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and Section 906
PERMIAN BASIN ROYALTY TRUST ANNUAL REPORT & FORM 10-K 2005
[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. On December 12, 2005, BRI and ConocoPhillips announced a proposed transaction
pursuant to which ConocoPhillips would acquire BRI, subject to shareholder approval by BRI.
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
2005
High
Low
Paid
First Quarter
$
15.57
$
12.13
$
0.284149
Second Quarter
15.50
10.75
0.268627
Third Quarter
17.23
14.73
0.340939
Fourth Quarter
17.15
15.00
0.442249
Total for 2005
$
1.335964
1
Distributions
2004
High
Low
Paid
First Quarter
$
9.45
$
7.00
$
0.193657
Second Quarter
9.32
7.80
0.191053
Third Quarter
11.87
9.01
0.248159
Fourth Quarter
15.29
11.06
0.322889
Total for 2004
$
0.955758
Approximately 1,581 Unit holders of record held the 46,608,796 Units of the Trust at December31, 2005.
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-fifth 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, 2005, 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.
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, 2005, was $62,967,150
and interest income earned for the same period was $63,909. General and administrative expenses
amounted to $763,390. A total of $62,267,669 or 1.335964 per Unit, was distributed to Unit holders
during 2005. A discussion of factors affecting the distributions for 2005 may be found in the
Trustee’s Discussion and Analysis section of this report and the accompanying Form 10-K.
As of December 31, 2005, the Trust’s proved reserves were estimated at 6,850,000 Bbls of oil
and 26,532,000 Mcf of gas. The estimated future net revenues from
2
proved
reserves at December 31, 2005 amount to $518,074,000 or $11.12 per Unit. The present
value of estimated future net revenues discounted at 10% at December 31, 2005 was $293,351,000 or
$6.08 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 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. Riverhill will continue to perform all accounting operations
pertaining to the Texas Royalty properties.
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 2005, 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, 2006, and for the year ending
December 31, 2006. Unit holders owning Units in nominee name may obtain monthly tax information
from the Trustee upon request.
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, 2005, is approximately 9 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 782 gross (349 net) productive oil wells, 193 gross
(81 net) productive gas wells and 316 gross (137 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,
installation of larger capacity pumping equipment. Capital expenditures for remedial and
maintenance activities during 2005 totaled approximately $14.7 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 2006 capital expenditures budget with regard to the
Waddell Ranch properties should total approximately $30.3 million gross of which $14.3 million
gross is attributable to drilling, $15 million gross to workovers and recompletions, and $1 million
gross to facilities.
4
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 December31, 2005, was computed as shown in the table on the next page.
Gross Proceeds of Sales
From the Underlying Properties:
Oil Proceeds
$
43,967,934
$
17,415,261
$
32,078,721
$
12,296,982
$
24,418,227
$
9,454,914
$
20,543,224
$
7,785,749
$
26,477,679
$
9,524,586
Gas Proceeds
37,531,266
5,050,206
28,746,318
3,970,231
25,255,338
3,606,615
14,861,094
2,245,648
26,068,379
3,771,184
Total
81,499,200
22,465,467
60,825,039
16,267,213
49,673,565
13,061,529
35,404,318
10,031,397
52,546,058
13,295,770
Less:
Severance Tax
Oil
1,806,281
675,609
1,366,942
457,308
1,045,413
350,440
863,299
302,665
1,108,968
374,204
Gas
2,319,699
325,044
1,702,937
262,673
1,632,642
228,928
813,581
159,431
1,160,095
239,337
Other
42,505
—
42,763
252,906
26,850
—
72,397
—
—
—
Lease Operating Expense and Property Tax
Oil and Gas
12,191,168
963,563
9,391,083
894,383
10,540,850
823,331
9,424,724
933,646
9,086,468
605,125
Other Payments
50,000
Capital Expenditures
7,151,598
—
6,539,015
—
7,734,224
—
3,394,674
0
3,350,003
—
Total
23,511,251
1,964,216
19,042,740
1,867,270
20,979,979
1,402,699
14,568,674
1,395,742
14,755,534
1,218,666
Net Profits
57,987,949
20,501,251
41,782,299
14,399,943
28,693,586
11,658,830
20,835,643
8,635,655
37,790,524
12,077,104
Net Overriding Royalty Interest
75
%
95
%
75
%
95
%
75
%
95
%
75
%
95
%
75
%
95
%
Royalty Income
43,490,961
19,476,189
31,336,724
13,679,946
21,520,190
11,075,888
15,626,732
8,203,872
28,342,893
11,473,248
Total Royalty Income for Distribution
$
43,490,961
$
19,476,189
$
31,336,724
$
13,679,946
$
21,520,190
$
11,075,888
$
15,626,732
$
8,203,872
$
28,342,893
$
11,473,248
6
Discussion and Analysis
Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 2005
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 31st 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.
7
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, 2005, is
reported in the following table:
Year Ended December 31,
Royalties
2005
2004
2003
Total Revenue
$
62,967,150
$
45,016,670
$
32,596,081
100
%
100
%
100
%
Oil Revenue
38,924,579
27,180,560
17,927,843
62
%
60
%
55
%
Gas Revenue
24,042,571
17,836,110
14,668,235
38
%
40
%
45
%
Total Revenue/Unit
$
1.35097
$
.965841
$
.69935
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 2005, 2004 and 2003 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,
Royalties
2005
2004
2003
Oil Sales (Bbls)
827,275
779,052
699,402
Gas Sales (Mcf)
3,608,778
3,245,117
3,160,921
Underlying Properties
Oil
Total Oil Sales (Bbls)
1,258,584
1,222,579
1,200,844
Average Per Day (Bbls)
3,448
3,340
3,290
Average Price/Bbl
$
48.77
$
36.30
$
28.21
8
Year Ended December 31,
Royalties
2005
2004
2003
Gas
Total Gas Sales (Mcf)
6,132,716
5,975,867
6,243,956
Average Per Day (Mcf)
16,802
16,328
17,107
Average Price/Mcf
$
6.94
$
5.47
$
4.62
The average price of oil increased to $48.77 per barrel in 2005, up from $36.30 per barrel in
2004. In addition, the average price of gas increased from $5.47 per Mcf in 2004 to $6.94 per Mcf
in 2005.
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 6% from 2004 to 2005 primarily due to higher oil prices compared to previous years.
Total gas production increased approximately 11% from 2004 to 2005 primarily due to an increase in
capital expenditures for gas wells.
Total capital expenditures in 2005 used in the net overriding royalty calculation were
approximately $7.2 million compared to $6.5 million in 2004 and $7.7 million in 2003. During 2005,
there were 6 gross (3 net) wells drilled and completed on the Waddell Ranch properties. At
December 31, 2005, there were no wells in progress on the Waddell Ranch properties.
In 2005, lease operating expense and property taxes on the Waddell Ranch properties amounted
to approximately $12.2 million, which amount was higher than
2004 by $2.8 million.
The Trustee has been advised by BROG that for the period August 1, 1993, through January 1,2006, the oil from the Waddell Ranch was and will be sold under a competitive bid to a third party.
During 2005, the monthly royalty receipts were invested by the Trustee in U.S. Treasury
securities until the monthly distribution date, and earned interest
totaled $63,909. Interest
income for 2004 and 2003 was $ 19,883 and $13,937, respectively.
General
and administrative expenses in 2005 were $763,390 compared to $489,810 in 2004 and
$496,890 in 2003.
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.
Distributable income for 2003 was $32,113,125, or $.688993 per Unit.
9
Results of the Fourth Quarters of 2005 and 2004
Royalty income received by the Trust for the fourth quarter of 2005 amounted to $20,700,741 or
$.444138 per Unit. For the fourth quarter of 2004, the Trust received royalty income of
$15,117,305 or $.367255 per Unit. Interest income for the fourth quarter of 2005 amounted to
$27,098 compared to $9,045 for the fourth quarter of 2004. The increase in interest income can be
attributed primarily to an increase in funds available for investment and an increase in interest
rate. General and administrative expenses totaled $115,154 for the fourth quarter of 2005 compared
to $76,881 for the fourth quarter of 2004.
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 2004 are as follows:
Fourth Quarter
2005
2004
Royalties
Oil Sales (Bbls)
222,071
222,843
Gas Sales (Mcf)
991,092
994,151
Underlying Properties
Total Oil Sales (Bbls)
309,862
322,871
Average Per Day (Bbls)
3,368
3,509
Average Price/Bbls
$
58.88
$
43.87
Total Gas Sales (Mcf)
1,499,863
1,530,758
Average Per Day (Mcf)
16,303
16,639
Average Price/Mcf
$
8.70
$
6.18
The posted price of oil increased for the fourth quarter of 2005 compared to the fourth
quarter of 2004, resulting in an average price per barrel of $58.88 compared to $43.87 in the same
period of 2004. The average price of gas increased for the fourth quarter of 2005 compared to the
same period in 2004, resulting in an average price per Mcf of $8.70 compared to $6.18 in the fourth
quarter of 2004.
The Trustee has been advised that oil sales increased in 2005 compared to the same period in
2004 primarily due to higher capital expenditures in 2005 offsetting natural production declines.
Gas sales from the Underlying Properties increased in the fourth quarter of 2005 compared to the
same period in 2004 due to the same factors.
10
The Trust has been advised that no well was drilled and completed during the three months
ended December 31, 2005, and there were no wells in progress.
Off-Balance Sheet Arrangements.
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.
Therefore, the Trust has not engaged in any off-balance sheet arrangements.
Net Overriding Royalty Interests in Producing Oil and
Gas Properties - Net (Notes 2 and 3)
1,610,630
1,795,267
$
8,874,678
$
7,224,412
LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit Holders
$
7,264,048
$
5,429,145
Trust Corpus – 46,608,796 Units of Beneficial Interest
Authorized and Outstanding
1,610,630
1,795,267
$
8,874,678
$
7,224,412
STATEMENTS OF DISTRIBUTABLE INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2005
2005
2004
2003
Royalty Income (Notes 2 and 3)
$
62,967,150
$
45,016,670
$
32,596,078
Interest Income
63,909
19,883
13,937
63,031,059
45,036,553
32,610,015
Expenditures — General and
Administrative
763,390
489,810
496,890
Distributable Income
$
62,267,669
$
44,546,743
$
32,113,125
Distributable Income per Unit
(46,608,796 Units)
$
1.335964
$
.955758
$
.688993
12
STATEMENTS OF CHANGES IN TRUST CORPUS
FOR THE THREE YEARS ENDED DECEMBER 31, 2005
2005
2004
2003
Trust Corpus, Beginning of Period
$
1,795,267
$
1,991,594
$
2,172,393
Amortization of Net Overriding
Royalty Interests
(Notes 2 and 3)
(184,637
)
(196,327
)
(180,799
)
Distributable Income
62,267,669
44,546,743
32,113,125
Distributions Declared
(62,267,669
)
(44,546,743
)
(32,113,125
)
Trust Corpus, End of Period
$
1,610,630
$
1,795,267
$
1,991,594
The accompanying notes to financial statements are an integral part of these statements.
13
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
14
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 December31, 2005 and 2004, aggregated $9,364,586 and $9,179,949, 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
SFAS No. 123R “Accounting for Stock-Based Compensation” was issued in December 2004 and
provides new implementation guidance for stock-based compensation accounting. This Statement is
effective for public entities that do not file as small business issuers-as of the beginning of the
first interim or annual reporting period that begins after June 15, 2005. The Trust has no options
or other stock-based instruments and accordingly, the impact of this new Standard will not be
material to the financial statements of the Trust.
In
May 2005, the FASB issued Statement of Financial Accounting Standards
No. 154, “Accounting Changes and Error Corrections - A
Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires retrospective application, or the latest practical date, as the preferred method to report a change in accounting principle or correction of an error.
SFAS No. 154 is effective for accounting changes and corrections of
errors made in fiscal years beginning after December 15, 2005.
This new standard has no impact on the financial statements of the Trust.
In
March 2005, the FASB issued FASB Interpretation No. 47,
“Accounting for Conditional Asset Retirement Obligations,”
(“FIN 47”). FIN 47 clarifies the term conditional asset retirement obligation and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset
retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation
to perform an asset retirement activity; however the timing and/or
method of settling the obligation are conditional on a future event
that may or may not be within the control of the entity. FIN 47 is effective for fiscal years ending after December 15, 2005. This new standard has no impact on the financial statements of the Trust.
15
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 Royalties constitute “economic interests” in oil and gas properties for Federal income tax
purposes. Unit holders must report their share of the revenues of the Trust as ordinary income
from oil and gas royalties and are entitled to claim depletion with respect to such income.
The Trust has on file technical advice memoranda confirming the tax treatment described above.
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.
Unit holders should consult their tax advisors for further information.
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, 2005 (in thousands, except per Unit amounts):
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
16
Distributable
Income and
Royalty
Distributable
Distribution
2004
Income
Income
Per Unit
First Quarter
$
9,207
$
9,026
$
.193657
Second Quarter
9,046
8,905
.191053
Third Quarter
11,647
11,566
.248159
Fourth Quarter
15,117
15,050
.322889
Total
$
45,017
$
44,547
$
.955758
9. Subsequent Events
Subsequent to December 31,2005, the Trust declared the following distributions:
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, 2005 and 2004, and the related statements of distributable
income and changes in trust corpus for each of the three years in the period ended
December 31, 2005. 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, 2005 and 2004, and the distributable income and changes in trust corpus for each of the
three years in the period ended December 31, 2005, 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 December31, 2005, 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 14, 2006
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.