UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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:

Outstanding as of May

HUGOTON ROYALTY TRUST

FORM 10-Q FOR THE QUARTERLY PERIOD ENDED MARCH 31,SEPTEMBER 30, 2003

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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,September 30, 2003 and the distributable income and changes in trust corpus for the three-monththree- and nine-month periods ended March 31,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.

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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 March 31,September 30, 2003 and the related condensed statements of distributable income and changes in trust corpus for the three-monththree- and nine-month periods ended March 31,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’strust’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
April 30,

October 15, 2003

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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 (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)

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)

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 $44,546,990$50,926,116 as of March 31,September 30, 2003 and $41,573,708 as of December 31, 2002.

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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:

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 two separate lawsuits related to the underlying properties that could, if adversely determined, decrease future trust distributable income.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 the creation 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 allegealleged that since 1991, XTO Energy 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.  The parties have entered intoagreed on a settlement agreement under whichthat the trust’scourt 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 will be approximately $850,000,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.  This amount reflects the trust’s 80% share of the settlement relating to production from the underlying properties for periods since December 1, 1998.  The court approved this settlement in April 2003.  Assuming that no appeal is filed, and based on XTO Energy’s anticipated settlement payment date of July 2003, this amount will reduce the trust’s August 2003 distribution, which is paid to unitholders in September.  The effect of the settlement on future distributions for other months will not be significant.

A second lawsuit,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 actionlawsuit 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

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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

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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.

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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 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 March 31,September 30, 2003 net profits income was $16,412,178,$21,446,124, as compared to $7,412,420$8,670,968 for firstthird quarter 2002.  Increased net profits income is primarily the result of higher oil and gas prices.  See “Net Profits Income” below.on the following page.

After adding interest income of $5,578$7,511 and deducting administration expense of $52,196,$75,555, distributable income for the quarter ended March 31,September 30, 2003 was $16,365,560,$21,378,080, or $0.409139$0.534452 per unit of beneficial interest.  Administration expense for the quarter decreased 18%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 firstthird quarter 2002, distributable income was $7,352,640,$8,622,680, or $0.183816$0.215567 per unit.  Distributions to unitholders for the quarter ended March 31,September 30, 2003 were:

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.

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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, 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)          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 31September 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 January.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.

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The following are explanations of significant variances from firstthird quarter 2002 to third quarter 2003 and from the first nine months of 2002 to the comparable period in 2003:

Sales Volumes

First quarter gasGas

Gas sales volumes decreased 10%9% for the third quarter and oil sales volumes decreased 4%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 first quarter 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 firstthird quarter 2003 average gas price was $3.80increased 85% to $4.82 per Mcf a 60% increase fromand for the first quarter 2002 average gas price of $2.38.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 quarternine months of 2002.  Prices gradually climbed in fourth quarter 2002 as a result of low levels of drilling activity, increased industrial demand, colder weather late in 2002 and international instability.  With colder than normal weather, and seasonallyrecord 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 continuedbeen injected into storage due to risediminished demand related to higher prices, resulting in 2003.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 February through AprilAugust and September 2003 was $5.92$4.81 per MMBtu.  At May 1,October 15, 2003, the average NYMEX futures price for the following twelve months was $5.35$5.19 per MMBtu.  Recent trust gas prices have averaged approximately $2.10$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 firstthird quarter 2003 average oil price was $28.76increased 14% to $29.58 per Bbl a 53% increase fromand for the first quarter 2002 average oil pricenine-month period increased 36% to $30.31 per Bbl.  Because of $18.80.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 volatilerelatively high in 2003, however, because of the war in Iraq, andslower than anticipated resumption of Iraqi oil exports.  On April 24, 2003,exports and unusually low storage levels.  OPEC members tentatively agreed to reducereduced 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

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for February through AprilAugust and September 2003 was $32.38$30.01 per Bbl.  At May 1,October 15, 2003, the average NYMEX futures price for the following twelve months was $25.22$29.78 per Bbl.  Recent trust oil prices have approximatedaveraged approximately $0.50 per Bbl lower than the NYMEX price.

Costs

Taxes

Taxes, transportation and other increased 93%62% for the first quarter and 79% for the nine-month period primarily because of increased Kansas property taxes, the timing of Wyoming property tax disbursements and higher production taxes related to increased revenues.

Production

Production expense decreased 9%increased 19% for the quarter and 3% for the nine-month period.  Increased production expense for the quarter is primarily because of decreased laborincreased fuel costs related to higher gas prices and timing of disbursements.maintenance projects.  The nine-month period increase is primarily because of higher fuel costs.

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Development

Development costs deducted in the calculation of net profits income are based on the 2003 budget.  These development costs decreased 34%61% for firstthe third quarter 2003 fromand 49% for the prior year quarternine-month period because of reduced drilling activity.the timing of development projects.  During the first threenine months of 2003, three12 wells were started and completed on the underlying properties and were pending completion at March 31.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, for the quarter ended March 31, 2003, XTO Energy deducted budgeted development costs of $3.8 million.$2.3 million for the quarter and $8.8 million for the nine months ended September 30, 2003.  After considering actual development costs of $2.6$4.3 million for the quarter and $10.0 million for the nine-month period, cumulative development costs deducted exceeded actual costs by $4.3$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 3% primarily12% 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.

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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 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.

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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.Procedures.

WithinAs of the 90 days prior toend of the date ofperiod 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 Rule 13a-14.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.  No significant changesThere has not been any change in the trust’s internal controlscontrol over financial reporting during the period covered by this report that has materially affected, or other factors that couldis reasonably likely to materially affect, these controls have occurred subsequent to the date of such evaluation.trust’s internal control over financial reporting.

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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 allegealleged that since 1991, XTO Energy 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.  The parties have entered intoagreed on a settlement agreement under whichthat the trust’scourt 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 will be approximately $850,000,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.  This amount reflects the trust’s 80% share of the settlement relating to production from the underlying properties for periods since December 1, 1998.  The court approved this settlement in April 2003.  Assuming that no appeal is filed, and based on XTO Energy’s anticipated settlement payment date of July 2003, this amount will reduce the trust’s August 2003 distribution, which is paid to unitholders in September.  The effect of the settlement on future distributions for other months will not be significant.

Items 2 through 5.  Not applicable.

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

(a)          Exhibits.

Exhibit Number
and Description

(15)                                    Awareness letter of KPMG LLP

(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)

(99.1)                           Trustee Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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.

On January 22, 2003, the trust filed a reportNo reports on Form 8-K dated January 21, 2003, to report that XTO Energy’s 2003 development cost budget forwere filed during the underlying properties is approximately $16 million, which will be deducted in the calculation of net profits income at a monthly rate of $1,000,000 for the February 2003 through March 2004 distributions.

On March 20, 2003, thequarter.  The trust filed a reportfurnished two reports on Form 8-K dated March 20, 2003, to announce XTO Energy’s settlement of the Booth lawsuit, the trust’s portion of which is approximately $850,000, or 2.1 cents per unit, and is anticipated to reduce the trust’s August 2003 distribution which will be paid to unitholders in September 2003, after court approval.under Item 12 for this period.

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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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CERTIFICATIONS

I, Nancy G. Willis, certify that:

1.                         I have reviewed this quarterly report on Form 10-Q of Hugoton Royalty Trust, for which Bank of America, N.A. acts as Trustee;

2.                         Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3.                         Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this quarterly report;

4.                         I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), or for causing such procedures to be established and maintained, for the registrant and I have:

a)                       designed such disclosure controls and procedures, or caused such controls and procedures to be designed, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this quarterly report is being prepared;

b)                      evaluated the effectiveness of the registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

c)                       presented in this quarterly report my conclusions about the effectiveness of the disclosure controls and procedures based on my evaluation as of the Evaluation Date;

5.                         I have disclosed, based on my most recent evaluation, to the registrant’s auditors:

a)                       all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

b)                      any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal controls; and

6.                         I have indicated in this quarterly report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

In giving the certifications in paragraphs 4, 5 and 6 above, I have relied to the extent I consider reasonable on information provided to me by XTO Energy Inc.

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