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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2006
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
Commission file number 1-8033
PERMIAN BASIN ROYALTY TRUST
(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust Indenture)
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| Texas
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75-6280532 |
| (State or Other Jurisdiction of
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(I.R.S. Employer Identification No.) |
| Incorporation or Organization) |
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Bank of America, N.A.
Trust Department
P.O. Box 830650
Dallas, Texas 75202
(Address of Principal Executive
Offices; Zip Code)
(Registrant’s Telephone Number, Including Area Code)
(214) 209-2400
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
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Name of Each Exchange on |
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Which Registered |
| Units of Beneficial Interest
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New York Stock Exchange |
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in
Rule 405 of the Securities Act. Yes þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation
S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated
filer” in Rule 12b-2 of the Exchange Act.
Large accelerated filer o Accelerated filer þ Non-accelerated filer o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Act). Yes o No þ
The aggregate market value of the voting and non-voting common equity held by non-affiliates
computed by reference to the price at which the common equity was last sold, or the average bid and
asked price of such common equity, as of the last business day of the registrant’s most recently
completed second fiscal quarter was $571,465,450.
At March 1, 2007, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
“Units of Beneficial Interest” at page 1; “Trustee’s Discussion and Analysis for the
Three-Year Period Ended December 31, 2006” at pages 8 through 10; “Results of the 4th Quarters of
2006 and 2005” at page 11; and “Statements of Assets, Liabilities and Trust Corpus,” “Statements of
Distributable Income,” “Statements of Changes in Trust Corpus,” “Notes to Financial Statements” and
“Report of Independent Registered Public Accounting Firm” at page 13 et seq., in registrant’s
Annual Report to security holders for fiscal year ended December 31, 2006 are incorporated herein
by reference for Item 5, Item 7 and Item 8 of Part II of this Report.
FORWARD LOOKING INFORMATION
Certain information included in this report contains, and other materials filed or to be filed
by the Trust with the Securities and Exchange Commission (as well as information included in oral
statements or other written statements made or to be made by the Trust) may contain or include,
forward looking statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Such forward looking
statements may be or may concern, among other things, capital expenditures, drilling activity,
development activities, production efforts and volumes, hydrocarbon prices and the results thereof,
and regulatory matters. Although the Trustee believes that the expectations reflected in such
forward looking statements are reasonable, such expectations are subject to numerous risks and
uncertainties and the Trustee can give no assurance that they will prove correct. There are many
factors, none of which is within the Trustee’s control, that may cause such expectations not to be
realized, including, among other things, factors such as actual oil and gas prices and the
recoverability of reserves, capital expenditures, general economic conditions, actions and policies
of petroleum-producing nations and other changes in the domestic and international energy markets
and the factors identified under Item 1A, “Risk Factors.” Such forward looking statements
generally are accompanied by words such as “estimate,” “expect,” “anticipate,” “goal,” “should,”
“assume,” “believe,” or other words that convey the uncertainty of future events or outcomes.
PART I
Item 1. Business
The Permian Basin Royalty Trust (the “Trust”) is an express trust created under the laws of
the state of Texas by the Permian Basin Royalty Trust Indenture (the “Trust Indenture”) entered
into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and The First
National Bank of Fort Worth, as Trustee. Bank of America, N.A., a banking association organized
under the laws of the United States, as the successor of The First National Bank of Fort Worth, is
now the Trustee of the Trust. The principal office of the Trust (sometimes referred to herein as
the “Registrant”) is located at 901 Main Street, Dallas, Texas (telephone number (214) 209-2400).
On October 23, 1980, the stockholders of Southland Royalty approved and authorized that
company’s conveyance of net overriding royalty interests (equivalent to net profits interests) to
the Trust for the benefit of the stockholders of Southland Royalty of record at the close of
business on the date of the conveyance consisting of a 75% net overriding royalty interest carved
out of that company’s fee mineral interests in the Waddell Ranch properties in Crane County, Texas
and a 95% net overriding royalty interest carved out of that company’s major producing royalty
properties in Texas. The conveyance of these interests (the “Royalties”) was made on November 3,
1980, effective as to production from and after November 1, 1980 at 7:00 a.m. The properties and
interests from which the Royalties were carved and which the Royalties now burden are collectively
referred to herein as the “Underlying Properties.” The Underlying Properties are more particularly
described under “Item 2. Properties” herein.
The function of the Trustee is to collect the income attributable to the Royalties, to pay all
expenses and charges of the Trust, and then distribute the remaining available income to the Unit
holders. The Trust is not empowered to carry on any business activity and has no employees, all
administrative functions being performed by the Trustee.
The Royalties constitute the principal asset of the Trust and the beneficial interests in the
Royalties are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust
equal to the number of shares of the common stock of Southland Royalty outstanding as of the close
of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of
business on November 3, 1980, received one Unit for each share of the common stock of Southland
Royalty then held.
In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington Northern Inc.
(“BNI”). In 1988, BNI transferred its natural resource operations to Burlington Resources Inc.
(“BRI”) as a result of which Southland Royalty became a wholly-owned indirect subsidiary of BRI.
As a result of this transfer, Meridian Oil Inc. (“MOI”), which was the parent company of Southland
Royalty, became a wholly owned direct subsidiary of BRI. In 1996, Southland Royalty was merged
with and into MOI. As a result of this merger, the separate corporate existence of Southland
Royalty ceased and MOI survived and succeeded to the ownership of all of the assets of Southland
Royalty and assumed all of its rights, powers, privileges, liabilities and obligations. In 1996,
MOI changed its name to Burlington Resources Oil & Gas Company, now Burlington Oil & Gas Company LP
(“BROG”). 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.
The term “net proceeds” is used in the above described conveyance and means the excess of
“gross proceeds” received by BROG during a particular period over “production costs” for such
period. “Gross proceeds” means the amount received by BROG (or any subsequent owner of the
Underlying Properties) from the sale of the production attributable to the Underlying Properties,
subject to certain adjustments. “Production costs” means, generally, costs incurred on an accrual
basis in operating the Underlying Properties, including both capital and non-capital costs; for
example, development drilling, production and processing costs, applicable taxes, and operating
charges. If production costs exceed gross proceeds in any month, the excess is recovered out of
future gross proceeds prior to the making of further payment to the Trust, but the Trust is not
liable for any production costs or liabilities attributable to these properties and interests or
the minerals produced therefrom. If at any time the Trust receives more than the
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amount due from the Royalties, it shall not be obligated to return such overpayment, but the
amounts payable to it for any subsequent period shall be reduced by such overpaid amount, plus
interest, at a rate specified in the conveyance.
To the extent it has the legal right to do so, BROG is responsible for marketing the
production from such properties and interests, either under existing sales contracts or under
future arrangements at the best prices and on the best terms it shall deem reasonably obtainable in
the circumstances. BROG also has the obligation to maintain books and records sufficient to
determine the amounts payable to the Trustee. BROG, however, can sell its interests in the
Underlying Properties.
Proceeds from production in the first month are generally received by BROG in the second
month, the net proceeds attributable to the Royalties are paid by BROG to the Trustee in the third
month and distribution by the Trustee to the Unit holders is made in the fourth month. The
identity of Unit holders entitled to a distribution will generally be determined as of the last
business day of each calendar month (the “monthly record date”). The amount of each monthly
distribution will generally be determined and announced ten days before the monthly record date.
Unit holders of record as of the monthly record date will be entitled to receive the calculated
monthly distribution amount for each month on or before ten business days after the monthly record
date. The aggregate monthly distribution amount is the excess of (i) net revenues from the Trust
properties, plus any decrease in cash reserves previously established for contingent liabilities
and any other cash receipts of the Trust over (ii) the expenses and payments of liabilities of the
Trust plus any net increase in cash reserves for contingent liabilities.
Cash held by the Trustee as a reserve for liabilities or contingencies (which reserves may be
established by the Trustee in its discretion) or pending distribution is placed, at the Trustee’s
discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any
agency thereof, repurchase agreements secured by obligations issued by the United States or any
agency thereof, or certificates of deposit of banks having a capital surplus and undivided profits
in excess of $50,000,000, subject, in each case, to certain other qualifying conditions.
The income to the Trust attributable to the Royalties is not subject in material respects to
seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or
concessions. The Trust conducts no research activities. The Trust has no employees since all
administrative functions are performed by the Trustee.
BROG has advised the Trustee that it believes that comparable revenues could be obtained in
the event of a change in purchasers of production.
Website/SEC Filings
Our Internet address is http://www.pbt-permianbasintrust.com. You can review, free of
charge, the filings the Trust has made with respect to its annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. We shall post
these reports as soon as reasonably practicable after we electronically file them with, or furnish
them to the SEC.
Item 1A. Risk Factors
Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors;
Lower prices could reduce the net proceeds payable to the Trust and Trust distributions.
The Trust’s monthly distributions are highly dependent upon the prices realized from the sale
of crude oil and natural gas and a material decrease in such prices could reduce the amount of cash
distributions paid to Unit holders. Crude oil and natural gas prices can fluctuate widely on a
month-to-month basis in response to a variety of factors that are beyond the control of the Trust.
Factors that contribute to price fluctuation include, among others:
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political conditions in major oil producing regions, especially in the Middle East; |
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worldwide economic conditions; |
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weather conditions; |
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the supply and price of domestic and foreign crude oil or natural gas; |
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the level of consumer demand; |
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the price and availability of alternative fuels; |
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the proximity to, and capacity of, transportation facilities; |
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the effect of worldwide energy conservation measures; and |
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the nature and extent of governmental regulation and taxation. |
When crude oil and natural gas prices decline, the Trust is affected in two ways. First, net
income from the Royalties is reduced. Second, exploration and development activity on the
Underlying Properties may decline as some projects may become uneconomic and are either delayed or
eliminated. It is impossible to predict future crude oil and natural gas price movements, and this
reduces the predictability of future cash distributions to Unit holders.
Increased production and development costs attributable to the Royalties will result in decreased
Trust distributions unless revenues also increase.
Production and development costs attributable to the Royalties are deducted in the calculation
of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs
will directly decrease or increase the amount received by the Trust from the Royalties. Production
and development costs are impacted by increases in commodity prices, both directly, through
commodity price dependent costs, such as electricity, and indirectly, as a result of demand driven
increases in costs of oilfield goods and services. For example, the costs of electricity that will
be included in production and development costs deducted in calculating the Trust’s share of 2007
net proceeds could increase compared to the electrical costs incurred during 2006 principally as a
result of higher fuel surcharges which could be charged by the third party electricity provider in
response to the higher costs of natural gas consumed to generate the electricity. These increased
costs could reduce the Trust share of 2007 net proceeds below the level that would exist if such
costs remained at the level experienced in 2006. If production and development costs attributable
to the Royalties exceed the gross proceeds related to production from the Underlying Properties,
the Trust will not receive net proceeds until future proceeds from production exceed the total of
the excess costs plus accrued interest during the deficit period. Development activities may not
generate sufficient additional proceeds to repay the costs.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could
cause both estimated reserves and estimated future net revenues to be too high, leading to
write-downs of estimated reserves.
The value of the Units will depend upon, among other things, the reserves attributable to the
Royalties from the Underlying Properties. The calculations of proved reserves and estimating
reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon
various assumptions regarding future production levels, prices and costs that may prove to be
incorrect over time.
The accuracy of any reserve estimate is a function of the quality of available data,
engineering interpretation and judgment, and the assumptions used regarding the quantities of
recoverable crude oil and
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natural gas and the future prices of crude oil and natural gas. Petroleum engineers consider many
factors and make many assumptions in estimating reserves. Those factors and assumptions include:
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historical production from the area compared with production rates from similar
producing areas; |
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the effects of governmental regulation; |
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assumptions about future commodity prices, production and development costs, taxes, and
capital expenditures; |
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the availability of enhanced recovery techniques; and |
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relationships with landowners, working interest partners, pipeline companies and others. |
Changes in any of these factors and assumptions can materially change reserve and future net
revenue estimates. The Trust’s estimate of reserves and future net revenues is further complicated
because the Trust holds an interest in net overriding royalties and does not own a specific
percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and
expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust,
will vary from estimates and those variations could be material. Results of drilling, testing and
production after the date of those estimates may require substantial downward revisions or
write-downs of reserves.
The assets of the Trust are depleting assets and, if BROG and the other operators developing the
Underlying Properties do not perform additional development projects, the assets may deplete
faster than expected. Eventually, the assets of the Trust will cease to produce in commercial
quantities and the Trust will cease to receive proceeds from such assets. In addition, a reduction
in depletion tax benefits may reduce the market value of the Units.
The net proceeds payable to the Trust are derived from the sale of depleting assets. The
reduction in proved reserve quantities is a common measure of depletion. Future maintenance and
development projects on the Underlying Properties will affect the quantity of proved reserves and
can offset the reduction in proved reserves. The timing and size of these projects will depend on
the market prices of crude oil and natural gas. If the operators developing the Underlying
Properties, including BROG, do not implement additional maintenance and development projects, the
future rate of production decline of proved reserves may be higher than the rate currently expected
by the Trust.
Because the net proceeds payable to the Trust are derived from the sale of depleting assets,
the portion of distributions to Unit holders attributable to depletion may be considered a return
of capital as opposed to a return on investment. Distributions that are a return of capital will
ultimately diminish the depletion tax benefits available to the Unit holders, which could reduce
the market value of the Units over time. Eventually, the Royalties will cease to produce in
commercial quantities and the Trust will, therefore, cease to receive any distributions of net
proceeds therefrom.
The market price for the Units may not reflect the value of the royalty interests held by the
Trust.
The public trading price for the Units tends to be tied to the recent and expected levels of
cash distribution on the Units. The amounts available for distribution by the Trust vary in
response to numerous factors outside the control of the Trust, including prevailing prices for
crude oil and natural gas produced from the Royalties. The market price is not necessarily
indicative of the value that the Trust would realize if it sold those Royalties to a third party
buyer. In addition, such market price is not necessarily reflective of the fact that since the
assets of the Trust are depleting assets, a portion of each cash distribution paid on the Units
should be considered by investors as a return of capital, with the remainder being considered as a
return on investment. There is no guarantee that distributions made to a Unit holder over the life
of these depleting assets will equal or exceed the purchase price paid by the Unit holder.
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Operational risks and hazards associated with the development of the Underlying Properties may
decrease Trust distributions.
There are operational risks and hazards associated with the production and transportation of
crude oil and natural gas, including without limitation natural disasters, blowouts, explosions,
fires, leakage of crude oil or natural gas, releases of other hazardous materials, mechanical
failures, cratering, and pollution. Any of these or similar occurrences could result in the
interruption or cessation of operations, personal injury or loss of life, property damage, damage
to productive formations or equipment, or damage to the environment or natural resources, or
cleanup obligations. The operation of oil and gas properties is also subject to various laws and
regulations. Non-compliance with such laws and regulations could subject the operator to
additional costs, sanctions or liabilities. The uninsured costs resulting from any of these or
similar occurrences could be deducted as a cost of production in calculating the net proceeds
payable to the Trust and would therefore reduce Trust distributions by the amount of such uninsured
costs.
As oil and gas production from the Waddell Ranch properties is processed through a single
facility, future distributions from those properties may be particularly susceptible to such risks.
A partial or complete shut-down of operations at that facility could disrupt the flow of royalty
payments to the Trust and, accordingly, the Trust’s distributions to its Unit holders. In
addition, although BROG is the operator of record of the properties burdened by the Waddell Ranch
overriding royalty interests, none of the Trustee, the Unit holders or BROG has an operating
interest in the properties burdened by the Texas Royalty properties’ overriding royalty interests.
As a result, these parties are not in a position to eliminate or mitigate the above or similar
occurrences with respect to such properties and may not become aware of such occurrences prior to
any reduction in Trust distributions which may result therefrom.
Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the
market price of the Units.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as
the military or other actions taken in response, cause instability in the global financial and
energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely
affect Trust distributions or the market price of the Units in unpredictable ways, including
through the disruption of fuel supplies and markets, increased volatility in crude oil and natural
gas prices, or the possibility that the infrastructure on which the operators developing the
Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.
Unit holders and the Trustee have no influence over the operations on, or future development of,
the Underlying Properties.
Neither the Trustee nor the Unit holders can influence or control the operations on, or future
development of, the Underlying Properties. The failure of an operator to conduct its operations,
discharge its obligations, deal with regulatory agencies or comply with laws, rules and
regulations, including environmental laws and regulations, in a proper manner could have an adverse
effect on the net proceeds payable to the Trust. The current operators developing the Underlying
Properties are under no obligation to continue operations on the Underlying Properties. Neither the
Trustee nor the Unit holders have the right to replace an operator.
The operators developing the Texas Royalty properties have no duty to protect the interests of the
Unit holders, and do not have sole discretion regarding development activities on the Underlying
Properties.
Under the terms of a typical operating agreement relating to oil and gas properties, the
operator owes a duty to working interest owners to conduct its operations on the properties in a
good and workmanlike manner and in accordance with its best judgment of what a prudent operator
would do under the same or similar circumstances. BROG is the operator of record of the Waddell
Ranch overriding royalty interests and in such capacity owes the Trust a contractual duty under the
conveyance agreement for that overriding royalty interest to operate the Waddell Ranch properties
in good faith and in accordance with a prudent operator standard. The operators of the properties
burdened by the Texas Royalty properties’
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overriding royalty interests, however, have no contractual or fiduciary duty to protect the
interests of the Trust or the Unit holders other than indirectly through its duty of prudent
operations to the unaffiliated owners of the working interests in those properties.
In addition, even if an operator, including BROG in the case of the Waddell Ranch properties,
concludes that a particular development operation is prudent on a property, it may be unable to
undertake such activity unless it is approved by the requisite approval of the working interest
owners of such properties (typically the owners of at least a majority of the working interests).
Even if the Trust concludes that such activities in respect of any of its overriding royalty
interests would be in its best interests, it has no right to cause those activities to be
undertaken.
The operator developing any Underlying Property may transfer its interest in the property without
the consent of the Trust or the Unit holders.
Any operator developing any of the Underlying Properties may at any time transfer all or part
of its interest in the Underlying Properties to another party. Neither the Trust nor the Unit
holders are entitled to vote on any transfer of the properties underlying the Royalties, and the
Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred
property will continue to be subject to the Royalties, but the net proceeds from the transferred
property will be calculated separately and paid by the transferee. The transferee will be
responsible for all of the transferor’s obligations relating to calculating, reporting and paying
to the Trust the Royalties from the transferred property, and the transferor will have no
continuing obligation to the Trust for that property.
The operator developing any Underlying Property may abandon the property, thereby terminating the
Royalties payable to the Trust.
The operators developing the Underlying Properties, or any transferee thereof, may abandon any
well or property without the consent of the Trust or the Unit holders if they reasonably believe
that the well or property can no longer produce in commercially economic quantities. This could
result in the termination of the Royalties relating to the abandoned well or property.
The Royalties can be sold and the Trust would be terminated.
The Trustee must sell the Royalties if the holders of 75% or more of the Units approve the
sale or vote to terminate the Trust. The Trustee must also sell the Royalties if they fail to
generate net revenue for the Trust of at least $1,000,000 per year over any consecutive two-year
period. Sale of all of the Royalties will terminate the Trust. The net proceeds of any sale will be
distributed to the Unit holders.
Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights
against the current or future operators developing the Underlying Properties.
The voting rights of a Unit holder are more limited than those of stockholders of most public
corporations. For example, there is no requirement for annual meetings of Unit holders or for an
annual or other periodic re-election of the Trustee.
The Trust indenture and related trust law permit the Trustee and the Trust to sue BROG,
Riverhill Energy Corporation or any other future operators developing the Underlying Properties to
compel them to fulfill the terms of the conveyance of the Royalties. If the Trustee does not take
appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would
likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified
actions. Unit holders probably would not be able to sue BROG, Riverhill Energy Corporation or any
other future operators developing the Underlying Properties.
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Financial information of the Trust is not prepared in accordance with GAAP.
The financial statements of the Trust are 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, or GAAP. Although this basis of accounting is permitted for royalty trusts by
the U.S. Securities and Exchange Commission, the financial statements of the Trust differ from GAAP
financial statements because revenues are not accrued in the month of production and cash reserves
may be established for specified contingencies and deducted which could not be accrued in GAAP
financial statements.
The limited liability of the Unit holders is uncertain.
The Unit holders are not protected from the liabilities of the Trust to the same extent that a
shareholder would be protected from a corporation’s liabilities. The structure of the Trust does
not include the interposition of a limited liability entity such as a corporation or limited
partnership which would provide further limited liability protection to Unit holders. While the
Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such
liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are
unsettled on this point, a holder of Units may be jointly and severally liable for any liability of
the Trust if the satisfaction of such liability was not contractually limited to the assets of the
Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a
result, Unit holders may be exposed to personal liability.
If it is determined that the Trust is subject to the Texas margin tax, the Trustee may have to
withhold a disproportionate amount from future distributions to pay the tax liability.
The Trustee does not intend to pay any amounts for the new Texas margin tax for tax year 2007,
based on the assumption that the Trust is exempt from tax as a passive entity; however, there is
currently no clear statutory authority that the Trust meets requirements for the margin tax
exemption as a passive entity. If it is subsequently determined that the Trust is not exempt from
the margin tax, the Trust would be required to deduct and withhold from future distributions the
amounts necessary to pay the margin tax for the entire 2007 year, including the tax liability
accruing on income distributed after December 2006 attributable to 2007 Trust revenues from which
no tax was withheld. For more information about the margin tax, see Note 9 to the Trust’s
financial statements contained in the Trust’s Annual Report to security holders.
Item 1B. Unresolved Staff Comments
The
Trust has not received any written comments from the Securities and
Exchange Commission staff regarding its
periodic or current reports under the Act within the 180 days preceding December 31, 2006, which
comments remain unresolved.
Item 2. Properties
The net overriding royalties conveyed to the Trust (the “Royalties”) include: (1) a 75% net
overriding royalty carved out of Southland Royalty’s fee mineral interests in the Waddell Ranch in
Crane County, Texas (the “Waddell Ranch properties”); and (2) a 95% net overriding royalty carved
out of Southland Royalty’s major producing royalty interests in Texas (the “Texas Royalty
properties”). The net overriding royalty for the Texas Royalty properties is subject to the
provisions of the lease agreements under which such royalties were created. References below to
“net” wells and acres are to the interests of BROG (from which the Royalties were carved) in the
“gross” wells and acres.
The following information under this Item 2 is based upon data and information, including
audited computation statements, furnished to the Trustee by BROG and Riverhill Energy.
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PRODUCING ACREAGE, WELLS AND DRILLING
Waddell Ranch Properties. The Waddell Ranch properties consist of 76,922 gross (33,246 net)
producing acres. A majority of the proved reserves are attributable to six fields: Dune, Sand
Hills (Judkins), Sand Hills (McKnight), Sand Hills (Tubb), University-Waddell (Devonian) and
Waddell. At
December 31, 2006, the Waddell Ranch properties contained 800 gross (353 (net) productive oil
wells, 205 gross (97 net)] productive gas wells and 309 gross (134 net) injection wells.
BROG is operator of record of the Waddell Ranch properties. All field, technical and
accounting operations have been contracted by an agreement between the working interest owners and
Schlumberger Integrated Project Management (IPM) but remain under the direction of BROG.
The Waddell Ranch properties are mature producing properties, and all of the major oil fields
are currently being waterflooded for the purpose of facilitating enhanced recovery. Proved
reserves and estimated future net revenues attributable to the properties are included in the
reserve reports summarized below. BROG does not own the full working interest in any of the tracts
constituting the Waddell Ranch properties and, therefore, implementation of any development
programs will require approvals of other working interest holders as well as BROG. In addition,
implementation of any development programs will be dependent upon oil and gas prices currently
being received and anticipated to be received in the future. There were 23 gross (11 net) wells
drilled and completed on the Waddell Ranch properties during 2006. At December 31, 2006, there
were 3 drill wells and 6 workovers in progress on the Waddell Ranch properties. There were 6 gross
(3 net) wells drilled and completed on the Waddell Ranch properties during 2005. At December 31,
2005 there were no wells in progress on the Waddell Ranch properties. There were 4 gross (2 net)
wells drilled and completed on the Waddell Ranch properties during 2004. At December 31, 2004
there were no wells in progress on the Waddell Ranch properties.
BROG has advised the Trustee that the total amount of capital expenditures for 2006 with
regard to the Waddell Ranch properties totaled $35.6 million. Capital expenditures include the
cost of remedial and maintenance activities. This amount spent is approximately $12.3 million
more than the budgeted amount projected by BROG for 2006. BROG has advised the Trustee that the
capital expenditures budget for 2007 totals approximately $32.4 million, of which approximately
$18.9 million (gross) is attributable to the 2007 drilling program, and $12.4 million (gross) to
workovers and recompletions. Accordingly, there is a 9.0% decrease in capital expenditures for
2007 as compared with the 2006 capital expenditures. The major reason for the variance is the
decrease in the number of planned capital drill wells. There will be 20 new drill wells in 2007 as
compared to 26 in 2006.
Texas Royalty Properties. The Texas Royalty properties consist of royalty interests in mature
producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle
Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others. The
Texas Royalty properties contain approximately 303,000 gross (approximately 51,000 net) producing
acres. Detailed information concerning the number of wells on royalty properties is not generally
available to the owners of royalty interests. Consequently, an accurate count of the number of
wells located on the Texas Royalty properties cannot readily be obtained.
In February 1997, BROG sold its interests in the Texas Royalty properties that are subject to
the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (“Texas Royalty
Conveyance”) to Riverhill Energy Corporation (“Riverhill Energy”), which was then a wholly-owned
subsidiary of Riverhill Capital Corporation (“Riverhill Capital”) and an affiliate of Coastal
Management Corporation (“CMC”). At the time of such sale, Riverhill Capital was a privately owned
Texas corporation with offices in Bryan and Midland, Texas. The Trustee was informed by BROG that,
as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the requirements
upon and the responsibilities of BROG under the Texas Royalty Conveyance with regard to the Texas
Royalty properties. BROG and Riverhill Energy further advised the Trustee that all accounting
operations pertaining to the Texas Royalty properties were being performed by Riverhill Energy.
10
The Trustee has been advised that, effective April 1, 1998, Schlumberger Technology
Corporation (“STC”) acquired all of the shares of stock at Riverhill Capital. Prior to the
acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital.
The Trustee has further been advised, in accordance with the STC acquisition of Riverhill Capital,
the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill
Energy. Effective January 1, 2001 CMC merged into STC. Thus, the ownership in the Texas Royalty
properties remained in Riverhill Energy.
The Trustee has been advised that as of May 1, 2000, the accounting operations, pertaining to
the Texas Royalty properties, were being transferred from STC to Riverhill Energy. STC currently
conducts all field, technical and accounting operations, on behalf of BROG, with regard to the
Waddell Ranch properties. STC currently provides summary reporting of monthly results for both the
Texas Royalty properties and the Waddell Ranch properties.
Well Count and Acreage Summary. The following table shows as of December 31, 2006, the gross
and net producing wells and acres for the BROG and Riverhill Energy interests. The net wells and
acres are determined by multiplying the gross wells or acres by the BROG and Riverhill Energy
interests owner’s working interest in the wells or acres. There is very little undeveloped acreage
held by the Trust, and all this is held by production.
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
NUMBER OF WELLS |
|
ACRES |
| |
|
Gross |
|
Net |
|
Gross |
|
Net |
BROG and Riverhill Energy Interests |
|
|
1,313 |
|
|
|
589 |
|
|
|
76,922 |
|
|
|
33,246 |
|
OIL AND GAS PRODUCTION
The Trust recognizes production during the month in which the related distribution is
received. Production of oil and gas attributable to the Royalties and the Underlying Properties
and the related average sales prices attributable to the Underlying Properties for the three years
ended December 31, 2006, excluding portions attributable to the adjustments discussed below, were
as follows:
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Waddell Ranch |
|
Texas Royalty |
|
|
| |
|
Properties |
|
Properties |
|
Total |
| |
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
|
2006 |
|
2005 |
|
2004 |
Royalties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (barrels) |
|
|
429,052 |
|
|
|
501,499 |
|
|
|
471,441 |
|
|
|
320,897 |
|
|
|
325,776 |
|
|
|
307,611 |
|
|
|
749,949 |
|
|
|
827,275 |
|
|
|
779,052 |
|
Gas (Mcf) |
|
|
2,640,873 |
|
|
|
3,052,103 |
|
|
|
2,642,599 |
|
|
|
513,918 |
|
|
|
556,675 |
|
|
|
602,518 |
|
|
|
3,154,791 |
|
|
|
3,608,778 |
|
|
|
3,245,117 |
|
Underlying Properties: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (barrels) |
|
|
863,198 |
|
|
|
899,197 |
|
|
|
873,466 |
|
|
|
357,967 |
|
|
|
359,387 |
|
|
|
349,113 |
|
|
|
1,221,165 |
|
|
|
1,258,584 |
|
|
|
1,222,579 |
|
Gas (Mcf) |
|
|
5,396,777 |
|
|
|
5,517,845 |
|
|
|
5,291,295 |
|
|
|
576,411 |
|
|
|
614,871 |
|
|
|
684,572 |
|
|
|
5,973,188 |
|
|
|
6,132,716 |
|
|
|
5,975,867 |
|
Average Price
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil/barrel |
|
|
59.15 |
|
|
$ |
49.35 |
|
|
$ |
37.13 |
|
|
|
59.50 |
|
|
$ |
48.97 |
|
|
$ |
34.89 |
|
|
|
59.30 |
|
|
$ |
49.20 |
|
|
$ |
36.25 |
|
Gas/Mcf |
|
|
7.63 |
|
|
$ |
6.90 |
|
|
$ |
5.47 |
|
|
|
10.02 |
|
|
$ |
8.22 |
|
|
$ |
5.79 |
|
|
|
8.02 |
|
|
$ |
7.11 |
|
|
$ |
5.53 |
|
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.
11
Waddell Ranch properties lease operating expense for 2006 was $28 million (gross) and $25
million (net). The lease operating expense increased 3% from 2005 to 2006 primarily because of an
increase in electrical costs. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis
was $6.95/bbl as compared to $6.05 in 2005 and $5.32 in 2004.
PRICING INFORMATION
Reference is made to the caption entitled “Regulation” for information as to federal
regulation of prices of natural gas. The following paragraphs provide information regarding sales
of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill Energy is not
furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.
Oil. The Trustee has been advised by BROG that for the period August 1, 1993 through
February 28, 2007, the oil from the Ranch properties was and will be sold under a
competitive bid to independent third parties.
Gas. The gas produced from the Waddell Ranch properties is processed through a natural gas
processing plant and sold at the tailgate of the plant. Plant products are marketed by Burlington
Resources Trading Inc., an indirect subsidiary of BRI. The processor of the gas (Warren Petroleum
Company, L.P.) receives 15% of the liquids and residue gas as a fee for gathering, compression,
treating and processing the gas.
OIL AND GAS RESERVES
The following are definitions adopted by the Securities and Exchange Commission (“SEC”) and
the Financial Accounting Standards Board which are applicable to terms used within this Item:
“Proved reserves” are those estimated quantities of crude oil, natural gas and natural gas
liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty
to be recoverable in the future from known oil and gas reservoirs under existing economic and
operating conditions.
“Proved developed reserves” are those proved reserves which can be expected to be recovered
through existing wells with existing equipment and operating methods.
“Proved undeveloped reserves” are those proved reserves which are expected to be recovered
from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is
required.
“Estimated future net revenues” are computed by applying current prices of oil and gas (with
consideration of price changes only to the extent provided by contractual arrangements and allowed
by federal regulation) to estimated future production of proved oil and gas reserves as of the date
of the latest balance sheet presented, less estimated future expenditures (based on current costs)
to be incurred in developing and producing the proved reserves, and assuming continuation of
existing economic conditions.
“Estimated future net revenues” are sometimes referred to herein as “estimated future net cash
flows.”
“Present value of estimated future net revenues” is computed using the estimated future net
revenues and a discount factor of 10%.
The independent petroleum engineers’ reports as to the proved oil and gas reserves
attributable to the Royalties conveyed to the Trust were obtained from Cawley, Gillespie &
Associates, Inc. The
12
following table presents a reconciliation of proved reserve quantities from
January 1, 2004 through December 31, 2006 (in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Waddell Ranch |
|
Texas Royalty |
|
|
| |
|
Properties |
|
Properties |
|
Total |
| |
|
Oil |
|
Gas |
|
Oil |
|
Gas |
|
Oil |
|
Gas |
| |
|
(Bbls) |
|
(Mcf) |
|
(Bbls) |
|
(Mcf) |
|
(Bbls) |
|
(Mcf) |
January 1, 2004 |
|
|
3,531 |
|
|
|
21,822 |
|
|
|
3,376 |
|
|
|
5,425 |
|
|
|
6,907 |
|
|
|
27,247 |
|
Extensions, discoveries, and
other additions |
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
|
|
0 |
|
Revisions of previous estimates |
|
|
546 |
|
|
|
2,692 |
|
|
|
434 |
|
|
|
1,091 |
|
|
|
980 |
|
|
|
3,783 |
|
Production |
|
|
(471 |
) |
|
|
(2,643 |
) |
|
|
(308 |
) |
|
|
(602 |
) |
|
|
(779 |
) |
|
|
(3,245 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2004 |
|
|
3,606 |
|
|
|
21,871 |
|
|
|
3,502 |
|
|
|
5,914 |
|
|
|
7,108 |
|
|
|
27,785 |
|
Extensions, discoveries, and
other additions |
|
|
84 |
|
|
|
415 |
|
|
|
0 |
|
|
|
0 |
|
|
|
84 |
|
|
|
415 |
|
Revisions of previous estimates |
|
|
126 |
|
|
|
1,695 |
|
|
|
359 |
|
|
|
246 |
|
|
|
485 |
|
|
|
1,941 |
|
Production |
|
|
(501 |
) |
|
|
(3,052 |
) |
|
|
(326 |
) |
|
|
(557 |
) |
|
|
(827 |
) |
|
|
(3,609 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2005 |
|
|
3,315 |
|
|
|
20,929 |
|
|
|
3,535 |
|
|
|
5,603 |
|
|
|
6,850 |
|
|
|
26,532 |
|
Extensions, discoveries, and
other additions |
|
|
33 |
|
|
|
490 |
|
|
|
0 |
|
|
|
2 |
|
|
|
33 |
|
|
|
492 |
|
Revisions of previous estimates |
|
|
233 |
|
|
|
208 |
|
|
|
212 |
|
|
|
53 |
|
|
|
445 |
|
|
|
261 |
|
Production |
|
|
(429 |
) |
|
|
(2,641 |
) |
|
|
(321 |
) |
|
|
(514 |
) |
|
|
(750 |
) |
|
|
(3,155 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2006 |
|
|
3,152 |
|
|
|
18,986 |
|
|
|
3,426 |
|
|
|
5,144 |
|
|
|
6,578 |
|
|
|
24,130 |
|
Estimated quantities of proved developed reserves of crude oil and natural gas as of
December 31, 2006, 2005 and 2004 were as follows (in thousands):
| |
|
|
|
|
|
|
|
|
| |
|
Crude Oil |
|
Natural Gas |
| |
|
(Bbls) |
|
(Mcf) |
December 31, 2006 |
|
|
6,443 |
|
|
|
23,233 |
|
December 31, 2005 |
|
|
6,764 |
|
|
|
25,877 |
|
December 31, 2004 |
|
|
6,988 |
|
|
|
27,545 |
|
The Financial Accounting Standards Board requires supplemental disclosures for oil and gas
producers based on a standardized measure of discounted future net cash flows relating to proved
oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by
applying year-end prices of oil and gas relating to the enterprise’s proved reserves to the
year-end quantities of those reserves. Future price changes are only considered to the extent
provided by contractual arrangements in existence at year end. The standardized measure of
discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the
timing of future cash flows relating to proved oil and gas reserves.
Estimates of proved oil and gas reserves are by their very nature imprecise. Estimates of future
net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and
gas and other variables.
13
The 2006, 2005 and 2004 change in the standardized measure of discounted future net cash revenues
related to future royalty income from proved reserves attributable to the Royalties discounted at
10% is as follows (in thousands):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
Waddell Ranch |
|
|
Texas Royalty |
|
|
|
|
| |
|
Properties |
|
|
Properties |
|
|
Total |
|
| |
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
January 1 |
|
$ |
188,697 |
|
|
$ |
156,014 |
|
|
$ |
117,755 |
|
|
$ |
104,654 |
|
|
$ |
81,179 |
|
|
$ |
57,796 |
|
|
$ |
293,351 |
|
|
$ |
237,193 |
|
|
$ |
175,551 |
|
Extensions,
discoveries, and
other additions |
|
|
2,108 |
|
|
|
3,743 |
|
|
|
0 |
|
|
|
15 |
|
|
|
0 |
|
|
|
0 |
|
|
|
2,123 |
|
|
|
3,743 |
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accretion of discount |
|
|
18,870 |
|
|
|
15,601 |
|
|
|
11,776 |
|
|
|
10,465 |
|
|
|
8,118 |
|
|
|
5,780 |
|
|
|
29,335 |
|
|
|
23,719 |
|
|
|
17,556 |
|
Revisions of
previous estimates
and other |
|
|
(3,224 |
) |
|
|
56,830 |
|
|
|
57,820 |
|
|
|
10,793 |
|
|
|
34,833 |
|
|
|
31,283 |
|
|
|
7,569 |
|
|
|
91,663 |
|
|
|
89,103 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income |
|
|
(43,143 |
) |
|
|
(43,491 |
) |
|
|
(31,337 |
) |
|
|
(23,264 |
) |
|
|
(19,476 |
) |
|
|
(13,680 |
) |
|
|
(66,407 |
) |
|
|
(62,967 |
) |
|
|
(45,017 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31 |
|
$ |
163,308 |
|
|
$ |
188,697 |
|
|
$ |
156,014 |
|
|
$ |
102,663 |
|
|
$ |
104,654 |
|
|
$ |
81,179 |
|
|
$ |
265,971 |
|
|
$ |
293,351 |
|
|
$ |
237,193 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas prices of $53.44 and $53.47 per barrel and $5.37 and $7.69 per Mcf were used to
determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty
properties, respectively, at December 31, 2006. The downward revisions of both reserves and
discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties
are primarily due to decrease in oil and gas prices from 2005 to 2006.
Oil and gas prices of $54.89 and $54.02 per barrel and $6.38 and $7.06 per Mcf were used to
determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty
properties, respectively, at December 31, 2005. The upward revisions of both reserves and
discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties
were mostly due to increase in oil and gas prices from 2004 to 2005.
Oil and gas prices of $37.90 and $39.07 per barrel and $6.22 and $6.61 per Mcf, respectively, were
used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas
Royalty properties, respectively, at December 31, 2004. The upward revisions of both reserves and
discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties
were primarily due to increases in oil and gas prices from 2003 to 2004.
The following presents estimated future net revenue and the present value of estimated future net
revenue attributable to the Royalties, for each of the years ended December 31, 2006, 2005 and 2004
(in thousands except amounts per Unit):
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
2006 |
|
|
2005 |
|
|
2004 |
|
| |
|
Estimated |
|
|
Present |
|
|
Estimated |
|
|
Present |
|
|
Estimated |
|
|
Present |
|
| |
|
Future Net |
|
|
Value at |
|
|
Future Net |
|
|
Value at |
|
|
Future Net |
|
|
Value at |
|
| |
|
Revenue |
|
|
10% |
|
|
Revenue |
|
|
10% |
|
|
Revenue |
|
|
10% |
|
Total Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Waddell Ranch properties |
|
$ |
255,703 |
|
|
$ |
163,308 |
|
|
$ |
298,417 |
|
|
$ |
188,697 |
|
|
$ |
257,563 |
|
|
$ |
156,014 |
|
Texas Royalty properties |
|
$ |
212,486 |
|
|
$ |
102,663 |
|
|
$ |
219,657 |
|
|
$ |
104,654 |
|
|
$ |
167,402 |
|
|
$ |
81,179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
468,189 |
|
|
$ |
265,971 |
|
|
$ |
518,074 |
|
|
$ |
293,351 |
|
|
$ |
424,965 |
|
|
$ |
237,193 |
|
Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated
from projections of reserves and revenue attributable to the combined BROG, River Hill Energy and
Trust interests in the Waddell Ranch properties and Texas Royalty properties. Reserve quantities
attributable to the Royalties were estimated by allocating to the Royalties a portion of the total
estimated net reserve quantities of the interests, based upon gross revenue less production taxes.
Because the reserve quantities attributable to the Royalties are estimated using an allocation of
the reserves, any changes in prices or costs will result in changes in the estimated reserve
quantities allocated to the Royalties. Therefore, the reserve quantities estimated will vary if
different future price and cost assumptions occur.
14
Proved reserve quantities are estimates based on information available at the time of preparation
and such estimates are subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of those reserves may be substantially different
from the original estimate. Moreover, the present values shown above should not be considered as
the market values of such oil and gas reserves or the costs that would be incurred to acquire
equivalent reserves. A market value determination would include many additional factors.
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 the above royalty properties, the number of exploratory
or development wells drilled on the above royalty
properties during the periods presented by this report, or the number of wells in process or other
present activities on the above royalty properties, and the Registrant cannot readily obtain such
information.
REGULATION
Many aspects of the production, pricing, transportation and marketing of crude oil and natural gas
are regulated by federal and state agencies. Legislation affecting the oil and gas industry is
under constant review for amendment or expansion, frequently increasing the regulatory burden on
affected members of the industry.
Exploration and production operations are subject to various types of regulation at the federal,
state and local levels. Such regulation includes requiring permits for the drilling of wells,
maintaining bonding requirements in order to drill or operate wells, and regulating the location of
wells, the method of drilling and casing wells, the surface use and restoration of properties upon
which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations
are also subject to various conservation laws and regulations that regulate the size of drilling
and spacing units or proration units and the density of wells which may be drilled and unitization
or pooling of oil and gas properties. In addition, state conservation laws establish maximum
allowable production from natural gas and oil wells, generally prohibit the venting or flaring of
natural gas and impose certain requirements regarding the ratability of production. The effect of
these regulations is to limit the amounts of natural gas and oil that can be produced, potentially
raise prices, and to limit the number of wells or the locations which can be drilled.
Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the “FERC”) is primarily responsible for federal
regulation of natural gas. The interstate transportation and sale for resale of natural gas is
subject to federal governmental regulation, including regulation of transportation and storage
tariffs and various other matters, by FERC. On August 8, 2005, Congress enacted the Energy Policy
Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit
market manipulation by any entity, to direct FERC to facilitate market transparency in the market
for sale or transportation of physical natural gas in interstate commerce, and to significantly
increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978,
or FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas are not
subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to
applicable contract provisions.
Sales of natural gas are affected by the availability, terms and cost of transportation. The price
and terms for access to pipeline transportation remain subject to extensive federal and state
regulation. Several major regulatory changes have been implemented by Congress and the FERC from
1985 to the present that affect the economics of natural gas production, transportation, and sales.
In addition, the FERC continues to promulgate revisions to various aspects of the rules and
regulations affecting those segments of the natural gas industry, most notably interstate natural
gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may
also affect the intrastate transportation of gas under certain circumstances. The stated purpose
of many of these regulatory changes is to promote competition among the various sectors of the
natural gas industry and these initiatives generally reflect more light-handed regulation of the
natural gas industry. The ultimate impact of the rules and regulations issued by the FERC
15
since
1985 cannot be predicted. In addition, many aspects of these regulatory developments have not
become final but are still pending judicial and FERC final decisions.
New proposals and proceedings that might affect the natural gas industry are considered from time
to time by Congress, the FERC, state regulatory bodies and the courts. The Trust cannot predict
when or if any such proposals might become effective, or their effect, if any, on the Trust. The
natural gas industry historically has been very heavily regulated; therefore, there is no assurance
that the less stringent regulatory approach recently pursued by the FERC and Congress will
continue.
Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market
prices. Crude oil prices are affected by a variety of factors. Since domestic crude price
controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have
been the pricing and production of the members of the Organization of Petroleum Export Countries
(OPEC).
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing
requirements for obtaining drilling permits, the method of developing new fields, the spacing and
operation of wells and the prevention of waste of oil and gas resources. The rates of production
may be regulated and the maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.
Other Regulation
The petroleum industry is also subject to compliance with various other federal, state and local
regulations and laws, including, but not limited to, environmental protection, occupational safety,
resource conservation and equal employment opportunity. The Trustee does not believe that
compliance with these laws by the operating parties will have any material adverse effect on Unit
holders.
Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Trust is a party or of which any of
its property is the subject.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of Unit holders, through the solicitation of proxies or
otherwise, during the fourth quarter ended December 31, 2006.
PART II
Item 5. Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of
Units
The information under “Units of Beneficial Interest” at page 1 of the Trust’s Annual Report to
security holders for the year ended December 31, 2006, is herein incorporated by reference.
The Trust has no equity compensation plans and has not repurchased any units during the period
covered by this report.
16
Item 6. Selected Financial Data
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
For the Year Ended December 31, |
| |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
2002 |
Royalty income |
|
$ |
66,407,199 |
|
|
$ |
62,967,150 |
|
|
$ |
45,016,670 |
|
|
$ |
32,596,078 |
|
|
$ |
23,830,604 |
|
Distributable income |
|
$ |
65,715,369 |
|
|
$ |
62,267,669 |
|
|
|
44,546,743 |
|
|
|
32,113,125 |
|
|
|
23,415,406 |
|
Distributable income per Unit |
|
$ |
1.410082 |
|
|
|
1.335964 |
|
|
|
.955758 |
|
|
|
0.688993 |
|
|
|
0.502382 |
|
Distributions per Unit |
|
$ |
1.410082 |
|
|
|
1.335964 |
|
|
|
.955758 |
|
|
|
0.688993 |
|
|
|
0.502382 |
|
Total assets, December 31 |
|
$ |
6,574,350 |
|
|
$ |
8,874,678 |
|
|
$ |
7,224,412 |
|
|
$ |
4,865,569 |
|
|
$ |
4,543,780 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
The “Trustee’s Discussion and Analysis for the Three Year Period Ended December 31, 2006” and
“Results of the 4th Quarters of 2006 and 2005” at pages 7 et seq. of the Trust’s Annual
Report to security holders for the year ended December 31, 2006 is herein incorporated by
reference.
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
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. The
amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically
holds short-term investments acquired with funds held by the Trust pending distribution to Unit
holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of
the short-term nature of these borrowings and investments and certain limitations upon the types of
such investments which may be held by the Trust, the Trustee believes that the Trust is not subject
to any material interest rate risk. The Trust does not engage in transactions in foreign
currencies which could expose the Trust or Unit holders to any foreign currency related market
risk. The Trust invests in no derivative financial instruments and has no foreign operations or
long-term debt instruments.
Item 8. Financial Statements and Supplementary Data
The Financial Statements of the Trust and the notes thereto at page 13 et seq. of the Trust’s
Annual Report to security holders for the year ended December 31, 2006, are herein incorporated by
reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
There have been no changes in accountants and no disagreements with accountants on any matter
of accounting principles or practices or financial statement disclosures during the twenty-four
months ended December 31, 2006.
Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
As of the end of the period covered by this report, the Trustee carried out an evaluation of
the effectiveness of the design and operation of the Trust’s disclosure controls and procedures
pursuant to Rules 13a-15 and 15d-15 promulgated under the Securities and Exchange Act of 1934, as
amended. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and
procedures are effective in timely alerting the Trustee to material information relating to the
Trust required to be included in the Trust’s periodic filings with the Securities and Exchange
Commission. In its evaluation of disclosure controls and procedures, the trustee has relied, to the
extent considered reasonable, on information provided
17
by Burlington Resources Oil & Gas Company,
LP, the owner of the Waddell Ranch properties, and Riverhill Energy Corporation, the owner of the
Texas Royalty properties.
Changes in Internal Control over Financial Reporting
There has not been any change in the Trust’s internal control over financial reporting during
the fourth quarter of 2006 that has materially affected, or is reasonably likely to materially
affect, the Trust’s internal control over financial reporting.
Trustee’s Report on Internal Control Over Financial Reporting
The Trustee is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and
Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the
Trust’s internal control over financial reporting – modified cash basis (“internal control over
financial reporting”) based on the criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the
Trustee’s evaluation under the framework in Internal Control-Integrated Framework, the Trustee
concluded that the Trust’s internal control over financial reporting was effective as of December
31, 2006. The Trustee’s assessment of the effectiveness of the Trust’s internal control over
financial reporting as of December 31, 2006 has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in their report which is included herein.
18
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 Trustee’s assessment, included in the accompanying Trustee’s report on internal
control over financial reporting that Permian Basin Royalty Trust (the “Trust”) maintained
effective internal control over financial reporting as of December 31, 2006, based on criteria
established in Internal Control –Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective
internal control over financial reporting – modified cash basis (“internal control over financial
reporting”) and for its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion
on the effectiveness of the Trust’s internal control over financial reporting based on our audit.
We conducted our audit 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 effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management’s assessment, testing and evaluating the
design and operating effectiveness of internal control, and performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis
for our opinions.
The Trust’s internal control over financial reporting is a process designed by, or under the
supervision of, the Trustee, or persons performing similar functions, and effected by the Trustee
to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with the modified cash
basis of accounting, which is a comprehensive basis of accounting other than accounting principles
generally accepted in the United States of America and is described in Note 3 to the Trust’s
financial statements. The Trust’s internal control over financial reporting includes those
policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of the Trust; (2)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of
financial statements in accordance with the modified cash basis of accounting discussed above, and
that receipts and expenditures of the Trust are being made only in accordance with authorizations
of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of
unauthorized acquisition, use, or disposition of the Trust’s assets that could have a material
effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trustee’s assessment that the Trust maintained effective internal control over
financial reporting as of December 31, 2006, is fairly stated, in all material respects, based on
the criteria established in Internal Control –Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Trust maintained, in
all material respects, effective 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.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the 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, which financial statements have been prepared on the modified cash basis of
accounting as described in Note 3 to such
financial statements, and our report dated March 13, 2007 expressed an unqualified opinion on those
financial statements.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 13, 2007
19
Item 9B. Other Information.
None.
PART III
Item 10. Directors and Executive Officers of the Registrant
DIRECTORS AND OFFICERS
The Trust has no directors or executive officers. The Trustee is a corporate trustee which
may be removed, with or without cause, at a meeting of the Unit holders, by the affirmative vote of
the holders of a majority of all the Units then outstanding.
AUDIT COMMITTEE AND NOMINATING COMMITTEE
Because the Trust has no directors, it does not have an audit committee, an audit committee
financial expert or a nominating committee.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange At of 1934 requires the Trust’s directors, officers
or beneficial owners of more than ten percent of a registered class of the Trust’s equity
securities to file reports of ownership and changes in ownership with the SEC and to furnish the
Trust with copies of all such reports.
The Trust has no directors or officers and based solely on its review of the reports received
by it, the Trust believes that during the fiscal year of 2006, no person who was a beneficial owner
of more than ten percent the Trust’s Units failed to file on a timely basis any report required by
Section 16(a), with the exception that BROG failed to timely make a filing related to a sale of
units of the Trust.
CODE OF ETHICS
Because the Trust has no employees, it does not have a code of ethics. Employees of the
Trustee, Bank of America, N.A., must comply with the bank’s code of ethics, a copy of which will be
provided to Unit holders, without charge, upon request made to Bank of America, N.A., Trustee, P.O.
Box 830650, Dallas, Texas 75202, Attention: Ron Hooper.
Item 11. Executive Compensation
During the years ended December 31, 2006, 2005 and 2004, the Trustee received total
remuneration as follows:
| |
|
|
|
|
|
|
|
|
| Name of Individual or Number |
|
Cash |
|
|
| of Persons in Group |
|
Compensation |
|
Year |
Bank of America, N.A |
|
$ |
67,395 |
(1) |
|
|
2006 |
|
|
|
$ |
78,294 |
(1) |
|
|
2005 |
|
|
|
$ |
46,693 |
(1) |
|
|
2004 |
|
20
|
|
|
| (1) |
|
Under the Trust Indenture, the Trustee is entitled to an administrative fee for its
administrative services, preparation of quarterly and annual statements with attention to
tax and legal matters of: (i) 1/20 of 1% of the first $100 million and (ii) Trustee’s
standard hourly rate in excess of 300 hours annually. The administrative fee is subject
to reduction by a credit for funds provision. |
COMPENSATION COMMITTEE
Because the Trust has no directors, it does not have a compensation committee.
Item 12. Security Ownership of Certain Beneficial Owners and Management
(a) Security Ownership of Certain Beneficial Owners. Based solely on a review of statements
filed with the SEC pursuant to Section 13(d) or 13(g) of the Securities Exchange Act of 1934, as
amended, the Trustee is not aware of any person owning beneficially more than 5% of the outstanding
Units of the Trust as of March 1, 2007.
(b) Security Ownership of Management. The Trustee does not beneficially own any securities of
the Trust. In various fiduciary capacities, Bank of America, N.A. owned as of March 1, 2007, an
aggregate of 172,310 Units with no right to vote all of these Units, shared right to vote none of
these Units and sole right to vote none of these Units. Bank of America, N.A., disclaims any
beneficial interests in these Units. The number of Units reflected in this paragraph includes
Units held by all branches of Bank of America, N.A.
(c) Change In Control. The Trustee knows of no arrangements which may subsequently result in
a change in control of the Trust.
(d) Securities Authorized for Issuance under Equity Compensation Plans. The Trust has no
equity compensation plans.
Item 13. Certain Relationships and Related Transactions
The Trust has no directors or executive officers. See Item 11 for the remuneration received
by the Trustee during the years ended December 31, 2006, 2005 and 2004 and Item 12(b) for
information concerning Units owned by Bank of America, N.A. in various fiduciary capacities.
Item 14. Principal Accounting Fees and Services.
Fees for services performed by Deloitte &
Touche LLP for the years ended December 31, 2006 and 2005 are:
| |
|
|
|
|
|
|
|
|
| |
|
2006 |
|
2005 |
Audit Fees |
|
$ |
132,100 |
|
|
$ |
132,850 |
|
Audit-related fees |
|
|
19,250 |
|
|
|
— |
|
Tax fees |
|
|
— |
|
|
|
— |
|
All other fees |
|
|
— |
|
|
|
— |
|
| |
|
|
Total |
|
$ |
151,350 |
|
|
$ |
132,850 |
|
As referenced in Item 10 above, the Trust has no audit committee, and as a result, has no
audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP.
21
PART IV
Item 15. Exhibits, Financial Statement Schedules
The following documents are filed as a part of this Report:
1. Financial Statements
Included in Part II of this Report by reference to the Annual Report of the Trust for the year
ended December 31, 2006:
| |
|
| |
Report of Independent Registered Public Accounting Firm |
| |
|
| |
Statements of Assets, Liabilities and Trust Corpus at December 31, 2006 and 2005 |
| |
|
| |
Statements of Distributable Income for Each of the Three Years in the Period Ended
December 31, 2006 |
| |
|
| |
Statements of Changes in Trust Corpus for Each of the Three Years in the Period
Ended December 31, 2006 |
| |
|
| |
Notes to Financial Statements |
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which
they are required or because the required information is given in the financial statements or notes
thereto.
3. Exhibits
| |
|
|
|
|
| Exhibit |
|
|
|
|
| Number |
|
|
|
Exhibit |
|
|
|
|
|
(4)(a)
|
|
—
|
|
Permian Basin Royalty Trust Indenture dated November 3, 1980,
between Southland Royalty Company and The First National Bank of Fort
Worth (now Bank of America, N.A.), as Trustee, heretofore filed as
Exhibit (4)(a) to the Trust’s Annual Report on Form 10-K to the
Securities and Exchange Commission for the fiscal year ended December
31, 1980, is incorporated herein by reference.* |
|
|
|
|
|
(b)
|
|
—
|
|
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) from
Southland Royalty Company to The First National Bank of Fort Worth
(now Bank of America, N.A.), as Trustee, dated November 3, 1980
(without Schedules), heretofore filed as Exhibit (4)(b) to the Trust’s
Annual Report on Form 10-K to the Securities and Exchange Commission
for the fiscal year ended December 31, 1980, is incorporated herein by
reference.* |
|
|
|
|
|
(c)
|
|
—
|
|
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust —
Waddell Ranch) from Southland Royalty Company to The First National
Bank of Fort Worth (now Bank of America, N.A.), as Trustee, dated
November 3, 1980 (without Schedules), heretofore filed as Exhibit
(4)(c) to the Trust’s Annual Report on Form 10-K to the Securities and
Exchange Commission for the fiscal year ended December 31, 1980, is
incorporated herein by reference.* |
22
| |
|
|
|
|
| Exhibit |
|
|
|
|
| Number |
|
|
|
Exhibit |
|
|
|
|
|
(10)(a)
|
|
—
|
|
Underwriting Agreement dated December 15, 2005 among the Permian
Basin Royalty Trust, Burlington Resources, Inc., Burlington Resources
Oil & Gas L.P. and Lehman Brothers Inc. and Wachovia Capital Markets,
LLC as representatives of the several underwriters, heretofore filed
as Exhibit 10.1 to the Trust’s current report on Form 8-K to the
Securities and Exchange Commission filed on December 19, 2005, is
incorporated herein by reference.* |
|
|
|
|
|
(b)
|
|
—
|
|
Underwriting Agreement dated August 2, 2005 among the Permian Basin
Royalty Trust, Burlington Resources, Inc., Burlington Resources Oil &
Gas L.P. and Goldman Sachs & Co. and Lehman Brothers Inc. as
representatives of the several underwriters, heretofore filed as
Exhibit 10.1 to the Trust’s current report on Form 8-K to the
Securities and Exchange Commission filed on August 8, 2005, is
incorporated herein by reference.* |
|
|
|
|
|
(c)
|
|
—
|
|
Underwriting Agreement dated August 17, 2006, among Permian Basin
Royalty Trust, ConocoPhillips, Burlington Resources Oil & Gas Company
LP and Lehman Brothers Inc. and Wachovia Capital Markets, LLC as
representatives of the several underwriters heretofore filed as
Exhibit 10.1 to the Trust’s current report on Form 8-K to the
Securities and Exchange Commission filed on August 22, 2006, is
incorporated herein by reference.* |
|
|
|
|
|
(d)
|
|
—
|
|
Registration Rights Agreement dated as of July 21, 2004 by and
between Burlington Resources, Inc. and Bank of America, N.A., as
trustee of Permian Basin Royalty Trust, heretofore filed as Exhibit
10.1 to the Trust’s Quarterly Report on Form 10-Q to the Securities
and Exchange Commission for the quarterly period ended June 30, 2004
is incorporated herein by reference.* |
|
|
|
|
|
(13)
|
|
—
|
|
Registrant’s Annual Report to security holders for fiscal year ended
December 31, 2006.** |
|
|
|
|
|
(23.1)
|
|
—
|
|
Consent of Cawley, Gillespie & Associates, Inc., reservoir
engineer.** |
|
|
|
|
|
(31.1)
|
|
—
|
|
Certification required by Rule 13a-14(a)/15d-14(a).** |
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(32.1)
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—
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Certification required by Rule 13a-14(b)/15d-14(b) and Section 906
of the Sarbanes-Oxley Act of 2002.** |
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| * |
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A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction,
upon written request to the Trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas
75202. |
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| ** |
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Filed herewith. |
23
SIGNATURE
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934,
THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO
DULY AUTHORIZED.
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PERMIAN BASIN ROYALTY TRUST
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By: |
BANK OF AMERICA, N.A., Trustee
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By: |
/s/Ron E. Hooper
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Ron E. Hooper |
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Senior Vice President |
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Date:
March 13, 2007
(The Trust has no directors or executive officers.)
24
INDEX TO EXHIBITS
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| EXHIBIT |
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| NUMBER |
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EXHIBIT |
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(4)(a)
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—
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Permian Basin Royalty Trust Indenture dated November 3,
1980, between Southland Royalty Company and The First
National Bank of Fort Worth (now Bank of America, N.A.), as
Trustee, heretofore filed as Exhibit (4)(a) to the Trust’s
Annual Report on Form 10-K to the Securities and Exchange
Commission for the fiscal year ended December 31, 1980, is
incorporated herein by reference.* |
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(b)
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—
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Net Overriding Royalty Conveyance (Permian Basin Royalty
Trust) from Southland Royalty Company to The First National
Bank of Fort Worth (now Bank of America, N.A.), as Trustee,
dated November 3, 1980 (without Schedules), heretofore filed
as Exhibit (4)(b) to the Trust’s Annual Report on Form 10-K
to the Securities and Exchange Commission for the fiscal year
ended December 31, 1980, is incorporated herein by
reference.* |
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(c)
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—
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Net Overriding Royalty Conveyance (Permian Basin Royalty
Trust — Waddell Ranch) from Southland Royalty Company to The
First National Bank of Fort Worth (now Bank of America,
N.A.), as Trustee, dated November 3, 1980 (without
Schedules), heretofore filed as Exhibit (4)(c) to the Trust’s
Annual Report on Form 10-K to the Securities and Exchange
Commission for the fiscal year ended December 31, 1980, is
incorporated herein by reference.* |
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(10)(a)
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—
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Underwriting Agreement dated December 15, 2005 among the
Permian Basin Royalty Trust, Burlington Resources, Inc.,
Burlington Resources Oil & Gas L.P. and Lehman Brothers Inc.
and Wachovia Capital Markets, LLC as representatives of the
several underwriters, heretofore filed as Exhibit 10.1 to the
Trust’s current report on Form 8-K to the Securities and
Exchange Commission filed on December 19, 2005, is
incorporated herein by reference.* |
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(b)
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—
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Underwriting Agreement dated August 2, 2005 among the
Permian Basin Royalty Trust, Burlington Resources, Inc.,
Burlington Resources Oil & Gas L.P. and Goldman Sachs & Co.
and Lehman Brothers Inc. as representatives of the several
underwriters, heretofore filed as Exhibit 10.1 to the Trust’s
current report on Form 8-K to the Securities and Exchange
Commission filed on August 8, 2005, is incorporated herein by
reference.* |
25
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| EXHIBIT |
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| NUMBER |
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EXHIBIT |
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(c)
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—
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Underwriting Agreement dated August 17, 2006, among
Permian Basin Royalty Trust, ConocoPhillips, Burlington
Resources Oil & Gas Company LP and Lehman Brothers Inc. and
Wachovia Capital Markets, LLC as representatives of the
several underwriters heretofore filed as Exhibit 10.1 to the
Trust’s current report on Form 8-K to the Securities and
Exchange Commission filed on August 22, 2006, is incorporated
herein by reference.* |
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(d)
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—
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Registration Rights Agreement dated as of July 21, 2004 by
and between Burlington Resources, Inc. and Bank of America,
N.A., as trustee of Permian Basin Royalty Trust, heretofore
filed as Exhibit 10.1 to the Trust’s Quarterly Report on Form
10-Q to the Securities and Exchange Commission for the
quarterly period ended June 30, 2004 is incorporated herein
by reference.* |
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(13)
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—
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Registrant’s Annual Report to security holders for fiscal
year ended December 31, 2006.** |
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(23.1)
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—
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Consent of Cawley, Gillespie & Associates, Inc., reservoir
engineer.** |
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(31.1)
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—
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Certification required by Rule 13a-14(a)/15d-14(a).** |
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(32.1)
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—
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Certification required by Rule 13a-14(b)/15d-14(b) and
Section 906 of the Sarbanes-Oxley Act of 2002.** |
|
|
|
| * |
|
A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon
written request to the Trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75202. |
| |
| ** |
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Filed herewith. |
26