exv13

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
2006	High		Low		Paid

First Quarter	$	16.91	$	14.05	$	.400354
Second Quarter		16.93		14.35		.297034
Third Quarter		17.00		15.25		.398559
Fourth Quarter		16.68		15.23		.314135

Total for 2006					$	1.410082


	Sales Price				Distributions
2005	High		Low		Paid

First Quarter	$	15.57	$	12.13	$	.284149
Second Quarter		15.50		10.75		.268627
Third Quarter		17.23		14.73		.340939
Fourth Quarter		17.15		15.00		.442249

Total for 2005					$	1.335964

Approximately 1,524 Unit holders of record held the 46,608,796 Units of the Trust at December 31, 2006.

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-sixth 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, 2006, 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, 2006, was $66,407,199 and interest income earned for the same period was $133,648. General and administrative expenses amounted to $825,478. A total of $65,715,369 or 1.410082 per Unit, was distributed to Unit holders during 2006. A discussion of factors affecting the distributions for 2006 may be found in the Trustee’s Discussion and Analysis section of this report and the accompanying Form 10-K.

As of December 31, 2006, the Trust’s proved reserves were estimated at 6,578,000 Bbls of oil and 24,130,000 Mcf of gas. The estimated future net revenues from proved reserves at December 31, 2006 amount to $468,189,000 or $10.58 per Unit. The present value of estimated future net revenues discounted at 10% at December 31, 2006

was $265,970,500 or $5.71 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 2006, and it appears that percentage depletion will exceed cost depletion for all 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, 2007, and for the year ending December 31, 2007. 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, 2006, is approximately 8.3 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 76,922 gross acres and 33,246 net acres, containing 800 gross (353 net) productive oil wells, 205 gross (97 net) productive gas wells and 309 gross (134 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 2006 totaled approximately $35.6 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 2007 capital expenditures budget with regard to the Waddell Ranch properties should total approximately $32.4 million gross of which $18.9 million gross is attributable to drilling, $12.4 million gross to workovers and recompletions, and $1.1 million gross to facilities.


	Year Ended December 31,
	2006						2005						2004						2003						2002
	Waddell			Texas			Waddell			Texas			Waddell			Texas			Waddell			Texas			Waddell			Texasd
	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	$	51,185,185		$	21,301,642		$	43,967,934		$	17,415,261		$	32,078,721		$	12,296,982		$	24,418,227		$	9,454,914		$	20,543,224		$	7,785,749

Gas Proceeds		40,386,375			5,780,321			37,531,266			5,050,206			28,746,318			3,970,231			25,255,338			3,606,615			14,861,094			2,245,648


Total		91,571,560			27,081,963			81,499,200			22,465,467			60,825,039			16,267,213			49,673,565			13,061,529			35,404,318			10,031,397


Less:
Severance Tax
Oil		2,219,552			760,043			1,806,281			675,609			1,366,942			457,308			1,045,413			350,440			863,299			302,665
Gas		2,587,606			378,513			2,319,699			325,044			1,702,937			262,673			1,632,642			228,928			813,581			159,431
Other		42,695			-0-			42,505			—			42,763			252,906			26,850			—			72,397			—
Lease Operating Expense and Property Tax
Oil and Gas		13,932,289			1,454,993			12,191,168			963,563			9,391,083			894,383			10,540,850			823,331			9,424,724			933,646
Capital Expenditures		15,265,143			—			7,151,598			—			6,539,015			—			7,734,224			—			3,394,674			0

Total		34,047,285			2,593,549			23,511,251			1,964,216			19,042,740			1,867,270			20,979,979			1,402,699			14,568,674			1,395,742


Net Profits		57,524,275			24,488,414			57,987,949			20,501,251			41,782,299			14,399,943			28,693,586			11,658,830			20,835,643			8,635,655

Net Overriding Royalty Interest		75	%		95	%		75	%		95	%		75	%		95	%		75	%		95	%		75	%		95	%

Royalty Income		43,143,206			23,263,993			43,490,961			19,476,189			31,336,724			13,679,946			21,520,190			11,075,888			15,626,732			8,203,872

Total Royalty Income for Distribution	$	43,143,206		$	23,263,993		$	43,490,961		$	19,476,189		$	31,336,724		$	13,679,946		$	21,520,190		$	11,075,888		$	15,626,732		$	8,203,872

Discussion and Analysis

Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 2006

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.

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, 2006, is reported in the following table:


	Year Ended December 31,
	2006			2005			2004
Royalties
Total Revenue	$	66,407,199		$	62,967,150		$	45,016,670
		100	%		100	%		100	%
Oil Revenue		42,729,342			38,924,579			27,180,560
		64	%		62	%		60	%
Gas Revenue		23,677,857			24,042,571			17,836,110
		36	%		38	%		40	%
Total Revenue/Unit	$	1.424775		$	1.35097		$	.965841

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 2006, 2005 and 2004 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,
	2006		2005		2004
Royalties
Oil Sales (Bbls)		749,949		827,275		779,052
Gas Sales (Mcf)		3,154,791		3,608,778		3,245,117

Underlying Properties
Oil
Total Oil Sales (Bbls)		1,221,165		1,258,584		1,222,579
Average Per Day (Bbls)		3,346		3,448		3,340
Average Price/Bbl	$	59.36	$	48.77	$	36.30


	Year Ended December 31,
	2006		2005		2004
Gas
Total Gas Sales (Mcf)		5,973,188		6,132,716		5,975,867
Average Per Day (Mcf)		16,365		16,802		16,328
Average Price/Mcf	$	7.73	$	6.94	$	5.47

The average price of oil increased to $59.36 per barrel in 2006, up from $48.77 per barrel in 2005. The average price of oil in 2004 was $36.30 per barrel. In addition, the average price of gas increased from $6.94 per Mcf in 2005 to $7.73 per Mcf in 2006. The average price of gas in 2004 was $5.47 per Mcf.

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 decreased approximately 3% from 2005 to 2006 primarily due to natural decline of properties. Total gas production decreased approximately 3% from 2005 to 2006 primarily due to natural decline of properties.

Total capital expenditures in 2006 used in the net overriding royalty calculation were approximately $34 million compared to $7.2 million in 2005 and $6.5 million in 2004. During 2006, there were 23 gross (11 net) wells drilled and completed on the Waddell Ranch properties. At December 31, 2006, there were 3 drill wells and 6 workovers in progress on the Waddell Ranch properties.

In 2006, lease operating expense and property taxes on the Waddell Ranch properties amounted to approximately $13.9 million, which amount was higher than 2005 by $1.7 million.

The Trustee has been advised by BROG that for the period August 1, 1993, through January 1, 2007, the oil from the Waddell Ranch was and will be sold under a competitive bid to a third party.

During 2006, the monthly royalty receipts were invested by the Trustee in U.S. Treasury securities until the monthly distribution date, and earned interest totaled $133,648. Interest income for 2005 and 2004 was $ 63,909 and $19,883, respectively.

General and administrative expenses in 2006 were $825,478 compared to $763,390 in 2005 and $489,810 in 2004, primarily due to increased expenses related to compliance with the Sarbanes-Oxley Act and increased Unit holder reporting.

Distributable income for 2006 was $65,715,639, or $1.410082 per Unit.

Distributable income for 2005 was $62,267,669, or $1.335964 per Unit.

Distributable income for 2004 was $44,546,743, or $.955758 per Unit.

Results of the Fourth Quarters of 2006 and 2005

Royalty income received by the Trust for the fourth quarter of 2006 amounted to $14,751,459 or $.316495 per Unit. For the fourth quarter of 2005, the Trust received royalty income of $20,700,741 or $.444138 per Unit. Interest income for the fourth quarter of 2006 amounted to $38,297 compared to $27,098 for the fourth quarter of 2005. The increase in interest income can be attributed primarily to an increase in interest rate. General and administrative expenses totaled $148,089 for the fourth quarter of 2006 compared to $115,154 for the fourth quarter of 2005.

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 2005 are as follows:


	Fourth Quarter
	2006		2005
Royalties
Oil Sales (Bbls)		175,356		222,071
Gas Sales (Mcf)		734,754		991,092

Underlying Properties
Total Oil Sales (Bbls)		308,453		309,862
Average Per Day (Bbls)		3,353		3,368
Average Price/Bbls	$	59.14	$	58.88
Total Gas Sales (Mcf)		1,578,248		1,499,863
Average Per Day (Mcf)		17,155		16,303
Average Price/Mcf	$	6.83	$	8.70

The posted price of oil increased for the fourth quarter of 2006 compared to the fourth quarter of 2005, resulting in an average price per barrel of $59.14 compared to $58.88 in the same period of 2005. The average price of gas decreased for the fourth quarter of 2006 compared to the same period in 2005, resulting in an average price per Mcf of $6.83 compared to $8.70 in the fourth quarter of 2005.

The Trustee has been advised that oil sales decreased in 2006 compared to the same period in 2005 primarily due to natural production declines. Gas sales from the Underlying Properties decreased in the fourth quarter of 2006 compared to the same period in 2005 due to the same factor.

The Trust has been advised that 8 wells were drilled and completed during the three months ended December 31, 2006, and there were 3 wells in progress.

PERMIAN BASIN ROYALTY TRUST
FINANCIAL STATEMENTS

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 2006 AND 2005


	2006		2005
ASSETS
Cash and Short-term Investments	$	5,135,136	$	7,264,048
Net Overriding Royalty Interests in Producing Oil and Gas Properties — Net (Notes 2 and 3)		1,439,214		1,610,630

	$	6,574,350	$	8,874,678


LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit Holders	$	5,135,136	$	7,264,048
Trust Corpus – 46,608,796 Units of Beneficial Interest Authorized and Outstanding		1,439,214		1,610,630

	$	6,574,350	$	8,874,678

STATEMENTS OF DISTRIBUTABLE INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2006


	2006		2005		2004
Royalty Income (Notes 2 and 3)	$	66,407,199	$	62,967,150	$	45,016,670
Interest Income		133,648		63,909		19,883

		66,540,847		63,031,059		45,036,553
Expenditures — General and Administrative		825,478		763,390		489,810

Distributable Income	$	65,715,369	$	62,267,669	$	44,546,743

Distributable Income per Unit (46,608,796 Units)	$	1.410082	$	1.335964	$	.955758

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, 2006 and 2005, aggregated $9,536,002 and $9,364,586, 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

In February 2006, the FASB issued SFAS No. 155, Accounting for Certain Hybrid Financial Instruments – an amendment of FASB Statements No. 133 Accounting for Derivative Instruments and No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement resolves issues addressed in Statement 133 Implementation Issue No. D1, Application of Statement 133 to Beneficial interests in Securitized Financial Assets. This statement is effective for all financial instruments acquired or issued after the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Trust has no such financial instruments and accordingly, this new Standard will not impact the financial statements of the Trust.

In March 2006, the FASB issued SFAS No. 156, Accounting for Servicing of Financial Assets – an amendment of FASB Statements No. 140 Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. This statement requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in certain situations. This statement is effective as of the beginning of an entity’s first fiscal year that begins after September 15, 2006. The Trustee does not believe the adoption of this statement will have a material effect on the Trust’s financial statements.

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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

In September 2006, the FASB issued SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans –an amendment of FASB Statements No. 87, 88, 106 and 132(R). This statement improves financial reporting by requiring an employer to recognize the over funded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity or changes in unrestricted net assets of a not-for-profit organization. This statement is effective as of the end of the fiscal year ending after December 15, 2006. The Trustee does not believe that the adoption of this statement will have a material 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 Trustee does not believe that the adoption of this statement will have a material 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 and — 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 Trustee does not believe that the adoption of this statement will have a material effect on the Trust’s financial statements.

In September 2006, the FASB issued SAB No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in the Current Year Financial Statements, for the purpose of evaluating materiality. This statement is effective for annual financial statements covering the first fiscal year ending after November 15, 2006. The Trustee does not believe that the adoption of this standard 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.

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 2006, 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). 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 in 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 will likely 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. Significant Customers

Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is included in Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.

7. 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.

8. 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, 2006 (in thousands, except per Unit amounts):


					Distributable
					Income and
	Royalty		Distributable		Distribution
2006	Income		Income		Per Unit
First Quarter	$	18,918	$	18,653	$	.400354
Second Quarter		14,041		13,844		.297034
Third Quarter		18,697		18,576		.398559
Fourth Quarter		14,751		14,642		.314135

Total	$	66,407	$	65,715	$	1.410082


					Distributable
					Income and
	Royalty		Distributable		Distribution
2005	Income		Income		Per Unit
First Quarter	$	13,531	$	13,244	$	.284149
Second Quarter		12,746		12,521		.268627
Third Quarter		15,989		15,890		.340939
Fourth Quarter		20,701		20,613		.442249

Total	$	62,697	$	62,268	$	1.335964

9. SUBSEQUENT EVENTS

Subsequent to December 31, 2006, the Trust declared the following distributions:


Monthly Record Date	Payment Date	Distribution per Unit
January 31, 2007	February 14, 2007	$	.101215
February 28, 2007	March 14, 2007	$	.090695

10. STATE TAX CONSIDERATIONS

All revenues from the Trust are from sources within Texas, which has no individual income tax. However, the franchise tax imposed through December 31, 2006 by the state of Texas on corporations (the definition of which generally includes limited liability companies) is partly based on federal taxable income, which will include income from the Trust.

The Texas legislature recently passed H.B. 3, 79th Leg., 3d C.S. (2006), which was signed into law on May 18, 2006. H.B. 3 significantly reforms the Texas franchise tax system and replaces it with a new Texas margin tax system. The margin tax expands the type of entities subject to tax to generally include all active business entities,

including corporations and limited liability companies currently subject to the franchise tax. The new margin tax also will apply to the following common entity types that are not currently subject to tax: general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, and joint ventures. The effective date of the margin tax is January 1, 2008, but the tax generally will be imposed on gross revenues generated in 2007 and thereafter (earlier for certain fiscal year taxpayers).

If the Trust is exempt from the margin tax at the Trust level as a passive entity, each Unit holder that is a business entity subject to the margin tax would generally include its share of the Trust’s revenues in its margin tax computation. If, however, the margin tax is imposed on the Trust at the Trust level, each such Unit holder would generally exclude its share of the Trust’s revenues from its margin tax calculation.

Trusts and partnerships that meet statutory requirements and receive at least 90% of their gross income from designated sources, including royalties from mineral properties, are generally exempt from the margin tax as “passive entities.” Virtually all of the income of the Trust consists of income from net overriding royalty interests (or net profits interests) that are treated as royalty income for federal income tax purposes. Although the income of the Trust is passive as it consists almost entirely of royalty and other non-operating mineral interests, there is currently no clear authority that the Trust satisfies all the statutory requirements for the exemption for passive entities to apply. Therefore, pending additional legislative action in the 2007 legislative session or the issuance of applicable administrative rules promulgated by the Texas Comptroller, it is uncertain whether the Trust would be exempt from the margin tax as a passive entity or subject to the margin tax at the Trust level.

Each Unit holder that is a business entity should consult his own tax advisor regarding the requirements for filing Texas, franchise and margin tax returns.

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, 2006 and 2005, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006. 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 consolidated financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2006 and 2005, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006, 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 effectiveness of the Trust’s internal control over financial reporting as of December 31, 2006, 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 13, 2007 expressed an unqualified opinion on the Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.

/s/ Deloitte & Touche LLP

Dallas, Texas
March 13, 2007


			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	$	5,135,136	$	5,135,136		0		0		0
Total	$	5,135,136	$	5,135,136		0		0		0


	2006			2005			2004
Trust Corpus, Beginning of Period	$	1,610,630		$	1,795,267		$	1,991,594
Amortization of Net Overriding Royalty Interests (Notes 2 and 3)		(171,416	)		(184,637	)		(196,327	)
Distributable Income		65,715,369			62,267,669			44,546,743
Distributions Declared		(65,715,369	)		(62,267,669	)		(44,546,743	)

Trust Corpus, End of Period	$	1,439,214		$	1,610,630		$	1,795,267