HUGOTON ROYALTY TRUST
GLOSSARY OF TERMS
The following are definitions of significant terms used in this Annual Report:
Bbl | Barrel (of oil) | |
Bcf | Billion cubic feet (of natural gas) | |
Mcf | Thousand cubic feet (of natural gas) | |
MMBtu | One million British Thermal Units, a common energy measurement | |
net proceeds | Gross proceeds received by XTO Energy from sale of production from the underlying properties, less applicable costs, as defined in the net profits interest conveyances | |
net profits income | Net proceeds multiplied by the net profits percentage of 80%, which is paid to the trust by XTO Energy. "Net profits income" is referred to as "royalty income" for tax reporting purposes. | |
net profits interest | An interest in an oil and gas property measured by net profits from the sale of production, rather than a specific portion of production. The following defined net profits interests were conveyed to the trust from the underlying properties: | |
80% net profits interests—interests that entitle the trust to receive 80% of the net proceeds from the underlying properties that are working interests in Kansas, Oklahoma and Wyoming. | ||
underlying properties | XTO Energy's interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include working interests in predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming. | |
working interest | An operating interest in an oil and gas property that provides the owner a specified share of production that is subject to all production and development costs |
THE TRUST
Hugoton Royalty Trust was created on December 1, 1998 when XTO Energy Inc. conveyed 80% net profits interests in certain predominantly gas-producing properties located in Kansas, Oklahoma and Wyoming to the trust. The net profits interests are the only assets of the trust, other than cash held for trust expenses and for distribution to unitholders.
Net profits income received by the trust on the last business day of each month is calculated and paid by XTO Energy based on net proceeds received from the underlying properties in the prior month. Distributions, as calculated by the trustee, are paid to month-end unitholders of record within ten business days.
UNITS OF BENEFICIAL INTEREST
The units of beneficial interest in the trust began trading on the New York Stock Exchange on April 9, 1999 under the symbol "HGT." The following are the high and low unit sales prices and total cash distributions per unit paid by the trust during each quarter of 2003 and 2002:
| | Sales Price | | |||||||
|---|---|---|---|---|---|---|---|---|---|
| Quarter | Distributions per Unit | ||||||||
| High | Low | ||||||||
| 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 | ||||||||
2002 | |||||||||
| First | $ | 12.10 | $ | 9.44 | $ | 0.183816 | |||
| Second | 12.43 | 10.22 | 0.133366 | ||||||
| Third | 12.00 | 9.44 | 0.215567 | ||||||
| Fourth | 13.19 | 10.86 | 0.206560 | ||||||
| $ | 0.739309 | ||||||||
At December 31, 2003, there were 40,000,000 units outstanding and approximately 219 unitholders of record; 17,565,355 of these units were held by depository institutions. As of March 1, 2004, 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 costs, development costs and overhead from revenues. If monthly costs exceed revenues from the underlying properties in any state, such excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. Excess costs generally can occur during periods of higher development activity and lower gas prices.
Unitholders may be eligible to receive the following tax benefits, but should consult their tax advisors:
As an example, a unitholder that acquired units in January 2003 and held them throughout 2003 would be entitled to a cost depletion deduction of approximately 6% of his cost. Assuming a cost of $13.00 per unit, cost depletion would offset 40% of 2003 taxable trust income. After considering the tight sands tax credit and assuming a 30% tax rate, the 2003 taxable equivalent return as a percentage of unit cost would be 18%. (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 2003 Annual Report of the Hugoton Royalty Trust. This report includes a copy of the trust's 2003 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, 2003, net profits income totaled $80,687,778. After adding interest income of $29,622 and deducting trust administration expense of $344,280, distributable income was $80,373,120 or $2.009328 per unit. Net profits income and distributions were 170% higher than 2002 amounts primarily because of higher gas prices.
Natural gas prices averaged $4.54 per Mcf for 2003, 86% higher than the 2002 average price of $2.44 per Mcf. The average 2003 oil price was $30.13 per Bbl, 27% higher than the 2002 average price of $23.70 per Bbl.
Gas sales volumes from the underlying properties for 2003 were 31,490,564 Mcf, or 86,276 Mcf per day, or an 8% decline from 94,014 Mcf per day in 2002. Oil sales volumes from the underlying properties were 331,867 Bbls, or 909 Bbls per day in 2003, or a decline of 6% from 968 Bbls per day in 2002. For further information on sales volumes and product prices, see "Trustee's Discussion and Analysis."
Tight sands gas sales volumes from the underlying properties eligible for the 2003 tax credit calculation were 470,455 Mcf which were produced and sold before 2003 from wells drilled prior to January 1, 1993 and after November 5, 1990 (or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977). After reduction of volumes related to production and development costs, tight sands gas sales volumes allocated to the net profits interests were 208,086 Mcf, resulting in a tight sands tax credit for 2003 of $0.001600 per unit. This credit (or a portion thereof, if units were acquired after January 2003) can be applied against the unitholder's regular federal income tax liability, subject to certain limitations. Unitholders should consult their tax advisors regarding use of this credit. There currently is no significant tight sands tax credit expected for future years.
As of December 31, 2003, proved reserves for the net profits interests were estimated by independent engineers to be 297.5 Bcf of natural gas and 2.4 million Bbls of oil. Estimated gas reserves decreased 1% and oil reserves decreased 6% from year-end 2002 to 2003, primarily because of production, partially offset by the increase in year-end realized gas prices from $4.37 to $5.76 per Mcf and West Texas Intermediate posted oil prices from $28.00 to $29.25 per Bbl and the resulting increased allocation of reserves to the net profits interests. All reserve information prepared by independent engineers has been provided to the trustee by XTO Energy.
Estimated future net cash flows from proved reserves of the net profits interests at December 31, 2003 are $1.64 billion, or $40.89 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2003 is $786.6 million, or $19.66 per unit. Proved reserve estimates and related future net cash flows have been determined based on year-end oil and gas prices, as well as other guidelines prescribed by the Financial Accounting Standards Board as further described under Item 2 of the accompanying Form 10-K. The present value of estimated future net cash flows is not representative of the market value of trust units.
As discussed in the tax instructions provided to unitholders in February 2004, 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, 2003 is approximately 15 years. This index is calculated using total proved reserves and estimated 2004 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 96% natural gas and 4% oil. XTO Energy operates approximately 94% of the underlying properties.
Because the underlying properties are working interests, production and development costs are deducted in calculating net profits income. As a result, net profits income is affected by the level of maintenance and development activity on the underlying properties. See "Trustee's Discussion and Analysis—Years Ended December 31, 2003, 2002 and 2001—Costs." Total 2003 development costs deducted for the underlying properties were $12,949,343, a decrease of 43% from the prior year. XTO Energy has informed the trustee that total 2004 budgeted development costs for the underlying properties are approximately $20 million.
Hugoton Area
Discovered in 1922, the Hugoton area is one of the largest natural gas producing areas in the United States. During 2003, gas sales volumes from the Hugoton area were 10.2 million Mcf, or approximately 32% 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.
XTO Energy continued its restimulation program in the Chase intervals, completing 37 of these restimulations in 2003. XTO Energy has informed the trustee that it plans to perform 35 Chase restimulations during 2004. 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 13.8 million Mcf in 2003, or approximately 44% 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 2003. In Major County, XTO Energy successfully drilled four gross (3.2 net) wells. XTO Energy has informed the trustee that it plans to drill up to seven wells and perform up to ten workovers in Major County in 2004. In Woodward County, the Chester formation, with its four separate producing intervals, was the primary target for 12 gross (9.8 net) wells successfully drilled and completed during 2003. XTO Energy has informed the trustee that it plans to drill up to five gross (4.7 net) wells and perform up to five workovers in Woodward County during 2004.
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 7.5 million Mcf in 2003, or approximately 24% of total sales volumes from the underlying properties.
XTO Energy successfully drilled six gross (six net) wells and performed 11 workovers in the Fontenelle Field in 2003. XTO Energy plans to perform up to seven workovers and may drill up to seven wells in the Green River Basin during 2004.
Estimated Proved Reserves and Future Net Cash Flows
The following are proved reserves of the underlying properties and proved reserves and future net cash flows from proved reserves of the net profits interests at December 31, 2003, as estimated by independent engineers:
| | | | Net Profits Interests | ||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | Underlying Properties | Proved Reserves(a)(b) | Future Net Cash Flows from Proved Reserves(a)(c) | ||||||||||||
| | Proved Reserves(a) | | | | | ||||||||||
| | Gas (Mcf) | Oil (Bbls) | Gas (Mcf) | Oil (Bbls) | Undiscounted | Discounted | |||||||||
| (in thousands) | |||||||||||||||
| Oklahoma | 280,553 | 3,510 | 182,288 | 2,276 | $ | 1,033,454 | $ | 516,843 | |||||||
| Wyoming | 142,923 | 200 | 91,680 | 128 | 499,645 | 216,261 | |||||||||
| Kansas | 38,852 | 59 | 23,510 | 36 | 102,366 | 53,493 | |||||||||
| TOTAL | 462,328 | 3,769 | 297,478 | 2,440 | $ | 1,635,465 | $ | 786,597 | |||||||
TRUSTEE'S DISCUSSION AND ANALYSIS
Years Ended December 31, 2003, 2002 and 2001
Net profits income for 2003 was $80,687,778, as compared with $29,934,195 for 2002 and $79,272,395 for 2001. The 170% increase in net profits income from 2002 to 2003 and the 62% decrease in net profits income from 2001 to 2002 were 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 $344,280 in 2003 as compared to $376,790 in 2002 and $277,532 in 2001. Decreased administration expense from 2002 to 2003 is primarily related to decreased stock exchange listing fees, partially offset by the timing of expenditures. Increased administration expense from 2001 to 2002 is primarily related to increased stock exchange listing fees. Interest income was $29,622 in 2003, $14,955 in 2002 and $136,177 in 2001. Changes in interest income are attributable to fluctuations in net profits income and interest rates. Distributable income was $80,373,120 or $2.009328 per unit in 2003, $29,572,360 or $0.739309 per unit in 2002 and $79,131,040 or $1.978276 per unit in 2001.
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:
Volumes
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. From 2001 to 2002, underlying gas sales volumes decreased 6% and underlying oil sales volumes decreased 10% primarily because natural production decline exceeded the effects of new wells and workovers.
Prices
Gas. The 2003 average gas price was $4.54 per Mcf, an 86% increase from the 2002 average gas price of $2.44 per Mcf, which was 43% lower than the 2001 average gas price of $4.30 per Mcf. Gas prices were at record highs at the beginning of 2001 because of gas supplies strained by winter weather. Throughout the remainder of 2001, prices declined because of fuel switching related to higher prices, milder weather and reduced demand from a weaker economy. The winter of 2001-2002 was one of the warmest on record, resulting in higher than average gas storage levels and lower gas prices in 2002. Prices climbed in fourth quarter 2002 as a result of low levels of drilling activity, increased industrial demand, colder weather and international instability. With colder than normal weather, record low gas storage levels and continued increasing demand, gas prices were 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. Prices in 2004 will continue to be affected by weather, the pace of recovery of the domestic economy and fluctuations in North American production. In any case, natural gas prices are expected to remain volatile. The average NYMEX price for January and February 2004 was $5.81 per MMBtu.
The trust's average gas price was $0.48 lower than the average NYMEX price of $4.78 in 2001, $0.64 lower than the average NYMEX price of $3.08 in 2002 and $0.75 lower than the average NYMEX price of $5.29 in 2003. Despite the increasing differential from 2001 to 2003, 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 which has increased capacity to deliver Wyoming production to western markets. An eastbound pipeline project is expected to be completed in 2005 which should further stabilize Rocky Mountain prices.
Oil. The average oil price for 2003 was $30.13 per Bbl, 27% higher than the 2002 average oil price of $23.70 per Bbl, which was 14% lower than the 2001 average price of $27.60 per Bbl. Oil prices began 2001 relatively strong and declined through the remainder of the year and in 2002 because of lagging demand caused by a global recession. Rising uncertainties in the Middle East led to higher prices late in 2002. OPEC members agreed to increase daily oil production 1.5 million barrels beginning February 2003, to help stabilize a volatile world market. Oil prices remained relatively high in 2003, however, because of the war in Iraq, slower than anticipated resumption of Iraqi oil exports and unusually low storage levels. OPEC reiterated its intent to maintain oil prices by reducing daily oil production by 2 million barrels beginning June 2003 and by an additional 900,000 barrels beginning November 2003. In January 2004, below normal temperatures combined with low U.S. oil supplies led oil prices to 10-month highs, reaching $36 per Bbl. Despite increasing demand in 2003, OPEC members agreed to reduce daily oil production by 1 million barrels beginning April 2004 to maintain market balance in the second quarter when there is seasonally low demand. The average NYMEX price for January and February 2004 was $34.30. Recent trust oil prices have averaged approximately $0.90 lower than the NYMEX price.
Costs
The calculation of net profits income includes deductions for production and development costs and overhead since the related underlying properties are working interests. If monthly costs exceed revenues for any state, these excess costs must be recovered, with accrued interest, from future net proceeds of that state and cannot reduce net profits income from another state. There have been no excess costs or related recoveries since September 1999.
Taxes, transportation and other. Taxes, transportation and other generally fluctuates with changes in total revenues.
Production. Production expenses increased 5% from 2002 to 2003 primarily because of higher fuel costs. Production expenses increased 3% from 2001 to 2002 because of increased compressor fuel, maintenance, insurance and labor costs and saltwater disposal expense.
Development. Development costs deducted were $12.9 million in 2003, $22.7 million in 2002 and $30.4 million in 2001. The decrease from 2002 to 2003 is attributable to the timing of budgeted development projects, billings and expenditures. The decrease from 2001 to 2002 is attributable to fewer wells drilled and fewer workovers in Oklahoma.
In 2003, budgeted development costs deducted from distributions totaled $12.9 million, compared with actual development costs of $17.6 million. At December 31, 2003, actual costs exceeded cumulative development costs deducted by $1.6 million. XTO Energy decreased the monthly development cost deduction from $1.9 million to $1 million beginning with the February 2003 distribution and further decreased the monthly development cost deduction to $750,000 beginning with the June 2003 distribution. Because of increased development activity and based on the development cost budget for calendar year 2004, the monthly development cost deduction was increased to $1.7 million beginning with the November 2003 distribution. This increased monthly deduction is expected to be maintained through the March 2005 distribution, but will be evaluated and revised as necessary.
Overhead. Overhead is charged by XTO Energy for reimbursement of administrative expenses of operating the underlying properties. Overhead fluctuates based on changes in the active well count and drilling activity on the underlying properties, as well as an annual inflation adjustment.
Other Proceeds
Net profits income includes proceeds of $60,000 ($48,000 net to the trust) in 2002 from the sale of a property in Oklahoma and $307,824 ($246,259 net to the trust) in 2001 from the sale of certain properties in Wyoming.
Litigation Settlement
In July 2003, XTO disbursed funds in final settlement of the class action lawsuit,Booth, et al. v. Cross Timbers Oil Company. The portion of this settlement related to the production from the underlying properties since December 1, 1998, the effective date of the trust, was $1,040,831. The settlement reduced royalty income paid to the trust in August 2003 and the distribution paid to unitholders in September by $832,665, or $0.021 per unit. For further information regarding this lawsuit, see Note 7 to Financial Statements.
Fourth Quarter 2003 and 2002
During fourth quarter 2003 the trust received net profits income totaling $18,148,172, compared with fourth quarter 2002 net profits income of $8,290,621. The 119% increase in net profits income from fourth quarter 2002 to 2003 was primarily because of higher gas prices.
Administration expense was $63,731 and interest income was $6,999, resulting in fourth quarter 2003 distributable income of $18,091,440, or $0.452286 per unit. Distributable income for fourth quarter 2002 was $8,262,400 or $0.206560 per unit. Distributions to unitholders for the quarter ended December 31, 2003 were:
| Record Date | Payment Date | Per Unit | |||
|---|---|---|---|---|---|
| October 31, 2003 | November 17, 2003 | $ | 0.165643 | ||
| November 28, 2003 | December 12, 2003 | 0.143987 | |||
| December 31, 2003 | January 15, 2004 | 0.142656 | |||
| $ | 0.452286 | ||||
Volumes
Fourth quarter underlying gas sales volumes decreased 8% while underlying oil sales volumes increased 2%. The decrease in gas sales volumes is primarily because of natural production decline and timing of cash receipts, partially offset by increased production from new wells and workovers. The increase in oil sales volumes is primarily because of timing of cash receipts and increased production from new wells and workovers, partially offset by natural production decline.
Prices
The average fourth quarter 2003 gas price was $4.33 per Mcf, or 72% higher than the fourth quarter 2002 average price of $2.52 per Mcf. The average fourth quarter oil price was $29.62 per Bbl, or 5% higher than the fourth quarter 2002 average price of $28.16 per Bbl. For further information about product prices, see "Years Ended December 31, 2003, 2002 and 2001—Prices" above.
Costs
Production. Fourth quarter production expenses increased 10% from 2002 to 2003 primarily because of increased fuel costs related to higher gas prices and timing of maintenance projects.
Development. Development costs, which were deducted based on budgeted development costs, declined 23% from fourth quarter 2002 to 2003.
Overhead. Overhead increased 22% from fourth quarter 2002 to 2003 because of the effect of prior period adjustments in 2002, partially offset by the annual rate adjustment based on an industry index.
For further information about costs, see "Years Ended December 31, 2003, 2002 and 2001—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) | ||||||||||||||||
|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | 2003 | 2002 | |||||||||||||
| Sales Volumes | ||||||||||||||||||
| Gas (Mcf)(b) | ||||||||||||||||||
| Underlying properties | 31,490,564 | 34,315,145 | 36,597,937 | 7,760,757 | 8,412,012 | |||||||||||||
| Average per day | 86,276 | 94,014 | 100,268 | 84,356 | 91,435 | |||||||||||||
| Net profits interests | 17,832,189 | 11,774,205 | 17,671,423 | 4,214,990 | 3,118,488 | |||||||||||||
Oil (Bbls)(b) | ||||||||||||||||||
| Underlying properties | 331,867 | 353,185 | 393,731 | 84,629 | 83,016 | |||||||||||||
| Average per day | 909 | 968 | 1,079 | 920 | 902 | |||||||||||||
| Net profits interests | 196,005 | 123,142 | 190,722 | 52,673 | 31,466 | |||||||||||||
Average Sales Prices | ||||||||||||||||||
| Gas (per Mcf) | $ | 4.54 | $ | 2.44 | $ | 4.30 | $ | 4.33 | $ | 2.52 | ||||||||
| Oil (per Bbl) | $ | 30.13 | $ | 23.70 | $ | 27.60 | $ | 29.62 | $ | 28.16 | ||||||||
Revenues | ||||||||||||||||||
| Gas sales | $ | 142,846,720 | $ | 83,610,392 | $ | 157,508,999 | $ | 33,618,018 | $ | 21,228,671 | ||||||||
| Oil sales | 9,999,958 | 8,369,027 | 10,867,817 | 2,506,975 | 2,337,918 | |||||||||||||
| Total Revenues | 152,846,678 | 91,979,419 | 168,376,816 | 36,124,993 | 23,566,589 | |||||||||||||
Costs | ||||||||||||||||||
| Taxes, transportation and other | 13,552,224 | 8,228,963 | 15,694,068 | 3,238,208 | 2,477,308 | |||||||||||||
| Production expense | 16,889,700 | 16,107,467 | 15,611,725 | 4,233,568 | 3,851,038 | |||||||||||||
| Development costs(c) | 12,949,343 | 22,733,333 | 30,367,276 | 4,150,000 | 5,383,333 | |||||||||||||
| Overhead | 7,556,090 | 7,551,912 | 7,921,077 | 1,818,752 | 1,491,634 | |||||||||||||
| Litigation | 1,040,831 | — | — | — | — | |||||||||||||
| Total Costs | 51,988,188 | 54,621,675 | 69,594,146 | 13,440,528 | 13,203,313 | |||||||||||||
Other Proceeds | ||||||||||||||||||
| Property sales | 1,232 | 60,000 | 307,824 | 750 | — | |||||||||||||
| Net Proceeds | 100,859,722 | 37,417,744 | 99,090,494 | 22,685,215 | 10,363,276 | |||||||||||||
| Net Profits Percentage | 80% | 80% | 80% | 80% | 80% | |||||||||||||
| Net Profits Income | $ | 80,687,778 | $ | 29,934,195 | $ | 79,272,395 | $ | 18,148,172 | $ | 8,290,621 | ||||||||
HUGOTON ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| | December 31 | ||||||
|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | |||||
| Assets | |||||||
| Cash and short-term investments | $ | 5,706,240 | $ | 3,227,840 | |||
| Net profits interests in oil and gas properties—net (Notes 1 and 2) | 193,245,847 | 205,493,243 | |||||
| $ | 198,952,087 | $ | 208,721,083 | ||||
Liabilities and Trust Corpus | |||||||
| Distribution payable to unitholders | $ | 5,706,240 | $ | 3,227,840 | |||
| Trust corpus (40,000,000 units of beneficial interest authorized and outstanding) | 193,245,847 | 205,493,243 | |||||
| $ | 198,952,087 | $ | 208,721,083 | ||||
STATEMENTS OF DISTRIBUTABLE INCOME
| | Year Ended December 31 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | |||||||
| Net profits income | $ | 80,687,778 | $ | 29,934,195 | $ | 79,272,395 | ||||
| Interest income | 29,622 | 14,955 | 136,177 | |||||||
| Total income | 80,717,400 | 29,949,150 | 79,408,572 | |||||||
| Administration expense | 344,280 | 376,790 | 277,532 | |||||||
| Distributable income | $ | 80,373,120 | $ | 29,572,360 | $ | 79,131,040 | ||||
| Distributable income per unit (40,000,000 units) | $ | 2.009328 | $ | 0.739309 | $ | 1.978276 | ||||
STATEMENTS OF CHANGES IN TRUST CORPUS
| | Year Ended December 31 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | |||||||
| Trust corpus, beginning of year | $ | 205,493,243 | $ | 215,346,192 | $ | 226,081,443 | ||||
| Amortization of net profits interests | (12,247,396 | ) | (9,852,949 | ) | (10,735,251 | ) | ||||
| Distributable income | 80,373,120 | 29,572,360 | 79,131,040 | |||||||
| Distributions declared | (80,373,120 | ) | (29,572,360 | ) | (79,131,040 | ) | ||||
| Trust corpus, end of year | $ | 193,245,847 | $ | 205,493,243 | $ | 215,346,192 | ||||
See Accompanying 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:
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:
The most significant differences between the trust's financial statements and those prepared in accordance with generally accepted accounting principles are:
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 $53,821,104 as of December 31, 2003 and $41,573,708 as of December 31, 2002.
3. Distributions to Unitholders
The trustee determines the amount to be distributed to unitholders each month by totaling net profits income, interest income and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount is distributed to unitholders of record within ten business days after the monthly record date, which is the last business day of the month.
Net profits income received by the trustee consists of net proceeds received in the prior month by XTO Energy from the underlying properties, multiplied by 80%. Net proceeds are the gross proceeds received from the sale of production, less costs. Costs generally include applicable taxes, transportation, legal and marketing charges, production costs, development and drilling costs, and overhead (Note 6).
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 | |||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| | 2003 | 2002 | 2001 | |||||||
| Cumulative development costs (over) under the amount deducted—beginning of period | $ | 3,089,563 | $ | (4,778,880 | ) | $ | — | |||
| Actual development costs | (17,622,894 | ) | (14,864,890 | ) | (35,146,156 | ) | ||||
| Development costs deducted | 12,949,343 | 22,733,333 | 30,367,276 | |||||||
| Cumulative development costs (over) under the amount deducted—end of period | $ | (1,583,988 | ) | $ | 3,089,563 | $ | (4,778,880 | ) | ||
XTO Energy decreased the monthly development cost deduction from $1.9 million to $1 million beginning with the February 2003 distribution and further decreased the monthly development cost deduction to $750,000 beginning with the June 2003 distribution. Because of increased development activity and based on the development cost budget for calendar year 2004, the monthly development cost deduction was increased to $1.7 million beginning with the November 2003 distribution. This increased monthly deduction is expected to be maintained through the March 2005 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.
XTO Energy has advised the trustee that the trust receives net profits income from tight sands gas wells. Production sold through 2002 from wells drilled on the underlying properties prior to January 1, 1993, and after November 5, 1990 (or after December 31, 1979 if the related formation was dedicated to interstate commerce as of April 20, 1977), qualified for the federal income tax credit for producing nonconventional fuels under Section 29 of the Internal Revenue Code.
This tax credit was approximately $0.52 per MMBtu, or $0.001600 per unit in 2003, $0.002991 per unit in 2002 and $0.017309 per unit in 2001. The credit is recalculated annually based on each year's qualifying production through the year 2002. Unitholders should be entitled to this tax credit with respect to royalty income reported in 2003 relating to sales of qualifying production through December 31, 2002. Unitholders should consult their tax advisors regarding use of this credit and other trust tax compliance matters. Congress is considering a new energy bill in 2004, but has not yet passed legislation that extends or renews the tight sands tax credit. Therefore, there currently is no significant benefit expected for future years.
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, 2003, the overhead charge was approximately $606,000 ($484,800 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 March 1, 2004, XTO Energy owned 54.3% of the trust.
XTO Energy sells a significant portion of natural gas production from the underlying properties to certain of XTO Energy's wholly owned subsidiaries under contracts in existence when the trust was created, generally at amounts approximating monthly published market prices. Most of the production from the Hugoton area is sold under a contract to Timberland Gathering & Processing Company, Inc. ("TGPC") 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 $76.5 million for the year ended December 31, 2003, or 54% of total gas sales, $59.1 million for the year ended December 31, 2002, or 71% of total gas sales and $128.5 million for the year ended December 31, 2001, or 82% of total gas sales.
7. Contingencies
Litigation
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 April 3, 1998, a class action lawsuit,Booth, et al. v. Cross Timbers Oil Company, was filed in the District Court of Dewey County, Oklahoma by royalty owners of natural gas wells in Oklahoma. The plaintiffs alleged that since 1991, XTO Energy underpaid royalty owners as a result of reducing royalties for improper charges for production, marketing, gathering, processing and transportation costs and selling natural gas through affiliated companies at prices less favorable than those paid by third parties. The parties agreed on a settlement that the court approved in April 2003 and was paid in July 2003. The portion of this settlement related to the production from the underlying properties since December 1, 1998, the effective date of the trust, was $1,040,831. The settlement reduced royalty income paid to the trust in August 2003 and the distribution paid to unitholders in September by $832,665, or 2.1 cents per unit. The effect of the settlement on future distributions will not be significant.
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. This lawsuit alleges that XTO Energy underpaid royalties on natural gas produced from federal leases and lands owned by Native Americans in amounts in excess of 20% as a result of mismeasuring the volume of natural gas and wrongfully analyzing its heating content during at least the past ten years. The suit, which was brought under thequi tam provisions of the U.S. False Claims Act, seeks treble damages for the unpaid royalties (with interest), civil penalties between $5,000 and $10,000 for each violation of the U.S. False Claims Act, and an order for XTO Energy to cease the allegedly improper measuring practices. The cases against XTO Energy and other defendants have been consolidated in the United States District Court for Wyoming. While XTO Energy is unable to predict the outcome of this case or estimate the amount of any possible loss, it has informed the trustee that it believes that the allegations of this lawsuit are without merit and intends to vigorously defend the action. However, an order to change measuring practices or a related settlement could adversely affect the trust by reducing net proceeds in the future by an amount that is presently not determinable, but, in XTO Energy management's opinion, is not currently expected to be material to the trust's annual distributable income, financial position or liquidity.
Certain of the trust properties are involved in various other lawsuits and certain governmental proceedings arising in the ordinary course of business. XTO Energy has advised the trustee that it does not believe that the ultimate resolution of these claims will have a material effect on trust annual distributable income, financial position or liquidity.
Other
Several states have enacted legislation to require state income tax withholding from nonresident royalty owners. After consultation with legal counsel, XTO Energy has advised the trustee that it believes the trust is not subject to these withholding requirements. However, 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 2003 and 2002:
| | Net Profits Income | Distributable Income | Distributable Income per Unit | ||||||
|---|---|---|---|---|---|---|---|---|---|
| 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 | ||||
2002 | |||||||||
| First Quarter | $ | 7,412,420 | $ | 7,352,640 | $ | 0.183816 | |||
| Second Quarter | 5,560,186 | 5,334,640 | 0.133366 | ||||||
| Third Quarter | 8,670,968 | 8,622,680 | 0.215567 | ||||||
| Fourth Quarter | 8,290,621 | 8,262,400 | 0.206560 | ||||||
| $ | 29,934,195 | $ | 29,572,360 | $ | 0.739309 | ||||
INDEPENDENT AUDITORS' REPORTS
Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:
We have audited the accompanying statements of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2003 and 2002, and the related statements of distributable income and changes in trust corpus for the years then ended. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audits. The 2001 financial statements were audited by other auditors who have ceased operations. Those auditors' report, dated March 19, 2002, on those financial statements was unqualified and included an explanatory paragraph that described the trust's method of accounting as explained in Note 2 to the financial statements.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.
In our opinion, the 2003 and 2002 financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the trust as of December 31, 2003 and 2002 and its distributable income and changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 2.
KPMG LLP
Dallas, Texas
March 5, 2004
Bank of America, N.A., as Trustee for the Hugoton Royalty Trust:
We have audited the accompanying statements of assets, liabilities and trust corpus of the Hugoton Royalty Trust as of December 31, 2001 and 2000, and the statements of distributable income and changes in trust corpus for each of the years then ended. These financial statements are the responsibility of the trustee. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the trust as of December 31, 2001 and 2000 and its distributable income and changes in trust corpus for each of the years then ended, in conformity with the modified cash basis of accounting described in Note 2.
ARTHUR ANDERSEN LLP
Fort Worth, Texas
March 19, 2002
The above report of Arthur Andersen LLP ("Arthur Andersen") is a copy of a report previously issued by Arthur Andersen on March 19, 2002. This audit report has not been reissued by Arthur Andersen in connection with this filing on Form 10-K. After reasonable efforts, the trust has been unable to obtain the consent of Arthur Andersen, the trust's former independent auditors, as to the incorporation by reference of their report for the year ended December 31, 2001 into XTO Energy's previously filed registration statements under the Securities Act of 1933, and the trust has not filed that consent with this Annual Report on Form 10-K in reliance on Rule 437a of the Securities Act of 1933. Because the trust has not been able to obtain Arthur Andersen's consent, you will not be able to recover against Arthur Andersen under Section 11 of the Securities Act for any untrue statements of a material fact contained in the trust's financial statements audited by Arthur Andersen or any omissions to state a material fact required to be stated therein.
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
