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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2001 Commission file number 1-10982
Cross Timbers Royalty Trust
(Exact name of registrant as specified in the Cross Timbers Royalty Trust
Indenture)
Texas 75-6415930
(State or other jurisdiction (I.R.S. Employer
incorporation or of organization) Identification No.)
Bank of America, N.A. 75283-0650
Trustee (Zip Code)
P.O. Box 830650
Dallas, Texas
(Address of principal executive offices)
Registrant's telephone number including area code: (877) 228-5084
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Name of each exchange on which registered
------------------- -----------------------------------------
Units of Beneficial Interest New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes __X__ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
At March 1, 2002, there were 6,000,000 units of beneficial interest of the
trust outstanding. The aggregate market value of the units (based on the
closing price on the New York Stock Exchange on March 1, 2002) held by
non-affiliates of the registrant on that date was approximately $84.1 million.
DOCUMENTS INCORPORATED BY REFERENCE
Listed below is the only document parts of which are incorporated herein by
reference and the parts of this report into which the document is incorporated:
2001 Annual Report to Unitholders--Part II
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PART I
Item 1. Business
Cross Timbers Royalty Trust is an express trust created under the laws of
Texas pursuant to the Cross Timbers Royalty Trust Indenture entered into on
February 12, 1991 between predecessors of XTO Energy Inc., as grantors, and
NCNB Texas National Bank, as trustee. Bank of America, N.A., successor of NCNB
Texas National Bank, is now the trustee of the trust. The principal office of
the trust is located at 901 Main Street, Dallas, Texas 75202 (telephone number
877-228-5084).
On February 12, 1991, the predecessors of XTO Energy (formerly known as
Cross Timbers Oil Company) conveyed defined net profits interests to the trust
under five separate conveyances:
-- one in each of the states of Texas, Oklahoma and New Mexico, to convey a
90% defined net profits interest carved out of substantially all royalty
and overriding royalty interests owned by the predecessors in those
states, and
-- one in each of the states of Texas and Oklahoma, to convey a 75% defined
net profits interest carved out of specific working interests owned by
the predecessors in those states.
The conveyance of these net profits interests was effective for production
from October 1, 1990. The net profits interests and the underlying properties
are further described under Item 2.
In exchange for the conveyance of the net profits interests to the trust,
the predecessors of XTO Energy received 6,000,000 units of beneficial interest
of the trust. Predecessors of XTO Energy distributed units to their owners in
February 1991 and November 1992, and in February 1992, sold units in the
trust's initial public offering. Units are listed and traded on the New York
Stock Exchange under the symbol "CRT." During 1996 and 1997, XTO Energy's Board
of Directors authorized XTO Energy to purchase two million units. As of
March 1, 2002, XTO Energy owned 1,360,000 units, or 22.7%, of the outstanding
units.
In June 1998 the trust and XTO Energy filed a registration statement with
the Securities and Exchange Commission to sell the 1,360,000 units held by XTO
Energy. As XTO Energy stated in a related news release, the filing was made in
anticipation of better commodity prices and any sale is dependent on an
improved market for oil and gas equities. The registration statement was
amended in October 2000 and June 2001. As of March 27, 2002, no sales have been
made under the registration statement. The trust did not participate in XTO
Energy's decisions to acquire or sell units and will not receive any of the
proceeds in the event of such sale.
Under the terms of each of the five conveyances, the trust receives net
profits income from the net profits interests on the last business day of each
month. Net profits income is determined by XTO Energy by multiplying the net
profit percentage (90% or 75%) times net proceeds from the underlying
properties for each of the five conveyances during the previous month. Net
proceeds are the gross proceeds received from the sale of production, less
production costs. For the 90% net profits interests and the 75% net profits
interests, "production costs" generally include applicable property taxes,
transportation, marketing and other charges. For the 75% net profits interests
only, production costs also include capital and operating costs paid (e.g.,
drilling, production and other direct costs of owning and operating the
property) and a monthly overhead charge that is adjusted annually. The monthly
overhead charge at December 31, 2001 was $23,925. If production costs exceed
gross proceeds for any conveyance, such excess is carried forward to the
computation of net proceeds for future months until the excess costs (plus
interest accrued as specified in the conveyances) are completely recovered.
Such excess production costs and related accrued interest from one conveyance
cannot be used to reduce net proceeds from any other conveyance.
The trust is not liable for any production costs or liabilities attributable
to the net profits interests. If at any time the trust receives net profits
income in excess of the amount due, the trust is not obligated to return such
overpayment, but net profits income payable to the trust for the next month
will be reduced by the overpayment, plus interest at the prime rate.
1
With the exception of working interests from which approximately 20
overriding royalty interests in the San Juan Basin were conveyed, XTO Energy
does not operate or control any of the underlying properties or related working
interests. As a working interest owner, XTO Energy can generally decline
participation in any operation and allow consenting parties to conduct such
operations, as provided under the operating agreements. XTO Energy also can
assign, sell, or otherwise transfer its interest in the underlying properties,
subject to the net profits interests, or can abandon an underlying property
that is a working interest if it is incapable of producing in paying
quantities, as determined by XTO Energy.
To the extent it has the right to do so, XTO Energy is responsible for
marketing its production from the underlying properties under existing sales
contracts or new arrangements on the best terms reasonably obtainable in the
circumstances.
Net profits income received by the trust on or before the last business day
of the month generally represents receipts attributable to oil production two
months prior and gas production three months prior. The monthly distribution
amount to unitholders is determined by:
Adding--
(1) net profits income received,
(2) estimated interest income to be received on the monthly distribution
amount, including an adjustment for the difference between the estimated
and actual interest received for the prior monthly distribution amount,
(3) cash available as a result of reduction of cash reserves, and
(4) any other cash receipts, and
Subtracting the sum of--
(1) liabilities paid and
(2) the reduction in cash available due to establishment of or increase in
any cash reserve.
The monthly distribution amount is distributed to unitholders of record
within ten business days after the monthly record date. The monthly record date
is generally the last business day of the month. The trustee calculates the
monthly distribution amount and announces the distribution per unit at least
ten days prior to the monthly record date.
The trustee may establish cash reserves for contingencies. Cash held for
such reserves, as well as for pending payment of the monthly distribution
amount may be invested in federal obligations or certificates of deposit of
major banks.
The trustee's function is to collect the net profits income from the net
profits interests, to pay all trust expenses and pay the monthly distribution
amount to unitholders. The trustee's powers are specified by the terms of the
indenture. The trust cannot engage in any business activity or acquire any
assets other than the net profits interests and specific short-term cash
investments. The trust has no employees since all administrative functions are
performed by the trustee.
Approximately 77% of the net profits income received by the trust during
2001, as well as 76% of the estimated proved reserves of the net profits
interests at December 31, 2001 (based on estimated future net revenues using
year-end oil and gas prices), is attributable to natural gas. There has
historically been a greater demand for gas during the winter months than the
rest of the year. Otherwise, trust income is not subject to seasonal factors,
nor dependent upon patents, licenses, franchises or concessions. The trust
conducts no research activities.
Item 2. Properties
The net profits interests are the principal asset of the trust. The trustee
cannot acquire any other asset, with the exception of certain short-term
investments as specified under Item 1. The trustee is prohibited from selling
any portion of the net profits interests unless approved by at least 80% of the
unitholders or at such time as trust gross revenue is less than $1,000,000 for
two successive years.
2
The net profits interests are composed of:
--the 90% net profits interests which are carved from:
a) producing royalty and overriding royalty interest properties in Texas,
Oklahoma and New Mexico, and
b) 11.11% non-participating royalty interests in nonproducing properties
located primarily in Texas and Oklahoma;
--the 75% net profits interests which are carved from nonoperated working
interests in four properties in Texas and three properties in Oklahoma.
All underlying royalties, underlying nonproducing royalties and underlying
working interest properties are currently owned by XTO Energy. XTO Energy may
sell all or any portion of the underlying properties at any time, subject to
and burdened by the net profits interests.
Producing Acreage, Wells and Drilling
Underlying Royalties. The underlying royalties are royalty and overriding
royalty interests primarily located in mature producing oil and gas fields. The
most significant producing region in which the underlying royalties are located
is the San Juan Basin in northwestern New Mexico. The trust's estimated proved
reserves from this region totaled 26.1 Bcf at December 31, 2001, or
approximately 82% of trust total gas reserves at that date. XTO Energy
estimates that underlying royalties in the San Juan Basin include more than
2,000 gross (approximately 30 net) wells, covering over 60,000 gross acres.
Most of these wells are operated by Amoco Production Company or Burlington
Resources Oil & Gas Company. Production from conventional gas wells is
primarily from the Dakota, Mesaverde and Pictured Cliffs formations.
Approximately 26% of trust 2001 gas sales volumes were from coal seam
production in the San Juan Basin. Through the year 2002, sales of certain coal
seam gas qualify for a federal income tax credit. See "Regulation--Coal Seam
Tax Credit." Operators are seeking approval to increase the density of coal
seam wells drilled in the San Juan Basin. XTO Energy anticipates that hearings
on the request will be held in June 2002. Although XTO Energy believes that the
outlook for approval of increased density drilling is good, there can be no
assurance that such an increase will be approved.
Most of the trust's San Juan Basin conventional, or non-coal seam,
production is from the Mesaverde formation. This formation has been approved
for increased density drilling, doubling the number of drill wells allowed to
four per spacing unit. XTO Energy has advised the trustee that it believes
operators will further develop the Mesaverde formation underlying the net
profits interests, and such future development could significantly impact
underlying gas sales volumes. There was minimal drilling in 2001 because of
environmental concerns that delayed the approval of drilling permits.
During 1996, additional eastward pipeline capacity was completed in the San
Juan Basin, reducing the dependence of San Juan Basin gas on California markets
and effectively increasing San Juan Basin gas prices in relation to prices from
other regions. Gas-powered electricity generation continues to increase in the
southwest U.S., thereby increasing demand for San Juan Basin gas. Additional
eastward pipeline capacity for western Canadian gas supplies, which previously
were primarily directed to U.S. West Coast markets, has also improved the
market for San Juan Basin gas.
The underlying royalties also include royalties in the Sand Hills field of
Crane County, Texas. Most of these properties are operated by ExxonMobil
Corporation or Chevron, U.S.A. The Sand Hills field was discovered in 1931 and
includes production from three main intervals, the Tubb, McKnight and Judkins.
Development potential for the field includes recompletions and additional
infill drilling.
The underlying royalties contain approximately 462,000 gross (approximately
26,000 net) producing acres. Well counts for the underlying royalties cannot be
provided because information regarding the number of wells on royalty
properties is generally not made available to royalty interest owners.
3
Underlying Working Interest Properties. The underlying working interest
properties, detailed below, are developed properties undergoing secondary or
tertiary recovery operations:
Ownership of
XTO Energy
----------------
Working Revenue
Unit County/State Operator Interest Interest
----------------------- --------------- ------------------------- -------- --------
North Cowden Ector/Texas Occidental Permian, Ltd. 1.7% 1.4%
North Central Levelland Hockley/Texas ExxonMobil Corporation 3.2% 2.1%
Penwell Ector/Texas Texaco Exploration 5.2% 4.6%
and Production, Inc.
Sharon Ridge Canyon Borden/Texas ExxonMobil Corporation 4.3% 2.8%
Hewitt Carter/Oklahoma ExxonMobil Corporation 11.3% 9.9%
Wildcat Jim Penn Carter/Oklahoma LeNorman Partners, L.L.C. 8.6% 7.5%
South Graham Deese Carter/Oklahoma Maynard Oil Company 8.2% 7.0%
The underlying working interest properties consist of 60,154 gross (2,290
net) producing acres. As of December 31, 2001, there were 1,525 gross (70.0
net) productive oil wells, 1,015 gross (43.4 net) injection wells and two wells
in process of drilling on these properties. During 2001, 50 gross (1.4 net)
wells were drilled, during 2000, 12 gross (0.2 net) wells were drilled and
during 1999, eight gross (0.1 net) wells were drilled. Nine gross (0.2 net)
wells drilled in 2001 were water injections wells.
Oil and Gas Production
Trust production is recognized in the period net profits income is received,
which is the month following receipt by XTO Energy, and generally two months
after the time of oil production and three months after gas production. Oil and
gas production and average sales prices attributable to the underlying
properties and the net profits interests for the three years ended December 31,
2001 were as follows:
90% Net Profits Interests 75% Net Profits Interests Total
----------------------------- ------------------------- -----------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
Production --------- --------- --------- ------- ------- ------- --------- --------- ---------
Underlying Properties
Oil--Sales (Bbls)........ 92,329 86,970 92,650 258,362 257,153 255,959 350,691 344,123 348,609
Average per day (Bbls).. 253 238 254 708 702 701 961 940 955
Gas--Sales (Mcf)......... 2,845,132 2,964,687 3,548,594 87,071 115,914 94,429 2,932,203 3,080,601 3,643,023
Average per day (Mcf)... 7,795 8,100 9,722 238 317 259 8,033 8,417 9,981
Net Profits Interests
Oil--Sales (Bbls)........ 82,745 76,959 77,783 62,933 86,260 19,894 145,678 163,219 97,677
Average per day (Bbls).. 227 210 213 172 236 55 399 446 268
Gas--Sales (Mcf)......... 2,530,916 2,659,139 3,152,693 21,291 30,120 10,249 2,552,207 2,689,259 3,162,942
Average per day (Mcf)... 6,934 7,266 8,638 58 82 28 6,992 7,348 8,666
Average Sales Price
Oil (per Bbl)............ $24.22 $26.41 $14.54 $25.26 $27.85 $15.01 $24.99 $27.49 $14.88
Gas (per Mcf)............ $ 5.14 $ 3.36 $ 2.01 $ 3.31 $ 2.28 $ 1.35 $ 5.09 $ 3.32 $ 1.99
Nonproducing Acreage
The underlying nonproducing royalties contain approximately 200,000 gross
(approximately 3,000 net) acres in Texas, Oklahoma and New Mexico which were
nonproducing at the date of the trust's creation. XTO Energy is the owner of
underlying mineral interests in the majority of this acreage. The trust is
entitled to 10% of oil and gas production attributable to the underlying
mineral properties, but is not entitled to delay rental payments or lease
bonuses. There has been no significant development of such nonproducing acreage
since the trust's creation.
4
Pricing and Sales Information
Oil and gas are generally sold from the underlying properties at
market-sensitive prices. The majority of sales from the underlying working
interest properties are to major oil and gas companies. Information about
purchasers of oil and gas from royalty properties is generally not provided by
operators to XTO Energy as a royalty owner, or to the trust.
Oil and Natural Gas Reserves
General
Miller and Lents, Ltd., independent petroleum engineers, has estimated oil
and gas reserves attributable to the underlying properties and net profits
interests as of December 31, 2001, 2000, 1999 and 1998. Numerous uncertainties
are inherent in estimating reserve volumes and values, and such estimates are
subject to change as additional information becomes available. The reserves
actually recovered and the timing of production of these reserves may be
substantially different from the original estimates.
Reserve quantities and revenues for the net profits interests were estimated
from projections of reserves and revenues attributable to the combined
interests of the trust and XTO Energy in the subject properties. Since the
trust has defined net profits interests, the trust does not own a specific
percentage of the oil and gas reserve quantities. Accordingly, reserves
allocated to the trust pertaining to its 75% net profits interests in the
working interest properties have effectively been reduced to reflect recovery
of the trust's 75% portion of applicable production and development costs.
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.
The standardized measure of discounted future net cash flows and changes in
such discounted cash flows as presented below are prepared using assumptions
required by the Financial Accounting Standards Board. Such assumptions include
the use of year-end prices for oil and gas and year-end costs for estimated
future development and production expenditures to produce the proved reserves.
Because natural gas prices are influenced by seasonal demand, use of year-end
prices, as required by the Financial Accounting Standards Board, may not be the
most representative in estimating future revenues or reserve data. Future net
cash flows are discounted at an annual rate of 10%. No provision is included
for federal income taxes since future net revenues are not subject to taxation
at the trust level.
Year-end oil prices used to determine the standardized measure were based on
a West Texas Intermediate crude oil posted price of $16.75 per Bbl in 2001,
$23.75 per Bbl in 2000, $22.75 per Bbl in 1999 and $9.50 per Bbl in 1998. The
year-end weighted average realized gas prices used to determine the
standardized measure were $2.28 per Mcf in 2001, $9.48 per Mcf in 2000, $2.19
per Mcf in 1999 and $1.88 per Mcf in 1998.
5
Proved Reserves
Net Profits Interests
---------------------------------------------------
90% Net Profits 75% Net Profits Underlying
Interests Interests Total Properties
(in thousands) --------------- --------------- ----------------- -----------------
Oil Gas Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
------ -------- ------- ------ ------- -------- ------- --------
Balance, December 31, 1998... 676.5 36,453.2 247.1 65.3 923.6 36,518.5 2,409.9 41,733.4
Extensions, discoveries
and other additions....... 10.5 162.2 -0- -0- 10.5 162.2 13.1 186.0
Revisions of prior estimates 109.9 1,462.1 1,251.8 533.4 1,361.7 1,995.5 2,385.7 2,322.0
Production.................. (77.8) (3,152.7) (19.9) (10.2) (97.7) (3,162.9) (348.6) (3,643.0)
----- -------- ------- ------ ------- -------- ------- --------
Balance, December 31, 1999... 719.1 34,924.8 1,479.0 588.5 2,198.1 35,513.3 4,460.1 40,598.4
Extensions, discoveries and
other additions........... 3.2 77.1 -0- -0- 3.2 77.1 3.5 85.7
Revisions of prior estimates 32.7 1,864.4 33.2 14.0 65.9 1,878.4 123.5 1,773.5
Production.................. (77.0) (2,659.1) (86.2) (30.1) (163.2) (2,689.2) (344.1) (3,080.6)
----- -------- ------- ------ ------- -------- ------- --------
Balance, December 31, 2000... 678.0 34,207.2 1,426.0 572.4 2,104.0 34,779.6 4,243.0 39,377.0
Extensions, discoveries and
other additions........... 12.3 247.8 -0- -0- 12.3 247.8 13.7 274.8
Revisions of prior estimates 6.9 (486.5) (678.2) (282.9) (671.3) (769.4) (483.6) (713.2)
Production.................. (82.8) (2,530.9) (62.9) (21.3) (145.7) (2,552.2) (350.7) (2,932.2)
----- -------- ------- ------ ------- -------- ------- --------
Balance, December 31, 2001... 614.4 31,437.6 684.9 268.2 1,299.3 31,705.8 3,422.4 36,006.4
===== ======== ======= ====== ======= ======== ======= ========
Revisions of prior estimates of the 75% net profits interests' proved
reserves and the underlying properties' proved oil reserves in each of the
years above were primarily the result of changes in the year-end oil prices
used in estimating proved reserves. During 2000 and 1999, upward revisions of
the 90% net profits interests' proved gas reserves were primarily because of
lower than anticipated production declines. Downward revisions of the 90% net
profits interests in 2001 were primarily because of significantly lower
year-end prices. Higher upward and downward revisions for the net profits
interests as compared to underlying properties in 2001 and 2000 were caused by
year-end price fluctuations which resulted in increased gas reserves allocated
to or from the trust. See "General" above.
Proved Developed Reserves
Net Profits Interests
------------------------------------------------
90% Net Profits 75% Net Profits Underlying
Interests Interests Total Properties
(in thousands) --------------- --------------- ---------------- ----------------
Oil Gas Oil Gas Oil Gas Oil Gas
(Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf)
------ -------- ------- ----- ------- -------- ------- --------
December 31, 1998 672.8 34,514.0 206.4 60.7 879.2 34,574.7 2,195.1 39,520.1
===== ======== ======= ===== ======= ======== ======= ========
December 31, 1999 715.7 33,036.5 1,375.0 570.3 2,090.7 33,606.8 4,245.6 38,463.3
===== ======== ======= ===== ======= ======== ======= ========
December 31, 2000 675.0 32,371.1 1,317.8 553.5 1,992.8 32,924.6 4,028.8 37,300.0
===== ======== ======= ===== ======= ======== ======= ========
December 31, 2001 611.4 29,608.5 602.0 253.7 1,213.4 29,862.2 3,208.3 33,937.3
===== ======== ======= ===== ======= ======== ======= ========
6
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
90% Net Profits Interests 75% Net Profits Interests Total
----------------------------- --------------------------- -----------------------------
December 31, December 31, December 31,
(in thousands) ----------------------------- --------------------------- -----------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
-------- --------- -------- ------- -------- -------- -------- --------- --------
Net Profits Interests
Future cash inflows.... $ 87,042 $ 347,874 $ 97,902 $12,275 $ 40,146 $ 36,670 $ 99,317 $ 388,020 $134,572
Future production taxes (6,945) (28,042) (7,751) (831) (2,786) (2,487) (7,776) (30,828) (10,238)
-------- --------- -------- ------- -------- -------- -------- --------- --------
Future net cash flows.. 80,097 319,832 90,151 11,444 37,360 34,183 91,541 357,192 124,334
10% discount factor.... (42,004) (169,073) (46,573) (5,493) (18,692) (17,135) (47,497) (187,765) (63,708)
-------- --------- -------- ------- -------- -------- -------- --------- --------
Standardized measure... $ 38,093 $ 150,759 $ 43,578 $ 5,951 $ 18,668 $ 17,048 $ 44,044 $ 169,427 $ 60,626
======== ========= ======== ======= ======== ======== ======== ========= ========
Underlying Properties
Future cash inflows................................................................ $145,759 $ 484,675 $200,075
Future costs:
Production....................................................................... (40,984) (78,973) (52,858)
Development...................................................................... (520) (520) (517)
-------- --------- --------
Future net cash flows.............................................................. 104,255 405,182 146,700
10% discount factor................................................................ (53,994) (212,781) (74,879)
-------- --------- --------
Standardized measure............................................................... $ 50,261 $ 192,401 $ 71,821
======== ========= ========
7
Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves
90% Net Profits Interests 75% Net Profits Interests Total
(in thousands) ---------------------------- -------------------------- ----------------------------
2001 2000 1999 2001 2000 1999 2001 2000 1999
--------- -------- ------- -------- ------- ------- --------- -------- -------
Net Profits Interests
Standardized measure,
January 1...................... $ 150,759 $ 43,578 $34,584 $ 18,668 $17,048 $ 1,192 $ 169,427 $ 60,626 $35,776
Extensions, discoveries
and other additions.......... 507 461 384 -0- -0- -0- 507 461 384
Accretion of discount......... 12,702 3,683 3,078 1,614 1,476 106 14,316 5,159 3,184
Revisions of prior estimates,
changes in price and other... (113,093) 112,338 11,864 (12,724) 2,504 16,109 (125,817) 114,842 27,973
Net profits income............ (12,782) (9,301) (6,332) (1,607) (2,360) (359) (14,389) (11,661) (6,691)
--------- -------- ------- -------- ------- ------- --------- -------- -------
Standardized measure,
December 31.................... $ 38,093 $150,759 $43,578 $ 5,951 $18,668 $17,048 $ 44,044 $169,427 $60,626
========= ======== ======= ======== ======= ======= ========= ======== =======
Underlying Properties
Standardized measure, January 1........................................................... $ 192,401 $ 71,821 $40,593
--------- -------- -------
Revisions:
Prices and costs........................................................................ (140,000) 122,144 12,549
Quantity estimates...................................................................... (1,581) 7,162 22,311
Accretion of discount................................................................... 16,265 6,060 3,561
Future development costs................................................................ (1,091) (738) (697)
Other................................................................................... 49 (1,079) 591
--------- -------- -------
Net revisions......................................................................... (126,358) 133,549 38,315
Extensions, additions and discoveries..................................................... 563 512 427
Production................................................................................ (17,479) (14,220) (8,250)
Development costs......................................................................... 1,134 739 736
--------- -------- -------
Net change............................................................................ (142,140) 120,580 31,228
--------- -------- -------
Standardized measure, December 31......................................................... $ 50,261 $192,401 $71,821
========= ======== =======
Discounted Present Value of the Coal Seam Tax Credit
The standardized measure above does not include the effects of the coal seam
tax credit since the trust is not a taxable entity. The following table
summarizes the estimated coal seam tax credit attributable to the 90% net
profits interests at December 31, 2001, 2000 and 1999. Such estimates are based
on projected coal seam gas production through the year 2002 (after which date
the tax credit may no longer be available) as estimated by independent
engineers. The estimates are also based on the current year estimated Btu
content and the coal seam tax credit of $1.08 per MMBtu at December 31, 2001,
$1.06 per MMBtu at December 31, 2000 and $1.02 per MMBtu at December 31, 1999.
See "Regulation--Coal Seam Tax Credit."
December 31,
(in thousands) --------------------
2001 2000 1999
------ ------ ------
Undiscounted................... $ 922 $1,225 $1,979
====== ====== ======
Discounted present value at 10% $ 880 $1,120 $1,740
====== ====== ======
Reversion Agreement
Certain of the underlying royalties are subject to a reversion agreement
between XTO Energy and a third party. The agreement calls for XTO Energy to
transfer 25% of its interest in those properties to the third party when
amounts received by XTO Energy from the underlying properties subject to the
agreement equal the purchase price of the properties plus a 1% per month return
on the unrecouped purchase price, known as payout. If payout were to occur and
the 25% interest were to be transferred to the third party, the amounts payable
to the trust would be proportionately reduced. Based on 2001 prices and levels
of production, XTO Energy has advised
8
the trustee that payout is not projected to occur for approximately 20 years.
Unless higher prices and production are sustained for several years, this
reversion agreement is not expected to have a material impact on the trust.
Regulation
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates charged and various other
matters, by the Federal Energy Regulatory Commission (FERC). Federal price
controls on wellhead sales of domestic natural gas terminated on January 1,
1993. While natural gas prices are currently unregulated, Congress historically
has been active in the area of natural gas regulation. It is impossible to
predict whether new legislation to regulate natural gas might be proposed, what
proposals, if any, might actually be enacted by Congress or the various state
legislatures, and what effect, if any, such proposals might have on the
operations of the underlying properties.
State Regulation
The various states regulate the production and sale of oil and natural gas,
including imposing requirements for obtaining drilling permits, the method of
developing new fields, the spacing and operation of wells and the prevention of
waste of oil and gas resources. The rates of production may be regulated and
the maximum daily production allowables from both oil and gas wells may be
established on a market demand or conservation basis, or both.
Coal Seam Tax Credit
The trust receives net profits income from coal seam gas wells. Under
Section 29 of the Internal Revenue Code, coal seam gas produced through the
year 2002 from wells drilled after December 31, 1979 and prior to January 1,
1993 qualifies for the federal income tax credit for producing nonconventional
fuels. This tax credit for 2001 was approximately $1.08 per MMBtu. Such credit,
calculated based on the unitholder's pro rata share of qualifying production,
may not reduce the unitholder's regular tax liability (after the foreign tax
credit and certain other nonrefundable credits) below his tentative minimum
tax. Any part of the Section 29 credit not allowed for the tax year solely
because of this limitation is subject to certain carryover provisions.
Congress is considering an extension of existing energy tax credits beyond
the scheduled December 31, 2002 expiration date, as well as the creation of
similar new tax credits. During 2001, the U.S. House passed a bill that would
extend existing Section 29 tax credits on certain production, while the U.S.
Senate is considering a separate bill to address energy tax credits, including
Section 29. The potential effect of any final legislation on unitholders is
unknown.
In 1999, a U.S. Court of Appeals held that a well drilled and completed in
an otherwise qualifying formation prior to January 1, 1993 is not eligible for
the Section 29 credit unless the producer received an appropriate well category
determination from the FERC. The decision indicated that lack of a well
category determination may render the Section 29 credit unavailable with
respect to production from wells recompleted in a qualified formation after
January 1, 1993, the date that the FERC's authority to render category
determinations ended. Effective September 2000, the FERC amended its
regulations to reinstate certain regulations to allow it to provide well
category determinations for Section 29 tax credits for well recompletions
commenced after January 1, 1993.
Other Regulation
The petroleum industry is also subject to compliance with various other
federal, state and local regulations and laws, including, but not limited to,
regulations and laws relating to environmental protection, occupational safety,
resource conservation and equal employment opportunity. XTO Energy has advised
the trustee that it does not believe that compliance with these laws will have
any material adverse effect upon the unitholders.
9
Item 3. Legal Proceedings
Certain of the trust properties are involved in various 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.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of unitholders during 2001.
10
PART II
Item 5. Market for Units of the Trust and Related Security Holder Matters
The section entitled "Units of Beneficial Interest" on page 1 of the trust's
annual report to unitholders for the year ended December 31, 2001 is
incorporated herein by reference.
Item 6. Selected Financial Data
Year Ended Decxember 31,
-----------------------------------------------------------
2001 2000 1999 1998 1997
----------- ----------- ----------- ----------- -----------
Net Profits Income........... $14,389,316 $11,660,510 $ 6,691,336 $ 7,079,632 $10,549,668
Distributable Income......... 14,209,884 11,502,114 6,549,803 6,927,338 10,407,250
Distributable Income per Unit 2.368314 1.917019 1.091635 1.154555 1.734541
Distributions per Unit....... 2.368314 1.917019 1.091635 1.154555 1.734541
Total Assets at Year-End..... 29,747,914 31,806,794 33,919,338 36,554,480 38,767,918
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The "Trustee's Discussion and Analysis" of financial condition and results
of operations for the three-year period ended December 31, 2001 on pages 6
through 8 of the trust's annual report to unitholders for the year ended
December 31, 2001 is incorporated herein by reference.
Liquidity and Capital Resources
The trust's only cash requirement is the monthly distribution of its income
to unitholders, which is funded by the monthly receipt of net profits income
after payment of trust administration expenses. The trust is not liable for any
production costs or liabilities attributable to the net profits interests. If
at any time the trust receives net profits income in excess of the amount due,
the trust is not obligated to return such overpayment, but future net profits
income payable to the trust will be reduced by the overpayment, plus interest
at the prime rate. The trust may borrow funds required to pay trust liabilities
if fully repaid prior to further distributions to unitholders.
The trust does not have any transactions, arrangements or other
relationships with unconsolidated entities or persons that could materially
affect the trust's liquidity or the availability of capital resources.
Contractual Obligations and Commitments
The trust had no obligations and commitments to make future contractual
payments as of December 31, 2001, other than the December distribution payable
to unitholders in January 2002, as reflected in the statement of assets,
liabilities and trust corpus. The trust has not guaranteed the debt of any
other party, nor does the trust have any other arrangements or relationships
with other entities that could potentially result in unconsolidated debt.
Related Party Transactions
The underlying properties are currently owned by XTO Energy. As of March 1,
2002, XTO Energy owned 1,360,000, or 22.7%, of the 6,000,000 outstanding units.
XTO Energy deducts an overhead charge from monthly net proceeds as
reimbursement for costs associated with monitoring the 75% net profits
interests. As of December 31, 2001, this monthly charge was $23,925 ($17,944
net to the trust) and is subject to annual adjustment based on an oil and gas
industry index. For further information regarding the trust's relationship with
XTO Energy, see Note 6 to Financial Statements in the accompanying annual
report.
11
Critical Accounting Policies
The financial statements of the trust are significantly affected by its
basis of accounting and estimates related to its oil and gas properties and
proved reserves, as summarized below.
Basis of Accounting
The trust's financial statements are prepared on a modified cash basis,
which is a comprehensive basis of accounting other than generally accepted
accounting principles. This method of accounting is consistent with reporting
of taxable income to trust unitholders. 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.
For further information regarding the trust's basis of accounting, see Note
2 to Financial Statements in the accompanying annual report.
All amounts included in the trust's financial statements are based on cash
amounts received or disbursed, or on the carrying value of the net profits
interests, which was derived from the historical cost of the interests at the
date of their transfer from XTO Energy. Accordingly, there are no fair value
estimates included in the financial statements based on either exchange or
non-exchange trade values.
Oil and Gas Reserves
The trust's proved oil and gas reserves are estimated by independent
petroleum engineers. Reserve engineering is a subjective process that is
dependent upon the quality of available data and the interpretation thereof.
Estimates by different engineers often vary, sometimes significantly. In
addition, physical factors such as the results of drilling, testing and
production subsequent to the date of an estimate, as well as economic factors
such as changes in product prices, may justify revision of such estimates.
Because proved reserves are required to be estimated using prices at the date
of the evaluation, estimated reserve quantities can be significantly impacted
by changes in product prices. Accordingly, oil and gas quantities ultimately
recovered and the timing of production may be substantially different from
original estimates.
The standardized measure of discounted future net cash flows and changes in
such cash flows, as reported in Item 2 of the trust's Annual Report on Form
10-K, is prepared using assumptions required by the Financial Accounting
Standards Board and the Securities and Exchange Commission. Such assumptions
include using year-end oil and gas prices and year-end costs for estimated
future development and production expenditures. Discounted future net cash
flows are calculated using a 10% rate. Changes in any of these assumptions,
including consideration of other factors, could have a significant impact on
the standardized measure. Accordingly, the standardized measure does not
represent XTO Energy's or the trustee's estimated current market value of
proved reserves.
Forward-Looking Statements
Certain information included in this annual report and other materials
filed, or to be filed, by the trust with the Securities and Exchange Commission
(as well as information included in oral statements or other written statements
made or to be made by XTO Energy or the trustee) contain forward-looking
statements within the meaning of Section 21E of the Securities Exchange Act of
1934, as amended, and Section 27A of the Securities Act of 1933, as amended,
relating to the trust operations of the underlying properties and the oil and
gas industry. Such forward-looking statements may concern, among other things,
development activities, maintenance projects, development, production and other
costs, oil and gas prices, pricing differentials, proved reserves,
12
production levels, litigation, regulatory matters and competition. Such
forward-looking statements are based on XTO Energy's current plans,
expectations, assumptions, projections and estimates and are identified by
words such as "expects," "intends," "plans," "projects," " anticipates,"
"predicts," "believes," "goals," "estimates," "should," "could", and similar
words that convey the uncertainty of future events. These statements are not
guarantees of future performance and involve certain risks, uncertainties and
assumptions that are difficult to predict. Therefore, actual results may differ
materially from expectations, estimates or assumptions expressed in, implied
in, or forecasted in such forward-looking statements. Any number of factors
could cause actual results to differ materially, including, but not limited to,
crude oil and natural gas price fluctuations, changes in the underlying demand
for oil and natural gas, changes in ownership and/or the operator of the
underlying properties, the timing and results of development activity, the
availability of drilling equipment, as well as general domestic and
international economic and political conditions.
Item 7a. Quantitative and Qualitative Disclosures about Market Risk
The only assets of and sources of income to the trust are the net profits
interests, which generally entitle the trust to receive a share of the net
profits from oil and gas production from the underlying properties.
Consequently, the trust is exposed to market risk from fluctuations in oil and
gas prices. The trust is a passive entity and, other than the trust's ability
to periodically borrow money as necessary to pay expenses, liabilities and
obligations of the trust that cannot be paid out of cash held by the trust, the
trust is prohibited from engaging in borrowing transactions. The amount of any
such borrowings is unlikely to be material to the trust. In addition, the
trustee is prohibited by the trust indenture from engaging in any business
activity or causing the trust to enter into any investments other than
investing cash on hand in specific short-term cash investments. Therefore, the
trust cannot hold any derivative financial instruments. As a result of the
limited nature of its borrowing and investing activities, the trust is not
subject to any material interest rate market risk. Additionally, any gains or
losses from any hedging activities conducted by XTO Energy are specifically
excluded from the calculation of net proceeds due the trust under the forms of
the conveyances. The trust does not engage in transactions in foreign
currencies which could expose the trust to any foreign currency related market
risk.
Item 8. Financial Statements and Supplementary Data
The financial statements of the trust and the notes thereto, together with
the related report of Arthur Andersen LLP dated March 19, 2002, appearing on
pages 9 through 12 of the trust's annual report to unitholders for the year
ended December 31, 2001 are incorporated herein by reference.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
There have been no changes in accountants or disagreements with accountants
on any matter of accounting principles or practices or financial statement
disclosures during the two years ended December 31, 2001.
13
PART III
Item 10. Directors and Executive Officers of the Registrant
The trust has no directors or executive officers. The trustee is a corporate
trustee which may be removed, with or without cause, by the affirmative vote of
the holders of a majority of all the units then outstanding.
Item 11. Executive Compensation
The trustee received the following annual compensation from 1999 through
2001 as specified in the trust indenture:
Other Annual
Name and Principal Position Year Compensation (1)
------------------------------ ---- ----------------
Bank of America, N.A., Trustee 2001 $7,195
2000 5,830
1999 3,346
(1) Under the trust indenture, the trustee is entitled to an administrative fee
of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of
the trust, and 1/30 of 1% of the annual gross revenue of the trust in
excess of $100 million, and (ii) trustee's standard hourly rates for time
in excess of 300 hours annually.
Item 12. Security Ownership of Certain Beneficial Owners and Management
(a) Security Ownership of Certain Beneficial Owners. The following table
sets forth as of March 1, 2002 information with respect to each person known to
the trustee to beneficially own more than 5% of the outstanding units of the
trust:
Amount and Nature of
Name and Address Beneficial Ownership Percent of Class
------------------------------ -------------------- ----------------
XTO Energy Inc. 1,360,000 units (1) 22.7%
810 Houston Street, Suite 2000
Fort Worth, TX 76102
(1) XTO Energy has the sole power to vote and dispose of these units.
(b) Security Ownership of Management. The trust has no directors or
executive officers. As of January 31, 2002, Bank of America, N.A. owned, in
various fiduciary capacities, 71,625 units with a shared right to vote 11,287
of these units and no right to vote 60,338 of these units. Bank of America,
N.A. disclaims any beneficial interests in these units. The number of units
reflected in this paragraph includes units held by all branches of Bank of
America, N.A.
(c) Changes in Control. The trustee knows of no arrangements which may
subsequently result in a change in control of the trust.
Item 13. Certain Relationships and Related Transactions
In computing net profits income paid to the trust for the 75% net profits
interests, XTO Energy deducts an overhead charge as reimbursement for costs
associated with monitoring these interests. This charge at December 31, 2001
was $23,925 per month, or $287,100 annually (net to the trust of $17,944 per
month or $215,325 annually), and is subject to annual adjustment based on an
oil and gas industry index.
During 2001, Bank of America, N.A. received $938 for oil and gas consulting
services performed on behalf of the trust. See Item 11 for the remuneration
received by the trustee from 1999 through 2001 and Item 12(b) for information
concerning units owned by the trustee, Bank of America, N.A., in various
fiduciary capacities.
14
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as a part of this report:
1. Financial Statements (incorporated by reference in Item 8 of this report)
Report of Independent Public Accountants
Statements of Assets, Liabilities and Trust Corpus at December 31, 2001
and 2000
Statements of Distributable Income for the years ended December 31,
2001, 2000 and 1999
Statements of Changes in Trust Corpus for the years ended December 31,
2001, 2000 and 1999
Notes to Financial Statements
2. Financial Statement Schedules
Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required
information is given in the financial statements or notes thereto.
3. Exhibits
(4) (a) Cross Timbers Royalty Trust Indenture amended and restated on
January 13, 1992 by NationsBank, N.A. (now Bank of America,
N.A.), as trustee, heretofore filed as Exhibit 3.1 to the trust's
Registration Statement No. 33-44385 filed with the Securities and
Exchange Commission on February 19, 1992, is incorporated herein
by reference.
(b) Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust,
90%--Texas) from South Timbers Limited Partnership, West Timbers
Limited Partnership, North Timbers Limited Partnership, East
Timbers Limited Partnership, Hickory Timbers Limited Partnership,
and Cross Timbers Partners, L.P. (predecessors of Cross Timbers
Oil Company, L.P.) to NCNB Texas National Bank (now Bank of
America, N.A.), as trustee, dated February 12, 1991 (without
Schedules A and B), heretofore filed as Exhibit 10.1 to the
trust's Registration Statement No. 33-44385 filed with the
Securities and Exchange Commission on February 19, 1992, is
incorporated herein by reference.
(c) Correction to Net Overriding Royalty Conveyance (Cross Timbers
Royalty Trust, 90%--Texas) from South Timbers Limited
Partnership, West Timbers Limited Partnership, North Timbers
Limited Partnership, East Timbers Limited Partnership, Hickory
Timbers Limited Partnership, and Cross Timbers Partners, L.P.
(predecessors of Cross Timbers Oil Company, L.P.) to NCNB Texas
National Bank (now Bank of America, N.A.), as trustee, dated
September 23, 1991 (without Schedules A and B), heretofore filed
as Exhibit 10.2 to the trust's Registration Statement No.
33-44385 filed with the Securities and Exchange Commission on
February 19, 1992, is incorporated herein by reference.
(d) Net Overriding Royalty Conveyance (Cross Timbers Royalty Trust,
75%--Texas) from South Timbers Limited Partnership, West Timbers
Limited Partnership, North Timbers Limited Partnership, East
Timbers Limited Partnership, Hickory Timbers Limited Partnership,
and Cross Timbers Partners, L.P. (predecessors of Cross Timbers
Oil Company, L.P.) to NCNB Texas National Bank (now Bank of
America, N.A.), as trustee, dated February 12, 1991 (without
Schedules A and B), heretofore filed as Exhibit 10.5 to the
trust's Registration Statement No. 33-44385 filed with the
Securities and Exchange Commission on February 19, 1992, is
incorporated herein by reference.
(13) Cross Timbers Royalty Trust annual report to unitholders for the
year ended December 31, 2001
(23.1) Consent of Arthur Andersen LLP
(23.2) Consent of Miller and Lents, Ltd.
15
(99.1) Assurance Letter Regarding Arthur Andersen LLP
Copies of the above Exhibits are available to any unitholder, at the
actual cost of reproduction, upon written request to the trustee, Bank
of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.
(b) Reports on Form 8-K
During the last quarter of the trust's fiscal year ended December 31, 2001,
there were no reports filed on Form 8-K by the trust with the Securities and
Exchange Commission.
16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Report to be signed
on its behalf by the undersigned thereunto duly authorized.
CROSS TIMBERS ROYALTY TRUST
By BANK OF AMERICA, N.A., TRUSTEE
By RON E. HOOPER
---------------------------------
Ron E. Hooper
Senior Vice President
XTO ENERGY INC.
Date: March 27, 2002 By LOUIS G. BALDWIN
----------------------------------
Louis G. Baldwin
Executive Vice President and
Chief Financial Officer
(The trust has no directors or executive officers.)
17