UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

ý

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2006

OR

o

ý     QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2005

OR

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number:  1-10476

 

Hugoton Royalty Trust

(Exact name of registrant as specified in its charter)

 

Texas

 

58-6379215

(State or other jurisdiction of

(I.R.S. Employer

incorporation or organization)

 

(I.R.S. Employer
Identification No.)

 

 

 

Bank of America, N.A., P.O. Box 830650, Dallas, Texas

 

75283-0650

(Address of principal executive offices)

 

(Zip Code)

 

(877) 228-5083

(Registrant’s telephone number, including area code)

 

NONE

(Former name, former address and former fiscal year, if changedchange since last report)

 

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 ý No o

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, (as definedor a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act).  YesAct.  (Check one):

Large accelerated filer  o  Accelerated filer  ý  NoNon-accelerated filer  o

 

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

 

Indicate the number of units of beneficial interest outstanding, as of the latest practicable date:

 

Outstanding as of OctoberApril 1, 20052006

40,000,000

 

 


 

HUGOTON ROYALTY TRUST

 

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2005MARCH 31, 2006

 

TABLE OF CONTENTS

 

TABLE OF CONTENTS

 

Glossary of Terms

 

 

 

 

PART I.

FINANCIAL INFORMATION

 

 

 

 

Item 1.

Financial Statements

 

 

 

 

 

Report of Independent Registered Public Accounting Firm

 

 

 

 

 

Condensed Statements of Assets, Liabilities and Trust Corpus

at September 30, 2005March 31, 2006 and December 31, 20042005

 

 

 

 

 

Condensed Statements of Distributable Income

for the Three and Nine Months Ended September 30,March 31, 2006 and 2005 and 2004

 

 

 

 

 

Condensed Statements of Changes in Trust Corpus

for the Three and Nine Months Ended September 30,March 31, 2006 and 2005 and 2004

 

 

 

 

 

Notes to Condensed Financial Statements

 

 

 

 

Item 2.

Trustee’s Discussion and Analysis

 

 

 

 

Item 3.

Quantitative and Qualitative Disclosures about Market Risk

 

 

 

 

Item 4.

Controls and Procedures

 

 

 

 

PART II.

OTHER INFORMATION

 

 

 

 

Item 1A.

Risk Factors

Item 6.

Exhibits

 

 

 

 

 

Signatures

 

 

32


 

HUGOTON ROYALTY TRUST

 

GLOSSARY OF TERMS

 

The following are definitions of significant terms used in this Form 10-Q:

 

Bbl

 

Barrel (of oil)

 

 

 

Mcf

 

Thousand cubic feet (of natural gas)

 

 

 

MMBtu

 

One million British Thermal Units, a common energy measurement

 

 

 

net proceeds

 

Gross proceeds received by XTO Energy Inc. from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances

 

 

 

net profits income

 

Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by XTO Energy Inc.Energy. “Net profits income” is referred to as “royalty income” for income tax reporting purposes.

 

 

 

net profits interest

 

An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:

 

 

 

 

 

80% net profits interests - interests that entitle the trust to receive 80% of the net proceeds from the underlying properties that are working interests in Kansas, Oklahoma and Wyomingproperties.

 

 

 

underlying properties

 

XTO Energy Inc.’sEnergy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming.

 

 

 

working interest

 

An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production expense and development costs

 

43


 

HUGOTON ROYALTY TRUST

 

PART I - - FINANCIAL INFORMATION

 

Item 1.  Financial Statements.

 

The condensed financial statements included herein are presented, 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.  These condensed financial statements should be read in conjunction with the trust’s financial statements and the notes thereto included in the trust’s 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 Hugoton Royalty Trust at September 30, 2005March 31, 2006 and the distributable income and changes in trust corpus for the three- and nine-monththree-month periods ended September 30,March 31, 2006 and 2005 and 2004 have been included.  Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

 

54


 

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

Bank of America, N.A., as Trustee

for the Hugoton Royalty Trust:

 

We have reviewed the accompanying condensed statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of September 30, 2005March 31, 2006 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-monththree-month periods ended September 30, 2005March 31, 2006 and 2004.2005.  These condensed financial statements are the responsibility of the trustee.

 

We conducted our review in accordance with standards established by the Public Company Accounting Oversight Board (United States).  A review of interim financial information consists principally of applying analytical procedures to financial data 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.

 

The accompanying condensed financial statements are prepared on a modified cash basis as described in Note 1 which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

 

Based on our review, we are not aware of any material modifications that should be made to the condensed financial statements referred to above for them to be in conformity with the basis of accounting described in Note 1.

 

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 the Hugoton Royalty Trust as of December 31, 2004,2005, and the related statements of distributable income and changes in trust corpus for the year then ended (not presented herein), included in the trust’s 20042005 Annual Report on Form 10-K, and in our report dated March 14, 2005,16, 2006, 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, 20042005 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 20042005 Annual Report on Form 10-K from which it has been derived.

 

 

KPMG LLP

 

Dallas, Texas

October 21, 2005April 28, 2006

 

65


 

HUGOTON ROYALTY TRUST

 

Condensed Statements of Assets, Liabilities and Trust Corpus

 

 

March 31,

 

December 31,

 

 

September 30,

 

December 31,

 

 

2006

 

2005

 

 

2005

 

2004

 

 

(Unaudited)

 

 

 

 

(Unaudited)

 

 

 

 

 

 

 

 

ASSETS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Cash and short-term investments

 

$

8,808,240

 

$

6,947,520

 

 

$

12,048,680

 

$

13,524,280

 

 

 

 

 

 

 

 

 

 

 

Net profits interests in oil and gas properties - net (Note 1)

 

174,484,666

 

182,551,814

 

 

169,197,088

 

171,935,330

 

 

 

 

 

 

 

 

 

 

 

 

$

183,292,906

 

$

189,499,334

 

 

$

181,245,768

 

$

185,459,610

 

 

 

 

 

 

 

 

 

 

 

LIABILITIES AND TRUST CORPUS

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distribution payable to unitholders

 

$

8,808,240

 

$

6,947,520

 

 

$

12,048,680

 

$

13,524,280

 

 

 

 

 

 

 

 

 

 

 

Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)

 

174,484,666

 

182,551,814

 

 

169,197,088

 

171,935,330

 

 

 

 

 

 

 

 

 

 

 

 

$

183,292,906

 

$

189,499,334

 

 

$

181,245,768

 

$

185,459,610

 

 

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

 

76


 

HUGOTON ROYALTY TRUST

 

Condensed Statements of Distributable Income (Unaudited)

 

 

Three Months Ended

 

Nine Months Ended

 

 

September 30

 

September 30

 

 

Three Months Ended March 31

 

 

2005

 

2004

 

2005

 

2004

 

 

2006

 

2005

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net profits income

 

$

24,325,921

 

$

23,521,511

 

$

73,110,521

 

$

60,868,299

 

 

$

39,085,894

 

$

25,818,940

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Interest income

 

29,600

 

9,303

 

71,509

 

20,156

 

 

86,245

 

20,050

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total income

 

24,355,521

 

23,530,814

 

73,182,030

 

60,888,455

 

 

39,172,139

 

25,838,990

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Administration expense

 

51,321

 

101,974

 

347,630

 

304,295

 

 

130,539

 

140,830

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributable income

 

$

24,304,200

 

$

23,428,840

 

$

72,834,400

 

$

60,584,160

 

 

$

39,041,600

 

$

25,698,160

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Distributable income per unit (40,000,000 units)

 

$

0.607605

 

$

0.585721

 

$

1.820860

 

$

1.514604

 

Distributable income per unit 40,000,000 units

 

$

0.976040

 

$

0.642454

 

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

7


HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)

 

 

Three Months Ended March 31

 

 

 

2006

 

2005

 

 

 

 

 

 

 

Trust corpus, beginning of period

 

$

171,935,330

 

$

182,551,814

 

 

 

 

 

 

 

Amortization of net profits interests

 

(2,738,242

)

(2,821,703

)

 

 

 

 

 

 

Distributable income

 

39,041,600

 

25,698,160

 

 

 

 

 

 

 

Distributions declared

 

(39,041,600

)

(25,698,160

)

 

 

 

 

 

 

Trust corpus, end of period

 

$

169,197,088

 

$

179,730,111

 

 

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

 

8


 

HUGOTON ROYALTY TRUST

 

Condensed Statements of Changes in Trust Corpus (Unaudited)

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30

 

September 30

 

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

 

 

 

 

 

Trust corpus, beginning of period

 

$

177,114,508

 

$

188,000,381

 

$

182,551,814

 

$

193,245,847

 

 

 

 

 

 

 

 

 

 

 

Amortization of net profits interests

 

(2,629,842

)

(2,808,249

)

(8,067,148

)

(8,053,715

)

 

 

 

 

 

 

 

 

 

 

Distributable income

 

24,304,200

 

23,428,840

 

72,834,400

 

60,584,160

 

 

 

 

 

 

 

 

 

 

 

Distributions declared

 

(24,304,200

)

(23,428,840

)

(72,834,400

)

(60,584,160

)

 

 

 

 

 

 

 

 

 

 

Trust corpus, end of period

 

$

174,484,666

 

$

185,192,132

 

$

174,484,666

 

$

185,192,132

 

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

9


HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements (Unaudited)

 

1.   Basis of Accounting

 

The financial statements of Hugoton Royalty Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with U.S. generally accepted accounting principles (“GAAP”):

 

•     Net profits income recorded for a month is the amount computed and paid by XTO Energy Inc., the owner of the underlying properties, to Bank of America, N.A., as trustee for the trust.  Net profits income consists of net proceeds received by XTO Energy Inc. from the underlying properties in the prior month, multiplied by a net profits percentage of 80%.

 

Costs deducted in the calculation of net proceeds for the 80% net profits interests generally include applicable taxes, transportation, marketing and legal costs, production expense, development costs, operating charges and other costs.

 

•     Net profits income is computed separately for each of three conveyances under which the net profits interests were conveyed to the trust.  If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net proceeds from the other conveyances.

 

•     Trust expenses are recorded based on liabilities paid and cash reserves established by the trustee for liabilities and contingencies.

 

•     Distributions to unitholders are recorded when declared by the trustee.

 

The trust’s financial statements differ from those prepared in conformity with U.S. GAAP because revenues are recognized when received rather than accrued in the month of production, expenses are recognized when paid rather than when incurred and certain cash reserves may be established by the trustee for contingencies which would not be recorded under U.S. GAAP.  This comprehensive basis of accounting other than U.S. 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.

 

Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. GAAP, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid.  Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the trust’s financial statements.

 

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy Inc.’sEnergy’s historical net book value for the interests on December 1, 1998, the date of the transfer to the trust.  Amortization of the net profits interests is calculated on a unit-of-production basis and charged directly to trust corpus.  Accumulated amortization was $72,582,285$77,869,863 as of September 30, 2005March 31, 2006 and $64,515,137$75,131,621 as of December 31, 2004.2005.

 

109


 

2.   Development Costs

 

The following summarizes actual development costs, budgeted development costs deducted in the calculation of net profits income, and the cumulative actual costs compared to the amount deducted:

 

 

Development Costs

 

 

Three Months Ended

 

 

Three Months Ended

 

Nine Months Ended

 

 

March 31

 

 

September 30

 

September 30

 

 

2006

 

2005

 

 

2005

 

2004

 

2005

 

2004

 

 

 

 

 

 

Cumulative actual costs (over) under the amount deducted - beginning of period

 

$

(951,511

)

$

1,420,005

 

$

(319,927

)

$

(1,583,988

)

 

$

113,905

 

$

(319,927

)

Actual costs

 

(10,883,949

)

(3,757,300

)

(25,515,533

)

(10,953,307

)

 

(12,450,558

)

(7,658,739

)

Budgeted costs deducted

 

9,900,000

 

5,100,000

 

23,900,000

 

15,300,000

 

 

9,900,000

 

6,800,000

 

Cumulative actual costs (over) under the amount deducted - end of period

 

$

(1,935,460

)

$

2,762,705

 

$

(1,935,460

)

$

2,762,705

 

 

$

(2,436,653

)

$

(1,178,666

)

 

The monthly development deduction was $2 million in January 2005; it has been2005, but was increased three times during 2005 as a result of increased development activity and higher costs.  The deductions were increased to $2.4 million beginning with the February 2005 distribution, to $3.3 million beginning with the July 2005 distribution and to $5.1 million beginning with the October 2005 distribution.  The development cost deduction was lowered to $3.3 million beginning with the January 2006 distribution, but was increased to $4.2 million beginning with the April 2006 distribution based on the current level of development activity and costs.

XTO Energy Inc. has advised the trustee that it currently expectsis reevaluating the 2006 budget of $40 million, which may be increased because of escalated drilling activity and higher costs.  The 2006 budget year generally coincides with the trust distribution months from April 2006 through March 2007.  The monthly development cost deduction will remain at $5.1 million forbe reevaluated and revised as necessary, based on the remainder2006 budget and the timing and amount of 2005, subject to reevaluation and revision as necessary.actual expenditures.

 

3.   Contingencies

 

Litigation

 

XTO Energy Inc. is a defendant in lawsuits related to the underlying properties that could, if adversely determined, decrease future trust distributable income attributable to production on or after December 1, 1998, the creation date of the trust.  Any damages relating to production prior to December 1, 1998 will be borne by XTO Energy Inc.Energy.

 

On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against XTO Energy Inc.Energy.  The plaintiff alleges that XTO Energy Inc. underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years.  The plaintiff seeks treble damages for the unpaid royalties (with interest, attorneys’attorney’s fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy Inc. to cease the allegedly improper measuring practices.  This lawsuit against XTO Energy Inc. and similar lawsuits filed by Grynberg against

10


more than 300 other companies have been consolidated in the United States District Court for Wyoming.  In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003.  The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act.  In June 2004, XTO Energy Inc. joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action.  A hearing on this motion occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and

11


make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some of the defendants but to retain jurisdiction of the case involving XTO Energy Inc. and other defendants.  XTO Energy Inc. and other defendants filed a motionmotions to modify the special master’s report, requesting the district judge to also dismiss the case as to XTO Energy Inc. and other defendants.  The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special master’s report, and XTO Energy is awaiting the decision of the district court.  While XTO Energy Inc. is unable to predict the outcome of this case or estimate the amount of any possible loss, it has informed the trustee that it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action.  However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy Inc. management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

 

Certain of the underlying properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy Inc. has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.

 

Other

 

Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds.  After consultation with its state tax counsel, XTO Energy Inc. has advised the trustee that it believes the trust is not subject to these withholding requirements.  However, regulations are subject to change by the various states, which could change this conclusion.  In the event it is determined thatShould the trust isbe required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.

 

4.XTO Energy Inc.

As of March 31, 2006, XTO Energy owned 54.3% of the trust.  In January 2006, XTO Energy declared a dividend of all of the 21.7 million trust units it owns.  These units are to be distributed on May 12, 2006 to XTO Energy’s common stockholders of record on April 26, 2006.  After this dividend, XTO Energy will not be a unitholder of the trust.  XTO Energy also announced in January 2006 that it will consider selling the underlying properties. Any sale is dependent upon XTO Energy’s ability to structure a tax-efficient transaction and receive sufficient consideration from a buyer it deems to be qualified.

11


 

Item 2.  Trustee’s Discussion and Analysis.

 

The following discussion should be read in conjunction with the trustee’s discussion and analysis contained in the trust’s 20042005 annual report, as well as the condensed financial statements and notes thereto included in this quarterly report on Form 10-Q.  The trust’s Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports are available on the trust’s web site at www.hugotontrust.com.

 

Distributable Income

Quarter

 

For the quarter ended September 30, 2005,March 31, 2006, net profits income was $24,325,921,$39,085,894, as compared to $23,521,511$25,818,940 for thirdfirst quarter 2004.  This 3% increase in2005.  Increased net profits income is primarily the result of higher oil and gas prices.  See “Net Profits Income” on the following page.below.

 

After adding interest income of $29,600$86,245 and deducting administration expense of $51,321,$130,539, distributable income for the quarter ended September 30, 2005March 31, 2006 was $24,304,200,$39,041,600, or $0.607605$0.976040 per unit of beneficial interest.  Administration expense for the quarter decreased 50%7% from the prior year quarter primarily because of the timing of expenditures.expenditures related to the 2004 audit of the trust’s internal control over financial reporting.  Increased interest income over these periods was because of the increase in net profits income and higher interest rates.  For thirdfirst quarter 2004,2005, distributable income was $23,428,840$25,698,160, or $0.585721$0.642454 per unit.  Distributions to unitholders for the quarter ended September 30, 2005March 31, 2006 were:

 

 

 

 

 

Distribution

 

Record Date

 

Payment Date

 

per Unit

 

 

 

 

 

 

 

July 29, 2005

 

August 12, 2005

 

$

0.210129

 

August 31, 2005

 

September 15, 2005

 

0.177270

 

September 30, 2005

 

October 17, 2005

 

0.220206

 

 

 

 

 

$

0.607605

 

Nine Months

For the nine months ended September 30, 2005, net profits income was $73,110,521, compared with $60,868,299 for the same 2004 period.  This 20% increase in net profits income is primarily the result of higher oil and gas prices.  See “Net Profits Income” on the following page.

After adding interest income of $71,509 and deducting administration expense of $347,630, distributable income for the nine months ended September 30, 2005 was $72,834,400, or $1.820860  per unit of beneficial interest.  Administration expense for the first nine months of 2005 was 14% higher than in the first nine months of 2004 primarily because of fees related to the audit of the trust’s internal control over financial reporting for 2004 and the timing of expenditures.  For the nine months ended September 30, 2004, distributable income was $60,584,160 or $1.514604 per unit.

13


 

 

 

 

Distribution

 

Record Date

 

Payment Date

 

per Unit

 

 

 

 

 

 

 

January 31, 2006

 

February 14, 2006

 

$

0.382209

 

February 28, 2006

 

March 14, 2006

 

0.292614

 

March 31, 2006

 

April 14, 2006

 

0.301217

 

 

 

 

 

$

0.976040

 

 

Net Profits Income

 

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy, Inc., and generally two months after oil and gas production.  Net profits income is generally affected by three major factors:

 

•     oil and gas sales volumes,

 

•     oil and gas sales prices, and

 

•     costs deducted in the calculation of net profits income.

 

1412


 

The following is a summary of the calculation of net profits income received by the trust:

 

 

Three Months

 

 

 

 

Ended March 31 (a)

 

Increase

 

 

Three Months
Ended September 30 (a)

 

Increase

 

Nine Months
Ended September 30 (a)

 

Increase

 

 

2006

 

2005

 

(Decrease)

 

 

2005

 

2004

 

(Decrease)

 

2005

 

2004

 

(Decrease)

 

 

 

 

 

 

 

 

Sales Volumes

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (Mcf) (b)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Underlying properties

 

7,639,778

 

7,610,566

 

—

 

22,341,911

 

22,731,973

 

(2)%

 

 

7,410,013

 

7,489,832

 

(1)%

 

Average per day

 

83,041

 

82,724

 

—

 

81,839

 

82,963

 

(1)%

 

 

80,544

 

81,411

 

(1)%

 

Net profits interests

 

3,922,803

 

4,323,048

 

(9)%

 

12,033,759

 

12,397,898

 

(3)%

 

 

4,330,569

 

4,209,237

 

3%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbls) (b)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Underlying properties

 

85,765

 

82,513

 

4%

 

245,405

 

240,365

 

2%

 

 

78,265

 

74,413

 

5%

 

Average per day

 

932

 

897

 

4%

 

899

 

877

 

3%

 

 

851

 

809

 

5%

 

Net profits interests

 

42,973

 

47,015

 

(9)%

 

131,924

 

138,137

 

(4)%

 

 

47,049

 

44,123

 

7%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average Sales Prices

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas (per Mcf)

 

$6.17

 

$5.50

 

12%

 

$6.09

 

$4.96

 

23%

 

 

 

$ 9.10

 

 

$ 6.22

 

46%

 

Oil (per Bbl)

 

$52.49

 

$38.59

 

36%

 

$49.49

 

$35.30

 

40%

 

 

 

$ 59.10

 

 

$ 45.03

 

31%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Revenues

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gas sales

 

$

47,155,805

 

$

41,844,270

 

13%

 

$

135,955,911

 

$

112,657,193

 

21%

 

 

$

67,404,751

 

$

46,577,676

 

45%

 

Oil sales

 

4,501,609

 

3,183,986

 

41%

 

12,146,012

 

8,484,473

 

43%

 

 

4,625,299

 

3,350,990

 

38%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Revenues

 

51,657,414

 

45,028,256

 

15%

 

148,101,923

 

121,141,666

 

22%

 

 

72,030,050

 

49,928,666

 

44%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Costs

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Taxes, transportation and other

 

4,606,027

 

3,819,435

 

21%

 

13,530,251

 

10,330,456

 

31%

 

 

5,727,555

 

4,609,139

 

24%

 

Production expense

 

4,761,078

 

4,666,777

 

2%

 

13,488,822

 

13,772,433

 

(2)%

 

 

5,546,717

 

4,340,197

 

28%

 

Development costs (c)

 

9,900,000

 

5,100,000

 

94%

 

23,900,000

 

15,300,000

 

56%

 

 

9,900,000

 

6,800,000

 

46%

 

Overhead

 

1,982,908

 

2,040,155

 

(3)%

 

5,794,699

 

5,653,403

 

2%

 

 

1,998,411

 

1,905,655

 

5%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Costs

 

21,250,013

 

15,626,367

 

36%

 

56,713,772

 

45,056,292

 

26%

 

 

23,172,683

 

17,654,991

 

31%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Proceeds

 

30,407,401

 

29,401,889

 

3%

 

91,388,151

 

76,085,374

 

20%

 

 

48,857,367

 

32,273,675

 

51%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Profits Percentage

 

80%

 

80%

 

 

 

80%

 

80%

 

 

 

 

80%

 

80%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net Profits Income

 

$

24,325,921

 

$

23,521,511

 

3%

 

$

73,110,521

 

$

60,868,299

 

20%

 

 

$

39,085,894

 

$

25,818,940

 

51%

 

 

(a)

Because of the two-month interval between time of production and receipt of net profits income by the trust, oil and gas sales for the quarter ended March 31 generally represent production for the period November through January.

(b)

Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs. Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c)

See Note 2 to Condensed Financial Statements.

(a)                                  Because of the two-month interval between time of production and receipt of net profits income by the trust, (1) oil and gas sales for the quarter ended September 30 generally represent production for the period May through July and (2) oil and gas sales for the nine months ended September 30 generally represent production for the period November through July.

(b)                                 Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expense and development costs.  Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests.  Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.

(c)                                  See Note 2 to Condensed Financial Statements.

1513


 

The following are explanations of significant variances on the underlying properties from third quarter 2004 to thirdfirst quarter 2005 and from theto first nine months of 2004 to the comparable period in 2005:quarter 2006:

 

Sales Volumes

 

Gas

ThirdFirst quarter gas sales volumes remained relatively unchanged as increased production from new wells and workovers and the timing of cash receipts was offset by natural production decline.  Gasdecreased 1%, while oil sales volumes for the nine-month period decreased 2%increased 5%.  Lower gas sales volumes are primarily because of natural production decline, and the timing of cash receipts, partially offset by increased production from new wells and workovers.

Oil

Oil  Increased oil sales volumes increased 4% for the third quarter and 2% for the nine-month periodare primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline.

 

See “Gulf of Mexico Hurricanes” below.

Sales Prices

 

Gas

 

The thirdfirst quarter 2006 average gas price was $9.10 per Mcf, a 46% increase from the first quarter 2005 average gas price was $6.17of $6.22 per Mcf, a 12% increase from the third quarter 2004 average gas price of $5.50 per Mcf.  For the nine-month period, the average gas price increased 23% to $6.09 per Mcf in 2005 from $4.96 per Mcf in 2004. Gas prices increased forfrom first quarter 2005 to first quarter 2006 primarily due to the third quarter and for the nine-month period primarily becauseeffects of hurricanes on Gulf of Mexico production in 2005, as well as increased demand warmer-than-normal temperatures and reduced gas production as a result of July tropical storms in the Gulf of Mexico.declining North American production.  Prices will continue to be affected by weather, the U.S. economy, the level of North American production crude oil prices and import levels of liquified natural gas, and are expected to remain volatile.  The third quarter 2005 gas price is primarily related to production from May through July 2005, when the average NYMEX price was $7.08 per MMBtu, or 13% higher than the comparable 2004 period average NYMEX price of $6.25 per MMBtu.  The average NYMEX price for AugustFebruary and September 2005March 2006 was $10.68$7.24 per MMBtu.  At October 21, 2005,April 26, 2006, the average NYMEX futures price for the following twelve months was $11.58$9.32 per MMBtu.  TheRecent trust gas price for August 2005 production, included in the October 2005 distribution, was $1.05 per Mcfprices have averaged approximately 24% lower than the NYMEX price.  This decrement is expected to widen for September and October production, which will affect the November and December 2005 distributions.

 

Oil

 

The thirdfirst quarter 2006 average oil price was $59.10 per Bbl, a 31% increase from the first quarter 2005 average oil price was $52.49of $45.03 per Bbl, a 36% increase from the third quarter 2004 average oil price of $38.59 per Bbl.  The year-to-date average oil price increased 40% to $49.49 per Bbl in 2005 from $35.30 per Bbl in 2004.  Oil prices increased for the thirdfrom first quarter and for the nine-month period2005 to first quarter 2006 primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of July tropical storms and hurricanes in the Gulf of Mexico market speculationin 2005 and political instability, and are expected to remain volatile.  Oilinstability.  NYMEX oil prices increased to record levels in August 2005,April 2006, exceeding $69.00$75.00 per Bbl.  Oil prices are expected to remain volatile.  The average NYMEX price for AugustFebruary and September 2005March 2006 was $65.22$62.45 per Bbl.  At October 21, 2005,April 26, 2006, the average NYMEX futures price for the following twelve months was $61.12$74.76 per Bbl.  Recent trust oil prices have averaged approximately $2.40 per Bbl3% lower than the NYMEX price.

16


See “Gulf of Mexico Hurricanes” below.

 

Costs

 

Taxes

 

Taxes, transportation and other increased 21%24% for the first quarter and 31% for the nine-month period primarily because of increased production taxes related to higher revenues.  The increase for the nine-month period was also affectedrevenues, partially offset by decreased property taxes related to the timing of cash disbursements.

 

Production

 

Production expense increased 2% for the quarter and decreased 2% for the nine-month period.  Fluctuations in production expense are28% primarily because of the timing ofincreased maintenance projects as well as the timing of cash disbursements.and fuel costs.

 

Development

 

Development costs deducted in the calculation of net profits income are based on the development budget.  These development costs for first quarter 2006 increased 94% for46% from the thirdprior year quarter and 56% for the nine-month period primarily because of

14


increased development activity in western Oklahoma and higher drilling costs in 2005.southwestern Wyoming. During the first ninethree months of 2005, 242006, two wells were completed on the underlying properties and foursix wells were pending completion on the underlying properties at September 30.  XTO Energy Inc. has informed the trustee that it plans to drill 37 wells and perform approximately 25 workovers and 65 restimulations during 2005.March 31.

 

As of December 31, 2004, cumulative actual development costs exceeded2005, cumulative budgeted costs deducted exceeded cumulative actual costs by $319,927.approximately $114,000.  In calculating net profits income for the quarter ended March 31, 2006, XTO Energy Inc. deducted budgeted development costs of $9.9 million.  After considering actual development costs of $12.5 million for the quarter, and $23.9 million for the nine-month period.  After considering actual costs of $10.9 million for the quarter and $25.5 million for the nine-month period, cumulative actual costs exceeded cumulative budgeted costs deducted by $1.9$2.4 million.  First quarter actual development costs primarily relate to disbursements for development activity in fourth quarter 2005.  The development cost deduction was lowered to $3.3 million at September 30, 2005.beginning with the January 2006 distribution, but was increased to $4.2 million beginning with the April 2006 distribution based on the current level of development activity and costs.

XTO Energy has advised the trustee that it is reevaluating the 2006 budget of $40 million, which may be increased because of escalated drilling activity and higher costs.  The 2006 budget year generally coincides with the trust distribution months from April 2006 through March 2007.  The monthly development cost deduction will be reevaluated and revised as necessary, based on the 2006 budget and the timing and amount of actual expenditures.  See Note 2 to Condensed Financial Statements.

 

Because of increased development activity and higher costs, the monthly development cost deduction was increased from $2.4 million to $3.3 million beginning with the July 2005 distribution and to $5.1 million beginning with the October 2005 distribution.  Development projects have recently been accelerated because of gas supply disruptions and higher prices.  XTO Energy Inc. has advised the trustee that it currently expects the monthly development cost deduction will remain at $5.1 million for the remainder of 2005, subject to reevaluation and revision as necessary.

Overhead

 

Overhead decreased 3% for the quarter and increased 2% for the nine-month period.  Decreased overhead for the quarter is primarily because of the timing of an annual Oklahoma administrative fee.  Increased overhead for the nine-month period is5% primarily because of the annual rate adjustment based on an industry index.

Gulf of Mexico Hurricanes

In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher prices.  These increased prices will affect distributions to unitholders beginning with the November 2005 distribution to be paid in December 2005.  The underlying

17


properties to the trust are not located near the Gulf and related production was not significantly affected. However, because of greater supply and weaker demand in areas where trust related oil and gas is produced, the price received for such production will be significantly lower than the price received for Gulf production or NYMEX prices.  As a result of storm damages and related supply shortages, production expense and development costs are expected to increase throughout the industry.  The duration of these higher prices and costs cannot be predicted.

 

Forward-Looking Statements

 

This Form 10-Q includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended.  All statements other than statements of historical fact included in this Form 10-Q, including, without limitation, statements regarding the net profits interests, underlying properties, development activities, development, production and other costs and expenses, oil and gas prices and differentials to NYMEX prices, supply shortages, future drilling, workover and restimulation plans, distributions to unitholders and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part II,I, Item 71A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2004,2005, which is incorporated by this reference as though fully set forth herein.  Although XTO Energy Inc. and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy Inc. nor the trustee can give any assurance that such expectations will prove to be correct.

15


 

Item 3.  Quantitative and Qualitative Disclosures about Market Risk.

 

There have been no material changes in the trust’s market risks, as disclosed in Part II, Item 7A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2004.2005.

 

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 timely alerting the trustee to material information relating to the trust required to be included in the trust’s periodic filings with the Securities and Exchange Commission.  In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by XTO Energy Inc.Energy.  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.

 

1816


 

PART II - - OTHER INFORMATION

 

Item 1.

Not applicable.

Item 1A.  Risk Factors.

There have been no material changes in the risk factors disclosed under Part I, Item 1A of the trust’s Annual Report on Form 10-K for the year ended December 31, 2005.

Items 12 through 5.

 

Not applicable.

 

Item 6.    Exhibits.

 

(a)   Exhibits.

 

Exhibit Number
and Description

and Description

 

 

(15)

Awareness letter of KPMG LLP

 

 

(31)

Rule 13a-14(a)/15d-14(a) Certification

 

 

(32)

Section 1350 Certification

 

 

(99)

Items 7 and 7A to the Annual Report on Form 10-K for Hugoton Royalty Trust filed with the Securities and Exchange Commission on March 14, 200516, 2006 (incorporated herein by reference)

 

1917


 

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.

 

 

 

HUGOTON ROYALTY TRUST

 

By BANK OF AMERICA, N.A., TRUSTEE

 

 

 

 

 

By

/S/ NANCY G. WILLIS

 

 

Nancy G. Willis

 

 

Vice President

 

 

 

 

 

XTO ENERGY INC.

 

 

 

 

Date: October 25, 2005April 28, 2006

By

/S/ LOUIS G. BALDWIN

 

 

Louis G. Baldwin

 

 

Executive Vice President

 

 

and Chief Financial Officer

 

2018