UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

For the quarterly period ended March 31,June 30, 2002

OR

Commission File Number:  1-10476

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 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 MARCH 31,JUNE 30, 2002

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HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

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

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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 March 31,June 30, 2002 and the distributable income and changes in trust corpus for the three-monththree- and six-month periods ended March 31,June 30, 2002 and 2001 have been included.  Distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

The financial data for the three- and six-month periods ended June 30, 2002 included herein have been subjected to a limited review by KPMG LLP, the registrant’s independent accountants.  The accompanying review report of independent accountants is not a report within the meaning of Sections 7 and 11 of the Securities Act of 1933 and the independent accountant’s liability under Section 11 does not extend to it.  The trust’s financial statements for the year ended December 31, 2001 were audited by other independent accountants.

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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTSACCOUNTANTS’ 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 March 31,June 30, 2002 and the related condensed statements of distributable income and changes in trust corpus for the three-monththree- and six-month periods ended March 31, 2002 and 2001.June 30, 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,auditing standards, 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.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, the statement of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2001 included in the trust’s annual report on Form 10-K, and in our report dated March 19, 2002, we expressed an unqualified opinion on that statement.  In our opinion, the information set forth in the accompanying condensed statement of assets, liabilities and trust corpus as of December 31, 2001 is fairly stated in all material respects in relation to the statement of assets, liabilities and trust corpus included in the trust’s financial statements from which they have been derived.

ARTHUR ANDERSENKPMG LLP

Fort Worth,Dallas, Texas

May 1,August 5, 2002

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HUGOTON ROYALTY TRUST

Condensed Statements of Assets, Liabilities and Trust Corpus

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

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HUGOTON ROYALTY TRUST

Condensed Statements of Distributable Income Income (Unaudited)

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

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HUGOTON ROYALTY TRUST

Condensed Statements of Changes in Trust Corpus (Unaudited)(Unaudited)

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

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HUGOTON ROYALTY TRUST

Notes to Condensed Financial Statements (Unaudited)(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 $34,330,324$36,274,469 as of March 31,June 30, 2002 and $31,720,759 as of December 31, 2001.

2.             Development Costs

As of December 31, 2001, cumulativeCumulative actual development costs exceeded the amount deducted in the calculation of net profits income by $4.8 million.million as of December 31, 2001 and by $200,000 at March 31, 2002.  In calculating net profits income, for the quarter ended March 31, 2002, XTO Energy deducted budgeted development costs of $5.8 million.million for the quarter and $11.6 million for the six months ended June 30, 2002.  After considering actual development costs of $1.2$4.4 million for the quarter cumulative actual development costs exceededand $5.6 million for the amount deducted by $231,000.  As of the April 2002 distribution,six-month period, cumulative actual development costs were $713,000$1.2 million less than the amount deducted as of June 30, 2002.  As of the July 2002 distribution,

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cumulative actual development costs were $1 million less than the amount deducted.  XTO Energy has advised the trustee that it will

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continue to deduct development costs at a rate of $1.9 million per month through the remainder of 2002 based on the estimated development budget for 2002 and drilling completed and in progress.to date.

3.             Litigation

XTO Energy is a defendant in two separate lawsuits that could, if adversely determined, decrease future trust distributable income.  Any damages relating to production prior to December 1, 1998, the formationcreation date of the trust, 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 allege that since 1991, XTO Energy, formerly known as Cross Timbers Oil Company, has 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.  No class has been certified.  The court has ordered that the parties enter mediation, which shouldis expected to occur in the first half of 2002.  XTO Energy believes that it has strong defenses to this lawsuit and intends to vigorously defend its position.  However, if XTO Energy ultimately makes any payments, the trust will bear its 80% share of such payments related to production from the underlying properties for periods since December 1, 1998.  Additionally, if a judgment or settlement increases the amount of future payments to royalty owners, the trust would bear its proportionate share of the increased payments through reduced net proceeds.  The amount of any potential settlement related to the trust and reduction in net proceeds, is not presently 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.

A second lawsuit, 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 action alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans by at least 20% as a result of mismeasuring the volume of natural gas and wrongfully analyzing its heating content.  The suit, which was brought under the qui tam provisions of the U.S. False Claims Act, seeks treble damages for 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.

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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 2001 annual report, as well as the condensed financial statements and notes thereto included in this quarterly report on Form 10-Q.

Distributable Income

Quarter

For the quarter ended March 31,June 30, 2002 net profits income was $7,412,420,$5,560,186, as compared to $33,683,872$21,720,948 for firstsecond quarter 2001.  DecreasedThis 74% decline in net profits income is primarily the result of lower gas prices.  See “Net Profits Income” below.

After adding interest income of $3,727$2,352 and deducting administration expense of $63,507,$227,898, distributable income for the quarter ended March 31,June 30, 2002 was $7,352,640,$5,334,640, or $0.183816$0.133366 per unit of beneficial interest.  Administration expense for the quarter decreased 20%increased $184,592 from the prior year quarter, while interest income decreased $51,646.  The significant increase in administration expense for the quarter was primarily because of increased stock exchange listing fees and the timing of expenditures;expenditures.  Decreased interest income decreased 93% over these periods was primarily because of the decline in net profits income and interest rates.  For firstsecond quarter 2001, distributable income was $33,654,480,$21,731,640, or $0.841362$0.543291 per unit.  Distributions to unitholders for the quarter ended March 31,June 30, 2002 were:

Six Months

For the six months ended June 30, 2002, net profits income was $12,972,606, compared with $55,404,820 for the same 2001 period.  This 77% decrease in net profits income is primarily the result of lower gas prices.

After adding interest income of $6,079 and deducting administration expense of $291,405, distributable income for the six months ended June 30, 2002 was $12,687,280, or $0.317182 per unit of beneficial interest.  Administration expense for the first six months of 2002 was significantly higher than in the first half of 2001 because of increased stock exchange listing fees and the timing of expenditures.  Interest income decreased over these periods primarily because of the decrease in net profits income and interest rates.  For the six months ended June 30, 2001, distributable income was $55,386,120, or $1.384653 per unit.

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.

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

((a)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 March 31June 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 January.April.

((b)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)c)          During 2001, the costs related to well recompletions and remedial workovers were classified as development costs, consistent with their budget classification.  These costs were previously included in production expense.  The costs are reclassified in prior periods for consistency with current presentation.

((d)d)         See Note 2 to Financial Statements.

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The following are explanations of significant variances from firstsecond quarter 2001 to second quarter 2002 and from the first six months of 2001 to the comparable period in 2002:

Sales Volumes

Gas

FirstSecond quarter gas sales volumes decreased 2%5% and year-to-date volumes decreased 3% primarily because of natural production decline, and gathering line freezes and compressor outagesdowntime in Wyoming, partially offset by increased production from new wells and workovers.workovers in Oklahoma.

Oil

First quarter oilOil sales volumes decreased 6% as a resultwere 13% lower for the second quarter and 10% lower for the six-month period because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers.workovers in Oklahoma.

Sales Prices

Gas

The firstsecond quarter 2002 average gas price was $2.38$2.25 per Mcf, a 62%58% decrease from the firstsecond quarter 2001 average gas price of $6.31.$5.33. Gas prices were unusually high in first quarterat the beginning of 2001 as winter demand strained already low gas supplies.  Gas pricesPrices subsequently declined and gas storage levels increased in 2001 because of fuel switching due to higher prices, milder weather and a weaker economy, which reduced demand for gas and resulted in sharply increased gas storage levels.  Despiteto generate electricity.  Although the winter of 2001-2002 beingwas one of the warmest on record and the likely result thatwith resulting higher than average storage levels, will be higher than historical averages, gas prices have increased slightly during 2002 and are expected to remain volatile.second quarter 2002.  The average NYMEX gas price for FebruaryMay through AprilJuly 2002 was $2.90$3.26 per MMBtu.  Continuing mild weather and a weak economy have further reduced demand, causing current NYMEX prices again to drop below $3.00.  At MayAugust 1, 2002, the average NYMEX futures price for the following twelve months was $3.93$3.39 per MMBtu.  Recent trustGas prices are expected to remain volatile.  Trust gas prices haverelated to the July 2002 distribution averaged approximately $0.25$0.70 per MMBtuMcf lower than the NYMEX price.  This differential increased from the spread of approximately $0.25 per Mcf for first quarter production primarily because of lower Wyoming prices related to pipeline constraints and reduced West Coast demand.

Oil

The first quarter 2002 average oil price was $18.80for the second quarter decreased 22% to $22.27 per Bbl a 38% decrease fromand for the first  quarter 2001 averagesix-month period decreased 30% to $20.52.  Trust oil price of $30.43.  Oil prices were significantly higher in the first quarterhalf of  2001 as a result of global demand outpacing supply.supply at the end of 2000 and early in 2001.  Lagging demand, resulting from a worldwide economic slowdown, caused oil prices to decline induring the remainder of 2001.  OPEC members agreed to cut daily production by one million barrels in April 2001 and an additional one million barrels in September 2001 to adjust for weak demand and excess supply. The economic decline was accelerated by the terrorist attacks in the U.S. on September 11, 2001, placing additional downward pressure on oil prices.  In December 2001, OPEC announcedcut an additional production cuts of 1.5 million barrels per day for six months effective January 1,the first half of 2002, and in June 2002, announced it would maintain the production cut through September 2002.  With economic recoveries in the U.S. and global markets, as well as rising concerns over tension in the Middle East, oilOil prices have strengthenedshown some strengthening during 2002.2002, but are expected to remain volatile.  The average NYMEX oil price for FebruaryMay through AprilJuly 2002 was $23.81.$26.52 per Bbl.  At MayAugust 1, 2002, the average NYMEX futures price for the following twelve months was $25.41.$25.20.  Recent trust oil prices have averaged approximately $1.05$1.00 lower than the NYMEX price.

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Costs

Taxes

Taxes, transportation and other decreased 68%63% for the first quarter and 65% for the six-month period, generally corresponding with revenue fluctuations.reduced revenues.

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Production

Production expense remained relatively unchangeddecreased 6% for the quarter and 3% for the six-month period, primarily because prior periodof the timing of maintenance projects, billings and expenditures and decreased fuel adjustment charges recorded in first quarter 2001 were offset by higher maintenance and insurance costs in first quarter 2002.related to lower gas prices.

Development

Development costs decreased 24%47% for the firstsecond quarter and 38% for the six-month period because of reduced drilling activity at the end of 2001.  During the first three monthshalf of 2002, fivesix wells were startedcompleted on the underlying properties, and five were pending completion at March 31.June 30.  XTO Energy plans to drill 19eight more wells during 2002.  All 2002, drilling activity is to occurall in western Oklahoma.

As of December 31, 2001, cumulativeCumulative actual development costs exceeded the amount deducted in the calculation of net profits income by $4.8 million.million as of December 31, 2001 and by $200,000 at March 31, 2002.  In calculating net profits income, for the quarter ended March 31, 2002, XTO Energy deducted budgeted development costs of $5.8 million.million for the quarter and $11.6 million for the six months ended June 30, 2002.  After considering actual development costs of $1.2$4.4 million for the quarter and $5.6 million for the six-month period, cumulative actual development costs exceededwere $1.2 million less than the amount deducted by $231,000.as of June 30, 2002.  As of the AprilJuly 2002 distribution, cumulative actual development costs were $713,000$1 million less than the amount deducted.  XTO Energy has advised the trustee that it will continue to deduct development costs at a rate of $1.9 million per month through the remainder of 2002 based on the estimated development budget for 2002 and drilling completed and in progress.to date.

Overhead

Overhead increased 10%5% for the quarter and 7% for the six-month period because of an increased well count, and thepartially offset by a decreased annual rate adjustment during the second quarter based on an industry index.

Other Proceeds

Net profits income for firstthe quarter and six months ended June 30, 2002 includes proceeds of $60,000 ($48,000 net to the trust) from the sale of a property in Major County, Oklahoma.  Net profits income for the six months ended June 30, 2001 includes proceeds of $307,824 ($246,259 net to the trust) from the sale of certain underlying properties in Sweetwater County, Wyoming.

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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 costs, oil and gas prices, 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, 2001, which is incorporated by this reference as though fully set forth herein.  Although XTO Energy believes 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.

Item 3.  Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in the trust’s market risks, as disclosed in the trust’s Form 10-K for the year ended December 31, 2001.

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PART II - OTHER INFORMATION

Items 1 through 5.    Not applicable.

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

(a)  Exhibits.

(b)  Reports on Form 8-K.

No reportsOn June 28, 2002, the trust filed a report on Form 8-K have been filed duringdated June 25, 2002, to report its appointment of KPMG LLP as the quartertrust’s independent auditors for which this report is filed.fiscal 2002 to replace Arthur Andersen LLP, effective with such appointment.

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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.

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