HUGOTON ROYALTY TRUST - Quarter Report: 2005 June (Form 10-Q)
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 June 30, 2005
OR
o
TRANSITION 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)
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Texas |
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58-6379215 |
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(State or other jurisdiction of |
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(I.R.S. Employer |
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Bank of America, N.A., P.O. Box 830650, Dallas, Texas |
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75283-0650 |
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(Address of principal executive offices) |
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(Zip Code) |
(877) 228-5083
(Registrant’s telephone number, including area code)
NONE
(Former name, former address and former fiscal year, if changed 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 an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes ý No o
Indicate the number of units of beneficial interest outstanding, as of the latest practicable date:
Outstanding as of July 15, 2005
40,000,000
HUGOTON ROYALTY TRUST
FORM 10-Q FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2005
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TABLE OF CONTENTS |
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Condensed Statements of Assets, Liabilities and Trust Corpus at June 30, 2005 and December 31, 2004 |
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2
HUGOTON ROYALTY TRUST
The following are definitions of significant terms used in this Form 10-Q:
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Barrel (of oil) |
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Mcf |
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Thousand cubic feet (of natural gas) |
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MMBtu |
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One million British Thermal Units, a common energy measurement |
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net proceeds |
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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 |
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net profits income |
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Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by XTO Energy Inc. “Net profits income” is referred to as “royalty income” for income tax purposes. |
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net profits interest |
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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: |
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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 Wyoming |
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underlying properties |
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XTO Energy Inc.’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. |
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working interest |
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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 |
3
HUGOTON ROYALTY TRUST
PART I - FINANCIAL INFORMATION
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 June 30, 2005 and the distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 2005 and 2004 have been included. Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.
4
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 June 30, 2005 and the related condensed statements of distributable income and changes in trust corpus for the three- and six-month periods ended June 30, 2005 and 2004. 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, 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 2004 Annual Report on Form 10-K, and in our report dated March 14, 2005, 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, 2004 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2004 Annual Report on Form 10-K from which it has been derived.
KPMG LLP
Dallas, Texas
July 19, 2005
5
HUGOTON ROYALTY TRUST
Condensed Statements of Assets, Liabilities and Trust Corpus
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June 30, |
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December 31, |
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(Unaudited) |
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ASSETS |
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Cash and short-term investments |
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$ |
8,746,880 |
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$ |
6,947,520 |
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Net profits interests in oil and gas properties - net (Note 1) |
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177,114,508 |
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182,551,814 |
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$ |
185,861,388 |
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$ |
189,499,334 |
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LIABILITIES AND TRUST CORPUS |
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Distribution payable to unitholders |
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$ |
8,746,880 |
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$ |
6,947,520 |
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Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) |
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177,114,508 |
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182,551,814 |
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$ |
185,861,388 |
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$ |
189,499,334 |
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The accompanying notes to condensed financial statements are an integral part of these statements.
6
HUGOTON ROYALTY TRUST
Condensed Statements of Distributable Income (Unaudited)
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Three Months Ended |
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Six Months Ended |
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2005 |
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2004 |
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2005 |
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2004 |
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Net profits income |
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$ |
22,965,660 |
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$ |
18,289,557 |
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$ |
48,784,600 |
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$ |
37,346,788 |
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Interest income |
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21,859 |
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6,751 |
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41,909 |
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10,853 |
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Total income |
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22,987,519 |
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18,296,308 |
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48,826,509 |
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37,357,641 |
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Administration expense |
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155,479 |
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117,748 |
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296,309 |
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202,321 |
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Distributable income |
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$ |
22,832,040 |
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$ |
18,178,560 |
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$ |
48,530,200 |
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$ |
37,155,320 |
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Distributable income per unit (40,000,000 units) |
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$ |
0.570801 |
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$ |
0.454464 |
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$ |
1.213255 |
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$ |
0.928883 |
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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)
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Three Months Ended |
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Six Months Ended |
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2005 |
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2004 |
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2005 |
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2004 |
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Trust corpus, beginning of period |
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$ |
179,730,111 |
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$ |
190,517,602 |
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$ |
182,551,814 |
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$ |
193,245,847 |
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Amortization of net profits interests |
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(2,615,603 |
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(2,517,221 |
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(5,437,306 |
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(5,245,466 |
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Distributable income |
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22,832,040 |
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18,178,560 |
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48,530,200 |
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37,155,320 |
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Distributions declared |
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(22,832,040 |
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(18,178,560 |
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(48,530,200 |
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(37,155,320 |
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Trust corpus, end of period |
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$ |
177,114,508 |
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$ |
188,000,381 |
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$ |
177,114,508 |
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$ |
188,000,381 |
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The accompanying notes to condensed financial statements are an integral part of these statements.
8
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 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 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 GAAP. 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.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with 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.’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 $69,952,443 as of June 30, 2005 and $64,515,137 as of December 31, 2004.
9
2. Development Costs
The following summarizes actual development costs, the amount of development costs deducted in the calculation of net profits income and the cumulative actual development costs (over) under the amount deducted:
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Three Months Ended |
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Six Months Ended |
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2005 |
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2004 |
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2005 |
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2004 |
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Cumulative development costs (over) the amount deducted - beginning of period |
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$ |
(1,178,666 |
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$ |
(1,197,564 |
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$ |
(319,927 |
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$ |
(1,583,988 |
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Actual development costs |
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(6,972,845 |
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(2,482,431 |
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(14,631,584 |
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(7,196,007 |
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Development costs deducted |
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7,200,000 |
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5,100,000 |
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14,000,000 |
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10,200,000 |
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Cumulative development costs (over) under the amount deducted - end of period |
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$ |
(951,511 |
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$ |
1,420,005 |
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$ |
(951,511 |
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$ |
1,420,005 |
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The monthly development cost deduction was $1.7 million throughout 2004 until it was increased to $2 million beginning with the October 2004 distribution because of increased drilling in Oklahoma. Because of increased development activity and higher drilling costs, the monthly development cost deduction was increased to $2.4 million beginning with the February 2005 distribution and was increased again to $3.3 million beginning with the July 2005 distribution. XTO Energy Inc. has advised the trustee that it currently expects the monthly development cost deduction will remain at $3.3 million for the remainder of 2005, subject to reevaluation and revision as necessary.
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.
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. 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’ 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 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
10
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 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 motion to modify the special master’s report. 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 that the trust is 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.
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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 2004 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 June 30, 2005, net profits income was $22,965,660, as compared to $18,289,557 for second quarter 2004. This 26% 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 $21,859 and deducting administration expense of $155,479, distributable income for the quarter ended June 30, 2005 was $22,832,040, or $0.570801 per unit of beneficial interest. Administration expense for the quarter increased 32% from the prior year quarter primarily because of the timing of expenditures. For second quarter 2004, distributable income was $18,178,560 or $0.454464 per unit. Distributions to unitholders for the quarter ended June 30, 2005 were:
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Record Date |
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Payment Date |
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Distribution |
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April 29, 2005 |
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May 13, 2005 |
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$ |
0.163129 |
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May 31, 2005 |
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June 14, 2005 |
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0.189000 |
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June 30, 2005 |
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July 15, 2005 |
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0.218672 |
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$ |
0.570801 |
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Six Months
For the six months ended June 30, 2005, net profits income was $48,784,600, compared with $37,346,788 for the same 2004 period. This 31% 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 $41,909 and deducting administration expense of $296,309, distributable income for the six months ended June 30, 2005 was $48,530,200, or $1.213255 per unit of beneficial interest. Administration expense for the first six months of 2005 was 46% higher than in the first six months of 2004 primarily because of fees related to the 2004 audit of the trust’s internal control over financial reporting and the timing of expenditures. For the six months ended June 30, 2004, distributable income was $37,155,320, or $0.928883 per unit.
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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.
13
The following is a summary of the calculation of net profits income received by the trust:
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Three Months |
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Increase |
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Six Months Ended June 30 (a) |
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Increase |
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2005 |
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2004 |
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(Decrease) |
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2005 |
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2004 |
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(Decrease) |
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Sales Volumes |
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Gas (Mcf) (b) |
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Underlying properties |
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7,212,301 |
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7,360,541 |
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(2)% |
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14,702,133 |
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15,121,407 |
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(3)% |
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Average per day |
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81,037 |
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81,784 |
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(1)% |
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81,227 |
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83,085 |
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(2)% |
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Net profits interests |
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3,901,719 |
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3,875,212 |
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1% |
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8,110,956 |
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8,074,850 |
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— |
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Oil (Bbls) (b) |
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Underlying properties |
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85,227 |
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79,676 |
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7% |
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159,640 |
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157,852 |
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1% |
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Average per day |
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958 |
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885 |
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8% |
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882 |
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867 |
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2% |
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Net profits interests |
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44,828 |
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43,311 |
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4% |
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88,951 |
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91,122 |
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(2)% |
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Average Sales Prices |
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Gas (per Mcf) |
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$5.85 |
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$4.77 |
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23% |
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$6.04 |
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$4.68 |
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29% |
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Oil (per Bbl) |
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$50.38 |
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$35.60 |
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42% |
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$47.89 |
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$33.58 |
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43% |
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Revenues |
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Gas sales |
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$ |
42,222,430 |
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$ |
35,146,341 |
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20% |
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$ |
88,800,106 |
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$ |
70,812,923 |
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25% |
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Oil sales |
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4,293,413 |
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2,836,538 |
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51% |
|
7,644,403 |
|
5,300,487 |
|
44% |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Total Revenues |
|
46,515,843 |
|
37,982,879 |
|
22% |
|
96,444,509 |
|
76,113,410 |
|
27% |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Taxes, transportation and other |
|
4,315,085 |
|
3,500,087 |
|
23% |
|
8,924,224 |
|
6,511,021 |
|
37% |
|
||||
|
Production expense |
|
4,387,547 |
|
4,690,989 |
|
(6)% |
|
8,727,744 |
|
9,105,656 |
|
(4)% |
|
||||
|
Development costs (c) |
|
7,200,000 |
|
5,100,000 |
|
41% |
|
14,000,000 |
|
10,200,000 |
|
37% |
|
||||
|
Overhead |
|
1,906,136 |
|
1,829,857 |
|
4% |
|
3,811,791 |
|
3,613,248 |
|
5% |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Total Costs |
|
17,808,768 |
|
15,120,933 |
|
18% |
|
35,463,759 |
|
29,429,925 |
|
21% |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net Proceeds |
|
28,707,075 |
|
22,861,946 |
|
26% |
|
60,980,750 |
|
46,683,485 |
|
31% |
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net Profits Percentage |
|
80% |
|
80% |
|
|
|
80% |
|
80% |
|
|
|
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Net Profits Income |
|
$ |
22,965,660 |
|
$ |
18,289,557 |
|
26% |
|
$ |
48,784,600 |
|
$ |
37,346,788 |
|
31% |
|
(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 June 30 generally represent production for the period February through April and (2) oil and gas sales for the six months ended June 30 generally represent production for the period November through April.
(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.
14
The following are explanations of significant variances on the underlying properties from second quarter 2004 to second quarter 2005 and from the first six months of 2004 to the comparable period in 2005:
Sales Volumes
Gas
Gas sales volumes decreased 2% for the second quarter and 3% for the six-month period primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers.
Oil
Oil sales volumes increased 7% for the second quarter and 1% for the six-month period primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline.
Sales Prices
Gas
The second quarter 2005 average gas price was $5.85 per Mcf, a 23% increase from the second quarter 2004 average gas price of $4.77 per Mcf. For the six-month period, the average gas price increased 29% to $6.04 per Mcf in 2005 from $4.68 per Mcf in 2004. Gas prices increased for the second quarter and for the six-month period primarily because of increased demand and 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 second quarter 2005 gas price is primarily related to production from February through April 2005, when the average NYMEX price was $6.80 per MMBtu, or 22% higher than the comparable 2004 period average NYMEX price of $5.56 per MMBtu. The average NYMEX price for May and June 2005 was $6.85 per MMBtu. At July 15, 2005, the average NYMEX futures price for the following twelve months was $8.30 per MMBtu. Recent trust gas prices have averaged approximately $0.50 per MMBtu lower than the NYMEX price.
Oil
The second quarter 2005 average oil price was $50.38 per Bbl, a 42% increase from the second quarter 2004 average oil price of $35.60 per Bbl. The year-to-date average oil price increased 43% to $47.89 per Bbl in 2005 from $33.58 per Bbl in 2004. Oil prices increased for the second quarter and for the six-month period primarily because of increasing global demand and supply shortage concerns, the weaker U.S. dollar, market speculation and political instability. Oil prices increased to record levels in July 2005, exceeding $61.00 per Bbl. The average NYMEX price for May and June 2005 was $53.18 per Bbl. At July 15, 2005, the average NYMEX futures price for the following twelve months was $59.93 per Bbl. Recent trust oil prices have averaged approximately $2.50 per Bbl lower than the NYMEX price.
15
Costs
Taxes
Taxes, transportation and other increased 23% for the quarter and 37% for the six-month period primarily because of increased production taxes related to higher revenues. In addition, increased taxes, transportation and other for the six-month period was because of increased property taxes related to the timing of cash disbursements.
Production
Production expense decreased 6% for the quarter and 4% for the six-month period primarily because of decreased maintenance, insurance and labor costs related to the timing of maintenance projects.
Development
Development costs deducted in the calculation of net profits income are based on the development budget. These development costs increased 41% for the second quarter and 37% for the six-month period primarily because of increased development activity in western Oklahoma and higher drilling costs in 2005. During the first half of 2005, 13 wells were completed and five wells were pending completion on the underlying properties at June 30. XTO Energy Inc. has informed the trustee that it plans to drill up to 29 wells and perform 22 workovers and 50 restimulations during 2005.
As of December 31, 2004, actual costs exceeded cumulative development costs deducted by $319,927. In calculating net profits income, XTO Energy Inc. deducted budgeted development costs of $7.2 million for the quarter and $14 million for the six-month period. After considering actual development costs of $7 million for the quarter and $14.6 million for the six-month period, cumulative actual development costs exceeded budgeted development costs deducted by approximately $1 million at June 30, 2005. See Note 2 to Condensed Financial Statements.
Because of increased development activity and higher drilling costs, the monthly development cost deduction was increased from $2.4 million to $3.3 million beginning with the July 2005 distribution. XTO Energy Inc. has advised the trustee that it currently expects the monthly development cost deduction will remain at $3.3 million for the remainder of 2005, subject to reevaluation and revision as necessary.
Overhead
Overhead increased 4% for the quarter and 5% for the six-month period because of the annual rate adjustment based on an industry index.
16
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, oil and gas prices, future drilling, workover and restimulation plans and industry and market conditions, are forward-looking statements that are subject to risks and uncertainties which are detailed in Part II, Item 7 of the trust’s Annual Report on Form 10-K for the year ended December 31, 2004, 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.
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.
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. 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.
17
Items 1 through 5.
Not applicable.
(a) Exhibits.
|
Exhibit
Number |
|
||
|
|
|
|
|
|
(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, 2005 (incorporated herein by reference) |
|
18
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: July 20, 2005 |
By |
/S/ LOUIS G. BALDWIN |
|
|
|
Louis G. Baldwin |
|
|
|
Executive Vice President |
|
|
|
and Chief Financial Officer |
19