XNYS:PBT Permian Basin Royalty Trust Quarterly Report 10-Q Filing - 6/30/2012

Effective Date 6/30/2012

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-Q

 

 

 

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period ended June 30, 2012

 

¨ Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from                      to                     

Commission file number 1-8033

 

 

PERMIAN BASIN ROYALTY TRUST

(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust Indenture)

 

 

 

Texas    75-6280532

(State or Other Jurisdiction of

Incorporation or Organization)

  

(I.R.S. Employer

Identification No.)

U.S. Trust, Bank of America

Private Wealth Management

Trust Department

901 Main Street

Dallas, Texas 75202

(Address of Principal Executive Offices; Zip Code)

(214) 209-2400

(Registrant’s Telephone Number, Including Area Code)

 

 

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  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ¨    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer   x    Accelerated filer   ¨
Non-accelerated filer   ¨  (Do not check if a smaller reporting company)    Smaller reporting company   ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Number of Units of beneficial interest of the Trust outstanding at August 8, 2012: 46,608,796.

 

 

 


PERMIAN BASIN ROYALTY TRUST

PART I - FINANCIAL INFORMATION

Item1. Financial Statements

The condensed financial statements included herein have been prepared by Bank of America, N.A. as Trustee for the Permian Basin Royalty Trust, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to such rules and regulations, although the Trustee believes that the disclosures are adequate to make the information presented not misleading. It is suggested that these condensed financial statements and notes thereto be read in conjunction with the financial statements and the notes thereto included in the Trust’s latest annual report on Form 10-K. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the assets, liabilities and trust corpus of the Permian Basin Royalty Trust at June 30, 2012, the distributable income for the three-month and six-month periods ended June 30, 2012 and 2011 and the changes in trust corpus for the six-month periods ended June 30, 2012 and 2011, have been included. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

The condensed financial statements as of June 30, 2012, and for the three-month and six-month periods ended June 30, 2012 and 2011, included herein, have been reviewed by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report appearing herein.

 

2


REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Unit Holders of Permian Basin Royalty Trust and

Bank of America, N.A., Trustee

Dallas, Texas

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of Permian Basin Royalty Trust (the “Trust”) as of June 30, 2012, and the related condensed statements of distributable income for the three-month and six-month periods ended June 30, 2012 and 2011 and changes in trust corpus for the six-month periods ended June 30, 2012 and 2011. These condensed interim financial statements are the responsibility of the Trustee.

We conducted our reviews in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

As described in Note 2 to the condensed financial statements, these condensed interim 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.

Based on our reviews, we are not aware of any material modifications that should be made to such condensed interim financial statements for them to be in conformity with the basis of accounting described in Note 2.

We have previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statement of assets, liabilities, and trust corpus of Permian Basin Royalty Trust as of December 31, 2011, and the related statements of distributable income and changes in trust corpus for the year then ended (not presented herein); and in our report dated March 2, 2012, we expressed an unqualified opinion on those financial statements. In our opinion, the information set forth in the accompanying condensed statement of assets, liabilities, and trust corpus as of December 31, 2011, is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus from which it has been derived.

/s/ Deloitte & Touche LLP

Dallas, Texas

August 8, 2012

 

3


PERMIAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (UNAUDITED)

 

     June 30,
2012
     December 31,
2011
 

ASSETS

     

Cash and short-term investments

   $ 4,060,709       $ 4,727,946   

Net overriding royalty interests in producing oil and gas properties (net of accumulated amortization of $10,123,940 and $10,083,640 at June 30, 2012 and December 31, 2011, respectively)

     851,276         891,576   
  

 

 

    

 

 

 

TOTAL ASSETS

   $ 4,911,985       $ 5,619,522   
  

 

 

    

 

 

 

LIABILITIES AND TRUST CORPUS

     

Distribution payable to Unit holders

   $ 4,060,709       $ 4,727,946   

Commitments and contingencies (Note 6)

     —           —     

Trust corpus - 46,608,796 Units of beneficial interest authorized and outstanding

     851,276         891,576   
  

 

 

    

 

 

 

TOTAL LIABILITIES AND TRUST CORPUS

   $ 4,911,985       $ 5,619,522   
  

 

 

    

 

 

 

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

 

4


PERMIAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

 

     THREE
MONTHS
ENDED

June 30, 2012
    THREE
MONTHS
ENDED

June 30, 2011
 

Royalty income

   $ 16,142,279      $ 18,398,691   

Interest income

     149        165  
  

 

 

   

 

 

 
     16,142,428        18,398,856   

General and administrative expenditures

     (485,146     (502,935
  

 

 

   

 

 

 

Distributable income

   $ 15,657,282      $ 17,895,921   
  

 

 

   

 

 

 

Distributable income per Unit (46,608,796 Units)

   $ .34      $ .38   
  

 

 

   

 

 

 

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

 

5


PERMIAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

 

     SIX
MONTHS
ENDED

June 30, 2012
    SIX
MONTHS
ENDED

June 30, 2011
 

Royalty income

   $ 36,563,959      $ 35,196,974   

Interest income

     535        364   
  

 

 

   

 

 

 
     36,564,494        35,197,338   

General and administrative expenditures

     (810,743     (842,452
  

 

 

   

 

 

 

Distributable income

   $ 35,753,751      $ 34,354,886   
  

 

 

   

 

 

 

Distributable income per Unit (46,608,796 Units)

   $ .77      $ .74   
  

 

 

   

 

 

 

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

 

6


PERMIAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

 

     SIX
MONTHS
ENDED

June 30, 2012
    SIX
MONTHS
ENDED

June 30, 2011
 

Trust corpus, beginning of period

   $ 891,576      $ 971,207   

Amortization of net overriding royalty interests

     (40,300     (43,454

Distributable income

     35,753,751        34,354,886   

Distributions declared

     (35,753,751     (34,354,886
  

 

 

   

 

 

 

Total Trust Corpus, end of period

   $ 851,276      $ 927,753   
  

 

 

   

 

 

 

Distributions per Unit

   $ .77      $ .74   
  

 

 

   

 

 

 

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

 

7


PERMIAN BASIN ROYALTY TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

 

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. The net overriding royalties conveyed to the Trust include (1) a 75% net overriding royalty in Southland Royalty Company’s fee mineral interest in the Waddell Ranch in Crane County, Texas (the “Waddell Ranch properties”) and (2) a 95% net overriding royalty carved out of Southland Royalty Company’s major producing royalty properties 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. 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 Royalty Company’s shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland Royalty Company common stock held. The Units are traded on the New York Stock Exchange.

Burlington Resources Oil & Gas Company LP (“BROG”), a subsidiary of ConocoPhillips, is the interest owner for the Waddell Ranch properties and Riverhill Energy Corporation (“Riverhill Energy”), formerly a wholly owned subsidiary of Riverhill Capital Corporation (“Riverhill Capital”) and formerly an affiliate of Coastal Management Corporation (“CMC”), is the interest owner for the Texas Royalty properties. Schlumberger Integrated Project Management currently conducts all field, technical and accounting operations on behalf of BROG with regard to the Waddell Ranch properties. Riverhill Energy currently conducts the accounting operations for the Texas Royalty properties.

In February 1997, BROG sold its interest in the Texas Royalty properties to Riverhill Energy.

The Trustee was advised that in the first quarter of 1998, Schlumberger Technology Corporation (“STC”) acquired all of the shares of stock of Riverhill Capital. Prior to such acquisition by STC, CMC and Riverhill Energy were wholly owned subsidiaries of Riverhill Capital. The Trustee was further advised that in connection with STC’s acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all of the shares of stock of Riverhill Energy. Thus, the ownership in the Texas Royalty properties referenced above remained in Riverhill Energy, the stock ownership of which was acquired by the former shareholders of Riverhill Capital.

 

8


In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as Trustee of the Trust did not change.

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 3 to condensed financial statements).

 

2. ACCOUNTING POLICIES

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

 

  Royalty income recorded for a month is the amount computed and paid to the Trustee as Trustee for the Trust by the interest owners. Royalty income consists of the amounts received by the owners of the interest burdened by the Royalties from the sale of production less accrued production costs, development and drilling costs, applicable taxes, 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.

 

  Trust expenses, consisting principally of routine general and administrative costs, 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.

 

  Royalty income is computed separately for each of the conveyances under which the Royalties were conveyed to the Trust. If monthly costs exceed revenues for any conveyance (“excess costs”), such excess costs cannot reduce royalty income from other conveyances, but is carried forward with accrued interest to be recovered from future net proceeds of that conveyance.

 

  Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.

 

9


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. In addition, 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 June 30, 2012.

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.

Distributable Income Per Unit

Basic distributable income per Unit is computed by dividing distributable income by the weighted average of Units outstanding. Distributable income per Unit assuming dilution is computed by dividing distributable income by the weighted average number of Units and equivalent Units outstanding. The Trust had no equivalent Units outstanding for any period presented. Therefore, basic distributable income per Unit and distributable income per Unit assuming dilution are the same.

New Accounting Pronouncements

There are no new accounting pronouncements that are expected to have a significant impact on the Trust’s financial statements.

 

10


3. 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.

 

4. FEDERAL INCOME TAXES

For federal income tax purposes, the Trust constitutes a fixed investment trust that 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 and not when distributed by the Trust.

The Royalties constitute “economic interests” in oil and gas properties for federal income tax purposes. Unit holders must report their share of the revenues from the Royalties as ordinary income from oil and gas royalties and are entitled to claim depletion with respect to such income. During the second quarter of 2012, the Trust also incurred administration expenses and earned interest income on funds held for distribution and for the cash reserve maintained for the payment of contingent and future obligations of the Trust.

The Trust has on file technical advice memoranda confirming the tax treatment described above.

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

 

11


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 customer 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, email address trustee@pbt-permianbasintrust.com, 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.

Unit holders should consult their tax advisors regarding Trust tax compliance matters.

 

5. STATE TAX CONSIDERATIONS

All revenues from the Trust are from sources within Texas, which has no individual income tax. However, 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 statutes. Entities subject to tax generally include trusts unless otherwise exempt. 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 that 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.” Because 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 will generally be required to include its portion of Trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code sourcing such income according to the principal place of business of the Trust, which is Texas.

Unit holders should consult their tax advisors regarding state tax requirements, if any, applicable to such Unit holder’s ownership of Trust units.

 

6. COMMITMENTS AND 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.

 

12


On May 2, 2011, ConocoPhillips, as the parent company of BROG, the operator of the Waddell Ranch properties, notified the Trustee that as a result of inaccuracies in ConocoPhillips’ accounting and record keeping relating to the Trust’s interest in proceeds from the gas plant production since January 2007 ConocoPhillips overpaid the Trust approximately $5.9 million initially. ConocoPhillips informed the Trustee on September 20, 2011 that it was withholding $4,068,067 (all of the Waddell Ranch portion of the September 2011 proceeds, which would be reflective of July 2011 production, of approximately 29,796 bbls of oil and 180,425 mcf of gas) in order to recoup this overpayment. This affected the Trust’s distribution declared September 20, 2011 and paid October 17, 2011. ConocoPhillips also withheld $474,480 from the proceeds for October 2011, which ConocoPhillips has informed the Trustee completes the recoupment. ConocoPhillips has indicated that these two recoupments will satisfy the initial claim of $5.9 million. Additionally, ConocoPhillips informed the Trustee that beginning with the June 2011 distribution, proceeds to the Trust relating to the gas plant production have been adjusted to reflect ConocoPhillips’ calculation of the corrected interest. The Trustee is continuing to evaluate the matter.

 

7. SUBSEQUENT EVENTS

Subsequent to June 30, 2012, the Trust declared a distribution on July 20, 2012 of $.073765 per Unit payable on August 14, 2012 to Unit holders of record on July 31, 2012.

* * * * *

Item 2. Trustee’s Discussion and Analysis

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 are 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. Such forward looking statements generally are accompanied by words such as “estimate,” “expect,” “predict,” “anticipate,” “goal,” “should,” “assume,” “believe,” or other words that convey the uncertainty of future events or outcomes.

 

13


Three Months Ended June 30, 2012 Compared to Three Months Ended June 30, 2011

For the quarter ended June 30, 2012 royalty income received by the Trust amounted to $16,142,279 compared to royalty income of $18,398,691 during the second quarter of 2011. The decrease in royalty income is primarily attributable to decreases in both oil and gas production and decreases in gas prices, offset by increases in oil prices.

Interest income for the quarter ended June 30, 2012, was $149 compared to $165 during the second quarter of 2011. The decrease in interest income is primarily attributable to fewer available funds for investment. General and administrative expenses during the second quarter of 2012 amounted to $485,146 compared to $502,935 during the second quarter of 2011. The decrease in general and administrative expenses can be primarily attributed to decreased professional expenses.

These transactions resulted in distributable income for the quarter ended June 30, 2012 of $15,657,282 or $.335929 per Unit of beneficial interest. Distributions of $.111279, $.137527 and $.087123 per Unit were made to Unit holders of record as of April 30, 2012, May 31, 2012 and June 29, 2012, respectively. For the second quarter of 2011, distributable income was $17,895,921, or $.383959 per Unit of beneficial interest.

Royalty income for the Trust for the second quarter of the calendar year is associated with actual oil and gas production for the period of February, March and April of 2012 from the properties from which the Trust’s net overriding royalty interests (“Royalties”) were carved. Oil and gas sales attributable to the Royalties and the properties from which the Royalties were carved are as follows:

 

     Second Quarter  
     2012      2011  

Production:

     

Oil sales (Bbls)

     143,036         152,584   

Gas sales (Mcf)

     470,327         632,460   

Product Sales From Which The Royalties Were Carved:

     

Oil:

     

Total oil sales (Bbls)

     257,526         240,626   

Average per day (Bbls)

     2,861         2,704   

Average price per Bbl

   $ 98.65       $ 93.97   

Gas:

     

Total gas sales (Mcf)

     1,097,989         1,159,749   

Average per day (Mcf)

     12,200         13,031   

Average price per Mcf

   $ 6.19       $ 7.59   

 

14


The average received price of oil increased to an average price per barrel of $98.65 per Bbl in the second quarter of 2012 compared to $93.97 per Bbl in the second quarter of 2011 due to worldwide market variables. The Trustee has been advised by ConocoPhillips that for the period of August 1, 1993, through June 30, 2012, the oil from the Waddell Ranch properties was being sold under a competitive bid to a third party. The average price of gas (including natural gas liquids) decreased from $7.59 per Mcf in the second quarter of 2011 to $6.19 per Mcf in the second quarter of 2012 due to change in overall market variables.

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), the production amounts in the Royalties section of the above table do not provide a meaningful comparison. Oil sales volumes decreased and gas sales volumes decreased from the Underlying Properties (as defined in the Trust’s Annual Report on Form 10-K for the year ended December 31, 2011) for the applicable period in 2012 compared to 2011.

Capital expenditures for drilling, remedial and maintenance activities on the Waddell Ranch properties during the second quarter of 2012 totaled $5.6 million as compared to $1.9 million to the Trust for the second quarter of 2011. ConocoPhillips has informed the Trustee that the 2012 capital expenditures budget has been revised to $75.4 million (gross) for the Waddell Ranch properties. The total amount of capital expenditures for 2011 was $11.5 million. Through the second quarter of 2012, capital expenditures of $8.0 million (gross) have been expended.

The Trustee has been advised that there were 0 wells completed and 0 wells in progress, and 12 workover wells completed and 14 workover wells in progress, during the three months ended June 30, 2012 as compared to 1 well completed and 1 well in progress, and 3 workover wells completed and 9 workover wells in progress for the three months ended June 30, 2011 on the Waddell Ranch properties. There were 0 facility projects completed and 1 project in progress for the second quarter of 2012.

Lease operating expenses and property taxes totaled $5.4 million for the second quarter of 2012, compared to $5.1 million in the second quarter of 2011 on the Waddell Ranch properties. This increase is primarily attributable to increased costs of services.

Six Months Ended June 30, 2012 Compared to Six Months Ended June 30, 2011

For the six months ended June 30, 2012, royalty income received by the Trust amounted to $36,563,959 compared to royalty income of $35,196,974 for the six months ended June 30, 2011. The increase in royalty income is primarily due to an increase in oil and gas prices in the first six months of 2012, compared to the first six months in 2011.

Interest income for the six months ended June 30, 2012 was $535 compared to $364 for the six months ended June 30, 2011. The increase in interest income is attributable primarily to more funds available to invest. General and administrative expenses for the six months ended June 30, 2012 were $810,743. During the six months ended June 30, 2011, general and administrative expenses were $842,452. The decrease in general and administrative expenses is primarily due to reduced Unit holder reporting and other professional expenses.

These transactions resulted in distributable income for the six months ended June 30, 2012 of $35,753,751, or $.767103, per Unit. For the six months ended June 30, 2011, distributable income was $34,354,886, or $.737090, per Unit.

 

15


Royalty income for the Trust for the six months ended June 30, 2012 is associated with actual oil and gas production for the period November 2011 through April 2012 from the properties from which the Royalties were carved. Oil and gas production attributable to the Royalties and the properties from which the Royalties were carved are as follows:

 

     Six Months Ended  
     2012      2011  

Royalties:

     

Oil sales (Bbls)

     317,877         306,605   

Gas sales (Mcf)

     1,127,867         1,294,334   

Properties From Which The Royalties Were Carved:

     

Oil:

     

Total oil sales (Bbls)

     520,528         501,717   

Average per day (Bbls)

     2,860         2,772   

Average price per Bbl

   $ 96.95       $ 88.26   

Gas:

     

Total gas sales (Mcf)

     2,239,785         2,469,708   

Average per day (Mcf)

     12,307         13,645   

Average price per Mcf

   $ 6.91       $ 7.32   

The average received price of oil increased during the six months ended June 30, 2012 to $96.95 per barrel compared to $88.26 per barrel for the same period in 2011. The increase in the average price of oil is primarily due to worldwide market variables. The decrease in the average price of gas (including natural gas liquids) from $7.32 per Mcf for the six months ended June 30, 2011 to $6.91 per Mcf for the six months ended June 30, 2012 is primarily the result of a decrease in the spot prices of natural gas.

Since the oil and gas sales volumes attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), the production amounts in the Royalties section of the above table do not provide a meaningful comparison. The oil and gas sales volumes from the properties from which the Royalties are carved have fluctuated for the applicable period of 2012 compared to 2011.

Capital expenditures for the Waddell Ranch properties for the six months ended June 30, 2012 totaled $8.0 million compared to $5.7 million net to the Trust for the same period in 2011. ConocoPhillips has previously advised the Trust that the remaining 2012 capital expenditures budget for the Waddell Ranch properties is $67.4 million (gross).

The Trustee has been advised that 0 wells were drilled and completed and 0 wells were to be completed on the Waddell Ranch properties during the six months ended June 30, 2012, as compared to 4 wells drilled and completed and 0 wells to be completed on the Waddell Ranch properties during the six months ended June 30, 2011. Approximately 12 workover wells were completed and approximately 14 workover wells were in progress as of June 30, 2012.

 

16


Lease operating expense and property taxes totaled $9.9 million for the six months ended June 30, 2012 compared to $9.6 million for the same period in 2011. The increase in lease operating expense is primarily attributable to additional spending on facilities.

Calculation of Royalty Income

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. These percentages of net profits are 75% and 95% in the case of the Waddell Ranch properties and the Texas Royalty properties, respectively. Royalty income received by the Trust for the three months ended June 30, 2012 and 2011, respectively, were computed as shown in the table below:

 

     Three Months Ended June 30,  
     2012     2011  
     Waddell
Ranch
Properties
    Texas
Royalty
Properties
    Waddell
Ranch
Properties
    Texas
Royalty
Properties
 

Gross proceeds of sales from the Underlying Properties

        

Oil proceeds

   $ 17,300,173      $ 8,104,325      $ 15,598,929      $ 7,013,101   

Gas proceeds

     5,699,754        1,093,043        7,803,005        996,692   
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     22,999,927        9,197,368        23,401,934        8,009,793   
  

 

 

   

 

 

   

 

 

   

 

 

 

Less:

        

Severance tax:

        

Oil

     713,124        308,125        633,581        255,781   

Gas

     350,953        62,238        422,182        48,155   

Lease operating expenses and property tax:

        

Oil and gas

     5,376,661        420,000        5,076,209        420,000   

Other

     22,633        —          39,802        —     

Capital expenditures

     5,662,389        —          1,927,325        —     
  

 

 

   

 

 

   

 

 

   

 

 

 

Total

     12,125,760        790,363        8,099,099        723,936   

Net profits

     10,874,167        8,407,005        15,302,835        7,285,857   

Net overriding royalty interests

     75     95     75     95
  

 

 

   

 

 

   

 

 

   

 

 

 

Royalty income

   $ 8,155,625      $ 7,986,654      $ 11,477,127      $ 6,921,564   
  

 

 

   

 

 

   

 

 

   

 

 

 

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.

 

17


Basis of Accounting

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

 

  Royalty income recorded for a month is the amount computed and paid to the Trustee on behalf of the Trust by the interest owners. Royalty income consists of the amounts received by the owners of the interest burdened by the Royalties from the sale of production less accrued production costs, development and drilling costs, applicable taxes, 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.

 

  Trust expenses, consisting principally of routine general and administrative costs, 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.

 

  Royalty income is computed separately for each of the conveyances under which the Royalties were conveyed to the Trust. If monthly costs exceed revenues for any conveyance (“excess costs”), such excess costs cannot reduce royalty income from other conveyances, but is carried forward with accrued interest to be recovered from future net proceeds of that conveyance.

 

  Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.

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.

Revenue Recognition

Revenues from the 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, on an entitlement basis, from natural gas produced and sold for the twelve-month period ended October 31st in that calendar year. Royalty income received by the Trust in the second quarter of 2012 generally reflects the proceeds associated with actual oil and gas production for the period of February 2012 through April 2012.

 

18


Reserve Disclosure

As of January 1, 2012, independent petroleum engineers estimated 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 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. 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 additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserves estimates.

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.

On May 2, 2011, ConocoPhillips, as the parent company of BROG, the operator of the Waddell Ranch properties, notified the Trustee that as a result of inaccuracies in ConocoPhillips’ accounting and record keeping relating to the Trust’s interest in proceeds from the gas plant production since January 2007 ConocoPhillips overpaid the Trust approximately $5.9 million initially. ConocoPhillips informed the Trustee on September 20, 2011 that it was withholding $4,068,067 (all of the Waddell Ranch portion of the September, 2011 proceeds, which would be reflective of July 2011 production, of approximately 29,796 bbls of oil and 180,425 mcf of gas) in order to recoup this overpayment. This affected the Trust’s distribution declared September 20, 2011 and paid October 17, 2011. ConocoPhillips also withheld $474,480 from the proceeds for October 2011, which ConocoPhillips has informed the Trustee completes the recoupment. ConocoPhillips has indicated that these two recoupments will satisfy the initial claim of $5.9 million. Additionally, ConocoPhillips informed the Trustee that beginning with the June 2011 distribution, proceeds to the Trust relating to the gas plant production have been adjusted to reflect ConocoPhillips’ calculation of the corrected interest. The Trustee is continuing to evaluate the matter.

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 the reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting period. 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 June 30, 2012.

 

19


Distributable Income Per Unit

Basic distributable income per Unit is computed by dividing distributable income by the weighted average of Units outstanding. Distributable income per Unit assuming dilution is computed by dividing distributable income by the weighted average number of Units and equivalent Units outstanding. The Trust had no equivalent Units outstanding for any period presented. Therefore, basic distributable income per Unit and distributable income per Unit assuming dilution are the same.

New Accounting Pronouncements

There are no new accounting pronouncements that are expected to have a significant impact on the Trust’s financial statements.

Item 3. Qualitative and Quantitative Disclosures About Market Risk

There have been no material changes in the Trust’s market risk, as disclosed in the Trust’s Annual Report on Form 10-K for the fiscal year ended December 31, 2011.

Item 4. 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 Exchange Act Rules 13a-15 and 15d-15. 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. There has not been any change in the Trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

 

20


PART II - OTHER INFORMATION

Items 1 through 5.

Not applicable.

Item 6. Exhibits

 

  4.1 Permian Basin Royalty Trust Indenture dated November 3, 1980, between Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.

 

  4.2 Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.

 

  4.3 Net Overriding Royalty Conveyance (Permian Basin Royalty Trust—Waddell Ranch) from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.

 

  10.1 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.

 

  10.2 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.

 

21


  10.3 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.

 

  10.4 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.

 

  31.1 Certification by Ron E. Hooper, Senior Vice President and Trust Administrator of Bank of America, Trustee of Permian Basin Royalty Trust, dated August 8, 2012 and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 

  32.1 Certificate by Bank of America, Trustee of Permian Basin Royalty Trust, dated August 8, 2012 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

 

22


SIGNATURES

Pursuant to the requirements 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.

BANK OF AMERICA, N.A.,

TRUSTEE FOR THE

PERMIAN BASIN ROYALTY TRUST

By: /s/ Ron E. Hooper                                                      

      Ron E. Hooper

      Senior Vice President

      Trust Administrator

Date: August 8, 2012

(The Trust has no directors or executive officers.)

 

23


INDEX TO EXHIBITS

 

Exhibit
Number
   Exhibit
4.1    Permian Basin Royalty Trust Indenture dated November 3, 1980, between Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.*
4.2    Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.*
4.3    Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) from Southland Royalty Company (now Burlington Resources Oil & Gas Company LP) 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.*
10.1    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.*
10.2    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.*
10.3    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.*

 

24


10.4    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.*
31.1    Certification by Ron E. Hooper, Senior Vice President and Trust Administrator of Bank of America, Trustee of Permian Basin Royalty Trust, dated August 8, 2012 and submitted pursuant to Rule 13a-14(a)/15d-14(a) and pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1    Certificate by Bank of America, Trustee of Permian Basin Royalty Trust, dated August 8, 2012 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

 

* A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon written request to the Trustee, U.S. Trust, Bank of America Private Wealth Management, 901 Main Street, Dallas, Texas 75202.

 

25

XNYS:PBT Permian Basin Royalty Trust Quarterly Report 10-Q Filling

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