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 not less than 180 days before December 31, 2010, which comments remain unresolved.
Item 2.
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 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 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.
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, 2010, is approximately 10 years.
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.
PRODUCING ACREAGE, WELLS AND DRILLING
Waddell Ranch Properties. The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the Trust. The mineral interests in the Waddell Ranch, from which such net royalty interests are carved vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 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, 2010, the Waddell Ranch properties contained 797 gross (371 net) productive oil wells, 212 gross (87 net) productive gas wells and 267 gross (119 net) injection wells.
BROG is operator of record of the Waddell Ranch properties. All field, technical and accounting operations have been contracted by agreements between the working interest owners and Schlumberger Integrated Project Management (IPM) and Riverhill Capital Corporation (“Riverhill Capital”), but remain under the direction of BROG.
Six major fields on the Waddell Ranch properties account for more than 80% 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. Also productive from the San Andres are the Sand Hills (Judkins) gas field and the Sand
Hills (McKnight) oil field, the Dune (Grayburg/San Andres) oil field, and the Waddell (Grayburg/San Andres) 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.
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 was 1 gross (0.5 net) well drilled and completed on the Waddell Ranch properties during 2010. At December 31, 2010, there were 4 drill wells and 5 workovers in progress on the Waddell Ranch properties. There were 11 gross (5 net) wells drilled and completed on the Waddell Ranch properties during 2009. At December 31, 2009 there were no drill wells and 2 workovers in progress on the Waddell Ranch properties. There were 3 gross (1 net) wells drilled and completed on the Waddell Ranch properties during 2008. At December 31, 2008 there were 6 drill wells and 3 workovers in progress on the Waddell Ranch properties.
In 2010, there were 0 net productive and 0 dry exploratory wells drilled, and 0.5 net productive and 0 dry development wells drilled on the Waddell Ranch properties, compared to no net productive and no dry exploratory wells drilled and 5 net productive and no dry development wells drilled in 2009. In 2008, there were no net productive and no dry exploratory wells drilled, and 1 net productive and no dry development wells drilled on the Waddell Ranch Properties.
BROG has advised the Trustee that the total amount of capital expenditures for 2010 with regard to the Waddell Ranch properties totaled $12.0 million. Capital expenditures include the cost of remedial and maintenance activities. This amount spent is approximately $10 million less than the budgeted amount projected by BROG for 2010. BROG has advised the Trustee that the capital expenditures budget for 2011 totals approximately $23 million, of which approximately $0 million (gross) is attributable to the 2011 drilling program, and $19 million (gross) to workovers and recompletions. The remaining $4 million is attributable to facilities. Accordingly, there is a 91% increase in capital expenditures for 2011 as compared with the 2010 capital expenditures. The major reason for the variance is the increase in the number of planned capital recompletions and an increased level of facility work. There will be no new drill wells in 2011 as compared to 0 in 2010.
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 located in 33 counties across Texas. The Texas Royalty properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 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. 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 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.
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, 2010, the gross and net producing wells and acres for the BROG interests. The net wells and acres are determined by multiplying the gross wells or acres by the BROG interests owner’s working interest in the wells or acres. Similar information is not available for the Riverhill Energy interests. There is no undeveloped acreage on the Waddell Ranch properties.
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, the related average sales prices and the average production cost per unit of production attributable to the Underlying Properties for the three years ended December 31, 2010, excluding portions attributable to the adjustments discussed below, were as follows:
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.
Waddell Ranch properties lease operating expense for 2010 was $38.6 million (gross) and $14.6 million (net). The lease operating expense decreased 1% from 2009 to 2010 primarily because of decreased electrical costs. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $11.56 /bbl as compared to $11.04 in 2009 and $8.91 in 2008.
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 since June 2006, the oil from the Waddell Ranch has been marketed by ConocoPhillips by soliciting bids from third parties on an outright sale basis of production listed in bid packages.
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 oil and gas reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
“Developed oil and gas reserves” are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.
“Estimated future net revenues” are computed by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual arrangements) 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%.
“Reserves” are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.
“Undeveloped oil and gas reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.
The process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal policies and controls for estimating reserves. As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers production information (which information is net to the Trust’s interests in the Underlying Properties) and provides such information to Cawley, Gillespie & Associates, Inc., who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trust’s policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.
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. Cawley, Gillespie & Associates, Inc, has been in business since 1973 when the petroleum consulting firm Keller & Augustson merged with the petroleum consulting firm Cawley, Harrington & Gillespie. The primary business of Cawley, Gillespie & Associates, Inc, is the estimation and evaluation of petroleum reserves. Kenneth J. Mueller, has been employed by Cawley, Gillespie & Associates since 1996. Mr. Mueller attended Texas A&M University from 1975 to 1979, graduating with a Bachelor of Science degree, Summa Cum Laude, in Petroleum Engineering in 1979, and has in excess of fifteen years experience in oil and gas reserves studies and evaluations. Mr. Mueller is a licensed professional engineer with the Texas Board of Professional Engineers and a member of the Texas Society of Professional Engineers.
Cawley, Gillespie & Associates, Inc.’s reports are attached as exhibits to this Form 10-K. The following table presents a reconciliation of proved reserve quantities from January 1, 2008 through December 31, 2010 (in thousands):
Estimated quantities of proved reserves and net cash flow as of December 31, 2010 are as follows:
Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in thousands):
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 the average prices during
the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. 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.
The 2010, 2009 and 2008 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):
Average oil and gas prices of $79.43 per barrel and $4.37 per Mcf were used to determine the estimated future net revenues from both the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2010. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties are primarily due to stronger pricing for oil and gas.
Average oil and gas prices of $55.87 and $55.38 per barrel and $4.49 and $6.27 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, 2009. 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 stronger pricing for oil and gas.
Oil and gas prices of $41.43 and $41.22 per barrel and $3.69 and $6.52 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, 2008. The downward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties were primarily due to a decrease in oil and gas prices from 2007 to 2008.
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, 2010, 2009 and 2008 (in thousands):
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.
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
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).
On December 19, 2007, President Bush signed into law the Energy Independence & Security Act of 2007 (PL 110 140). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.
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.
Environmental Regulation
Companies that are engaged in the oil and gas industry are affected by federal, state and local laws regulating the discharge of materials into the environment. Those laws may impact operations of the underlying properties.
Climate change has become the subject of an important public policy debate. Climate change legislation and regulations have been adopted by many foreign countries and some states in the United States; however, legislation and regulations have not been enacted at the federal level, although the United States Congress and several more states have or are considering adopting climate change legislation. Further, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter. Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under Section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of future generations. The EPA has issued final regulations requiring petroleum and natural gas operators meeting a certain emission threshold to report their greenhouse gas emissions to the EPA. The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits.
The Trustee is unable to predict the total impact of the potential regulations upon the operators of the Underlying Properties, and it is possible that operators of the underlying properties could face increases in operating costs in order to comply with climate change legislation, which costs could reduce net proceeds payable to the Trust and Trust distributions.
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, 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.
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.
Item 4. Removed and Reserved.
PART II
Item 5.
Item 5. Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units
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:
Approximately 1,327 Unit holders of record held the 46,608,796 Units of the Trust at December 31, 2010.
The Trust has no equity compensation plans and has not repurchased any Units during the period covered by this report.
Item 6.
Item 6. Selected Financial Data
Computation of Royalty Income Received by the Trust
The Trust’s royalty income is computed as a percentage of the net profit from the operation of the properties in which the Trust owns net overriding royalty interests. The percentages of net profits are 75% and 95% in the cases of the Waddell Ranch properties and the Texas Royalty properties, respectively. Royalty income received by the Trust for the five years ended December 31, 2010, was computed as shown in the table on the next page.
Item 7.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 2010
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 crude oil and 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. Estimates of future net revenues from proved reserves have been prepared using average 12-month oil and gas prices, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within the 12-month period preceding the end of the most recent fiscal year, unless prices are defined by contractual arrangements. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates and related costs. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as market conditions change.
Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on its royalty properties, the number of exploratory or development wells drilled on its royalty properties during the periods presented by this report, or the number of wells in process or other present activities on its royalty properties, and the Registrant cannot readily obtain such information.
3. Contingencies
Contingencies related to the Underlying Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders.
Liquidity and Capital Resources
As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Underlying Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and pay Trust liabilities and expenses and its actions have been limited to those activities. The Trust is a passive entity and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. As a result, other than such borrowings, if any, the Trust has no source of liquidity or capital resources other than the Royalties.
Results of Operations
Royalty income received by the Trust for the three-year period ended December 31, 2010, is reported in the following table:
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 2010, 2009 and 2008 for the Royalties and the Underlying Properties, excluding portions attributable to the adjustments discussed hereafter, are presented in the following table:
The average price of oil increased to $73.24 per barrel in 2010, up from $51.82 per barrel in 2009. The average price of oil in 2008 was $102.04 per barrel. In addition, the average price of gas increased from $4.67 per Mcf in 2009 to $6.83 per Mcf in 2010. The average price of gas in 2008 was $10.55 per Mcf. Oil prices have increased primarily because of world market conditions. Higher demand as a result of the ending of the U.S. recession and a slow growing global economy have caused crude oil prices to rise since the second half of 2009. Oil prices are expected to remain volatile.
Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison. Total oil production increased approximately 18% from 2009 to 2010 primarily due to higher prices received on production. Total gas production increased approximately 28% from 2009 to 2010 primarily due to higher prices for gas and lower capital expenditures.
Total capital expenditures in 2010 used in the net overriding royalty calculation were approximately $4.2 million compared to $11.5 million in 2009 and $9.1 million in 2008. During 2010, there was 1 gross (.5 net) wells drilled and completed on the Waddell Ranch properties. At December 31, 2010, there were 4 drill wells and 5 workovers in progress on the Waddell Ranch properties.
In 2010, lease operating expense and property taxes on the Waddell Ranch properties amounted to approximately $19.5 million, which amount was higher than 2009 by $1.4 million.
The Trustee has been advised by BROG that since June 2006, the oil from the Waddell Ranch has been marketed by ConocoPhillips by soliciting bids from third parties on an outright sale basis of production listed in bid packages.
During 2010, the monthly royalty receipts were invested by the Trustee until the monthly distribution date, and earned interest totaled $1,216. Interest income for 2009 and 2008 was $3,319 and $90,572, respectively. General and administrative expenses in 2010 were $1,149,849 compared to $1,265,483 in 2009 and $973,761 in 2008, primarily due to timing and expenses.
Distributable income for 2010 was $64,116,670, or $1.375635 per Unit.
Distributable income for 2009 was $37,695,948, or $.808773 per Unit.
Distributable income for 2008 was $111,458,507, or $2.391356 per Unit.
Results of the Fourth Quarters of 2010 and 2009
Royalty income received by the Trust for the fourth quarter of 2010 amounted to $14,296,119 or $.306726 per Unit. For the fourth quarter of 2009, the Trust received royalty income of $14,050,477 or $.301455 per Unit. Interest income for the fourth quarter of 2010 amounted to $407 compared to $302 for the fourth quarter of 2009. The increase in interest income can be attributed primarily to an increase of funds available. General and administrative expenses totaled $162,457 for the fourth quarter of 2010 compared to $199,869 for the fourth quarter of 2009. The decrease in expenses related to a decrease of professional expenses.
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 2009 are as follows:
The posted price of oil increased for the fourth quarter of 2010 compared to the fourth quarter of 2009, resulting in an average price per barrel of $74.30 compared to $51.82 in the same period of 2009. The average price of gas increased for the fourth quarter of 2010 compared to the same period in 2009, resulting in an average price per Mcf of $6.46 compared to $4.67 in the fourth quarter of 2009.
The Trustee has been advised that oil sales decreased in the fourth quarter of 2010 compared to the same period in 2009 primarily due to market demand and natural decline of production. Gas sales from the Underlying Properties decreased in the fourth quarter of 2010 compared to the same period in 2009 due to market demands.
The Trust has been advised that 4 wells were drilled and completed during the three months ended December 31, 2010, and there were 5 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.
Tabular Disclosure of Contractual Obligations.
Item 7A.
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.
Item 8. Financial Statements and Supplementary Data
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, 2010 and 2009, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 3 to the financial statements, these financial statements have been prepared on a modified cash basis of accounting which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2010 and 2009, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2010, on the basis of accounting described in Note 3.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trust’s internal control over financial reporting as of December 31, 2010, 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 1, 2011 expressed an unqualified opinion on the Trustee’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
Austin, TX
March 1, 2011
PERMIAN BASIN ROYALTY TRUST
FINANCIAL STATEMENTS
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
DECEMBER 31, 2010 AND 2009
STATEMENTS OF DISTRIBUTABLE INCOME
FOR THE THREE YEARS ENDED DECEMBER 31, 2010
The accompanying notes to financial statements are an integral part of these statements
STATEMENTS OF CHANGES IN TRUST CORPUS
FOR THE THREE YEARS ENDED DECEMBER 31, 2010
The accompanying notes to financial statements are an integral part of these statements.
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
The Permian Basin Royalty Trust (“Trust”) was established as of November 1, 1980. Bank of America, N.A. (“Trustee”) is Trustee for the Trust. Southland Royalty Company (“Southland”) conveyed to the Trust (1) a 75% net overriding royalty in Southland’s fee mineral interest in the Waddell Ranch in Crane County, Texas (“Waddell Ranch properties”) and (2) a 95% net overriding royalty carved out of Southland’s major producing royalty properties in Texas (“Texas Royalty properties”). The net overriding royalties above are collectively referred to as the “Royalties.”
On November 3, 1980, Units of Beneficial Interest (“Units”) in the Trust were distributed to the Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland common stock held. The Units are traded on the New York Stock Exchange.
The terms of the Trust Indenture provide, among other things, that:
•
the Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust;
•
the Trustee may not sell all or any part of the Royalties unless approved by holders of 75% of all Units outstanding in which case the sale must be for cash and the proceeds promptly distributed;
•
the Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount;
•
the Trustee is authorized to borrow funds to pay liabilities of the Trust; and
•
the Trustee will make monthly cash distributions to Unit holders (see Note 2).
2. Net Overriding Royalty Interests and Distribution to Unit Holders
The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are determined on a monthly basis. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month. To the extent the distribution amount is a negative number, that amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or before 10 business days after the monthly record date, which is generally the last business day of each calendar month.
The cash received by the Trustee consists of the amounts received by owners of the interest burdened by the Royalties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75% in the case of the Waddell Ranch properties and 95% in the case of the Texas Royalty properties.
The initial carrying value of the Royalties ($10,975,216) represented Southland’s historical net book value at the date of the transfer to the Trust. Accumulated amortization as of December 31, 2010 and 2009, aggregated $10,004,009 and $9,895,230, 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.
Use of Estimates
The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates.
Impairment
The Trustee routinely reviews its royalty interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trust’s royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. There is no impairment of the assets as of December 31, 2010.
4. New Accounting Pronouncements
In June 2009, the Financial Accounting Standards Board (“FASB”) issued guidance effective July 1, 2009 that requires all then-existing non-SEC accounting and reporting standards to be superseded by the FASB Accounting Standards Codification (the “Codification”), the source of authoritative GAAP recognized by the FASB to be applied by nongovernmental entities. Previous references to then-existing non-SEC accounting and reporting standards were removed and are reflected in the Trust’s footnotes herein.
In May 2009, the FASB issued guidance which establishes accounting and reporting standards for events that occur after the balance sheet date but before the financial statements are issued or are available to be issued. This guidance was effective for the Trust for the period ended June 30, 2009 and the adoption did not have an impact on the Trust’s financial statements.
5. Federal Income Tax
For Federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit holders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust. The Trust has on file technical advice memoranda confirming the tax treatment of the Trust.
Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. Federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.pbt-permianbasintrust.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.
Because the Trust is a grantor trust for Federal tax purposes, each Unit holder is taxed directly on his proportionate share of income, deductions and credits of the Trust consistent with each such Unit holder’s taxable year and method of accounting and without regard to the taxable year or method of accounting employed by the Trust. The income of the Trust consists primarily of a specified share of the proceeds from the sale of coal seam gas produced from the Underlying Properties. During 2010, the Trust earned interest income on funds held for distribution and made adjustments to the cash reserve maintained for the payment of contingent and future obligations of the Trust.
The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each Unit holder is entitled to depletion deductions because the Royalties constitute “economic interests” in oil and gas properties for Federal income tax purposes. Each Unit holder is entitled to amortize the cost of the Units through cost depletion over the life of the Royalties or, if greater, through percentage depletion equal to 15 percent of gross income. Unlike cost depletion, percentage depletion is not limited to a Unit holder’s depletable tax basis in the Units. Rather, a Unit holder is entitled to a percentage depletion deduction as long as the applicable Underlying Properties generate gross income. If any portion of the Royalties is treated as a production payment or is not treated as an economic interest, however, a Unit holder will not be entitled to depletion in respect of such portion. 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 has estimated the cost depletion for January through December 2010, and it appears that percentage depletion will exceed cost depletion for some of the Unit holders.
If a taxpayer disposes of any “section 1254 property” (certain oil, gas, geothermal or other mineral property), and if the adjusted basis of such property includes adjustments for deductions for depletion under Section 611 of the Internal Revenue Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Internal Revenue Service likely will take the position that a Unit holder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit.
Individuals may deduct “miscellaneous itemized deductions” (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust.
The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit holder. Royalty income generally is treated as portfolio income and does not offset passive losses. 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, 2011, and for the year ending December 31, 2011. Unit holders owning Units in nominee may obtain monthly tax information from the Trustee upon request. See discussion above regarding certain reporting requirements imposed upon middlemen under U.S. Treasury Regulations because the Trust is considered a WHIFT for Federal income tax purposes.
The Tax consequences to a Unit holder of the ownership and sale of Units will depend in part on the Unit holder’s tax circumstances. Unit holders should consult their tax advisors about the Federal tax consequences relating to owning the Units in the Trust.
6. Proved Oil and Gas Reserves (Unaudited)
Reserve Quantities
Information regarding estimates of the proved oil and gas reserves attributable to the Trust are based on reports prepared by Cawley, Gillespie & Associates, Inc., independent petroleum engineering consultants. Estimates were prepared in accordance with the guidelines established by the FASB and the Securities and Exchange Commission. Certain information required by this guidance is not presented because that information is not applicable to the Trust due to its passive nature.
Oil and gas reserve quantities (all located in the United States) are estimates based on information available at the time of their preparation. Such estimates are subject to change as additional information becomes available. Reserves actually recovered, and the timing of the production of those reserves, may differ substantially from original estimates. The following schedule presents changes in the Trust’s total proved reserves (in thousands):
Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in thousands):
Disclosure of a Standardized Measure of Discounted Future Net Cash Flows
The following is a summary of a standardized measure (in thousands) of discounted future net cash flows related to the Trust’s total proved oil and gas reserve quantities. Information presented is based upon valuation of proved reserves by using discounted cash flows based upon average oil and gas prices ($79.43 per bbl and $4.37 per Mcf, respectively) during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions and severance and ad valorem taxes, if any, and economic conditions, discounted at the required rate of 10 percent. As the Trust is not subject to taxation at the trust level, no provision for income taxes has been made in the following disclosure. Trust prices may differ from posted NYMEX prices due to differences in product quality and property location. The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and gas properties nor should it be viewed as indicative of any trends.
The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2010, 2009 and 2008 is as follows (in thousands):
7. Quarterly Schedule of Distributable Income (Unaudited)
The following is a summary of the unaudited quarterly schedule of distributable income for the two years ended December 31, 2010 (in thousands, except per Unit amounts):
8. SUBSEQUENT EVENTS
Subsequent to December 31, 2010, the Trust declared the following distributions:
9. STATE TAX CONSIDERATIONS
All revenues from the Trust are from sources within Texas, which has no individual income tax. Texas imposes a franchise tax at a rate of 1% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statute. Entities subject to tax generally include trusts unless otherwise exempt and most other types of entities that provide limited liability protection. Trusts that receive at least 90% of their Federal gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as “passive entities.” The Trust should be exempt from Texas franchise tax as a “passive entity.” Since the Trust should be exempt from Texas franchise tax at the Trust level as a passive entity, each Unit holder that is considered a taxable entity under the Texas franchise tax would generally be required to include its Texas portion of Trust revenues in its own Texas franchise tax computation. This revenue would be sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the principal place of business of the Trust, which is Texas.
Each Unit holder is urged to consult his own tax advisor regarding the requirements for filing state tax returns.
* * * * *
Item 9.
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, 2010.
Item 9A.
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 Exchange Act of 1934, as amended. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in recording, processing, summarizing and reporting, on a timely basis, information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 and are effective in ensuring that information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934 is accumulated and communicated to the Trustee to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided 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 2010 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, 2010. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors of the statements of assets, liabilities, and trust corpus, and the related statements of distributable income and changes in trust corpus for the period ended December 31, 2010, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.
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 internal control over financial reporting of Permian Basin Royalty Trust (the “Trust”) as of December 31, 2010, 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 and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on 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, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A 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. A 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 Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, 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 the Trust as of December 31, 2010, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2010, 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 1, 2011 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
Austin, TX
March 1, 2011
Item 9B.
Item 9B. Other Information.
None.
PART III
Item 10.
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 2010, 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).
CODE OF ETHICS
Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Bank of America Private Wealth Management 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 U.S. Trust, Bank of America Private Wealth Management, Trustee, P.O. Box 830650, Dallas, Texas 75202, Attention: Ron Hooper.
Item 11.
Item 11. Executive Compensation
During the years ended December 31, 2010, 2009 and 2008, the Trustee received total remuneration as follows:
(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, and the Trust has not engaged any consultants to provide advice or recommendations on the amount or form of compensation.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
(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 February 1, 2011.
(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 February 1, 2011, an aggregate of 186,878 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.
Item 13. Certain Relationships and Related Transactions, and Director Independence
The Trust has no directors or executive officers. See Item 11 for the remuneration received by the Trustee during the years ended December 31, 2010, 2009 and 2008 and Item 12(b) for information concerning Units owned by Bank of America, N.A. in various fiduciary capacities.
Item 14.
Item 14. Principal Accounting Fees and Services. Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2010 and 2009 are:
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.
PART IV
Item 15.
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:
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.
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.*
(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
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.
(The Trust has no directors or executive officers.)
INDEX TO 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)
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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.*
(10)(a)
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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.*
(b)
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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.*