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.
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 expense 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 2005 and 2004:
| | Sales Price | | Distributions | |
Quarter | | High | | Low | | per Unit | |
2005 | | | | | | | |
| | | | | | | |
First | | $ | 32.19 | | $ | 23.72 | | $ | 0.642454 | |
Second | | 31.05 | | 24.88 | | 0.570801 | |
Third | | 41.84 | | 29.80 | | 0.607605 | |
Fourth | | 41.80 | | 31.03 | | 0.799937 | |
| | | | | | $ | 2.620797 | |
| | | | | | | |
2004 | | | | | | | |
First | | $ | 22.54 | | $ | 17.10 | | $ | 0.474419 | |
Second | | 24.40 | | 19.60 | | 0.454464 | |
Third | | 28.25 | | 22.85 | | 0.585721 | |
Fourth | | 29.95 | | 24.75 | | 0.525319 | |
| | | | | | $ | 2.039923 | |
At December 31, 2005, there were 40,000,000 units outstanding and approximately 192 unitholders of record; 17,587,316 of these units were held by depository institutions. As of December 31, 2005, XTO Energy owned 21,705,893 units. In January 2006, the Board of Directors of XTO Energy declared a dividend of all of the 21.7 million trust units it owns. These units are to be distributed on May 12, 2006 to XTO Energy’s common stockholders of record on April 26, 2006. After this dividend, XTO Energy will not be a unitholder of the trust.
XTO Energy also announced in January 2006 that it will consider selling the underlying properties. Any sale is dependent upon XTO Energy’s ability to structure a tax-efficient transaction and receive sufficient consideration from a buyer it deems to be qualified.
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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 I, Item 1A 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 expense, 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.
• 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 2005 and held them throughout 2005 would be entitled to a cost depletion deduction of approximately 6% of his cost. Assuming a cost of $25.00 per unit, cost depletion would offset approximately 56% of 2005 taxable trust income. Assuming a 30% tax rate, the 2005 taxable equivalent return as a percentage of unit cost would be 13%. (NOTE—Because the units are a depleting asset, a portion of this return is effectively a return of capital.)
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TO UNITHOLDERS
We are pleased to present the 2005 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust’s 2005 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, 2005, net profits income totaled $105,129,321. After adding interest income of $112,642 and deducting trust administration expense of $410,083, distributable income was $104,831,880 or $2.620797 per unit. Net profits income and distributions were 28% higher than 2004 amounts primarily because of higher product prices, partially offset by increased development costs.
Natural gas prices averaged $6.64 per Mcf for 2005, 33% higher than the 2004 average price of $4.99 per Mcf. The average 2005 oil price was $52.27 per Bbl, 37% higher than the 2004 average price of $38.11 per Bbl.
Gas sales volumes from the underlying properties for 2005 were 29,986,698 Mcf, or 82,155 Mcf per day, or a 1% decline from 82,619 Mcf per day in 2004. Oil sales volumes from the underlying properties were 325,193 Bbls, or 891 Bbls per day in 2005, or an increase of 2% from 871 Bbls per day in 2004. For further information on sales volumes and product prices, see “Trustee’s Discussion and Analysis.”
As of December 31, 2005, proved reserves for the underlying properties were estimated by independent engineers to be 443.0 Bcf of natural gas and 3.8 million Bbls of oil. Natural gas and oil reserves for the underlying properties were relatively unchanged from year-end 2004 primarily because production was offset by reserve additions from development activity. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 271.9 Bcf of natural gas and 2.4 million Bbls of oil. Estimated gas and oil reserves attributable to the net profits interests were relatively unchanged from previously reported reserves at year-end 2004, as the increase in allocated reserves related to higher oil and gas prices was offset by a decreased allocation for the effect of deducting overhead costs. 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, 2005 are $2.32 billion, or $58.04 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2005 is $1.11 billion, or $27.81 per unit. Proved reserve estimates and related future net cash flows have been determined based on a year-end average realized gas price of $8.72 per Mcf and a year-end West Texas Intermediate posted oil price of $57.75 per Bbl. Other guidelines used in estimating proved reserves, as prescribed by the Financial Accounting Standards Board, are 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 disclosed in the tax instructions provided to unitholders in February 2006, 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
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, 2005 is approximately 15 years. This index is calculated using total proved reserves and estimated 2006 production for the underlying properties. The projected 2006 production is from proved developed producing reserves as of December 31, 2005. 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 expense, development costs and overhead 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, 2005, 2004 and 2003—Costs.” Total 2005 development costs deducted for the underlying properties were $39.2 million, an increase of 84% from the prior year. XTO Energy has informed the trustee that total 2006 budgeted development costs for the underlying properties are approximately $40 million.
In January 2006, XTO Energy announced that it will consider selling the underlying properties. Statements below regarding 2006 development plans assume that XTO Energy will continue to own and operate the underlying properties.
Hugoton Area
Discovered in 1922, the Hugoton area is one of the largest natural gas producing areas in the United States. During 2005, gas sales volumes from the underlying properties in the Hugoton area were 9.2 Bcf, or approximately 31% 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.
In 2005, XTO Energy successfully drilled four gross (3.2 net) wells in the Hugoton area and continued its restimulation program in the Chase intervals, completing 55 of these restimulations. XTO Energy has informed the trustee that it plans to drill up to ten wells and perform 50 Chase restimulations during 2006. Some of the Chase restimulations involve adding perforations in a tighter interval of the formation that was previously bypassed.
Anadarko Basin
The Anadarko Basin of western Oklahoma was discovered in 1945. Gas sales volumes from the underlying properties in the Anadarko Basin totaled 12.5 Bcf in 2005, or approximately 42% of total sales volumes from the underlying properties. XTO Energy is one of the largest producers in the Ringwood, Northwest Okeene
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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 2005. In Major County, XTO Energy successfully drilled ten gross (6.5 net) wells and performed nine workovers. XTO Energy has informed the trustee that it plans to drill up to 13 wells and perform up to 15 workovers in Major County in 2006. The most significant increase in 2005 new well production occurred in Woodward County, where 12 gross (11.3 net) wells were successfully drilled and completed in the Chester formation and four workovers were performed. XTO Energy has informed the trustee that it plans to drill up to ten wells and perform up to eight workovers in Woodward County during 2006.
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 underlying properties in the Green River Basin were 8.3 Bcf in 2005, or approximately 27% of total sales volumes from the underlying properties.
In 2005, XTO Energy successfully drilled seven gross (seven net) wells and performed ten workovers. XTO Energy plans to perform up to ten workovers and may drill up to ten wells in the Green River Basin during 2006. XTO Energy also plans to further test reduction in pipeline pressure which has recently shown potential for increasing production in the Fontenelle Field.
Estimated Proved Reserves and Future Net Cash Flows
The following are proved reserves of the underlying properties, as estimated by independent engineers, and proved reserves and future net cash flows from proved reserves of the net profits interests, based on an allocation of these reserves, at December 31, 2005:
| | Underlying Properties | | Net Profits Interests | |
| | Proved Reserves(a) | | Proved Reserves(a)(b) | | Future Net Cash Flows | |
| | Gas | | Oil | | Gas | | Oil | | from Proved Reserves(a)(c) | |
(in thousands) | | (Mcf) | | (Bbls) | | (Mcf) | | (Bbls) | | Undiscounted | | Discounted | |
| | | | | | | | | | | | | |
Oklahoma | | 266,975 | | 3,487 | | 172,962 | | 2,263 | | $ | 1,531,533 | | $ | 744,801 | |
Wyoming | | 139,507 | | 157 | | 76,642 | | 86 | | 641,097 | | 291,479 | |
Kansas | | 36,562 | | 137 | | 22,327 | | 84 | | 149,100 | | 76,065 | |
| | | | | | | | | | | | | | | |
TOTAL | | 443,044 | | 3,781 | | 271,931 | | 2,433 | | $ | 2,321,730 | | $ | 1,112,345 | |
(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.
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(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.
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TRUSTEE’S DISCUSSION AND ANALYSIS
Years Ended December 31, 2005, 2004 and 2003
Net profits income for 2005 was $105,129,321, as compared with $81,920,014 for 2004 and $80,687,778 for 2003. The 28% increase in net profits income from 2004 to 2005 is primarily the result of higher product prices, partially offset by increased development costs. The 2% increase in net profits income from 2003 to 2004 was primarily the result of higher product prices, partially offset by increased development costs and lower sales volumes. Over 90% of net profits income in each year was attributable to natural gas sales.
Trust administration expense was $410,083 in 2005 as compared to $357,891 in 2004 and $344,280 in 2003. Increased administration expense has been primarily because of fees related to the audit of the trust’s internal control over financial reporting. Interest income was $112,642 in 2005, $34,797 in 2004 and $29,622 in 2003. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $104,831,880 or $2.620797 per unit in 2005, $81,596,920 or $2.039923 per unit in 2004 and $80,373,120 or $2.009328 per unit in 2003.
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 2004 to 2005, underlying gas sales volumes decreased 1% and underlying oil sales volumes increased 2%. Lower gas sales volumes are primarily because of natural production decline and the timing of cash receipts, partially offset by increased production from new wells and workovers. Oil sales volumes increased primarily because of increased production from new wells and workovers and the timing of cash receipts, partially offset by natural production decline. From 2003 to 2004, underlying oil and gas sales volumes decreased 4% primarily because of natural production decline, partially offset by increased production from new wells and workovers.
Prices
Gas. The 2005 average gas price was $6.64 per Mcf, a 33% increase from the 2004 average gas price of $4.99 per Mcf, which was 10% higher than the 2003 average gas price of $4.54 per Mcf. Since late 2002, gas prices have generally been increasing due primarily to increased demand and declining North American production. These trends accelerated in the second half of 2005 due to the effects of hurricanes on Gulf of Mexico production. During the last half of 2005 and the first two months of 2006, gas prices have ranged from a high in excess of $15.00 per MMBtu to a low of almost $6.50 per MMBtu. Prices will continue to be affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquified natural gas. In any case, natural gas prices are expected to remain volatile. Prices will continue to be affected by weather, the U.S. economy, the level of North American production, crude oil prices and import levels of liquified natural gas. In any case, natural gas prices are expected to remain volatile.
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The trust’s average gas price was $0.75, or 14%, lower than the average NYMEX price of $5.29 in 2003; $0.93, or 16%, lower than the average NYMEX price of $5.92 in 2004; and $1.46, or 18%, lower than the average NYMEX price of $8.10 in 2005. NYMEX prices are generally representative of the price received for gas delivered in the Louisiana Gulf coast region, where demand is higher and supply has been diminished since August 2005 because of the Gulf hurricanes. Because of greater supply and weaker demand in the Mid-Continent and Rocky Mountain regions, where gas from the underlying properties is delivered and sold, trust gas prices have not risen as dramatically as NYMEX prices. This has resulted in a widening decrement between the NYMEX and trust average gas prices. Recent trust gas prices were approximately 25% lower than the NYMEX price. The average NYMEX price for January and February 2006 was $8.37 per MMBtu.
Oil. The average oil price for 2005 was $52.27 per Bbl, 37% higher than the average oil price for 2004 of $38.11 per Bbl, which was 26% higher than the 2003 average oil price of $30.13 per Bbl. Since late 2002, oil prices have generally been rising primarily because of increasing global demand and supply shortage concerns, inadequate refining capacity, reduced production as a result of tropical storms and hurricanes in the Gulf of Mexico and political instability. Oil prices increased to record levels in August 2005, exceeding $70.00 per Bbl. Oil prices are expected to remain volatile. The average NYMEX price for January and February 2006 was $63.67. Recent trust oil prices have averaged approximately $1.70, or 3%, lower than the NYMEX price.
See “Gulf of Mexico Hurricanes” below.
Costs
The calculation of net profits income includes deductions for production expense, 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 expense increased 3% from 2004 to 2005 because of increased fuel costs and 6% from 2003 to 2004 primarily because of the timing of maintenance projects as well as increased fuel costs.
Development. Development costs deducted were $39.2 million in 2005, $21.3 million in 2004 and $12.9 million in 2003. Increased development costs are attributable to the timing of budgeted development projects to benefit from higher gas prices. Development costs have also risen because of limited availability of drilling rigs, supplies and labor during a period of rising demand for these resources.
In 2005, underlying budgeted development costs deducted from distributions totaled $39.2 million, compared with actual development costs of $38.8 million. At December 31, 2005, cumulative budgeted costs deducted exceeded cumulative actual development costs by approximately $114,000. Because of increased development activity and higher costs, the monthly development cost deduction was increased three times in 2005. The deductions were increased to $2.4 million beginning with the February 2005 distribution, to $3.3 million beginning with the July 2005 distribution and to $5.1 million beginning with the October 2005 distribution. Development projects were accelerated in the third and fourth quarter of 2005 because of gas
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supply disruptions and higher prices. With a reduction in development activity in first quarter 2006 and based on the development budget for 2006, the development cost deduction was lowered to $3.3 million beginning with the January 2006 distribution. XTO Energy has advised the trustee that this monthly deduction is expected to be maintained at least through the March 2006 distribution, but will be evaluated and revised as necessary.
Overhead. Overhead is charged by XTO Energy for administrative expenses incurred to support operations of 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.
Litigation Settlement
In July 2003, XTO Energy 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 2003 by $832,665, or $0.021 per unit.
Gulf of Mexico Hurricanes
In late August and September 2005, hurricanes in the Gulf of Mexico disrupted a significant portion of U.S. oil and gas production, leading to higher and more volatile commodity prices. These increased prices began affecting distributions to unitholders beginning with the November 2005 distribution that was paid in December 2005. The underlying properties to the trust are not located near the Gulf and related production was not significantly affected. However, because of greater supply and weaker demand in areas where trust related oil and gas is produced, the price received for such production has been significantly lower than the price received for Gulf production or NYMEX prices. Production expense and development costs have increased throughout the industry because of storm damages and related supply shortages.
Fourth Quarter 2005 and 2004
During fourth quarter 2005 the trust received net profits income totaling $32,018,800 compared with fourth quarter 2004 net profits income of $21,051,715. The 52% increase in net profits income from fourth quarter 2004 to 2005 was primarily because of higher product prices and sales volumes, partially offset by higher development costs.
Administration expense was $62,453 and interest income was $41,133, resulting in fourth quarter 2005 distributable income of $31,997,480, or $0.799937 per unit. Distributable income for fourth quarter 2004 was $21,012,760 or $0.525319 per unit. Distributions to unitholders for the quarter ended December 31, 2005 were:
Record Date | | Payment Date | | Per Unit | |
October 31, 2005 | | November 15, 2005 | | $ | 0.188586 | |
November 30, 2005 | | December 14, 2005 | | 0.273244 | |
December 30, 2005 | | January 17, 2006 | | 0.338107 | |
| | | | $ | 0.799937 | |
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Volumes
Fourth quarter underlying gas and oil sales volumes increased 2% from 2004 to 2005. Increased volumes are primarily because of increased production from new wells and workovers, partially offset by natural production decline and the timing of cash receipts.
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Prices
The average fourth quarter 2005 gas price was $8.24 per Mcf, or 61% higher than the fourth quarter 2004 average price of $5.11 per Mcf. The average fourth quarter oil price was $60.80 per Bbl, or 30% higher than the fourth quarter 2004 average price of $46.73 per Bbl. For further information about product prices, see “Years Ended December 31, 2005, 2004 and 2003—Prices” above.
Costs
Taxes, transportation and other. Taxes, transportation and other generally fluctuates with changes in total revenues.
Production. Fourth quarter production expense increased 21% from 2004 to 2005 primarily because of the timing of maintenance projects and increased fuel costs.
Development. Development costs, which were deducted based on budgeted development costs, increased 155% from fourth quarter 2004 to 2005 because of increased development activity and higher costs.
Overhead. Overhead increased 4% from fourth quarter 2004 to 2005 primarily because of the annual rate adjustment based on an oil and gas industry index.
For further information about costs, see “Years Ended December 31, 2005, 2004 and 2003—Costs” above.
See Item 7 of the accompanying Form 10-K for disclosures regarding liquidity and capital resources, off-balance sheet arrangements, 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:
| | | | | | | | Three Months | |
| | Year Ended December 31(a) | | Ended December 31(a) | |
| | 2005 | | 2004 | | 2003 | | 2005 | | 2004 | |
Sales Volumes | | | | | | | | | | | |
Gas (Mcf)(b) | | | | | | | | | | | |
Underlying properties | | 29,986,698 | | 30,238,663 | | 31,490,564 | | 7,644,787 | | 7,506,690 | |
Average per day | | 82,155 | | 82,619 | | 86,276 | | 83,096 | | 81,594 | |
Net profits interests | | 15,836,681 | | 16,462,378 | | 17,832,189 | | 3,802,922 | | 4,064,480 | |
| | | | | | | | | | | |
Oil (Bbls)(b) | | | | | | | | | | | |
Underlying properties | | 325,193 | | 318,694 | | 331,867 | | 79,788 | | 78,329 | |
Average per day | | 891 | | 871 | | 909 | | 867 | | 851 | |
Net profits interests | | 177,980 | | 184,487 | | 196,005 | | 46,056 | | 46,350 | |
| | | | | | | | | | | |
Average Sales Prices | | | | | | | | | | | |
Gas (per Mcf) | | $ | 6.64 | | $ | 4.99 | | $ | 4.54 | | $ | 8.24 | | $ | 5.11 | |
Oil (per Bbl) | | $ | 52.27 | | $ | 38.11 | | $ | 30.13 | | $ | 60.80 | | $ | 46.73 | |
| | | | | | | | | | | |
Revenues | | | | | | | | | | | |
Gas sales | | $ | 198,985,047 | | $ | 151,041,142 | | $ | 142,846,720 | | $ | 63,029,136 | | $ | 38,383,949 | |
Oil sales | | 16,997,457 | | 12,144,887 | | 9,999,958 | | 4,851,445 | | 3,660,414 | |
Total Revenues | | 215,982,504 | | 163,186,029 | | 152,846,678 | | 67,880,581 | | 42,044,363 | |
| | | | | | | | | | | |
Costs | | | | | | | | | | | |
Taxes, transportation and other | | 19,113,977 | | 14,029,943 | | 13,552,224 | | 5,583,726 | | 3,699,487 | |
Production expense | | 18,468,101 | | 17,893,352 | | 16,889,700 | | 4,979,279 | | 4,120,919 | |
Development costs(c) | | 39,200,000 | | 21,300,000 | | 12,949,343 | | 15,300,000 | | 6,000,000 | |
Overhead | | 7,788,775 | | 7,562,716 | | 7,556,090 | | 1,994,076 | | 1,909,313 | |
Litigation | | — | | — | | 1,040,831 | | — | | — | |
Total Costs | | 84,570,853 | | 60,786,011 | | 51,988,188 | | 27,857,081 | | 15,729,719 | |
| | | | | | | | | | | |
Other Proceeds | | | | | | | | | | | |
Property sales | | — | | — | | 1,232 | | — | | — | |
| | | | | | | | | | | |
Net Proceeds | | 131,411,651 | | 102,400,018 | | 100,859,722 | | 40,023,500 | | 26,314,644 | |
| | | | | | | | | | | |
Net Profits Percentage | | 80 | % | 80 | % | 80 | % | 80 | % | 80 | % |
| | | | | | | | | | | |
Net Profits Income | | $ | 105,129,321 | | $ | 81,920,014 | | $ | 80,687,778 | | $ | 32,018,800 | | $ | 21,051,715 | |
(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 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 expense and development costs. Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests. Therefore, comparative discussion of oil and gas sales volumes is based on the underlying properties.
(c) See Note 4 to Financial Statements.
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HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| | December 31 | |
| | 2005 | | 2004 | |
Assets | | | | | |
| | | | | |
Cash and short-term investments | | $ | 13,524,280 | | $ | 6,947,520 | |
| | | | | |
Net profits interests in oil and gas properties—net (Notes 1 and 2) | | 171,935,330 | | 182,551,814 | |
| | | | | |
| | $ | 185,459,610 | | $ | 189,499,334 | |
| | | | | |
Liabilities and Trust Corpus | | | | | |
| | | | | |
Distribution payable to unitholders | | $ | 13,524,280 | | $ | 6,947,520 | |
| | | | | |
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) | | 171,935,330 | | 182,551,814 | |
| | | | | |
| | $ | 185,459,610 | | $ | 189,499,334 | |
STATEMENTS OF DISTRIBUTABLE INCOME
| | Year Ended December 31 | |
| | 2005 | | 2004 | | 2003 | |
| | | | | | | |
Net profits income | | $ | 105,129,321 | | $ | 81,920,014 | | $ | 80,687,778 | |
| | | | | | | |
Interest income | | 112,642 | | 34,797 | | 29,622 | |
| | | | | | | |
Total income | | 105,241,963 | | 81,954,811 | | 80,717,400 | |
| | | | | | | |
Administration expense | | 410,083 | | 357,891 | | 344,280 | |
| | | | | | | |
Distributable income | | $ | 104,831,880 | | $ | 81,596,920 | | $ | 80,373,120 | |
| | | | | | | |
Distributable income per unit (40,000,000 units) | | $ | 2.620797 | | $ | 2.039923 | | $ | 2.009328 | |
See Accompanying Notes to Financial Statements.
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HUGOTON ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
| | Year Ended December 31 | |
| | 2005 | | 2004 | | 2003 | |
| | | | | | | |
Trust corpus, beginning of year | | $ | 182,551,814 | | $ | 193,245,847 | | $ | 205,493,243 | |
| | | | | | | |
Amortization of net profits interests | | (10,616,484 | ) | (10,694,033 | ) | (12,247,396 | ) |
| | | | | | | |
Distributable income | | 104,831,880 | | 81,596,920 | | 80,373,120 | |
| | | | | | | |
Distributions declared | | (104,831,880 | ) | (81,596,920 | ) | (80,373,120 | ) |
| | | | | | | |
Trust corpus, end of year | | $ | 171,935,330 | | $ | 182,551,814 | | $ | 193,245,847 | |
See Accompanying Notes to Financial Statements.
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Hugoton Royalty Trust
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, XTO Energy received 40 million units of beneficial interest in the trust. 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. See Note 6.
Bank of America, N.A. is the trustee for the trust. The trust indenture provides, among other provisions, that:
• the trust cannot engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments;
• 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;
• the trustee may establish a cash reserve for payment of any liability that is contingent or not currently payable;
• the trustee may borrow funds to pay trust liabilities if repaid in full prior to further distributions to unitholders;
• the trustee will make monthly cash distributions to unitholders (Note 3); and
• the trust will terminate upon the first occurrence of:
• disposition of all net profits interests pursuant to terms of the trust indenture,
• gross proceeds from the underlying properties falling below $1 million per year for two successive years, or
• 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 U.S. generally accepted accounting principles:
• Net profits income is recorded in the month received by the trustee (Note 3).
• 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 (Note 3).
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The most significant differences between the trust’s financial statements and those prepared in accordance with U.S. generally accepted accounting principles are:
• Net profits income is recognized in the month received rather than accrued in the month of production.
• Expenses are recognized when paid rather than when incurred.
• Cash reserves may be established by the trustee for contingencies that would not be recorded under generally accepted accounting principles.
This comprehensive basis of accounting other than U.S. generally accepted accounting principles corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.
Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with U.S. generally accepted accounting principles, directing such entities to accrue or defer revenues and expenses in a period other than when such revenues were received or expenses were paid. Because the trust’s financial statements are prepared on the modified cash basis, as described above, most accounting pronouncements are not applicable to the trust’s financial statements.
The initial carrying value of the net profits interests of $247,066,951 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 $75,131,621 as of December 31, 2005 and $64,515,137 as of December 31, 2004.
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 expense, development and drilling costs, and overhead (Note 6).
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the three conveyances (one for each of the states of Kansas, Oklahoma and Wyoming). 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, budgeted development costs deducted in the calculation of net profits income, and the cumulative actual costs compared to the amount deducted:
| | Development Costs | |
| | Year Ended December 31 | |
| | 2005 | | 2004 | | 2003 | |
Cumulative actual costs (over) under the amount deducted—beginning of period | | $ | (319,927 | ) | $ | (1,583,988 | ) | $ | 3,089,563 | |
Actual costs | | (38,766,168 | ) | (20,035,939 | ) | (17,622,894 | ) |
Budgeted costs deducted | | 39,200,000 | | 21,300,000 | | 12,949,343 | |
Cumulative actual costs (over) under the amount deducted—end of period | | $ | 113,905 | | $ | (319,927 | ) | $ | (1,583,988 | ) |
The monthly development deduction was $2 million in January 2005, but was increased three times during 2005 as a result of increased development activity and higher costs. The deductions were increased to $2.4 million beginning with the February distribution, to $3.3 million beginning with the July distribution and to $5.1 million beginning with the October distribution. With a reduction in development activity in first quarter 2006 and based on the development budget for 2006, the development cost deduction was lowered to $3.3 million beginning with the January 2006 distribution. XTO Energy has advised the trustee that this monthly deduction is expected to be maintained at least through the March 2006 distribution, but will be evaluated and revised as necessary.
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.
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, 2005, the overhead charge was approximately $666,000 ($532,800 net to the trust) per month and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement.
As of December 31, 2005, XTO Energy owned 54.3% of the trust. In January 2006, the Board of Directors of XTO Energy declared a dividend of all of the 21.7 million trust units it owns. These units are to be distributed on May 12, 2006 to XTO Energy’s common stockholders of record on April 26, 2006. After this dividend, XTO Energy will not be a unitholder of the trust. XTO Energy also announced in January 2006 that it will consider selling the underlying properties. Any sale is dependent upon XTO Energy’s ability to structure a tax-efficient transaction and receive sufficient consideration from a buyer it deems to be qualified.
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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”) based on the index price. 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 $107.9 million for the year ended December 31, 2005, or 54% of total gas sales, $81.7 million for the year ended December 31, 2004, or 54% of total gas sales and $76.5 million for the year ended December 31, 2003, or 54% of total gas sales.
7. Contingencies
Litigation
On October 17, 1997, an action, styled United States of America ex rel. Grynberg v. Cross Timbers Oil Company, et al., was filed in the United States District Court for the Western District of Oklahoma by Jack J. Grynberg on behalf of the United States under the qui tam provisions of the U.S. False Claims Act against XTO Energy. The plaintiff 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, incorrectly analyzing its heating content and improperly valuing the natural gas during at least the past ten years. The plaintiff seeks treble damages for the unpaid royalties (with interest, attorney’s fees and expenses), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. This lawsuit against XTO Energy and similar lawsuits filed by Grynberg against more than 300 other companies have been consolidated in the United States District Court for Wyoming. In October 2002, the court granted a motion to dismiss Grynberg’s royalty valuation claims, and Grynberg’s appeal of this decision was dismissed for lack of appellate jurisdiction in May 2003. The parties have completed discovery regarding whether the plaintiff has met the jurisdictional prerequisites for maintaining an action under the U.S. False Claims Act. In June 2004, XTO Energy joined with other defendants in filing a motion to dismiss, contending that the plaintiff has not satisfied the jurisdictional requirements to maintain this action. A hearing on this motion occurred in March 2005, and in May 2005, the special master, who was appointed by the district judge to expedite matters and make recommendations to the district judge in the case, issued a report and recommendation to dismiss the case against some of the defendants but to retain jurisdiction of the case involving XTO Energy and other defendants. XTO Energy and the other defendants filed motions to modify the special master’s report, requesting the district judge to also dismiss the case as to XTO Energy and other defendants. The district judge heard oral arguments on December 9, 2005, as to all motions seeking adoption, modification or reversal of the special master’s report, and XTO Energy is awaiting the decision of the district court. 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 underlying 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.
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Other
Several states have enacted legislation to require state income tax withholding from nonresident recipients of oil and gas proceeds. After consultation with its state tax counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, regulations are subject to change by the various states, which could change this conclusion. In the event it is determined that the trust is required to withhold state taxes, distributions to the unitholders would be reduced by the required amount, subject to the unitholder’s right to file a state tax return to claim any refund due.
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 2005 and 2004:
| | | | | | Distributable | |
| | Net Profits | | Distributable | | Income | |
| | Income | | Income | | per Unit | |
2005 | | | | | | | |
First Quarter | | $ | 25,818,940 | | $ | 25,698,160 | | $ | 0.642454 | |
Second Quarter | | 22,965,660 | | 22,832,040 | | 0.570801 | |
Third Quarter | | 24,325,921 | | 24,304,200 | | 0.607605 | |
Fourth Quarter | | 32,018,800 | | 31,997,480 | | 0.799937 | |
| | $ | 105,129,321 | | $ | 104,831,880 | | $ | 2.620797 | |
2004 | | | | | | | |
First Quarter | | $ | 19,057,231 | | $ | 18,976,760 | | $ | 0.474419 | |
Second Quarter | | 18,289,557 | | 18,178,560 | | 0.454464 | |
Third Quarter | | 23,521,511 | | 23,428,840 | | 0.585721 | |
Fourth Quarter | | 21,051,715 | | 21,012,760 | | 0.525319 | |
| | $ | 81,920,014 | | $ | 81,596,920 | | $ | 2.039923 | |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005. 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 the standards of the Public Company Accounting Oversight Board (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, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements have been 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 financial statements referred to above present fairly, in all material respects, the assets, liabilities, and trust corpus of the Hugoton Royalty Trust as of December 31, 2005 and 2004 and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005 in conformity with the modified cash basis of accounting described in Note 2.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Hugoton Royalty Trust’s internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 16, 2006 expressed an unqualified opinion on the trustee’s assessment of, and the effective operation of, internal control over financial reporting.
KPMG LLP
Dallas, Texas
March 16, 2006
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:
We have audited the trustee’s assessment, included in Trustee’s Report on Internal Control over Financial Reporting under Item 9A of the accompanying Annual Report on Form 10-K, that Hugoton Royalty Trust maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of the Hugoton Royalty Trust is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the trustee’s assessment and an opinion on the effectiveness of the trust’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
The trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting. The trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the trustee’s assessment that Hugoton Royalty Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Also, in our opinion, Hugoton Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities, and trust corpus of the Hugoton Royalty Trust as
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of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2005, and our report dated March 16, 2006 expressed an unqualified opinion on those financial statements and included an explanatory paragraph that described the trust’s method of accounting as explained in Note 2 to the financial statements.
KPMG LLP
Dallas, Texas
March 16, 2006
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HUGOTON ROYALTY TRUST
901 Main Street, 17th 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 or from the trust’s web site at www.hugotontrust.com.
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.
www.melloninvestor.com
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