net revenues from proved reserves have been prepared using year-end contractual gas prices. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates and related costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as market conditions change.

Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on its royalty properties, the number of exploratory or development wells drilled on its royalty properties during the periods presented by this report, or the number of wells in process or other present activities on its royalty properties, and the Registrant cannot readily obtain such information.

3. Contingencies

Contingencies related to the Underlying Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders.

4. New Accounting Pronouncements

In July 2006, the FASB issued FASB Interpretation No. 48 (“FIN 48”), Accounting for Uncertainty in Income Taxes, which clarifies the accounting for uncertainty in income taxes recognized in the financial statements in accordance with SFAS No. 109, Accounting for Income Taxes. FIN 48 is effective for fiscal years beginning after December 15, 2006. The adoption of this statement did not have an effect on the Trust’s financial statements.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements. This statement defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007. The adoption of this statement did not have an effect on the Trust’s financial statements.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities-Including an amendment of FASB Statement No. 115. This statement permits entities to choose to measure many financial instruments and certain other items at fair value. This statement is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. The adoption of this statement did not have an effect on the Trust’s financial statements.

In December 2007 the FASB issued SFAS No. 141(R), Business Combinations. This statement requires the acquiring entity in a business combination to recognize the full fair value of assets acquired and liabilities assumed in the transaction (whether a full or partial acquisition); establishes the acquisition-date fair value as the measurement objective for all assets acquired and liabilities assumed; requires expensing of most transaction and restructuring costs; and requires the acquirer to disclose to investors and other users all of the information needed to evaluate and understand the nature and financial effect of the business combination. This statement applies prospectively to business combinations for which the acquisition date is on or after January 1, 2009. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements—an amendment of Accounting Research Bulletin No. 51. This statement requires reporting entities to present noncontrolling (minority) interests as equity (as opposed to as a liability or mezzanine equity) and provides guidance on the accounting for transactions between an entity and noncontrolling interests. This statement applies prospectively as of January 1, 2009, except for the presentation and disclosure requirements which will be applied retrospectively for all periods presented. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

In March 2008, the FASB issued FASB Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (SFAS No. 161), effective for fiscal years and interim periods beginning after November 15, 2008, with early adoption allowed. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of an entity’s use of derivative instruments and the effect of those derivative instruments on an entity’s financial statements. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

In May 2008, the FASB issued Statement No. 162, The Hierarchy of Generally Accepted Accounting Principles. This statement identifies the sources of accounting principles and the framework for selecting the principles used in the preparation of financial statements in conformity with GAAP, and is effective 60 days following the SEC’s approval of the Public Company Accounting Oversight Board Auditing amendments to AU Section 411, The Meaning of Present Fairly in Conformity with Generally Accepted Accounting Principles. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

Liquidity and Capital Resources

As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and pay Trust liabilities and expenses and its actions have been limited to those activities. The Trust is a passive entity and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. As a result, other than such borrowings, if any, the Trust has no source of liquidity or capital resources other than the Royalties.

Results of Operations

Royalty income received by the Trust for the three-year period ended December 31, 2008, is reported in the following table:


	Year Ended December 31,
	2008			2007			2006
Royalties
Total Revenue	$	112,341,696		$	68,382,820		$	66,407,199
		100	%		100	%		100	%
Oil Revenue		72,758,958			42,116,916			42,729,342
		65	%		62	%		64	%
Gas Revenue		39,582,738			26,265,904			23,677,857
		35	%		38	%		36	%
Total Revenue/Unit	$	2.410311		$	1.467166		$	1.424778

Royalty income of the Trust for the calendar year is associated with actual oil and gas production for the period November of the prior year through October of the current year. Oil and gas sales for 2008, 2007 and 2006 for the Royalties and the Underlying Properties, excluding portions attributable to the adjustments discussed hereafter, are presented in the following table:


	Year Ended December 31,
	2008		2007		2006
Royalties
Oil Sales (Bbls)		760,258		740,878		749,949
Gas Sales (Mcf)		3,673,068		3,477,898		3,154,791

Underlying Properties
Oil
Total Oil Sales (Bbls)		1,105,717		1,190,270		1,221,165
Average Per Day (Bbls)		3,021		3,261		3,346


	Year Ended December 31,
	2008		2007		2006
Average Price/Bbl	$	102.04	$	60.95	$	59.36

Gas
Total Gas Sales (Mcf)		5,927,790		6,407,845		5,973,188
Average Per Day (Mcf)		16,196		17,556		16,365
Average Price/Mcf	$	10.55	$	7.38	$	7.73

The average price of oil increased to $102.04 per barrel in 2008, up from $60.95 per barrel in 2007. The average price of oil in 2006 was $59.36 per barrel. In addition, the average price of gas increased from $7.38 per Mcf in 2007 to $10.55 per Mcf in 2008. The average price of gas in 2006 was $7.73 per Mcf. Oil prices have risen primarily because of increasing global demand and supply shortage, inadequate sour crude refining capacity, reduced production as a result of tropical storms and political instability in some oil producing countries. In the last few months of 2007 and the first half of 2008, narrowing excess worldwide capacity, weakness in the dollar and continuing tension in the Middle East caused prices to reach record levels above $147.00 per Bbl in July 2008. However, lower demand as a result of the deepening U.S. recession and slowing global economy, the tightened credit markets and rising crude oil supplies have caused oil prices to decline sharply in the second half of 2008. Oil prices are expected to remain volatile.

Beginning in 2006 and into 2007, gas prices trended lower primarily because of adequate natural gas supply inventory due to warmer than normal winter weather in 2006 and the absence of hurricane activity in the Gulf of Mexico. Much colder temperatures in early 2007 caused prices to partially rebound. As a result of tighter storage levels and higher oil prices, gas prices increased in the first half of 2008 and reached as high as $13.00 per MMBtu in July. Due to concerns of oversupply from shale gas development, declining demand due to the deepening U.S. recession, falling oil prices and increased gas storage, recent gas prices have declined. Natural gas prices are expected to remain volatile.

Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison. Total oil production increased approximately 3% from 2007 to 2008 primarily due to higher prices of production. Total gas production increased approximately 6% from 2007 to 2008 primarily due to new drilling on the Waddell Ranch properties.

Total capital expenditures in 2008 used in the net overriding royalty calculation were approximately $9.1 million compared to $11.2 million in 2007 and $15.3 million in 2006. During 2008, there were 3 gross (1 net) wells drilled and completed on the Waddell Ranch properties. At December 31, 2008, there were 6 drill wells and 3 workovers in progress on the Waddell Ranch properties.

In 2008, lease operating expense and property taxes on the Waddell Ranch properties amounted to approximately $16.8 million, which amount was higher than 2007 by $0.9 million.

The Trustee has been advised by BROG that for the period August 1, 1993, through January 1, 2009, the oil from the Waddell Ranch was and will be sold under a competitive bid to a third party.

During 2008, the monthly royalty receipts were invested by the Trustee until the monthly distribution date, and earned interest totaled $90,572. Interest income for 2007 and 2006 was $ 125,338 and $133,648, respectively. General and administrative expenses in 2008 were $973,761 compared to $888,928 in 2007 and $825,478 in 2006, primarily due to increased expenses related to compliance with the Sarbanes Oxley Act and increased Unit holder reporting.

Distributable income for 2008 was $111,458,507, or $2.391356 per Unit.

Distributable income for 2007 was $67,619,230, or $1.450777 per Unit.

Distributable income for 2006 was $65,715,369, or $1.410082 per Unit.

Results of the Fourth Quarters of 2008 and 2007

Royalty income received by the Trust for the fourth quarter of 2008 amounted to $23,104,688 or $.495715 per Unit. For the fourth quarter of 2007, the Trust received royalty income of $23,062,536 or $.494811 per Unit. Interest income for the fourth quarter of 2008 amounted to $15,240 compared to $38,736 for the fourth quarter of 2007. The decrease in interest income can be attributed primarily to a decrease in interest rate. General and administrative expenses totaled $124,768 for the fourth quarter of 2008 compared to $144,965 for the fourth quarter of 2007.

Royalty income for the Trust for the fourth quarter is associated with actual oil and gas production during August through October from the Underlying Properties. Oil and gas sales attributable to the Royalties and the Underlying Properties for the quarter and the comparable period for 2007 are as follows:


	Fourth Quarter
	2008		2007
Royalties
Oil Sales (Bbls)		172,029		216,314
Gas Sales (Mcf)		751,593		1,066,321

Underlying Properties
Total Oil Sales (Bbls)		281,843		308,546
Average Per Day (Bbls)		3,064		3,354
Average Price/Bbls		96.13		73.93
Total Gas Sales (Mcf)		1,438,886		1,644,198
Average Per Day (Mcf)		15,640		17,872
Average Price/Mcf		8.96		7.56

The posted price of oil increased for the fourth quarter of 2008 compared to the fourth quarter of 2007, resulting in an average price per barrel of $96.13 compared to $73.93 in the same period of 2007. The average price of gas increased for the fourth quarter of 2008 compared to the same period in 2007, resulting in an average price per Mcf of $8.96 compared to $7.56 in the fourth quarter of 2007.

The Trustee has been advised that oil sales decreased in the fourth quarter of 2008 compared to the same period in 2007 primarily due to market demand and effects of Hurricane Ike on the oil industry. Gas sales from the Underlying Properties decreased in the fourth quarter of 2008 compared to the same period in 2007 due to the market demands and effects of Hurricane Ike on the industry.

The Trust has been advised that 3 wells were drilled and completed during the three months ended December 31, 2008, and there were 6 wells in progress.

Off-Balance Sheet Arrangements.

Tabular Disclosure of Contractual Obligations.


			Payments Due by Period
Contractual			Less than 1		1 - 3				More than
Obligations	Total		Year		Years		3-5 Years		5 Years
Distribution payable to Unit holders	$	5,147,216	$	5,147,216		0		0		0
Total	$	5,147,216	$	5,147,216		0		0		0

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Permian Basin Royalty Trust and
Bank of America, N.A, Trustee:

We have audited the accompanying statements of assets, liabilities, and trust corpus of Permian Basin Royalty Trust (the “Trust”) as of December 31, 2008 and 2007, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Trustee. 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.

As described in Note 3 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2008 and 2007, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2008, on the basis of accounting described in Note 3.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2008, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2009 expressed an unqualified opinion on the Trustee’s internal control over financial reporting.

DELOITTE & TOUCHE LLP

Dallas, TX
March 2, 2009

PERMIAN BASIN ROYALTY TRUST
FINANCIAL STATEMENTS

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 2008 AND 2007


	2008		2007
ASSETS
Cash and Short-term Investments	$	5,147,216	$	8,173,207
Net Overriding Royalty Interests in Producing Oil and Gas Properties — Net (Notes 2 and 3)		1,170,793		1,293,935

	$	6,318,009	$	9,467,142


LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit Holders	$	5,147,216	$	8,173,207
Trust Corpus – 46,608,796 Units of Beneficial Interest Authorized and Outstanding		1,170,793		1,293,935

	$	6,318,009	$	9,467,142

STATEMENTS OF DISTRIBUTABLE INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2008


	2008		2007		2006
Royalty Income (Notes 2 and 3)	$	112,341,696	$	68,382,820	$	66,407,199
Interest Income		90,572		125,338		133,648

		112,432,268		68,508,158		66,540,847

Expenditures — General and Administrative		973,761		888,928		825,478

Distributable Income	$	111,458,507	$	67,619,230	$	65,715,369

Distributable Income per Unit (46,608,796 Units)	$	2.391356	$	1.450777	$	1.410082

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

STATEMENTS OF CHANGES IN TRUST CORPUS
FOR THE THREE YEARS ENDED DECEMBER 31, 2008


	2008			2007			2006
Trust Corpus, Beginning of Period	$	1,293,935		$	1,439,214		$	1,610,630
Amortization of Net Overriding Royalty Interests (Notes 2 and 3)		(123,142	)		(145,279	)		(171,416	)
Distributable Income		111,458,507			67,619,230			65,715,369
Distributions Declared		(111,458,507	)		(67,619,230	)		(65,715,369	)

Trust Corpus, End of Period	$	1,170,793		$	1,293,935		$	1,439,214

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

NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

The Permian Basin Royalty Trust (“Trust”) was established as of November 1, 1980. Bank of America, N.A. (“Trustee”) is Trustee for the Trust. Southland Royalty Company (“Southland”) conveyed to the Trust (1) a 75% net overriding royalty in Southland’s fee mineral interest in the Waddell Ranch in Crane County, Texas (“Waddell Ranch properties”) and (2) a 95% net overriding royalty carved out of Southland’s major producing royalty properties in Texas (“Texas Royalty properties”). The net overriding royalties above are collectively referred to as the “Royalties.”

On November 3, 1980, Units of Beneficial Interest (“Units”) in the Trust were distributed to the Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland common stock held. The Units are traded on the New York Stock Exchange.

The terms of the Trust Indenture provide, among other things, that:

	•		the Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust;

	•		the Trustee may not sell all or any part of the Royalties unless approved by holders of 75% of all Units outstanding in which case the sale must be for cash and the proceeds promptly distributed;

	•		the Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount;

	•		the Trustee is authorized to borrow funds to pay liabilities of the Trust; and

	•		the Trustee will make monthly cash distributions to Unit holders (see Note 2).

2. Net Overriding Royalty Interests and Distribution to Unit Holders

The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are determined on a monthly basis. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month. To the extent the distribution amount is a negative number, that amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or

before 10 business days after the monthly record date, which is generally the last business day of each calendar month.

The cash received by the Trustee consists of the amounts received by owners of the interest burdened by the Royalties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75% in the case of the Waddell Ranch properties and 95% in the case of the Texas Royalty properties.

The initial carrying value of the Royalties ($10,975,216) represented Southland’s historical net book value at the date of the transfer to the Trust. Accumulated amortization as of December 31, 2008 and 2007, aggregated $9,804,423 and $9,681,281, respectively.

3. Basis of Accounting

The financial statements of the Trust are prepared on the following basis:

	•		Royalty income recorded is the amount computed and paid by the working interest owner to the Trustee on behalf of the Trust.

	•		Trust expenses recorded are based on liabilities paid and cash reserves established out of cash received or borrowed funds for liabilities and contingencies.

	•		Distributions to Unit holders are recorded when declared by the Trustee.

The financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) because revenues are not accrued in the month of production and certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the Royalties calculated on a unit-of-production basis is charged directly to trust corpus. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

4. New Accounting Pronouncements

interests as equity (as opposed to as a liability or mezzanine equity) and provides guidance on the accounting for transactions between an entity and noncontrolling interests. This statement applies prospectively as of January 1, 2009, except for the presentation and disclosure requirements which will be applied retrospectively for all periods presented. The Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

5. Federal Income Tax

For Federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit holders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust. The Trust has on file technical advice memoranda confirming the tax treatment of the Trust.

Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name, collectively referred to herein

as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.pbt-permianbasintrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

Because the Trust is a grantor trust for Federal tax purposes, each Unit holder is taxed directly on his proportionate share of income, deductions and credits of the Trust consistent with each such Unit holder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the Trust. The income of the Trust consists primarily of a specified share of the proceeds from the sale of coal seam gas produced from the Underlying Properties. During 2008, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent and future obligations of the Trust.

The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unit holder is entitled to depletion deductions because the Royalties constitute “economic interests” in oil and gas properties for Federal income tax purposes. Each Unit holder is entitled to amortize the cost of the Units through cost depletion over the life of the Royalties or, if greater, through percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a Unit holder’s depletable tax basis in the Units. Rather, a Unit holder is entitled to a percentage depletion deduction as long as the applicable Underlying Properties generate gross income. If any portion of the Royalties is treated as a production payment or is not treated as an economic interest, however, a Unit holder will not be entitled to depletion in respect of such portion.

If a taxpayer disposes of any “section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the United States Treasury regulations govern dispositions of property after March 13, 1995. The Service likely will take the position that a Unit holder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.

Individuals may deduct “miscellaneous itemized deductions” (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust.

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit holder. Royalty income generally is treated as portfolio income and does not offset passive losses.

The Tax consequences to a Unit holder of the ownership and sale of Units will depend in part on the Unit holder’s tax circumstances. Unit holders should consult their tax advisors about the Federal tax consequences relating to owning the Units in the Trust.

6. Proved Oil and Gas Reserves (Unaudited)

Proved oil and gas reserve information is included in Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.

7. Quarterly Schedule of Distributable Income (Unaudited)

The following is a summary of the unaudited quarterly schedule of distributable income for the two years ended December 31, 2008 (in thousands, except per Unit amounts):


					Distributable
					Income and
	Royalty		Distributable		Distribution
2008	Income		Income		Per Unit
First Quarter	$	26,424	$	26,103	$	.560051
Second Quarter		27,261		26,923		.577627
Third Quarter		35,552		35,438		.760315
Fourth Quarter		23,105		22,995		.493363

Total	$	112,342	$	111,459	$	2.391356


					Distributable
					Income and
	Royalty		Distributable		Distribution
2007	Income		Income		Per Unit
First Quarter	$	13,901	$	13,609	$	.291984
Second Quarter		13,419		13,124		.281583
Third Quarter		18,000		17,930		.384680
Fourth Quarter		23,063		22,956		.492530

Total	$	68,383	$	67,619	$	1.450777

8. SUBSEQUENT EVENTS

Subsequent to December 31, 2008, the Trust declared the following distributions:


Monthly Record Date	Payment Date	Distribution per Unit
January 30, 2009	February 13, 2009	$	.082862
February 27, 2009	March 13, 2009	$	.043564

9. STATE TAX CONSIDERATIONS

All revenues from the Trust are from sources within Texas, which has no individual income tax. However, effective January 1, 2008, Texas imposes a margin tax at a rate of 1% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute. The Texas margin tax is a significant change in Texas tax law. The tax generally will be imposed on gross revenues generated in 2007 and thereafter. Entities subject to tax generally include trusts unless otherwise exempt and most other types of entities that provide limited liability protection. Trusts that receive at least 90% of their Federal gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas margin tax as “passive entities.” The Trust should be exempt from Texas margin tax as a “passive entity.” Since the Trust should be exempt from Texas margin tax at the Trust level as a passive entity, each Unit holder that is considered a taxable entity under the Texas margin tax would generally be required to include its Texas portion of Trust revenues in its own Texas margin tax computation. This revenue would be sourced to Texas under Texas Comptroller guidance that provides such income is sourced according to the principal place of business of the Trust, which is Texas.

Each Unit holder is urged to consult his own tax advisor regarding the requirements for filing state tax returns.

PERMIAN BASIN ROYALTY TRUST

901 Main Street, Suite 1700
P.O. Box 830650
Dallas, Texas 75202
Bank of America, N.A., Trustee

AUDITORS
Deloitte & Touche LLP
Dallas, Texas

LEGAL COUNSEL
Thompson & Knight L.L.P.
Dallas, Texas

TAX COUNSEL
Winstead, Sechrest Minick
Houston, Texas

TRANSFER AGENT
Mellon Investor Services LLC
Ridgefield Park, New Jersey