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EXHIBIT 13

HUGOTON ROYALTY TRUST

GLOSSARY OF TERMS

        The following are definitions of significant terms used in this Annual Report:

Bbl	Barrel (of oil)
Bcf	Billion cubic feet (of natural gas)
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%, which is paid to the trust by XTO Energy. "Net profits income" is referred to as "royalty income" for tax reporting purposes.
net profits interest	An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties:
	80% net profits interests—interests that entitle the trust to receive 80% of the net proceeds from the underlying properties that are working interests in Kansas, Oklahoma and 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

THE TRUST

        Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certain predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming to the trust. The net profits interests are the only assets of the trust, other than cash held for trust expenses and for distribution to unitholders.

        Net profits income received by the trust on the last business day of each month is calculated and paid by XTO Energy based on net proceeds received from the underlying properties in the prior month. Distributions, as calculated by the trustee, are paid to month-end unitholders of record within ten business days.

UNITS OF BENEFICIAL INTEREST

        The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol "HGT." The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2002 and 2001:

	Sales Price
Quarter					Distributions per Unit
	High		Low
2002
First	$	12.10	$	9.44	$	0.183816
Second		12.43		10.22		0.133366
Third		12.00		9.44		0.215567
Fourth		13.19		10.86		0.206560
					$	0.739309
2001
First	$	16.00	$	13.50	$	0.841362
Second		17.01		12.00		0.543291
Third		13.70		9.70		0.381796
Fourth		11.67		9.91		0.211827
					$	1.978276

        At December 31, 2002, there were 40,000,000 units outstanding and approximately 154 unitholders of record; 17,694,639 of these units were held by depository institutions. As of March 3, 2003, XTO Energy owned 21,705,893 units.

Forward-Looking Statements

This Annual Report, including the accompanying Form 10-K, 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 Annual Report and Form 10-K, including, without limitation, statements regarding estimates of proved reserves, future development plans and costs, and industry and market conditions, are forward-looking statements that are subject to a number of risks and uncertainties which are detailed in Part II, Item 7 of the accompanying Form 10-K. 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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SUMMARY

        The trust was created to collect and distribute to unitholders monthly net profits income related to the 80% net profits interests. Such net profits income is calculated as 80% of the net proceeds received from certain working interests in predominantly gas-producing properties in Kansas, Oklahoma and Wyoming. Net proceeds from properties in each state are calculated by deducting production costs, development costs and overhead from revenues. If monthly costs exceed revenues from the underlying properties in any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Excess costs generally can occur during periods of higher development activity and lower gas prices.

        Unitholders may be eligible to receive the following tax benefits, but should consult their tax advisors:

•

The Nonconventional Fuel Source Tax Credit is related to tight sands gas production sold through 2002 from wells drilled on the underlying properties prior to January 1, 1993, and after November 5, 1990, or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977. This tax credit may be used to reduce the unitholder's regular income tax liability, but not below his tentative minimum tax. Congress has considered extending this credit beyond the December 31, 2002 expiration date, and the creation of similar new tax credits. Unless new legislation is passed, extending this credit on existing eligible production or allowing for credits on new production, there will be no further benefit on production past the year 2002.



•

Cost Depletion is generally available to unitholders as a deduction from royalty income. Available depletion is dependent upon the unitholder's cost of units, purchase date and prior allowable depletion. It may be more beneficial for unitholders to deduct percentage depletion. Unitholders should consult their tax advisors for further information.

As an example, a unitholder that acquired units in January 2002 and held them throughout 2002 would be entitled to a cost depletion deduction of approximately 5% of his cost. Assuming a cost of $10.00 per unit, cost depletion would offset 63% of 2002 taxable trust income. After considering the tight sands tax credit and assuming a 30% tax rate, the 2002 taxable equivalent return as a percentage of unit cost would be 9%. (NOTE- Because the units are a depleting asset, a portion of this return is effectively a return of capital.)

TO UNITHOLDERS

        We are pleased to present the 2002 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust's 2002 Form 10-K as filed with the Securities and Exchange Commission. Both reports contain important information about the trust's net profits interests, including information provided to the trustee by XTO Energy, and should be read in conjunction with each other.

        For the year ended December 31, 2002, net profits income totaled $29,934,195. After adding interest income of $14,955 and deducting trust administration expense of $376,790, distributable income was $29,572,360 or $0.739309 per unit. Net profits income and distributions were 62% lower than 2001 amounts primarily because of lower average gas prices.

        Natural gas prices averaged $2.44 per Mcf for 2002, 43% lower than the 2001 average price of $4.30 per Mcf. The average 2002 oil price was $23.70 per Bbl, 14% lower than the 2001 average price of $27.60 per Bbl.

        Gas sales volumes from the underlying properties for 2002 were 34,315,145 Mcf, or 94,014 Mcf per day, or a 6% decline from 100,268 Mcf per day in 2001. Oil sales volumes from the underlying properties were 353,185 Bbls, or 968 Bbls per day in 2002, or a decline of 10% from 1,079 Bbls per day

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in 2001. For further information on sales volumes and product prices, see "Trustee's Discussion and Analysis."

        Tight sands gas sales volumes from the underlying properties were 2,058,927 Mcf in 2002. After reduction of volumes related to production and development costs, tight sands gas sales volumes allocated to the net profits interests were 212,008 Mcf, resulting in a tight sands tax credit for the year of $0.002991 per unit. This credit (or a portion thereof, if units were acquired after January 2002) can be applied against the unitholder's regular federal income tax liability, subject to certain limitations. Unitholders should consult their tax advisors regarding use of this credit.

        As of December 31, 2002, proved reserves for the net profits interests were estimated by independent engineers to be 299.2 Bcf of natural gas and 2.6 million Bbls of oil. Estimated gas reserves increased 16% and oil reserves increased 24% from year-end 2001 to 2002, primarily because of the increase in year-end realized gas prices from $2.34 to $4.37 per Mcf and West Texas Intermediate posted oil prices from $16.75 to $28.00 per Bbl and the resulting increased allocation of reserves to the net profits interests. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy.

        Estimated future net cash flows from proved reserves of the net profits interests at December 31, 2002 are $1.26 billion, or $31.39 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2002 is $609.5 million, or $15.24 per unit. Proved reserve estimates and related future net cash flows have been determined based on year-end oil and gas prices, as well as other guidelines prescribed by the Financial Accounting Standards Board as further described under Item 2 of the accompanying Form 10-K. The present value of estimated future net cash flows is not representative of the market value of trust units.

        As discussed in the tax instructions provided to unitholders in February 2003, trust distributions are considered portfolio income, rather than passive income. Unitholders should consult their tax advisors for further information.

Hugoton Royalty Trust By: Bank of America, N.A., Trustee
By:	Nancy G. Willis Assistant Vice President

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THE UNDERLYING PROPERTIES

        The underlying properties are predominantly gas-producing properties with established production histories in the Hugoton area of Oklahoma and Kansas, the Anadarko Basin of Oklahoma and the Green River Basin of Wyoming. The average reserve-to-production index for the underlying properties as of December 31, 2002 is approximately 15 years. This index is calculated using total proved reserves and estimated 2003 production for the underlying properties. Based on estimated future net cash flows at year-end oil and gas prices, the proved reserves of the underlying properties are approximately 94% natural gas and 6% oil. XTO Energy operates approximately 94% of the underlying properties.

        Because the underlying properties are working interests, production and development costs are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See "Trustee's Discussion and Analysis—Years Ended December 31, 2002, 2001 and 2000—Costs." Total 2002 development costs for the underlying properties were $22,733,333, a decrease of 25% from the prior year. XTO Energy has informed the trustee that total 2003 budgeted development costs for the underlying properties are $16 million.

Hugoton Area

        Discovered in 1922, the Hugoton area is the largest natural gas producing area in North America. During 2002, gas sales volumes from the Hugoton area were 10,414,000 Mcf, or approximately 30% of total sales volumes from the underlying properties. Most of the production is from the Chase formation at depths of 2,700 to 2,900 feet. XTO Energy has informed the trustee that it plans to develop other formations, including the Council Grove, Chester, Morrow and St. Louis formations that underlie the 79,500 net acres held by production by the Chase formation wells. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of its net acreage position beneath the Chase formation.

        During 2002, development of the Hugoton area included four successful recompletions to the Towanda formation. XTO Energy also continued its restimulation program in the Chase intervals, completing 33 of these restimulations in 2002. XTO Energy has informed the trustee that it plans to perform 35 Chase restimulations during 2003.

Anadarko Basin

        The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the Anadarko Basin totaled 15,369,000 Mcf in 2002, or approximately 45% of total sales volumes from the underlying properties. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene and Cheyenne Valley fields in Major County, the principal producing region of the underlying properties in the Anadarko Basin.

        In Major and Woodward counties, the Mississippian (Osage), Chester and Red Fork formations were the primary drilling targets in 2002. In Major County, XTO Energy successfully drilled seven gross (4.9 net) wells. XTO Energy has informed the trustee that it plans to drill up to six wells and perform up to 11 workovers in Major County in 2003. In Woodward County, the Chester formation, with its four separate producing intervals, was the primary target for ten gross (8.0 net) wells successfully drilled and completed during 2002. XTO Energy has informed the trustee that it plans to drill up to 12 gross (11.5 net) wells and perform up to five workovers in Woodward County during 2003.

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Estimated Proved Reserves and Future Net Cash Flows

        The following are proved reserves of the underlying properties and proved reserves and future net cash flows from proved reserves of the net profits interests at December 31, 2002, as estimated by independent engineers:

		Underlying Properties		Net Profits Interests
				Proved Reserves(a)(b)		Future Net Cash Flows from Proved Reserves(a)(c)
		Proved Reserves(a)
		Gas (Mcf)	Oil (Bbls)	Gas (Mcf)	Oil (Bbls)	Undiscounted		Discounted
(in thousands)
Oklahoma		286,574	3,829	181,806	2,427	$	822,283	$	416,867
Wyoming		148,161	213	93,061	134		352,995		150,314
Kansas		41,766	69	24,330	40		80,696		42,328
	TOTAL	476,501	4,111	299,197	2,601	$	1,255,974	$	609,509

(a)

Based on year-end oil and gas prices. For further information regarding trust proved reserves, see Item 2 of the accompanying Form 10-K.



(b)

Since the trust has defined net profits interests, the trust does not own a specific percentage of the oil and gas reserves. Because trust reserve quantities are determined using an allocation formula, any fluctuations in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the net profits interests.



(c)

Before income taxes since future net cash flows are not subject to taxation at the trust level.

Green River Basin

        The Green River Basin is located in southwestern Wyoming. Natural gas was discovered in the Fontenelle Field of the Green River Basin in the early 1970s. The producing reservoirs are the Cretacious-aged Frontier and Dakota sandstones at depths ranging from 7,500 to 10,000 feet. Gas sales volumes from the Green River Basin were 8,532,000 Mcf in 2002, or approximately 25% of total sales volumes from the underlying properties.

        XTO Energy has informed the trustee that its development activities in the Fontenelle Field were delayed for the better part of 2002 due to the pipeline limitations and price volatility. XTO Energy plans to perform up to five workovers and may drill up to five wells in the Green River Basin during 2003.

TRUSTEE'S DISCUSSION AND ANALYSIS

Years Ended December 31, 2002, 2001 and 2000

        Net profits income for 2002 was $29,934,195, as compared with $79,272,395 for 2001 and $56,812,141 for 2000. The 62% decrease in net profits income from 2001 to 2002 was caused by lower average gas prices in 2002, while the 40% increase in net profits income from 2000 to 2001 was caused by higher average gas prices in 2001. Approximately 91% in 2002, 94% in 2001 and 90% in 2000 of net profits income was derived from natural gas sales.

        Trust administration expense was $376,790 in 2002 as compared to $277,532 in 2001 and $228,211 in 2000. Increased administration expense from 2001 to 2002 is primarily related to increased stock exchange listing fees. Increased administration expense from 2000 to 2001 is primarily related to increased unitholder reporting costs. Interest income was $14,955 in 2002, $136,177 in 2001 and

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$128,150 in 2000. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $29,572,360 or $0.739309 per unit in 2002, $79,131,040 or $1.978276 per unit in 2001 and $56,712,080 or $1.417802 per unit in 2000.

        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.

Volumes

        From 2001 to 2002, underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 10% primarily because natural production decline exceeded the effects of new wells and workovers. From 2000 to 2001, underlying gas sales volumes decreased 1% and underlying oil sales volumes decreased 2% primarily because natural production decline slightly exceeded the effects of new wells and workovers.

        Underlying tight sands gas sales volumes decreased 2% from 2,104,845 Mcf in 2001 to 2,058,927 Mcf in 2002. After reduction of volumes related to production and development costs, tight sands gas volumes allocated to the net profits interests in 2002 were 212,008 Mcf, which were significantly lower than volumes of 1,230,270 Mcf allocated to the net profits interests in 2001. This decrease in tight sands gas sales volumes allocated to the net profits interests was because of higher development costs on the related underlying properties in 2002, which resulted in a similar decrease in the tight sands credit per unit.

Prices

        Gas.    The 2002 average gas price was $2.44 per Mcf, a 43% decrease from the 2001 average gas price of $4.30 per Mcf, which was a 37% increase from the 2000 average gas price of $3.14 per Mcf. At the beginning of 2000, NYMEX gas prices approximated $2.30 per MMBtu. Gas prices strengthened in 2000, reaching a record high of $10.10 per MMBtu in December 2000, as winter demand strained gas supplies. Prices subsequently declined during 2001 because of fuel switching due to higher prices, milder weather and a weaker economy, which reduced demand for gas to generate electricity. The December 31, 2001 NYMEX gas price was $2.57 per MMBtu. Despite the winter of 2001-2002 being one of the warmest on record and higher than average gas storage levels, gas prices gradually climbed in 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 seasonally low gas storage levels, gas prices have continued to rise in 2003. The average NYMEX price for January and February 2003 was $5.97 per MMBtu. Gas prices have risen in March 2003 to an average NYMEX price of $6.49 through March 14.

        The trust's average gas price for January 2003 gas sales was approximately $1.00 per MMBtu lower than the average NYMEX price, primarily because of lower Wyoming prices related to pipeline constraints and reduced West Coast demand. In early March 2003, the Wyoming index price was approximately $4.00 lower than the NYMEX price of $9.00, which was elevated because gas supplies to the northeast U.S. were strained from severe winter weather. The gas price differential in Wyoming is expected to narrow later in 2003 because of pipeline expansion projects aimed at increasing capacity to western markets. These projects are anticipated to ultimately lead to higher gas prices for the region's producers.

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        Oil.    The average oil price for 2002 was $23.70 per Bbl, 14% lower than the 2001 average oil price of $27.60 per Bbl, which was 4% lower than the 2000 average price of $28.67 per Bbl. Despite OPEC production increases in 2000, increased demand sustained higher prices. The West Texas Intermediate ("WTI") posted price reached $34.25 in September 2000, then its highest level in ten years. Lagging demand, resulting from a worldwide economic slowdown, caused oil prices to decline during 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. OPEC cut an additional 1.5 million barrels per day during 2002. 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. However, with the war in Iraq, oil prices are expected to remain volatile. The average WTI posted price for January and February 2003 was $30.95. Oil prices have risen in March 2003 to an average WTI posted price of about $33.63 through March 14. Recent trust oil prices have averaged approximately $2.60 higher than the WTI posted price.

Costs

        The calculation of net profits income includes deductions for production and development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. There have been no excess costs or related recoveries since September 1999.

        Taxes, transportation and other.    Taxes, transportation and other generally fluctuates with changes in total revenues.

        Production.    Production expenses increased 3% from 2001 to 2002 because of increased compressor fuel, maintenance, insurance and labor costs and saltwater disposal expense. Production expenses increased 11% from 2000 to 2001 because of the timing of maintenance projects and higher compressor rentals.

        Development.    Development costs were $22.7 million in 2002, $30.4 million in 2001 and $22.8 million in 2000. The decrease from 2001 to 2002 is attributable to fewer wells drilled and workovers in Oklahoma. Development costs for 2001 were higher because of increased drilling, service and equipment costs related to demand generated by higher natural gas prices, as well as carryover of costs from 2000.

        In 2002, budgeted development costs deducted from distributions totaled $22.7 million, compared with actual development costs of $14.9 million. At December 31, 2002, cumulative development costs deducted exceeded actual costs by $3.1 million. This excess is expected to be reduced as 2002 development costs are billed and paid in 2003. 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.

        Overhead.    Overhead is charged by XTO Energy for reimbursement of administrative expenses of operating the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual inflation adjustment.

Other Proceeds

        Net profits income for 2002 includes proceeds of $60,000 ($48,000 net to the trust) from the sale of an underlying property in Major County, Oklahoma. Net profits income for 2001 includes proceeds

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of $307,824 ($246,259 net to the trust) from the sale of certain underlying properties in Sweetwater County, Wyoming.

Fourth Quarter 2002 and 2001

        During fourth quarter 2002 the trust received net profits income totaling $8,290,621, compared with fourth quarter 2001 net profits income of $8,507,804. The 3% decrease in net profits income from fourth quarter 2001 to 2002 was primarily because of lower product volumes partially offset by higher product prices.

        Administration expense was $31,879 and interest income was $3,658, resulting in fourth quarter 2002 distributable income of $8,262,400, or $0.206560 per unit. Distributable income for fourth quarter 2001 was $8,473,080 or $0.211827 per unit. Distributions to unitholders for the quarter ended December 31, 2002 were:

Record Date	Payment Date	Per Unit
October 31, 2002	November 15, 2002	$	0.062028
November 29, 2002	December 13, 2002		0.063836
December 31, 2002	January 15, 2003		0.080696
		$	0.206560

Volumes

        Fourth quarter underlying gas sales volumes decreased 12% while underlying oil sales volumes declined 13%. The decrease in oil and gas sales volumes is primarily because of natural production decline and timing of cash receipts.

Prices

        The average fourth quarter 2002 gas price was $2.52 per Mcf, or 15% higher than the fourth quarter 2001 average price of $2.19. The average fourth quarter oil price was $28.16 per Bbl, or 13% higher than the fourth quarter 2001 average price of $25.02. For further information about product prices, see "Years Ended December 31, 2002, 2001 and 2000—Prices" above.

Costs

        Production.    Fourth quarter production expenses increased 39% from 2001 to 2002 because of prior period salt water disposal adjustments recorded in fourth quarter 2001, and increased insurance premiums and the timing of maintenance projects and disbursements in fourth quarter 2002.

        Development.    Development costs, which were deducted based on budgeted development costs, declined 2% from fourth quarter 2001 to 2002.

        Overhead.    Overhead decreased 33% from fourth quarter 2001 to 2002 because of the timing of an annual Oklahoma administrative fee and a one-time reduction of prior period overhead on certain Wyoming wells.

        For further information about costs, see "Years Ended December 31, 2002, 2001 and 2000—Costs" above.

        See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and capital resources, contractual obligations and commitments, related party transactions and critical accounting policies of the trust. See Item 7a of the accompanying Form 10-K for quantitative and qualitative disclosures about market risk affecting the trust.

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Calculation of Net Profits Income

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

				Year Ended December 31 (a)						Three Months Ended December 31 (a)
				2002		2001		2000		2002		2001
Sales Volumes
	Gas (Mcf)(b)
		Underlying properties			34,315,145		36,597,937		36,842,156		8,412,012		9,521,295
			Average per day		94,014		100,268		100,662		91,435		103,492
		Net profits interests			11,774,205		17,671,423		18,199,754		3,118,488		3,627,744
	Oil (Bbls)(b)
		Underlying properties			353,185		393,731		399,929		83,016		95,063
			Average per day		968		1,079		1,093		902		1,033
		Net profits interests			123,142		190,722		198,677		31,466		38,698
Average Sales Prices
	Gas (per Mcf)			$	2.44	$	4.30	$	3.14	$	2.52	$	2.19
	Oil (per Bbl)			$	23.70	$	27.60	$	28.67	$	28.16	$	25.02
Revenues
	Gas sales			$	83,610,392	$	157,508,999	$	115,579,023	$	21,228,671	$	20,810,221
	Oil sales				8,369,027		10,867,817		11,467,882		2,337,918		2,378,744
		Total Revenues			91,979,419		168,376,816		127,046,905		23,566,589		23,188,965
Costs
	Taxes, transportation and other				8,228,963		15,694,068		12,023,222		2,477,308		2,078,658
	Production expense				16,107,467		15,611,725		14,026,261		3,851,038		2,779,198
	Development costs(c)				22,733,333		30,367,276		22,771,150		5,383,333		5,475,000
	Overhead				7,551,912		7,921,077		7,211,096		1,491,634		2,221,354
		Total Costs			54,621,675		69,594,146		56,031,729		13,203,313		12,554,210
Other Proceeds
	Property sales				60,000		307,824		—		—		—
Net Proceeds					37,417,744		99,090,494		71,015,176		10,363,276		10,634,755
Net Profits Percentage					80%		80%		80%		80%		80%
Net Profits Income				$	29,934,195	$	79,272,395	$	56,812,141	$	8,290,621	$	8,507,804

(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 year ended December 31, 2002, 2001 and 2000 generally relate to twelve months of production for the period November through October, and 2) oil and gas sales for the three months ended December 31 generally relate to production for the period August through October.

(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 4 to Financial Statements.

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HUGOTON ROYALTY TRUST

STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

		December 31
		2002		2001
Assets
	Cash and short-term investments	$	3,227,840	$	1,781,800
	Net profits interests in oil and gas properties—net (Notes 1 and 2)		205,493,243		215,346,192
		$	208,721,083	$	217,127,992
Liabilities and Trust Corpus
	Distribution payable to unitholders	$	3,227,840	$	1,781,800
	Trust corpus (40,000,000 units of beneficial interest authorized and outstanding)		205,493,243		215,346,192
		$	208,721,083	$	217,127,992

STATEMENTS OF DISTRIBUTABLE INCOME

		December 31
		2002		2001		2000
Net profits income		$	29,934,195	$	79,272,395	$	56,812,141
Interest income			14,955		136,177		128,150
	Total income		29,949,150		79,408,572		56,940,291
Administration expense			376,790		277,532		228,211
	Distributable income	$	29,572,360	$	79,131,040	$	56,712,080
	Distributable income per unit (40,000,000 units)	$	0.739309	$	1.978276	$	1.417802

STATEMENTS OF CHANGES IN TRUST CORPUS

	Year Ended December 31
	2002			2001			2000
Trust corpus, beginning of year	$	215,346,192		$	226,081,443		$	233,428,609
Amortization of net profits interests		(9,852,949	)		(10,735,251	)		(7,347,166	)
Distributable income		29,572,360			79,131,040			56,712,080
Distributions declared		(29,572,360	)		(79,131,040	)		(56,712,080	)
Trust corpus, end of year	$	205,493,243		$	215,346,192		$	226,081,443

See Accompanying Notes to Financial Statements.

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NOTES TO FINANCIAL STATEMENTS

1. Trust Organization and Provisions

        Hugoton Royalty Trust was created on December 1, 1998 by XTO Energy Inc. (formerly known as "Cross Timbers Oil Company"). Effective on that date, XTO Energy conveyed 80% net profits interests in certain predominantly gas-producing working interest properties in Kansas, Oklahoma and Wyoming to the trust under separate conveyances for each of the three states. XTO Energy currently owns and operates the majority of the underlying working interest properties.

        In exchange for the conveyances of the net profits interests to the trust, 40 million units of beneficial interest in the trust were issued to XTO Energy. In April and May 1999, XTO Energy sold a total of 17 million units in the trust's initial public offering. In 1999 and 2000, XTO Energy also sold 1.3 million units to certain of its officers. The trust did not receive any proceeds from the sale of trust units.

        Bank of America, N.A. is the trustee for the trust. The trust indenture provides, among other provisions, that:

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the trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;



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the trust may dispose of all or part of the net profits interests if approved by 80% of the unitholders, or upon trust termination. Otherwise, the trust may sell up to 1% of the value of the net profits interests in any calendar year, pursuant to notice from XTO Energy of its desire to sell the related underlying properties. Any sale must be for cash with the proceeds promptly distributed to the unitholders;



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the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;



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the trustee may borrow funds to pay trust liabilities if repaid in full prior to further distributions to unitholders;



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the trustee will make monthly cash distributions to unitholders (Note 3); and



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the trust will terminate upon the first occurrence of:



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disposition of all net profits interests pursuant to terms of the trust indenture,



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gross proceeds from the underlying properties falling below $1 million per year for two successive years, or



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a vote of 80% of the unitholders to terminate the trust in accordance with provisions of the trust indenture.

2. Basis of Accounting

        The financial statements of the 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:

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Net profits income is recorded in the month received by the trustee (Note 3).



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



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Distributions to unitholders are recorded when declared by the trustee (Note 3).

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        The most significant differences between the trust's financial statements and those prepared in accordance with generally accepted accounting principles are:

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Net profits income is recognized in the month received rather than accrued in the month of production.



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Expenses are recognized when paid rather than when incurred.



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Cash reserves may be established by the trustee for contingencies that would not be recorded under generally accepted accounting principles.

        The initial carrying value of the net profits interests of $247,066,951 was XTO Energy's historical net book value of 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 $41,573,708 as of December 31, 2002 and $31,720,759 as of December 31, 2001.

3. Distributions to Unitholders

        The trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day of the month.

        Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production costs, development and drilling costs, and overhead (Note 6).

        For monthly trust distributions declared through March 2000, the related net profits income was based on gross proceeds equal to the greater of:

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the actual amount received from sales of production, or



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the imputed amount that would be received from sales of production at a gas price of $2.00 per Mcf. For the year ended December 31, 2000, there were no imputed proceeds because actual gas prices were higher than the $2.00 price support.

        XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (Note 1). If 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 profits income from the other conveyances.

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4. 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:

	Year Ended December 31
	2002			2001
Cumulative development costs (over) under the amount deducted—beginning of period	$	(4,778,880	)	$	—
Actual development costs		(14,864,890	)		(35,146,156	)
Amount deducted		22,733,333			30,367,276
Cumulative development costs (over) under the amount deducted—end of period	$	3,089,563		$	(4,778,880	)

        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.

5. Federal Income Taxes

        Tax counsel has advised the trust that, under current tax laws, the trust will be classified as a grantor trust for federal income tax purposes and, therefore, is not subject to taxation at the trust level. However, the opinion of tax counsel is not binding on the Internal Revenue Service.

        For federal income tax purposes, unitholders of a grantor trust are considered to own the trust's income and principal as though no trust were in existence. The income of the trust is deemed to be received or accrued by the unitholders at the time such income is received or accrued by the trust, rather than when distributed by the trust.

        XTO Energy has advised the trustee that the trust receives net profits income from tight sands gas wells. Production sold through 2002 from wells drilled on the underlying properties prior to January 1, 1993, and after November 5, 1990 (or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977), qualifies for the federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code.

        This tax credit was approximately $0.52 per MMBtu and $0.002991 per unit in 2002, $0.017309 per unit in 2001 and $0.014499 per unit in 2000. The credit is recalculated annually based on each year's qualifying production through the year 2002. Unitholders should consult their tax advisors regarding use of this credit and other trust tax compliance matters.

        Congress has considered extending this credit beyond the December 31, 2002 expiration date, and the creation of similar new tax credits. Unless new legislation is passed, extending this credit on existing eligible production or allowing for credits on new production, there will be no further benefit on production past the year 2002.

6. XTO Energy Inc.

        XTO Energy operates approximately 94% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses on the underlying properties it operates. As of December 31, 2002, the overhead charge was approximately $720,000 ($576,000 net to the trust) per month and is subject to annual adjustment based on an oil and

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gas industry index as defined in the trust agreement. As of March 3, 2003, XTO Energy owned 54.3% of the trust.

        XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy's wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. ("TGPC"). Much of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company ("RGC"), which retains approximately $0.31 per Mcf compression and gathering fee. TGPC and RGC sell gas to Cross Timbers Energy Services, Inc. ("CTES"), which markets gas to third parties. XTO Energy sells directly to CTES most gas production not sold directly to TGPC or RGC.

        Total gas sales from the underlying properties to XTO Energy's wholly owned subsidiaries were $59.1 million for the year ended December 31, 2002, or 71% of total gas sales, $128.5 million for the year ended December 31, 2001, or 82% of total gas sales and $89.0 million for the year ended December 31, 2000, or 77% of total gas sales.

7. 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 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 allege 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 into a settlement agreement under which the trust's portion of the settlement will be approximately $850,000, 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 has tentatively approved the settlement, subject to a fairness hearing in April 2003 and approval of the court. 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, 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 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 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,

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is not currently expected to be material to the trust's annual distributable income, financial position or liquidity.

        For further information regarding these lawsuits and other legal proceedings pertaining to the trust, see Item 3 of the trust's Annual Report on Form 10-K included in this report.

8. Supplemental Oil and Gas Reserve Information (Unaudited)

        Proved oil and gas reserve information is included in Item 2 of the trust's Annual Report on Form 10-K included in this report.

9. Quarterly Financial Data (Unaudited)

        The following is a summary of net profits income, distributable income and distributable income per unit by quarter for 2002 and 2001:

	Net Profits Income		Distributable Income		Distributable Income per Unit
2002
First Quarter	$	7,412,420	$	7,352,640	$	0.183816
Second Quarter		5,560,186		5,334,640		0.133366
Third Quarter		8,670,968		8,622,680		0.215567
Fourth Quarter		8,290,621		8,262,400		0.206560
	$	29,934,195	$	29,572,360	$	0.739309
2001
First Quarter	$	33,683,872	$	33,654,480	$	0.841362
Second Quarter		21,720,948		21,731,640		0.543291
Third Quarter		15,359,771		15,271,840		0.381796
Fourth Quarter		8,507,804		8,473,080		0.211827
	$	79,272,395	$	79,131,040	$	1.978276

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INDEPENDENT AUDITORS' REPORTS

Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:

        We have audited the accompanying statements of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2002, and the related statement of distributable income and changes in trust corpus for the year then ended. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audit. The 2001 and 2000 financial statements were audited by other auditors who have ceased operations. Those auditors' report, dated March 19, 2002, on those financial statements was unqualified and included an explanatory paragraph that described the trust's method of accounting as explained in Note 2 to the financial statements.

        We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

        As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

        In our opinion, the 2002 financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the trust as of December 31, 2002 and its distributable income and changes in trust corpus for the year then ended in conformity with the modified cash basis of accounting described in Note 2.

KPMG LLP

Dallas, Texas
March 14, 2003

Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:

        We have audited the accompanying statements of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2001 and 2000, and the statements of distributable income and changes in trust corpus for each of the years then ended. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audits.

        We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

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        As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States.

        In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the trust as of December 31, 2001 and 2000 and its distributable income and changes in trust corpus for each of the years then ended, in conformity with the modified cash basis of accounting described in Note 2.

ARTHUR ANDERSEN LLP

Fort Worth, Texas
March 19, 2002

The above report of Arthur Andersen LLP ("Arthur Andersen") is a copy of a report previously issued by Arthur Andersen on March 19, 2002. This audit report has not been reissued by Arthur Andersen in connection with this filing on Form 10-K. After reasonable efforts, the trust has been unable to obtain the consent of Arthur Andersen, our former independent auditors, as to the incorporation by reference of their report for our fiscal years ended December 31, 2001 and 2000 into the trust's and XTO Energy's previously filed registration statements under the Securities Act of 1933, and the trust has not filed that consent with this Annual Report on Form 10-K in reliance on Rule 437a of the Securities Act of 1933. Because the trust has not been able to obtain Arthur Andersen's consent, you will not be able to recover against Arthur Andersen under Section 11 of the Securities Act for any untrue statements of a material fact contained in our financial statements audited by Arthur Andersen or any omissions to state a material fact required to be stated therein.

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HUGOTON ROYALTY TRUST

901 Main Street, 17^th Floor
P.O. Box 830650
Dallas, Texas 75283-0650
(877) 228-5083
Bank of America, N.A., Trustee

A copy of the Hugoton Royalty Trust Form 10-K has been provided with this Annual Report. Additional copies of this Annual Report and Form 10-K will be provided to unitholders without charge upon request. Copies of exhibits to the Form 10-K may be obtained upon request.

WEB SITE

www.hugotontrust.com

AUDITORS

KPMG LLP
Dallas, Texas

LEGAL COUNSEL

Thompson & Knight L.L.P.
Dallas, Texas

TAX COUNSEL

Winstead Sechrest & Minick P.C.
Houston, Texas

TRANSFER AGENT AND REGISTRAR

Mellon Investor Services, L.L.C.
Dallas, Texas
www.melloninvestor.com

QuickLinks

EXHIBIT 13
HUGOTON ROYALTY TRUST

THE TRUST
UNITS OF BENEFICIAL INTEREST
SUMMARY
TO UNITHOLDERS

THE UNDERLYING PROPERTIES
Hugoton Area
Anadarko Basin
Estimated Proved Reserves and Future Net Cash Flows
Green River Basin
TRUSTEE'S DISCUSSION AND ANALYSIS
Years Ended December 31, 2002, 2001 and 2000
Fourth Quarter 2002 and 2001
Calculation of Net Profits Income
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
STATEMENTS OF DISTRIBUTABLE INCOME
STATEMENTS OF CHANGES IN TRUST CORPUS

NOTES TO FINANCIAL STATEMENTS

INDEPENDENT AUDITORS' REPORTS

HUGOTON ROYALTY TRUST
WEB SITE
AUDITORS
LEGAL COUNSEL
TAX COUNSEL
TRANSFER AGENT AND REGISTRAR