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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 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 2004 and 2003:
| | Sales Price
| |
|
|---|
Quarter
| | Distributions
per Unit
|
|---|
| | High
| | Low
|
|---|
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 |
| | | | | | | | |
|
2003
|
|
|
|
|
|
|
|
|
|
| First | | $ | 15.35 | | $ | 12.30 | | $ | 0.409139 |
| Second | | | 20.89 | | | 13.51 | | | 0.613451 |
| Third | | | 19.17 | | | 17.02 | | | 0.534452 |
| Fourth | | | 23.33 | | | 18.77 | | | 0.452286 |
| | | | | | | | |
|
| | | | | | | | | $ | 2.009328 |
| | | | | | | | |
|
At December 31, 2004, there were 40,000,000 units outstanding and approximately 193 unitholders of record; 17,593,122 of these units were held by depository institutions. As of February 28, 2005, 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.
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 tax 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 2004 and held them throughout 2004 would be entitled to a cost depletion deduction of approximately 6% of his cost. Assuming a cost of $21.00 per unit, cost depletion would offset approximately 58% of 2004 taxable trust income. Assuming a 30% tax rate, the 2004 taxable equivalent return as a percentage of unit cost would be 12%. (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 2004 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust's 2004 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, 2004, net profits income totaled $81,920,014. After adding interest income of $34,797 and deducting trust administration expense of $357,891, distributable income was $81,596,920 or $2.039923 per unit. Net profits income and distributions were 2% higher than 2003 amounts primarily because of higher product prices, partially offset by increased production expense and development costs and lower sales volumes.
Natural gas prices averaged $4.99 per Mcf for 2004, 10% higher than the 2003 average price of $4.54 per Mcf. The average 2004 oil price was $38.11 per Bbl, 26% higher than the 2003 average price of $30.13 per Bbl.
Gas sales volumes from the underlying properties for 2004 were 30,238,663 Mcf, or 82,619 Mcf per day, or a 4% decline from 86,276 Mcf per day in 2003. Oil sales volumes from the underlying properties were 318,694 Bbls, or 871 Bbls per day in 2004, or a decline of 4% from 909 Bbls per day in 2003. For further information on sales volumes and product prices, see "Trustee's Discussion and Analysis."
As of December 31, 2004, proved reserves for the underlying properties were estimated by independent engineers to be 443.9 Bcf of natural gas and 3.8 million Bbls of oil. Natural gas reserves for the underlying properties declined 4% from year-end 2003 to 2004 primarily because of production, partially offset by reserve additions from drilling activity. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 272.3 Bcf of natural gas and 2.4 million Bbls of oil. Estimated gas reserves attributable to the net profits interests decreased 8% from year-end 2003 to 2004 primarily because of production and a reduced allocation of reserves to the net profits interests because of increased production expense and development costs. Oil reserves attributable to the net profits interests remained flat from year-end 2003 to 2004 as increased reserves from development activity and discoveries were offset by production. 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, 2004 are $1.51 billion, or $37.80 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2004 is $743.5 million, or $18.59 per unit. Proved reserve estimates and related future net cash flows have been determined based on a year-end average realized gas price of $5.68 per Mcf and a year-end West Texas Intermediate posted oil price of $40.25 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 January 2005, 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
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, 2004 is approximately 15 years. This index is calculated using total proved reserves and estimated 2005 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 95% 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, 2004, 2003 and 2002—Costs." Total 2004 development costs deducted for the underlying properties were $21.3 million, an increase of 64% from the prior year. XTO Energy has informed the trustee that total 2005 budgeted development costs for the underlying properties are approximately $30 million.
Hugoton Area
Discovered in 1922, the Hugoton area is one of the largest domestic natural gas producing areas. During 2004, gas sales volumes from the Hugoton area were 9.9 Bcf, or approximately 33% 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. During 2004, a successful well was drilled to the Morrow and Chester horizons and an additional well is planned in 2005. XTO Energy has participated in 3-D seismic shoots covering 30,000 acres of its net acreage position beneath the Chase formation.
XTO Energy continued its restimulation program in the Chase intervals, completing 27 of these restimulations in 2004. XTO Energy has informed the trustee that it plans to perform 50 Chase restimulations during 2005. 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 Anadarko Basin totaled 12.6 Bcf in 2004, or approximately 42% 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 2004. In Major County, XTO Energy successfully drilled 12 gross (8.6 net) wells and performed seven workovers. XTO Energy has informed the trustee that it plans to drill up to eight wells and perform up to ten workovers in Major County in 2005. The most significant increase in 2004 new well production occurred in Woodward County, where eight gross (7.4 net) wells were successfully drilled and completed in the Chester formation and two workovers were performed. XTO Energy has informed the trustee that it plans to drill up to ten wells and perform up to five workovers in Woodward County during 2005.
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 7.7 Bcf in 2004, or approximately 25% of total sales volumes from the underlying properties.
In 2004, XTO Energy successfully drilled seven gross (seven net) wells and performed 13 workovers. XTO Energy plans to perform up to seven workovers and may drill up to ten wells in the Green River Basin during 2005. 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, 2004:
| | Underlying Properties
| | Net Profits Interests
|
|---|
| | Proved Reserves(a)
| | Proved Reserves(a)(b)
| | Future Net Cash Flows
from Proved Reserves(a)(c)
|
|---|
| | Gas
(Mcf)
| | Oil
(Bbls)
| | Gas
(Mcf)
| | Oil
(Bbls)
|
|---|
| | Undiscounted
| | Discounted
|
|---|
(in thousands)
| |
| |
| |
| |
| |
| |
|
|---|
| Oklahoma | | 273,499 | | 3,482 | | 176,687 | | 2,249 | | $ | 1,022,581 | | $ | 510,882 |
| Wyoming | | 133,086 | | 167 | | 73,517 | | 92 | | | 395,811 | | | 183,201 |
| Kansas | | 37,348 | | 144 | | 22,106 | | 86 | | | 93,615 | | | 49,386 |
| | |
| |
| |
| |
| |
| |
|
| | TOTAL | | 443,933 | | 3,793 | | 272,310 | | 2,427 | | $ | 1,512,007 | | $ | 743,469 |
| | |
| |
| |
| |
| |
| |
|
- (a)
- Based on year-end oil and gas prices. For further information regarding proved reserves and the method of allocation of proved reserves to the net profits interests, 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.
TRUSTEE'S DISCUSSION AND ANALYSIS
Years Ended December 31, 2004, 2003 and 2002
Net profits income for 2004 was $81,920,014, as compared with $80,687,778 for 2003 and $29,934,195 for 2002. The 2% increase in net profits income from 2003 to 2004 is primarily the result of higher product prices, partially offset by increased production expense and development costs and lower sales volumes. The 170% increase in net profits income from 2002 to 2003 was primarily caused by gas price fluctuations. Over 90% of net profits income in each year was attributable to natural gas sales.
Trust administration expense was $357,891 in 2004 as compared to $344,280 in 2003 and $376,790 in 2002. Higher administration expense in 2002 was primarily because of the timing of stock exchange listing fee payments. Interest income was $34,797 in 2004, $29,622 in 2003 and $14,955 in 2002. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $81,596,920 or $2.039923 per unit in 2004, $80,373,120 or $2.009328 per unit in 2003 and $29,572,360 or $0.739309 per unit in 2002.
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 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. From 2002 to 2003, underlying gas sales volumes decreased 8% and underlying oil sales volumes decreased 6% primarily because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers and the effect of prior period volume adjustments recorded in 2002.
Prices
Gas. The 2004 average gas price was $4.99 per Mcf, a 10% increase from the 2003 average gas price of $4.54 per Mcf, which was 86% higher than the 2002 average gas price of $2.44 per Mcf. The warm winter of 2001-2002 resulted in higher than average gas storage levels and lower gas prices in 2002. Prices climbed late in 2002 as a result of lower drilling activity, increased industrial demand, colder weather and international instability. Colder than normal weather, record low gas storage levels and additional demand caused gas prices to remain relatively high during the first five months of 2003. With diminished demand related to higher prices, natural gas prices were lower during the summer months, then rose with cooler weather in the fall and early winter. Forecasted production declines, increased demand and unexpected storage withdrawals supported higher prices in the first six months of 2004. Mild summer weather and increased gas storage led to declining gas prices in August and early September. Natural gas prices rose again in mid-September because of reduced gas production as a result of hurricanes in the Gulf of Mexico. Gas prices remained relatively high for the remainder of 2004 because of sporadic colder weather and lower gas supplies. With moderate temperatures and favorable supply, prices were lower in January 2005, but rose in February as a result of colder weather in the U.S. Northeast. Prices will continue to be affected by weather, the U.S. economy, changes in the level of North American production and import levels of liquified natural gas. In any case, natural gas prices are expected to remain volatile. The average NYMEX price for January and February 2005 was $6.20 per MMBtu.
The trust's average gas price was $0.64 lower than the average NYMEX price of $3.08 in 2002, $0.75 lower than the average NYMEX price of $5.29 in 2003 and $0.93 lower than the average NYMEX price of $5.92 in 2004. Despite the increasing differential from 2002 to 2004, trust average gas sales prices improved in the second half of 2003 because of higher prices received for Wyoming production. These improved prices are attributable to completion of a pipeline expansion project in May 2003, increasing capacity to western markets. An eastbound pipeline began operations in December 2004, which should further improve Rocky Mountain prices.
Oil. The average oil price for 2004 was $38.11 per Bbl, 26% higher than the average oil price for 2003 of $30.13 per Bbl, which was 27% higher than the 2002 average oil price of $23.70 per Bbl. Oil prices were lower early in 2002 because of lagging demand caused by a global recession. Rising uncertainties in the Middle East led to higher prices late in 2002. During 2003, unusually low storage levels, the war in Iraq and production discipline by OPEC maintained oil prices at relatively high levels. Oil prices continued to increase in 2004 because of increasing demand and low crude stocks. Despite increased production by OPEC members, oil prices exceeded $55 per Bbl in October 2004 because of continued instability in the Middle East and Nigeria and hurricanes in the Gulf of Mexico. With mild winter weather and an ample supply of oil stocks, prices declined in late 2004 but rebounded in January and February 2005 following global supply outages, colder weather in the U.S. Northeast and Europe and continued disruptions of Iraqi exports. The average NYMEX price for January and February 2005 was $47.49. Recent trust oil prices have averaged approximately $0.70 lower than the NYMEX price.
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 6% from 2003 to 2004 primarily because of increased maintenance, fuel and labor costs. Production expense increased 5% from 2002 to 2003 primarily because of higher fuel costs.
Development. Development costs deducted were $21.3 million in 2004, $12.9 million in 2003 and $22.7 million in 2002. The increase from 2003 to 2004 is attributable to the timing of budgeted development projects and an increased number of wells drilled. The decrease from 2002 to 2003 is attributable to the timing of budgeted development projects, billings and expenditures.
In 2004, budgeted development costs deducted from distributions totaled $21.3 million, compared with actual development costs of $20 million. As a result, cumulative actual development costs in excess of deducted costs was reduced from $1.6 million at December 31, 2003 to $320,000 at December 31, 2004. See Note 4 to Financial Statements. The monthly development cost deduction was $1.7 million throughout 2004 until it was increased to $2 million beginning with the October 2004 distribution because of increased drilling in Oklahoma. Because of continued development activity and based on the development cost budget for calendar year 2005, the monthly development cost deduction was increased to $2.4 million beginning with the February 2005 distribution. XTO Energy has advised the trustee that this increased monthly deduction will be reevaluated in conjunction with the 2005 development budget and revised as necessary.
Overhead. Overhead is charged by XTO Energy for reimbursement of 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 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.
Fourth Quarter 2004 and 2003
During fourth quarter 2004 the trust received net profits income totaling $21,051,715, compared with fourth quarter 2003 net profits income of $18,148,172. The 16% increase in net profits income from fourth quarter 2003 to 2004 was primarily because of higher product prices, partially offset by higher development costs and lower sales volumes.
Administration expense was $53,596 and interest income was $14,641, resulting in fourth quarter 2004 distributable income of $21,012,760, or $0.525319 per unit. Distributable income for fourth quarter 2003 was $18,091,440 or $0.452286 per unit. Distributions to unitholders for the quarter ended December 31, 2004 were:
Record Date
| | Payment Date
| | Per Unit
|
|---|
| October 29, 2004 | | November 15, 2004 | | $ | 0.201158 |
| November 30, 2004 | | December 14, 2004 | | | 0.150473 |
| December 31, 2004 | | January 14, 2005 | | | 0.173688 |
| | | | |
|
| | | | | $ | 0.525319 |
| | | | |
|
Volumes
Fourth quarter underlying gas sales volumes decreased 3% and underlying oil sales volumes decreased 7% from 2003 to 2004. Decreased volumes are primarily because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers.
Prices
The average fourth quarter 2004 gas price was $5.11 per Mcf, or 18% higher than the fourth quarter 2003 average price of $4.33 per Mcf. The average fourth quarter oil price was $46.73 per Bbl, or 58% higher than the fourth quarter 2003 average price of $29.62 per Bbl. For further information about product prices, see "Years Ended December 31, 2004, 2003 and 2002—Prices" above.
Costs
Taxes. Taxes, transportation and other increased 14% for the quarter, approximating the 16% increase in total revenues.
Production. Fourth quarter production expense decreased 3% from 2003 to 2004 primarily because of decreased costs related to the timing of payments.
Development. Development costs, which were deducted based on budgeted development costs, increased 45% from fourth quarter 2003 to 2004 because of increased drilling in Oklahoma.
Overhead. Overhead increased 5% from fourth quarter 2003 to 2004 primarily because of adjustments in 2003 related to prior periods and the annual inflation adjustment.
For further information about costs, see "Years Ended December 31, 2004, 2003 and 2002—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.
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)
| |
|---|
| | 2004
| | 2003
| | 2002
| | 2004
| | 2003
| |
|---|
| Sales Volumes | | | | | | | | | | | | | | | | |
| | Gas (Mcf)(b) | | | | | | | | | | | | | | | | |
| | | Underlying properties | | | 30,238,663 | | | 31,490,564 | | | 34,315,145 | | | 7,506,690 | | | 7,760,757 | |
| | | | Average per day | | | 82,619 | | | 86,276 | | | 94,014 | | | 81,594 | | | 84,356 | |
| | | Net profits interests | | | 16,462,378 | | | 17,832,189 | | | 11,774,205 | | | 4,064,480 | | | 4,214,990 | |
| |
Oil (Bbls)(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | | Underlying properties | | | 318,694 | | | 331,867 | | | 353,185 | | | 78,329 | | | 84,629 | |
| | | | Average per day | | | 871 | | | 909 | | | 968 | | | 851 | | | 920 | |
| | | Net profits interests | | | 184,487 | | | 196,005 | | | 123,142 | | | 46,350 | | | 52,673 | |
Average Sales Prices |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Gas (per Mcf) | | $ | 4.99 | | $ | 4.54 | | $ | 2.44 | | $ | 5.11 | | $ | 4.33 | |
| | Oil (per Bbl) | | $ | 38.11 | | $ | 30.13 | | $ | 23.70 | | $ | 46.73 | | $ | 29.62 | |
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Gas sales | | $ | 151,041,142 | | $ | 142,846,720 | | $ | 83,610,392 | | $ | 38,383,949 | | $ | 33,618,018 | |
| | Oil sales | | | 12,144,887 | | | 9,999,958 | | | 8,369,027 | | | 3,660,414 | | | 2,506,975 | |
| | |
| |
| |
| |
| |
| |
| | | Total Revenues | | | 163,186,029 | | | 152,846,678 | | | 91,979,419 | | | 42,044,363 | | | 36,124,993 | |
| | |
| |
| |
| |
| |
| |
Costs |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Taxes, transportation and other | | | 14,029,943 | | | 13,552,224 | | | 8,228,963 | | | 3,699,487 | | | 3,238,208 | |
| | Production expense | | | 17,893,352 | | | 16,889,700 | | | 16,107,467 | | | 4,120,919 | | | 4,233,568 | |
| | Development costs(c) | | | 21,300,000 | | | 12,949,343 | | | 22,733,333 | | | 6,000,000 | | | 4,150,000 | |
| | Overhead | | | 7,562,716 | | | 7,556,090 | | | 7,551,912 | | | 1,909,313 | | | 1,818,752 | |
| | Litigation | | | — | | | 1,040,831 | | | — | | | — | | | — | |
| | |
| |
| |
| |
| |
| |
| | | Total Costs | | | 60,786,011 | | | 51,988,188 | | | 54,621,675 | | | 15,729,719 | | | 13,440,528 | |
| | |
| |
| |
| |
| |
| |
Other Proceeds |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| | Property sales | | | — | | | 1,232 | | | 60,000 | | | — | | | 750 | |
| | |
| |
| |
| |
| |
| |
Net Proceeds |
|
|
102,400,018 |
|
|
100,859,722 |
|
|
37,417,744 |
|
|
26,314,644 |
|
|
22,685,215 |
|
Net Profits Percentage |
|
|
80 |
% |
|
80 |
% |
|
80 |
% |
|
80 |
% |
|
80 |
% |
| | |
| |
| |
| |
| |
| |
Net Profits Income |
|
$ |
81,920,014 |
|
$ |
80,687,778 |
|
$ |
29,934,195 |
|
$ |
21,051,715 |
|
$ |
18,148,172 |
|
| | |
| |
| |
| |
| |
| |
- (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.
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| |
| | December 31
|
|---|
| |
| | 2004
| | 2003
|
|---|
| Assets | | | | | | | | |
| |
Cash and short-term investments |
|
|
|
$ |
6,947,520 |
|
$ |
5,706,240 |
| |
Net profits interests in oil and gas properties—net (Notes 1 and 2) |
|
|
|
|
182,551,814 |
|
|
193,245,847 |
| | | | |
| |
|
|
|
|
|
$ |
189,499,334 |
|
$ |
198,952,087 |
| | | | |
| |
|
Liabilities and Trust Corpus |
|
|
|
|
|
|
|
|
| |
Distribution payable to unitholders |
|
|
|
$ |
6,947,520 |
|
$ |
5,706,240 |
| |
Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) |
|
|
|
|
182,551,814 |
|
|
193,245,847 |
| | | | |
| |
|
|
|
|
|
$ |
189,499,334 |
|
$ |
198,952,087 |
| | | | |
| |
|
STATEMENTS OF DISTRIBUTABLE INCOME
| | Year Ended December 31
|
|---|
| | 2004
| | 2003
| | 2002
|
|---|
| Net profits income | | $ | 81,920,014 | | $ | 80,687,778 | | $ | 29,934,195 |
Interest income |
|
|
34,797 |
|
|
29,622 |
|
|
14,955 |
| | |
| |
| |
|
| |
Total income |
|
|
81,954,811 |
|
|
80,717,400 |
|
|
29,949,150 |
Administration expense |
|
|
357,891 |
|
|
344,280 |
|
|
376,790 |
| | |
| |
| |
|
| |
Distributable income |
|
$ |
81,596,920 |
|
$ |
80,373,120 |
|
$ |
29,572,360 |
| | |
| |
| |
|
| |
Distributable income per unit (40,000,000 units) |
|
$ |
2.039923 |
|
$ |
2.009328 |
|
$ |
0.739309 |
| | |
| |
| |
|
See Accompanying Notes to Financial Statements.
HUGOTON ROYALTY TRUST
STATEMENTS OF CHANGES IN TRUST CORPUS
| | Year Ended December 31
| |
|---|
| | 2004
| | 2003
| | 2002
| |
|---|
| Trust corpus, beginning of year | | $ | 193,245,847 | | $ | 205,493,243 | | $ | 215,346,192 | |
Amortization of net profits interests |
|
|
(10,694,033 |
) |
|
(12,247,396 |
) |
|
(9,852,949 |
) |
Distributable income |
|
|
81,596,920 |
|
|
80,373,120 |
|
|
29,572,360 |
|
Distributions declared |
|
|
(81,596,920 |
) |
|
(80,373,120 |
) |
|
(29,572,360 |
) |
| | |
| |
| |
| |
Trust corpus, end of year |
|
$ |
182,551,814 |
|
$ |
193,245,847 |
|
$ |
205,493,243 |
|
| | |
| |
| |
| |
See Accompanying Notes to Financial Statements.
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.
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 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).
The most significant differences between the trust's financial statements and those prepared in accordance with 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 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 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 $64,515,137 as of December 31, 2004 and $53,821,104 as of December 31, 2003.
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.
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
| |
|---|
| | 2004
| | 2003
| | 2002
| |
|---|
| Cumulative development costs (over) under the amount deducted—beginning of period | | $ | (1,583,988 | ) | $ | 3,089,563 | | $ | (4,778,880 | ) |
| Actual development costs | | | (20,035,939 | ) | | (17,622,894 | ) | | (14,864,890 | ) |
| Development costs deducted | | | 21,300,000 | | | 12,949,343 | | | 22,733,333 | |
| | |
| |
| |
| |
| Cumulative development costs (over) under the amount deducted—end of period | | $ | (319,927 | ) | $ | (1,583,988 | ) | $ | 3,089,563 | |
| | |
| |
| |
| |
The monthly development cost deduction was $1.7 million throughout 2004 until it was increased to $2 million beginning with the October 2004 distribution because of increased drilling in Oklahoma. Because of continued development activity and based on the development cost budget for calendar year 2005, the monthly development cost deduction was increased to $2.4 million beginning with the February 2005 distribution. XTO Energy has advised the trustee that this increased monthly deduction will be reevaluated in conjunction with the 2005 development budget 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 95% of the underlying properties. In computing net proceeds, XTO Energy deducts an overhead charge for reimbursement of administrative expenses incurred to support the underlying properties it operates. As of December 31, 2004, the monthly overhead charge was approximately $637,000 ($509,600 net to the trust) and is subject to annual adjustment based on an oil and gas industry index as defined in the trust agreement. As of February 28, 2005, 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. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. ("TGPC") based on a percentage of the residue price. Much of the gas production in Major County, Oklahoma is sold to Ringwood Gathering Company ("RGC"), which retains approximately $0.31 per residue Mcf as a 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 $81.7 million for the year ended December 31, 2004, or 54% of total gas sales, $76.5 million for the year ended December 31, 2003, or 54% of total gas sales and $59.1 million for the year ended December 31, 2002, or 71% of total gas sales.
7. Contingencies
XTO Energy is a defendant in lawsuits related to the underlying properties that could, if adversely determined, decrease future trust distributable income attributable to production on or after December 1, 1998, the creation date of the trust. Any damages relating to production prior to December 1, 1998 will be borne by XTO Energy.
On October 17, 1997, an action, styledUnited 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 thequi 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, attorneys 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 has been scheduled for March 2005. 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.
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 being developed or 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 2004 and 2003:
| | Net Profits
Income
| | Distributable
Income
| | Distributable
Income
per Unit
|
|---|
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 |
| | |
| |
| |
|
2003
|
|
|
|
|
|
|
|
|
|
| First Quarter | | $ | 16,412,178 | | $ | 16,365,560 | | $ | 0.409139 |
| Second Quarter | | | 24,681,304 | | | 24,538,040 | | | 0.613451 |
| Third Quarter | | | 21,446,124 | | | 21,378,080 | | | 0.534452 |
| Fourth Quarter | | | 18,148,172 | | | 18,091,440 | | | 0.452286 |
| | |
| |
| |
|
| | | $ | 80,687,778 | | $ | 80,373,120 | | $ | 2.009328 |
| | |
| |
| |
|
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, 2004 and 2003, 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, 2004. 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 trust as of December 31, 2004 and 2003 and its distributable income and changes in trust corpus for each of the years in the three-year period ended December 31, 2004 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 Hugoton Royalty Trust's internal control over financial reporting as of December 31, 2004, 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 14, 2005 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 14, 2005
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, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The trustee of 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, 2004, 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, 2004, 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 of December 31, 2004 and 2003, 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, 2004, and our report dated March 14, 2005 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 14, 2005
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.
Dallas, Texas
www.melloninvestor.com
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