Exhibit 13
CROSS TIMBERS 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 applicable net profits percentage of 75% or 90% and paid to the trust by XTO Energy. “Net profits income” is referred to as “royalty income” for income tax 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: | |
| 90% net profits interests – interests that entitle the trust to receive 90% of the net proceeds from the underlying properties that are royalty or overriding royalty interests in Texas, Oklahoma and New Mexico | ||
| 75% net profits interests – interests that entitle the trust to receive 75% of the net proceeds from the underlying properties that are working interests in Texas and Oklahoma | ||
royalty interest (and overriding royalty interest) | A nonoperating interest in an oil and gas property that provides the owner a specified share of production without any production expense or development costs | |
underlying properties | XTO Energy’s interest in certain oil and gas properties from which the net profits interests were conveyed. The underlying properties include royalty and overriding royalty interests in producing and nonproducing properties in Texas, Oklahoma and New Mexico, and working interests in producing properties located in Texas and Oklahoma. | |
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
Cross Timbers Royalty Trust was created on February 12, 1991 by conveyance of 90% net profits interests in certain royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and 75% net profits interests in certain working interest properties in Texas and Oklahoma. XTO Energy Inc. owns the underlying properties from which these net profits interests were conveyed. 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 are listed and traded on the New York Stock Exchange under the symbol “CRT.” 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 | Distributions per Unit | ||||||||
Quarter | High | Low | |||||||
2004 | |||||||||
First | $ | 28.85 | $ | 24.50 | $ | 0.507664 | |||
Second | 30.23 | 26.25 | 0.592632 | ||||||
Third | 33.33 | 27.74 | 0.654790 | ||||||
Fourth | 41.75 | 32.82 | 0.732257 | ||||||
| $ | 2.487343 | ||||||||
2003 | |||||||||
First | $ | 21.75 | $ | 17.45 | $ | 0.432538 | |||
Second | 25.75 | 18.30 | 0.611356 | ||||||
Third | 25.40 | 18.86 | 0.511602 | ||||||
Fourth | 30.46 | 21.30 | 0.559295 | ||||||
| $ | 2.114791 | ||||||||
At December 31, 2004, there were 6,000,000 units outstanding and approximately 477 unitholders of record; 5,703,702 of these units were held by depository institutions. In September 2003, XTO Energy distributed all of the 1,360,000 units it owned as a dividend to its common stockholders. XTO Energy currently is not a unitholder of the trust.
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 monthly net profits income to unitholders. Trust net profits income is received from two major components, the 90% net profits interests and the 75% net profits interests.
| — | The 90% net profits interests were conveyed from underlying royalty and overriding royalty interests in producing properties in Texas, Oklahoma and New Mexico. Most net profits income is from long-lived gas properties in the San Juan Basin of northwestern New Mexico. Because the 90% net profits interests are not subject to production expense or development costs, net profits income from these interests generally only varies because of changes in sales volumes or prices. |
| — | The 75% net profits interests were conveyed from underlying working interests in seven large, predominantly oil-producing properties in Texas and Oklahoma. Net profits income from these properties is reduced by production expense and development costs. If costs exceed revenues from the underlying working interest properties in either Texas or Oklahoma, the 75% net profits interests for that state will not contribute to trust net profits income until all excess costs and accrued interest have been recovered from future net proceeds of that state. However, such excess costs will not reduce net profits income from the other 75% net profits interests or from the 90% net profits interests. Because of excess costs, the Texas 75% net profits interests did not contribute to trust net profits income from February through April 2002. Such excess costs generally occur during periods of higher development activity and/or lower oil prices. For further information, see “Trustee’s Discussion and Analysis—Years Ended December 31, 2004, 2003 and 2002—Costs.” |
The following table summarizes the effect of the above components on distributions per unit for the last three years:
| 2004 | 2003 | 2002 | ||||||||||||||||||||||
| Monthly Average | Annual Total | Monthly Average | Annual Total | Monthly Average | Annual Total | |||||||||||||||||||
Net profits income: | ||||||||||||||||||||||||
— 90% net profits interests | $ | 0.174 | $ | 2.092 | $ | 0.153 | $ | 1.832 | $ | 0.109 | $ | 1.302 | ||||||||||||
— 75% net profits interests | 0.037 | 0.445 | 0.027 | 0.326 | 0.017 | 0.206 | ||||||||||||||||||
Administration expense (net of interest income) | (0.004 | ) | (0.050 | ) | (0.004 | ) | (0.043 | ) | (0.003 | ) | (0.038 | ) | ||||||||||||
Total Distribution | $ | 0.207 | $ | 2.487 | $ | 0.176 | $ | 2.115 | $ | 0.123 | $ | 1.470 | ||||||||||||
Cost Depletion is generally available to unitholders as a tax deduction from net profits 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 8% of his cost. Assuming a cost of $28.00 per unit, cost depletion would offset approximately 89% 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 Cross Timbers Royalty Trust and Form 10-K. 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 $15,222,417. After deducting trust administration expense and adding interest income, distributable income was $14,924,058, or $2.487343 per unit. Distributions for the year were higher than in 2003 primarily because of higher oil and gas prices.
Natural gas prices for 2004 averaged $5.73 per Mcf for sales from the underlying properties, an 18% increase from the 2003 average price of $4.86 per Mcf. Gas sales volumes from the underlying properties for the year ended December 31, 2004 totaled 2,584,814 Mcf, or 7,062 Mcf per day, a 3% decrease from 2003 production of 2,677,460 Mcf, or 7,336 Mcf per day. Gas volumes were lower primarily because of the timing of cash receipts and natural production decline, partially offset by the effect of prior period volume adjustments in 2003.
The average oil price increased to $35.68 per Bbl, up 27% from the 2003 average price of $28.04 per Bbl. Oil sales volumes from the underlying properties during 2004 were 275,792 Bbls, or 754 Bbls per day, an 8% decrease from 2003 levels of 298,869 Bbls, or 819 Bbls per day. Oil volumes were lower primarily because of natural production decline, partially offset by the effect of prior period volume adjustments in 2003.
As of December 31, 2004, proved reserves for the underlying properties were estimated by independent engineers to be 3.5 million Bbls of oil and 34.2 Bcf of natural gas. Based on an allocation of these reserves, proved reserves attributable to the net profits interests were estimated to be 1.7 million Bbls of oil and 30.1 Bcf of natural gas. Estimated oil reserves attributable to the net profits interests increased 6% from year-end 2003 to 2004 primarily because of an increased allocation of reserves to the net profits interests due to higher year-end prices, partially offset by production. Gas reserves for the underlying properties, as well as gas reserves attributable to the net profits interests, decreased 3% from year-end 2003 to 2004 primarily because of production, partially offset by reserve additions from development activity in the San Juan Basin. 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 $206.2 million, or $34.36 per unit. Using an annual discount factor of 10%, the present value of estimated future net cash flows at December 31, 2004 is $100.6 million, or $16.77 per unit. Proved reserve estimates and related future net cash flows have been determined based on a year-end West Texas Intermediate posted oil price of $40.25 per Bbl and a year-end average realized gas price of $5.14 per Mcf. 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 indicative 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.
Cross Timbers Royalty Trust
| By: | Bank of America, N.A., Trustee |
| By: | Nancy G. Willis |
| Vice President |
THE UNDERLYING PROPERTIES
The underlying properties include over 2,900 producing properties with established production histories in Texas, Oklahoma and New Mexico. The average reserve-to-production index for the underlying properties as of December 31, 2004 is approximately 13 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 32% oil and 68% natural gas. The underlying properties also include certain nonproducing properties in Texas, Oklahoma and New Mexico that are primarily mineral interests. As discussed below under “75% Net Profits Interests,” XTO Energy became operator of the Penwell Unit in August 2004. Other than this property and approximately 20 of the underlying royalty interests in the San Juan Basin that burden operated working interests, XTO Energy cannot significantly influence or control the operations of the underlying properties.
90% Net Profits Interests
Royalty and overriding royalty properties underlying the 90% net profits interests represent 78% of the discounted future net cash flows from trust proved reserves at December 31, 2004. Approximately 86% of the discounted future net cash flows from the 90% net profits interests is from gas reserves, totaling 29.6 Bcf. Oil reserves underlying the 90% net profits interests are primarily located in West Texas and are estimated to be 631,000 Bbls at December 31, 2004.
Because the properties underlying the 90% net profits interests are royalty interests and overriding royalty interests, net profits income from these properties is not reduced by production expense or development costs. Additionally, net profits income from these interests cannot be reduced by any excess costs of the 75% net profits interests. The trust, therefore, should generally receive monthly net profits income from these interests, as determined by oil and gas sales volumes and prices.
Most of the trust’s gas reserves are located in the San Juan Basin of northwestern New Mexico, one of the largest domestic gas fields. The San Juan Basin royalties produced approximately 78% of the trust’s gas sales volumes and 55% of the net profits income for 2004. As of December 31, 2004, trust proved gas reserves in this region are estimated to be 23.9 Bcf, or 80% of total trust gas reserves.
Approximately 26% of the trust’s 2004 gas sales volumes were from coal seam production in the San Juan Basin. Through 2002, sales of production from coal seam wells drilled from 1980 through 1992 qualified for a federal income tax credit. In October 2002, regulatory authorities approved increasing the density of coal seam wells drilled in the San Juan Basin from one to two wells per 320-acre spacing unit, doubling the number of drill wells allowed. Increasing the density of coal seam wells could impact a significant portion of the trust’s acreage. XTO Energy Inc. has informed the trustee that it believes operators will pursue increased density drilling, but the potential effect on the trust is unknown.
Most of the trust’s San Juan Basin conventional, or non-coal seam, gas is produced from the Mesaverde formation. In 1999, this formation was approved for increased density drilling, which doubled the number of drill wells allowed to four per spacing unit. XTO Energy has advised the trustee that the trust has received net proceeds from additional Mesaverde wells in recent years and that it believes operators will continue to further develop the Mesaverde formation underlying the net profits interests.
75% Net Profits Interests
Underlying the 75% net profits interests are working interests in seven large properties in Texas and Oklahoma operated primarily by established oil companies. These properties are located in mature fields undergoing secondary or tertiary recovery operations. As a result of an acquisition in August 2004, XTO Energy became operator of the Penwell Unit which is one of the properties underlying the Texas 75% net profits interests. With the exception of the Penwell Unit, XTO Energy generally has little influence or control over operations on any of these properties.
Proved reserves from the 75% net profits interests are almost entirely oil, estimated to be approximately 1.1 million Bbls at year-end 2004. Based on year-end oil and gas prices, proved reserves from these interests represent 22% of the discounted future net cash flows of the trust’s proved reserves at December 31, 2004.
Because these underlying properties are working interests, production expense and development costs are deducted in calculating net profits income from the 75% net profits interests. As a result, net profits income from these interests is affected by the level of maintenance and development activity on these underlying properties. Net profits income is also dependent upon oil and gas sales volumes and prices and is subject to reduction for any prior period excess costs.
Total 2004 development costs were $338,812, up 128% from 2003 development costs of $148,293. January and February 2005 development costs totaled approximately $21,000, and were primarily incurred in fourth quarter 2004.
As reported to XTO Energy by unit operators in February of each year, budgeted development costs were $777,000 for 2004 and $242,000 for 2003. Actual development costs often differ from amounts budgeted because of changes in product prices and other factors that may affect the timing or selection of projects. Also, costs are deducted in the calculation of trust net profits income several months after they are incurred by the operator. Unit operators have reported total budgeted costs, net to the underlying properties, of approximately $272,000 for 2005 and $329,000 for 2006.
In first quarter 2002, total excess costs and accrued interest of $67,484 were incurred on the Texas 75% net profits interests as a result of lower oil prices. There were no excess costs in the remainder of 2002 or in 2003 or 2004. For information regarding the effect of excess costs on trust net profits income, see “Trustee’s Discussion and Analysis—Years Ended December 31, 2004, 2003 and 2002—Costs.”
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) | ||||||||||||
| (in thousands) | Oil (Bbls) | Gas (Mcf) | Oil (Bbls) | Gas (Mcf) | Undiscounted | Discounted | ||||||||
90% Net Profits Interests | ||||||||||||||
San Juan Basin | 50 | 26,584 | 45 | 23,926 | $ | 108,227 | $ | 50,487 | ||||||
Other New Mexico | 72 | 242 | 65 | 201 | 3,804 | 2,045 | ||||||||
Texas | 510 | 3,561 | 459 | 3,205 | 37,467 | 19,022 | ||||||||
Oklahoma | 69 | 2,623 | 62 | 2,296 | 14,519 | 7,302 | ||||||||
Total | 701 | 33,010 | 631 | 29,628 | 164,017 | 78,856 | ||||||||
75% Net Profits Interests | ||||||||||||||
Texas | 1,441 | 759 | 647 | 341 | 25,906 | 12,396 | ||||||||
Oklahoma | 1,315 | 387 | 425 | 125 | 16,241 | 9,339 | ||||||||
Total | 2,756 | 1,146 | 1,072 | 466 | 42,147 | 21,735 | ||||||||
TOTAL | 3,457 | 34,156 | 1,703 | 30,094 | $ | 206,164 | $ | 100,591 | ||||||
| (a) | Based on year-end oil and gas prices. Discounted estimated future net cash flows from proved reserves increased 7% from year-end 2003 to 2004, primarily because of a 38% increase in year-end oil prices over these periods. 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 $15,222,417, as compared with $12,944,047 for 2003 and $9,049,271 for 2002. The 18% increase in net profits income from 2003 to 2004 and the 43% increase in net profits income from 2002 to 2003 was primarily because of increased oil and gas prices. During 2004, 2003 and 2002, 69%, 73% and 67%, respectively, of net profits income was derived from gas sales.
Trust administration expense was $304,390 in 2004 as compared to $259,811 in 2003 and $231,447 in 2002. Increased administration expense is primarily because of increased unitholder reporting expenses related to an increased number of unitholders and the timing of expenditures. Interest income was $6,031 in 2004, $4,510 in 2003 and $4,486 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 production and three months after 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
Oil. Underlying oil sales volumes decreased 8% from 2003 to 2004, as compared to a 12% decrease from 2002 to 2003. Decreased oil sales volumes in 2004 were primarily because of natural production decline, partially offset by the effect of prior period volume adjustments in 2003. Decreased oil sales volumes in 2003 were primarily because of natural production decline and timing of cash receipts.
Gas. Underlying gas sales volumes decreased 3% from 2003 to 2004 as compared to a 12% decrease from 2002 to 2003. Gas sales volumes were higher in 2002 primarily because of a correction of the trust’s interest in properties that were nonproducing at the trust’s inception. Excluding this correction, underlying volumes decreased 8% from 2002 to 2003. Decreased gas sales volumes in 2004 were primarily because of timing of cash receipts and natural production decline, partially offset by prior period volume adjustments in 2003. Decreased gas sales volumes in 2003 were primarily because of natural production decline.
Prices
Oil. The average oil price for 2004 was $35.68 per Bbl, 27% higher than the 2003 average oil price of $28.04, which was 26% higher than the 2002 average price of $22.31. 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, compared with $41.38 for the year 2004 and $48.34 for
fourth quarter 2004. Recent trust oil prices have averaged approximately $4.90 lower than the NYMEX price.
Gas. The 2004 average gas price was $5.73 per Mcf, an 18% increase from the 2003 average gas price of $4.86, which was 74% higher than the 2002 average price of $2.79. 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 compared with $6.18 for the year 2004 and $7.29 for fourth quarter 2004.
Costs
Because properties underlying the 90% net profits interests are royalty and overriding royalty interests, the calculation of net profits income from these interests only includes deductions for production and property taxes, legal costs, and marketing and transportation charges. In addition to these costs, the calculation of net profits income from the 75% net profits interests includes deductions for production expense and development costs since the related underlying properties are working interests. Net profits income is calculated monthly for each of the five conveyances under which the net profits interests were conveyed to the trust. If monthly costs exceed revenues for any conveyance, such excess costs must be recovered, with accrued interest, from future net proceeds of that conveyance and cannot reduce net profits income from other conveyances.
Total costs deducted in the calculation of net profits income were $7.2 million in 2004, $6.6 million in 2003 and $5.7 million in 2002. The 9% increase in costs from 2003 to 2004 is primarily attributable to higher production taxes associated with increased revenues and higher development costs, partially offset by decreased production expense related to the timing of maintenance projects. The 16% increase in costs from 2002 to 2003 is primarily attributable to higher production taxes associated with increased revenues and increased production expense caused by higher fuel costs and the timing of maintenance projects, partially offset by lower development costs. In 2003, lower development costs were related to reduced tertiary injectant costs and drilling activity.
During February and March 2002, costs exceeded revenues by $66,867 ($50,150 net to the trust) for the Texas 75% net profits interests as a result of lower oil prices. Total excess costs and accrued interest of $67,484 ($50,613 net to the trust) were fully recovered in April and May 2002. There were no excess costs or related recoveries in the remainder of 2002 or in 2003 or 2004.
Fourth Quarter 2004 and 2003
During the quarter ended December 31, 2004, the trust received net profits income totaling $4,430,024, compared with fourth quarter 2003 net profits income of $3,404,143. The 30% increase in net profits income from fourth quarter 2003 to 2004 was primarily because of higher oil and gas prices.
Administration expense was $39,424 and interest income was $2,942, resulting in fourth quarter 2004 distributable income of $4,393,542, or $0.732257 per unit. Distributable income for fourth quarter 2003 was $3,355,770, or $0.559295 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 | $0.243651 | ||
November 30, 2004 | December 14, 2004 | 0.249191 | ||
December 31, 2004 | January 14, 2005 | 0.239415 | ||
| $0.732257 | ||||
Volumes
Fourth quarter 2004 underlying oil sales volumes were 68,141 Bbls, or 16% lower than 2003 levels. Oil sales volumes decreased in 2004 because of the timing of cash receipts and natural production decline, partially offset by the effect of prior period volume adjustments in 2003. Underlying gas sales volumes were 651,276 Mcf, or 2% lower than 2003 levels. This decrease in gas sales volumes was primarily because of natural production decline and the timing of cash receipts, partially offset by the effect of prior period volume adjustments in 2003.
Prices
The average fourth quarter 2004 oil price was $43.68 per Bbl, 58% higher than the fourth quarter 2003 average price of $27.73. The average fourth quarter 2004 gas price was $6.15 per Mcf, 21% higher than the fourth quarter 2003 average price of $5.09. For further information about oil and gas prices, see “Years Ended December 31, 2004, 2003 and 2002 – Prices” above.
Costs
Costs deducted in the calculation of fourth quarter 2004 net profits income increased $140,704, or 8%, from fourth quarter 2003. This increase was primarily the result of higher production and property taxes associated with increased revenues, partially offset by decreased production expense related to the timing of maintenance projects.
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 | |||||||||||||||
| 2004 | 2003 | 2002 | 2004 | 2003 | ||||||||||||
Sales Volumes | ||||||||||||||||
Oil (Bbls) (b) | ||||||||||||||||
Underlying properties | 275,792 | 298,869 | 338,975 | 68,141 | 81,504 | |||||||||||
Average per day | 754 | 819 | 929 | 741 | 886 | |||||||||||
Net profits interests | 136,608 | 130,517 | 138,249 | 38,522 | 38,127 | |||||||||||
Gas (Mcf) (b) | ||||||||||||||||
Underlying properties | 2,584,814 | 2,677,460 | 3,029,949 | 651,276 | 661,913 | |||||||||||
Average per day | 7,062 | 7,336 | 8,301 | 7,079 | 7,195 | |||||||||||
Net profits interests | 2,272,853 | 2,337,530 | 2,648,794 | 570,854 | 580,905 | |||||||||||
Average Sales Price | ||||||||||||||||
Oil (per Bbl) | $ | 35.68 | $ | 28.04 | $ | 22.31 | $ | 43.68 | $ | 27.73 | ||||||
Gas (per Mcf) | $ | 5.73 | $ | 4.86 | $ | 2.79 | $ | 6.15 | $ | 5.09 | ||||||
Revenues | ||||||||||||||||
Oil sales | $ | 9,839,883 | $ | 8,381,516 | $ | 7,564,177 | $ | 2,976,382 | $ | 2,260,334 | ||||||
Gas sales | 14,823,564 | 13,020,253 | 8,462,810 | 4,005,420 | 3,369,344 | |||||||||||
Total Revenues | 24,663,447 | 21,401,769 | 16,026,987 | 6,981,802 | 5,629,678 | |||||||||||
Costs | ||||||||||||||||
Taxes, transportation and other | 3,693,129 | 3,078,195 | 2,110,506 | 1,040,195 | 856,009 | |||||||||||
Production expense (c) | 3,124,582 | 3,358,846 | 3,014,706 | 751,573 | 826,869 | |||||||||||
Development costs | 338,812 | 148,293 | 571,680 | 55,861 | 24,047 | |||||||||||
Excess costs | — | — | (66,867 | ) | — | — | ||||||||||
Recovery of excess costs and accrued interest | — | — | 67,484 | — | — | |||||||||||
Total Costs | 7,156,523 | 6,585,334 | 5,697,509 | 1,847,629 | 1,706,925 | |||||||||||
Net Proceeds | $ | 17,506,924 | $ | 14,816,435 | $ | 10,329,478 | $ | 5,134,173 | $ | 3,922,753 | ||||||
Net Profits Income | $ | 15,222,417 | $ | 12,944,047 | $ | 9,049,271 | $ | 4,430,024 | $ | 3,404,143 | ||||||
| (a) | Because of the interval between time of production and receipt of net profits income by the trust, oil and gas sales for the year ended December 31 generally relate to oil production from November through October and gas production from October through September, while oil and gas sales for the three months ended December 31 generally relate to oil production from August through October and gas production from July through September. |
| (b) | Oil and gas sales volumes are allocated to the net profits interests based upon a formula that considers oil and gas prices and the total amount of production expenses and development costs. Changes in any of these factors may result in disproportionate fluctuations in volumes allocated to the net profits interests. Therefore, comparative analysis is based on the underlying properties. |
| (c) | Includes an overhead charge deducted and retained by XTO Energy. As of December 31, 2004, this charge was $26,589 per month (including a monthly overhead charge of $3,324 which XTO Energy deducts as operator of the Penwell Unit) and is subject to adjustment each May based on an oil and gas industry index. |
Cross Timbers Royalty Trust
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
| December 31 | ||||||
| 2004 | 2003 | |||||
Assets | ||||||
Cash and short-term investments | $ | 1,435,478 | $ | 994,389 | ||
Interest to be received | 1,012 | 357 | ||||
Net profits interests in oil and gas properties—net (Notes 1 and 2) | 22,847,694 | 24,665,401 | ||||
| $ | 24,284,184 | $ | 25,660,147 | |||
Liabilities and Trust Corpus | ||||||
Distribution payable to unitholders | $ | 1,436,490 | $ | 994,746 | ||
Trust corpus (6,000,000 units of beneficial interest authorized and outstanding) | 22,847,694 | 24,665,401 | ||||
| $ | 24,284,184 | $ | 25,660,147 | |||
STATEMENTS OF DISTRIBUTABLE INCOME
| Year Ended December 31 | |||||||||
| 2004 | 2003 | 2002 | |||||||
Net profits income | $ | 15,222,417 | $ | 12,944,047 | $ | 9,049,271 | |||
Interest income | 6,031 | 4,510 | 4,486 | ||||||
Total income | 15,228,448 | 12,948,557 | 9,053,757 | ||||||
Administration expense | 304,390 | 259,811 | 231,447 | ||||||
Distributable income | $ | 14,924,058 | $ | 12,688,746 | $ | 8,822,310 | |||
Distributable income per unit (6,000,000 units) | $ | 2.487343 | $ | 2.114791 | $ | 1.470385 | |||
See Accompanying Notes to Financial Statements.
Cross Timbers Royalty Trust
STATEMENTS OF CHANGES IN TRUST CORPUS
| Year Ended December 31 | ||||||||||||
| 2004 | 2003 | 2002 | ||||||||||
Trust corpus, beginning of year | $ | 24,665,401 | $ | 26,556,533 | $ | 28,895,086 | ||||||
Amortization of net profits interests | (1,817,707 | ) | (1,891,132 | ) | (2,338,553 | ) | ||||||
Distributable income | 14,924,058 | 12,688,746 | 8,822,310 | |||||||||
Distributions declared | (14,924,058 | ) | (12,688,746 | ) | (8,822,310 | ) | ||||||
Trust corpus, end of year | $ | 22,847,694 | $ | 24,665,401 | $ | 26,556,533 | ||||||
See Accompanying Notes to Financial Statements.
Cross Timbers Royalty Trust
NOTES TO FINANCIAL STATEMENTS
1. Trust Organization and Provisions
Cross Timbers Royalty Trust was created on February 12, 1991 by predecessors of XTO Energy Inc., when the following net profits interests were conveyed under five separate conveyances to the trust effective October 1, 1990, in exchange for 6,000,000 units of beneficial interest in the trust:
| — | 90% net profits interests in certain producing and nonproducing royalty and overriding royalty interest properties in Texas, Oklahoma and New Mexico, and |
| — | 75% net profits interests in certain nonoperated working interest properties in Texas and Oklahoma. |
The underlying properties from which the net profits interests were carved are currently owned by XTO Energy. Bank of America, N.A. is the trustee of the trust. The trust indenture provides, among other provisions, that:
| — | the trust may not engage in any business activity or acquire any assets other than the net profits interests and specific short-term cash investments; |
| — | the trust may not dispose of all or part of the net profits interests unless approved by 80% of the unitholders, or upon trust termination, and 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 required to pay trust liabilities if fully repaid 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 revenue of the trust is less than $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). |
| — | Interest income, interest to be received and distribution payable to unitholders include interest to be earned on net profits income from the monthly record date (last business day of the month) through the date of the next distribution. |
| — | 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 certain 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 $61,100,449 was XTO Energy’s historical net book value of the interests on February 12, 1991, 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 $38,252,755 as of December 31, 2004 and $36,435,048 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 and other cash receipts, and subtracting liabilities paid and adjustments in cash reserves established by the trustee. The resulting amount (with estimated interest to be received on such amount through the distribution date) is distributed to unitholders of record within ten business days after the monthly record date, 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 the net profits percentage of 90% or 75%. Net proceeds are the gross proceeds received from the sale of production, less applicable costs. For the 90% net profits interests, such costs generally include applicable taxes, transportation, legal and marketing charges, and do not include production expense and development costs. For the 75% net profits interests, such costs include production expense, development and drilling costs, applicable taxes, operating charges and other costs.
XTO Energy, as owner of the underlying properties, computes net profits income separately for each of the five conveyances (Note 1). If costs exceed gross proceeds for any conveyance, such excess costs cannot be used to reduce the amounts to be received under the other conveyances. The trust is
not liable for excess costs; however, such excess costs plus accrued interest are deducted in calculating future net profits income from that conveyance.
4. 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 trust 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.
5. XTO Energy Inc.
The underlying properties include approximately 20 overriding royalty interests in New Mexico that burden working interests owned and operated by XTO Energy. These working interests were purchased by XTO Energy after the net profits interests were conveyed to the trust. As a result of an acquisition in August 2004, XTO Energy became operator of the Penwell Unit which is one of the properties underlying the Texas 75% net profits interests. Other than these properties, XTO Energy does not operate or control any of the underlying properties or related working interests.
In computing net profits income for the 75% net profits interests (Note 3), XTO Energy deducts an overhead charge as reimbursement for costs associated with monitoring these interests. This charge at December 31, 2004 was $23,265 per month, or $279,180 annually (net to the trust of $17,449 per month or $209,388 annually). XTO Energy also deducts an overhead charge as operator of the Penwell Unit. As of December 31, 2004, overhead attributable to the Penwell Unit was $3,324 per month, or $39,888 annually (net to the trust of $2,493 per month or $29,916 annually). These overhead charges are subject to annual adjustment based on an oil and gas industry index.
6. Contingencies
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.
7. 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 which is included in this report.
8. 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 per Unit | |||||||
2004 | |||||||||
First Quarter | $ | 3,116,138 | $ | 3,045,984 | $ | 0.507664 | |||
Second Quarter | 3,658,858 | 3,555,792 | 0.592632 | ||||||
Third Quarter | 4,017,397 | 3,928,740 | 0.654790 | ||||||
Fourth Quarter | 4,430,024 | 4,393,542 | 0.732257 | ||||||
| $ | 15,222,417 | $ | 14,924,058 | $ | 2.487343 | ||||
2003 | |||||||||
First Quarter | $ | 2,662,646 | $ | 2,595,228 | $ | 0.432538 | |||
Second Quarter | 3,755,142 | 3,668,136 | 0.611356 | ||||||
Third Quarter | 3,122,116 | 3,069,612 | 0.511602 | ||||||
Fourth Quarter | 3,404,143 | 3,355,770 | 0.559295 | ||||||
| $ | 12,944,047 | $ | 12,688,746 | $ | 2.114791 | ||||
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Bank of America, N.A., as Trustee for the Cross Timbers Royalty Trust:
We have audited the accompanying statements of assets, liabilities, and trust corpus of the Cross Timbers 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 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 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 Cross Timbers 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 Cross Timbers 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 Cross Timbers 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 Cross Timbers 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 Cross Timbers 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, Cross Timbers 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 Cross Timbers 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
CROSS TIMBERS ROYALTY TRUST
901 Main Street, 17th Floor
P.O. Box 830650
Dallas, Texas 75283-0650
(877) 228-5084
Bank of America, N.A., Trustee
A copy of the Cross Timbers 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.crosstimberstrust.com.
WEB SITE
www.crosstimberstrust.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
