HUGOTON ROYALTY TRUST - Quarter Report: 2003 September (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 September 30, 2003

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)

 

 

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:

 

 

 

HUGOTON ROYALTY TRUST

 

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2003

 

 

	TABLE OF CONTENTS
	Glossary of Terms
PART I.	FINANCIAL INFORMATION
Item 1.	Financial Statements
	Independent Accountants’ Review Report
	Condensed Statements of Assets, Liabilities and Trust Corpus at September 30, 2003 and December 31, 2002
	Condensed Statements of Distributable Income for the Three and Nine Months Ended September 30, 2003 and 2002
	Condensed Statements of Changes in Trust Corpus for the Three and Nine Months Ended September 30, 2003 and 2002
	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 1.	Legal Proceedings
Item 6.	Exhibits and Reports on Form 8-K
	Signatures

 

2

 

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 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% and paid to the trust by XTO Energy.  “Net profits income” is referred to as “royalty income” for income tax 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 Wyoming
underlying properties		XTO Energy’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 and development costs

 

3

 

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, 2003 and the distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2003 and 2002 have been included.  Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

 

4

 

INDEPENDENT ACCOUNTANTS’ REVIEW REPORT

 

 

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, 2003 and the related condensed statements of distributable income and changes in trust corpus for the three- and nine-month periods ended September 30, 2003 and 2002.  These condensed financial statements are the responsibility of the trustee.

 

We conducted our review in accordance with standards established by the American Institute of Certified Public Accountants.  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 auditing standards generally accepted in the United States of America, 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 auditing standards generally accepted in the United States of America, the statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2002, 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 2002 Annual Report on Form 10-K, and in our report dated March 14, 2003, 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, 2002 is fairly stated, in all material respects, in relation to the statement of assets, liabilities and trust corpus included in the trust’s 2002 Annual Report on Form 10-K from which it has been derived.

 

 

KPMG LLP

 

Dallas, Texas

October 15, 2003

 

5

 

HUGOTON ROYALTY TRUST

 

Condensed Statements of Assets, Liabilities and Trust Corpus

 

 

		September 30, 2003			December 31, 2002
		(Unaudited)
ASSETS
Cash and short-term investments		$	7,354,640		$	3,227,840
Net profits interests in oil and gas properties - net		196,140,835			205,493,243
		$	203,495,475		$	208,721,083
LIABILITIES AND TRUST CORPUS
Distribution payable to unitholders		$	7,354,640		$	3,227,840
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		196,140,835			205,493,243
		$	203,495,475		$	208,721,083

 

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

 

6

 

HUGOTON ROYALTY TRUST

 

Condensed Statements of Distributable Income (Unaudited)

 

		Three Months Ended September 30						Nine Months Ended September 30
		2003			2002			2003			2002
Net profits income		$	21,446,124		$	8,670,968		$	62,539,606		$	21,643,574
Interest income		7,511			5,218			22,623			11,296
Total income		21,453,635			8,676,186			62,562,229			21,654,870
Administration expense		75,555			53,506			280,549			344,910
Distributable income		$	21,378,080		$	8,622,680		$	62,281,680		$	21,309,960
Distributable income per unit (40,000,000 units)		$	0.534452		$	0.215567		$	1.557042		$	0.532749

 

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 September 30						Nine Months Ended September 30
		2003			2002			2003			2002
Trust corpus, beginning of period		$	199,282,415		$	210,792,482		$	205,493,243		$	215,346,192
Amortization of net profits interests		(3,141,580		)	(2,689,674		)	(9,352,408		)	(7,243,384		)
Distributable income		21,378,080			8,622,680			62,281,680			21,309,960
Distributions declared		(21,378,080		)	(8,622,680		)	(62,281,680		)	(21,309,960		)
Trust corpus, end of period		$	196,140,835		$	208,102,808		$	196,140,835		$	208,102,808

 

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 the interest owner, XTO Energy Inc., to Bank of America, N.A., as trustee for the trust.  Net profits income consists of net proceeds received by XTO Energy 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 expenses, 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.

 

The initial carrying value of the net profits interests of $247,066,951 represents XTO Energy’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 $50,926,116 as of September 30, 2003 and $41,573,708 as of December 31, 2002.

 

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:

 

		Three Months Ended September 30						Nine Months Ended September 30
		2003			2002			2003			2002
Cumulative development costs (over) under the amount deducted - beginning of period		$	3,963,563		$	1,230,748		$	3,089,563		$	(4,778,880	)
Actual development costs		(4,286,514		)	(5,934,607		)	(9,961,857		)	(11,491,646		)
Development costs deducted		2,250,000			5,783,333			8,799,343			17,350,000
Cumulative development costs under the amount deducted - end of period		$	1,927,049		$	1,079,474		$	1,927,049		$	1,079,474

 

Based on the 2003 budget, XTO Energy decreased the monthly development cost deduction from $1.9 million to $1 million beginning with the February 2003 distribution and further decreased the monthly development cost deduction to $750,000 beginning with the September 2003 distribution.

 

3.          Contingencies

 

Litigation

 

XTO Energy 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.

 

On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was filed in the District Court of Dewey County, Oklahoma by royalty owners of natural gas wells in Oklahoma.  The plaintiffs alleged that since 1991, XTO Energy underpaid royalty owners as a result of reducing royalties for improper charges for production, marketing, gathering, processing and transportation costs and selling natural gas through affiliated companies at prices less favorable than those paid by third parties.  The parties agreed on a settlement that the court approved in April 2003 and was paid in July 2003.  The portion of this settlement related to the production from the underlying properties since December 1, 1998, the effective date of the trust, was $1,040,831.  The settlement reduced royalty income paid to the trust in August 2003 and the distribution paid to unitholders in September by $832,665, or 2.1 cents per unit.  The effect of the settlement on future distributions will not be significant.

 

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.  This lawsuit alleges that XTO Energy 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 and wrongfully analyzing its heating content during at least the past ten years.  The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for

 

10

 

the unpaid royalties (with interest), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices.  The cases against XTO Energy and other defendants have been consolidated in the United States District Court for Wyoming.  While XTO Energy 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 management’s opinion, is not currently expected to be material to the trust’s annual distributable income, financial position or liquidity.

 

Certain of the trust properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy 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 royalty owners.  After consultation with legal counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements.  However, final regulations have not been issued.  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.

 

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 2002 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, 2003 net profits income was $21,446,124, as compared to $8,670,968 for third quarter 2002.  Increased net profits income is primarily the result of higher gas prices.  See “Net Profits Income” on the following page.

 

After adding interest income of $7,511 and deducting administration expense of $75,555, distributable income for the quarter ended September 30, 2003 was $21,378,080, or $0.534452 per unit of beneficial interest.  Administration expense for the quarter increased 41% from the prior year quarter primarily because of the timing of expenditures.  Increased interest income over these periods was because of the increase in net profits income.  For third quarter 2002, distributable income was $8,622,680, or $0.215567 per unit.  Distributions to unitholders for the quarter ended September 30, 2003 were:

 

Record Date		Payment Date		Distribution per Unit
July 31, 2003		August 14, 2003		$	0.174509
August 29, 2003		September 15, 2003		0.176077
September 30, 2003		October 15, 2003		0.183866
				$	0.534452

 

Nine Months

 

For the nine months ended September 30, 2003, net profits income was $62,539,606, compared with $21,643,574 for the same 2002 period.  This 189% increase in net profits income is primarily the result of higher gas prices.

 

After adding interest income of $22,623 and deducting administration expense of $280,549, distributable income for the nine months ended September 30, 2003 was $62,281,680, or $1.557042 per unit of beneficial interest.  Administration expense for the first nine months of 2003 was 19% lower than in the first nine months of 2002 primarily because of decreased stock exchange listing fees, partially offset by the timing of expenditures.  Interest income increased over these periods because of the increase in net profits income.  For the nine months ended September 30, 2002, distributable income was $21,309,960, or $0.532749 per unit.

 

12

 

Net Profits Income

 

Net profits income is recorded when received by the trust, which is the month following receipt by XTO Energy, 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:

 

		Three Months Ended September 30 (a)						Increase (Decrease)		Nine Months Ended September 30 (a)						Increase (Decrease)
		2003			2002					2003			2002
Sales Volumes
Gas (Mcf) (b)
Underlying properties		7,819,586			8,589,343			(9)%		23,729,807			25,903,133			(8)%
Average per day		84,996			93,362			(9)%		86,922			94,883			(8)%
Net profits interests		4,574,284			3,214,095			42%		13,617,199			8,655,717			57%
Oil (Bbls) (b)
Underlying properties		76,978			91,717			(16)%		247,238			270,169			(8)%
Average per day		837			997			(16)%		906			990			(8)%
Net profits interests		44,048			34,849			26%		143,332			91,676			56%
Average Sales Prices
Gas (per Mcf)		$	4.82		$	2.60		85%		$	4.60		$	2.41		91%
Oil (per Bbl)		$	29.58		$	25.84		14%		$	30.31		$	22.32		36%
Revenues
Gas sales		$	37,714,470		$	22,329,685		69%		$	109,228,702		$	62,381,721		75%
Oil sales		2,277,397			2,369,659			(4)%		7,492,983			6,031,109			24%
Total Revenues		39,991,867			24,699,344			62%		116,721,685			68,412,830			71%
Costs
Taxes, transportation and other		3,529,346			2,183,289			62%		10,314,016			5,751,655			79%
Production expense		4,544,674			3,832,095			19%		12,656,132			12,256,429			3%
Development costs (c)		2,250,000			5,783,333			(61)%		8,799,343			17,350,000			(49)%
Overhead		1,819,361			2,061,917			(12)%		5,737,338			6,060,278			(5)%
Litigation		1,040,831			—			—		1,040,831			—			—
Total Costs		13,184,212			13,860,634			(5)%		38,547,660			41,418,362			(7)%
Other Proceeds
Property sales		—			—			—		482			60,000			(99)%
Net Proceeds		26,807,655			10,838,710			147%		78,174,507			27,054,468			189%
Net Profits Percentage		80		%	80		%			80		%	80		%
Net Profits Income		$	21,446,124		$	8,670,968		147%		$	62,539,606		$	21,643,574		189%

 

(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 expenses 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 from third quarter 2002 to third quarter 2003 and from the first nine months of 2002 to the comparable period in 2003:

 

Sales Volumes

 

Gas

 

Gas sales volumes decreased 9% for the third quarter and 8% for the nine-month period primarily because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers.  In addition, decreased gas sales volumes for the nine-month period were partially offset by prior period volume adjustments recorded in 2002.

 

Oil

 

Oil sales volumes decreased 16% for the third quarter and 8% for the nine-month period because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers.

 

Sales Prices

 

Gas

 

The third quarter 2003 average gas price increased 85% to $4.82 per Mcf and for the nine-month period increased 91% to $4.60 per Mcf.  The winter of 2001-2002 was one of the warmest on record, resulting in higher than average gas storage levels and lower gas prices in the first nine months of 2002.  Prices climbed in fourth quarter 2002 as a result of low levels of drilling activity, increased industrial demand, colder weather and international instability.  With colder than normal weather, record low gas storage levels and continued increasing demand, gas prices were relatively high during the first five months of 2003.  Since May, higher than normal levels of gas have been injected into storage due to diminished demand related to higher prices, resulting in lower natural gas prices.  Prices for the remainder of 2003 will be influenced by weather, possible revived demand due to lower prices, the pace of recovery of the domestic economy and increases in North American production.  In any case, natural gas prices are expected to remain volatile.  The third quarter 2003 gas price is primarily related to production from May through July 2003, when the average NYMEX price was $5.63.  The average NYMEX price for August and September 2003 was $4.81 per MMBtu.  At October 15, 2003, the average NYMEX futures price for the following twelve months was $5.19 per MMBtu.  Recent trust gas prices have averaged approximately $0.60 per MMBtu lower than the NYMEX price.  This differential has continued to improve because of the completion of a pipeline expansion project in May 2003 which has increased capacity to deliver Wyoming production to western markets.

 

Oil

 

The third quarter 2003 average oil price increased 14% to $29.58 per Bbl and for the nine-month period increased 36% to $30.31 per Bbl.  Because of lower prices, OPEC members agreed to cut daily production by 1.5 million barrels during 2002 to support oil prices affected by weak demand and excess supply.  Oil prices increased during 2002 largely because of OPEC production discipline and rising uncertainty surrounding the Middle East.  OPEC members agreed to increase daily oil production 1.5 million barrels beginning February 1, 2003, to help stabilize a volatile world market.  Oil prices have remained relatively high in 2003, however, because of the war in Iraq, slower than anticipated resumption of Iraqi oil exports and unusually low storage levels.  OPEC reduced daily oil production by 2 million barrels beginning June 1, 2003 and, because of the recent fall in oil prices and the concern of increasing production from non-OPEC suppliers, agreed to cut daily oil production by 900,000 barrels beginning November 1, 2003.  The average NYMEX price

15

 

for August and September 2003 was $30.01 per Bbl.  At October 15, 2003, the average NYMEX futures price for the following twelve months was $29.78 per Bbl.  Recent trust oil prices have averaged approximately $0.50 per Bbl lower than the NYMEX price.

 

Costs

 

Taxes

 

Taxes, transportation and other increased 62% for the quarter and 79% for the nine-month period primarily because of higher production taxes related to increased revenues.

 

Production

 

Production expense increased 19% for the quarter and 3% for the nine-month period.  Increased production expense for the quarter is primarily because of increased fuel costs related to higher gas prices and timing of maintenance projects.  The nine-month period increase is primarily because of higher fuel costs.

 

Development

 

Development costs deducted in the calculation of net profits income are based on the 2003 budget.  These development costs decreased 61% for the third quarter and 49% for the nine-month period because of the timing of development projects.  During the first nine months of 2003, 12 wells were started and completed on the underlying properties.  XTO Energy plans to drill approximately 23 wells during 2003.  All 2003 drilling is expected to be in western Oklahoma and southwestern Wyoming.

 

As of December 31, 2002, cumulative development costs deducted exceeded actual costs by $3.1 million.  In calculating net profits income, XTO Energy deducted budgeted development costs of $2.3 million for the quarter and $8.8 million for the nine months ended September 30, 2003.  After considering actual development costs of $4.3 million for the quarter and $10.0 million for the nine-month period, cumulative development costs deducted exceeded actual costs by $1.9 million.  This excess is expected to be reduced as 2003 development activity is billed and paid.  See Note 2 to Condensed Financial Statements.

 

Overhead

 

Overhead decreased 12% for the quarter and 5% for the nine-month period because of the annual rate adjustment based on an industry index.  In addition, decreased overhead for the quarter is because of the timing of an annual Oklahoma administrative fee.

 

Litigation Settlement

 

In July 2003, XTO disbursed funds in final settlement of the class action lawsuit, Booth, et al. v. Cross Timbers Oil Company.  The portion of this settlement related to the production from the underlying properties since December 1, 1998, the effective date of the trust, was $1,040,831.  The settlement reduced royalty income paid to the trust in August 2003 and the distribution paid to unitholders in September by $832,665, or 2.1 cents per unit.  For further information regarding this lawsuit, see Note 3 to Condensed Financial Statements.

 

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 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, 2002, which is incorporated by this reference as though fully set forth herein.  Although XTO Energy and the trustee believe that the expectations reflected in such forward-looking statements are reasonable, neither XTO Energy nor the trustee can give any assurance that such expectations will prove to be correct.

 

17

 

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, 2002.

 

 

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.  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.

 

18

 

PART II - OTHER INFORMATION

 

Item 1.            Legal Proceedings.

 

On April 3, 1998, a class action lawsuit, Booth, et al. v. Cross Timbers Oil Company, was filed in the District Court of Dewey County, Oklahoma by royalty owners of natural gas wells in Oklahoma.  The plaintiffs alleged that since 1991, XTO Energy underpaid royalty owners as a result of reducing royalties for improper charges for production, marketing, gathering, processing and transportation costs and selling natural gas through affiliated companies at prices less favorable than those paid by third parties.  The parties agreed on a settlement that the court approved in April 2003 and was paid in July 2003.  The portion of this settlement related to the production from the underlying properties since December 1, 1998, the effective date of the trust, was $1,040,831.  The settlement reduced royalty income paid to the trust in August 2003 and the distribution paid to unitholders in September by $832,665, or 2.1 cents per unit.  The effect of the settlement on future distributions will not be significant.

 

Items 2 through 5.  Not applicable.

 

Item 6.            Exhibits and Reports on Form 8-K.

 

(a)          Exhibits.

 

Exhibit Number 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 31, 2003 (incorporated herein by reference)

 

(b)         Reports on Form 8-K.

 

No reports on Form 8-K were filed during the quarter.  The trust furnished two reports on Form 8-K under Item 12 for this period.

 

19

 

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	NANCY G.  WILLIS
		Nancy G. Willis
		Assistant Vice President
	XTO ENERGY INC.
Date:  October 17, 2003	By	LOUIS G. BALDWIN
		Louis G. Baldwin
		Executive Vice President and Chief Financial Officer

 

20