REGISTRATION NO. 333-
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM S-3
REGISTRATION STATEMENT
UNDER THE
SECURITIES ACT OF 1933
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CROSS TIMBERS OIL COMPANY CROSS TIMBERS ROYALTY TRUST
(EXACT NAME OF REGISTRANT AS (EXACT NAME OF REGISTRANT AS
SPECIFIED IN ITS CHARTER) SPECIFIED IN ITS CHARTER)
DELAWARE TEXAS
(STATE OR OTHER JURISDICTION OF (STATE OR OTHER JURISDICTION OF
INCORPORATION OR ORGANIZATION) INCORPORATION OR ORGANIZATION)
75-2347769 75-6415930
(I.R.S. EMPLOYER IDENTIFICATION NO.) (I.R.S. EMPLOYER IDENTIFICATION NO.)
NATIONSBANK, N.A., TRUSTEE
810 HOUSTON STREET, SUITE 2000 P. O. BOX 1317
FORT WORTH, TEXAS 76102 FORT WORTH, TEXAS 76101-1317
(ADDRESS, INCLUDING ZIP CODE, AND (ADDRESS, INCLUDING ZIP CODE, AND
TELEPHONE TELEPHONE
NUMBER, INCLUDING AREA CODE, OF NUMBER, INCLUDING AREA CODE, OF
REGISTRANT'S PRINCIPAL EXECUTIVE REGISTRANT'S PRINCIPAL EXECUTIVE
OFFICES) OFFICES)
BOB R. SIMPSON JOE B. GRISSOM
810 HOUSTON STREET, SUITE 2000 500 W. SEVENTH ST., SUITE 1300
FORT WORTH, TEXAS 76102 FORT WORTH, TEXAS 76102
(NAME, ADDRESS, INCLUDING ZIP CODE, (NAME, ADDRESS, INCLUDING ZIP CODE,
AND AND
TELEPHONE NUMBER, INCLUDING AREA TELEPHONE NUMBER, INCLUDING AREA
CODE, OF AGENT FOR SERVICE) CODE, OF AGENT FOR SERVICE)
COPIES TO:
F. RICHARD BERNASEK, ESQ. JAMES M. PRINCE, ESQ. RICHARD A. LOWE, ESQ.
KELLY, HART & HALLMAN, ANDREWS & KURTH L.L.P. BOSWELL & KOBER, P. C.
P.C. 4200 CHASE TOWER 1800 BANK ONE TOWER
201 MAIN STREET, SUITE HOUSTON, TEXAS 77002 500 THROCKMORTON STREET
2500 (713) 220-4300 FORT WORTH, TEXAS 76102
FORT WORTH, TEXAS 76102 (817) 878-4300
(817) 332-2500
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
If the only securities being registered on this form are being offered
pursuant to dividend or interest reinvestment plans, please check the
following box. [_]
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or
interest reinvestment plans, check the following box. [_]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following
box and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [_]
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [_]
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [_]
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CALCULATION OF REGISTRATION FEE
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PROPOSED
MAXIMUM PROPOSED
TITLE OF EACH CLASS OF AMOUNT OFFERING PRICE MAXIMUM AMOUNT OF
SECURITIES TO BE TO BE PER TRUST AGGREGATE REGISTRATION
REGISTERED REGISTERED UNIT(1) OFFERING PRICE FEE(2)
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Units of Beneficial
Interest.............. 1,360,000 $14.50 $19,720,000 $5,817.40
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(1) Estimated solely for the purpose of calculating the registration fee.
(2) Pursuant to Rule 457(c), the registration fee has been calculated on the
basis of the average of the high and low prices per share of the Units on
June 11, 1998, as reported by the consolidated reporting system of the New
York Stock Exchange.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT
SHALL FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS
REGISTRATION STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH
SECTION 8(A) OF THE SECURITIES ACT OF 1933 OR UNTIL THIS REGISTRATION
STATEMENT SHALL BECOME EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
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++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
+INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A +
+REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE +
+SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR MAY +
+OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT +
+BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR +
+THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE +
+SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE +
+UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF +
+ANY SUCH STATE. +
++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++++
SUBJECT TO COMPLETION, DATED , 1998
PROSPECTUS
1,200,000 TRUST UNITS
CROSS TIMBERS ROYALTY TRUST
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Each unit of beneficial interest ("Trust Unit") offered hereby evidences an
undivided interest in the Cross Timbers Royalty Trust (the "Trust"), a grantor
trust formed on February 12, 1991. The Trust Units offered hereby are currently
outstanding and are being offered by Cross Timbers Oil Company (the "Company").
See "Selling Trust Unitholder." The Trust will not receive any of the proceeds
of the offering. This Prospectus includes information provided to the Trustee
by the Company.
The assets of the Trust consist of defined net profits interests ("Net
Profits Interests") in royalties and overriding royalties in producing and non-
producing properties in Texas, Oklahoma and New Mexico and working interests in
producing properties located in Texas and Oklahoma (collectively, the
"Underlying Properties"). While the Trust and holders of Trust Units ("Trust
Unitholders") will not be liable for the costs of producing and developing oil
and natural gas, amounts payable to the Trust will be reduced by the amount of
such costs attributable to those Underlying Properties that are working
interests. The Underlying Properties are long-lived oil and natural gas
properties, most of which are operated by major oil companies or established
independent energy companies unaffiliated with the Trust. There are 6,000,000
Trust Units outstanding, which are listed on the New York Stock Exchange
("NYSE") under the symbol "CRT." On June 15, 1998, the last reported sale price
of Trust Units on the NYSE was $14 7/16 per Trust Unit.
SEE "RISK FACTORS" BEGINNING ON PAGE 9 FOR A DISCUSSION OF CERTAIN FACTORS
THAT SHOULD BE CONSIDERED IN CONNECTION WITH AN INVESTMENT IN THE TRUST UNITS
OFFERED HEREBY.
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THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION, OR ANY STATE SECURITIES COMMISSION, NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR
ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.
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PRICE TO UNDERWRITING PROCEEDS TO SELLING
PUBLIC DISCOUNT(1) TRUST UNITHOLDER(2)
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Per Trust Unit....................... $ $ $
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Total(3)............................. $ $ $
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(1) The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as
amended. See "Underwriting."
(2) Before deducting expenses payable by the Company estimated at $ .
(3) The Company has granted the Underwriters an option for 30 days to purchase
up to 160,000 additional Trust Units at the Price to Public, less the
Underwriting Discount, solely to cover over-allotments, if any. If such
option is exercised in full, the total Price to Public, Underwriting
Discount, and Proceeds to Selling Trust Unitholder will be $ , $ , and
$ , respectively. See "Underwriting."
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The Trust Units offered hereby are offered severally by the Underwriters, as
specified herein, subject to receipt and acceptance by them and subject to
their right to reject any order in whole or in part. It is expected that
delivery of the Trust Units will be made in New York, New York on or about
, 1998.
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MERRILL LYNCH & CO. DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
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The date of this Prospectus is , 1998.
[GRAPHIC HERE]
CERTAIN PERSONS PARTICIPATING IN THE OFFERING MAY ENGAGE IN TRANSACTIONS
THAT STABILIZE, MAINTAIN OR OTHERWISE AFFECT THE PRICE OF THE TRUST UNITS.
SUCH TRANSACTIONS MAY INCLUDE STABILIZING, THE PURCHASE OF TRUST UNITS TO
COVER SYNDICATE SHORT POSITIONS AND THE IMPOSITION OF PENALTY BIDS. FOR A
DESCRIPTION OF THESE ACTIVITIES, SEE "UNDERWRITING."
2
PROSPECTUS SUMMARY
The following Summary is qualified in its entirety by the more detailed
information appearing elsewhere in this Prospectus. Unless otherwise indicated,
the information in this Prospectus assumes that the Underwriters' over-
allotment option will not be exercised. Certain terms relating to the oil and
gas business are defined in "Glossary of Certain Oil and Gas Terms." The proved
oil and gas reserves of the Trust as of December 31, 1997 set forth in this
Prospectus were estimated by Miller and Lents, Ltd., an independent engineering
firm ("Miller and Lents").
CROSS TIMBERS ROYALTY TRUST
Cross Timbers Royalty Trust (the "Trust") is a grantor trust formed on
February 12, 1991 by the predecessors of Cross Timbers Oil Company (Cross
Timbers Oil Company, its subsidiaries and predecessors are collectively
referred to herein as the "Company"). The Trust was formed to provide its
owners with tax-advantaged cash distributions from defined net profits
interests ("Net Profits Interests") in certain royalties, overriding royalties
and working interests owned by the Company and located in the States of Texas,
Oklahoma and New Mexico (collectively, the "Underlying Properties"). The
Underlying Properties consist of long-lived oil and natural gas properties.
Estimated proved reserves attributable to the Underlying Properties are
approximately 31% oil and 69% natural gas, based on the discounted present
value of estimated future net revenues as of December 31, 1997. The Underlying
Properties are composed of (i) royalty and overriding royalty interests in
producing properties; (ii) working interests in currently producing properties;
and (iii) royalty interests in non-producing properties which may be developed
in the future, although no significant activity has occurred since the
inception of the Trust.
The Trust is a passive entity, and NationsBank, N.A., as trustee ("Trustee"),
has only such powers as are necessary for the collection and distribution of
the proceeds received by the Trust and the payment of Trust liabilities and
expenses. The Trustee does not participate in business decisions of the Company
and did not participate in the decisions of the Company to acquire or sell any
Trust Units. No additional properties will be contributed to the Trust. The
assets of the Trust are depleting assets and ultimately will decrease over
time.
The ownership of the Trust is divided into 6,000,000 units of beneficial
interest (the "Trust Units"). The Trust Units do not constitute an interest in
or security of the Company or the Trustee. See "The Trust."
THE COMPANY
The Company is a leading United States independent energy company engaged in
the acquisition, development and exploration of oil and natural gas properties,
and in the production, processing, marketing and transportation of oil and
natural gas. The Company organized the Trust and conveyed the Net Profits
Interests to the Trust in 1991. The Company currently owns the Underlying
Properties, subject to the Net Profits Interests, and will continue to own such
Properties, so burdened, after the Offering.
The Company originally acquired all of the Trust Units at the inception of
the Trust in exchange for the conveyance of the Net Profits Interests to the
Trust. During 1991 and 1992, the Company distributed a portion of the Trust
Units to its equity owners and sold the remainder in a registered public
offering. During 1996, 1997 and early 1998, the Company repurchased 1,360,000
Trust Units in private transactions and open market transactions effected on
the New York Stock Exchange at an average purchase price of $13.75 per Trust
Unit.
Since December 1997, the Company has acquired approximately $410 million of
producing oil and gas properties, which established two new core areas of
primarily operated properties. As the Underlying Properties are substantially
all non-operated interests and the reserves associated with the Trust Units
represent a small percentage of the Company's reserve base, the Company has
decided to sell its Trust Units and reinvest the proceeds in its new core areas
of operations.
3
THE TRUST ASSETS
THE NET PROFITS INTERESTS
The assets of the Trust consist of Net Profits Interests carved out of the
Underlying Properties. The Net Profits Interests were created under five
separately defined assignments (the "Conveyances"). The 90% Net Profits
Interests (as defined herein) were created under three Conveyances from
Underlying Properties located in Texas, New Mexico and Oklahoma, respectively.
The 75% Net Profits Interests (as defined herein) were created under two
Conveyances from Underlying Properties located in Oklahoma and Texas,
respectively. The Net Profits Interests entitle the Trust to receive 90% of the
Net Proceeds (as defined herein) from the sale of production from those
Underlying Properties that are royalties and overriding royalties (the "90% Net
Profits Interests") and 75% of the Net Proceeds (as defined herein) from the
sale of production from those Underlying Properties that are working interests
(the "75% Net Profits Interests").
"Net Proceeds" are generally defined to mean the amounts received by the
Company, as owner of the Underlying Properties, less costs associated with
ownership of such Underlying Properties. For the 90% Net Profits Interests, Net
Proceeds means gross proceeds received by the Company as the owner of the
Underlying Properties that are royalties and overriding royalties, less
property and production taxes. Net Proceeds for the 75% Net Profits Interests
means gross proceeds received by the Company as the owner of the Underlying
Properties that are working interests, less development and production costs
and property and production taxes. The Net Proceeds payable to the Trust from
the 90% Net Profits Interests, therefore, are dependent upon the quantities and
sales prices of oil and gas produced, and will not be decreased by the costs of
developing and producing such oil and gas, although such interests may bear
their proportionate share of costs incurred in making such production
marketable. In the case of the 75% Net Profits Interests, however, development
and operating costs are deducted from gross proceeds, so the Net Proceeds
payable to the Trust from the 75% Net Profits Interests are dependent upon both
the quantities and sales prices of oil and natural gas as well as the costs to
develop and produce such oil and gas. If, during any period, development and
operating costs exceed gross proceeds for a 75% Net Profits Interest, neither
the Trust nor Trust Unitholders would be liable for such excess, but the Trust
would not receive Net Proceeds with respect to such 75% Net Profits Interest
until the future Net Proceeds exceed the cumulative excess of such costs and
expenses, plus interest at the prime rate. Such conditions have existed for the
Trust in the past. See "Risk Factors--Development Costs" and "Computation of
Net Proceeds--75% Net Profits Interests."
The Trustee may cause the Net Profits Interests to be sold if it receives the
affirmative consent of the holders of 80% of the Trust Units. The Trustee is
required to sell the Net Profits Interests if the aggregate annual Net Proceeds
are less than $1,000,000 for two consecutive years. The net proceeds of any
such sale would be distributed to Trust Unitholders.
THE UNDERLYING PROPERTIES
The producing Underlying Properties are long-lived properties, substantially
all of which have well-established production histories and are operated by
major oil companies or established independent energy companies. The Underlying
Properties are comprised of the Company's interest in over 2,900 properties
that were acquired by the Company from 1986 through 1990 and represented, at
the time of formation of the Trust, substantially all of the royalties and
overriding royalties owned by the Company in Texas, Oklahoma and New Mexico, as
well as the non-operated working interests in seven unitized properties in
Texas and Oklahoma. See "The Net Profits Interests and the Underlying
Properties--Producing Acreage, Wells and Drilling." As of December 31, 1997,
approximately 82% of the discounted estimated future net revenues attributable
to the Net Profits Interests is allocable to the 90% Net Profits Interests and
18% is allocable to the 75% Net Profits Interests. Estimated proved reserves
attributable to the Underlying Properties are approximately 31% oil and 69%
natural gas, based on the discounted present value of estimated future net
revenues as of December 31, 1997. The average reserve-to-production index of
the Underlying Properties is 11 years for oil and 12 years for natural gas,
based on the proved reserves and production levels set forth in the Reserve
Report of Miller and Lents as of December 31, 1997 (the "Reserve Report") for
the Underlying Properties at December 31, 1997. Approximately 97% of the
discounted present value of estimated future net revenues is attributable to
proved developed reserves.
4
The following table sets forth, as of December 31, 1997, estimated proved oil
and gas reserves, estimated future net revenues and discounted estimated future
net revenues attributable to the Net Profits Interests in the producing
Underlying Properties:
ESTIMATED FUTURE
ESTIMATED NET REVENUES FROM
PROVED RESERVES (a)(b) PROVED RESERVES(a)(c)
-------------------------- ---------------------------
GAS
OIL GAS EQUIVALENTS
(MBBLS) (MMCF) (MMCFE) UNDISCOUNTED DISCOUNTED (d)
------- ------ ----------- ------------ --------------
(IN THOUSANDS)
90% Net Profits
Interests
San Juan Basin
Conventional.......... 84 24,942 25,446 $38,134 $15,823
Coal seam............. -- 6,750 6,750 9,785 6,282
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Total............... 84 31,692 32,196 47,919 22,105
Other New Mexico....... 143 429 1,287 2,853 1,669
Texas.................. 430 3,900 6,480 15,773 8,796
Oklahoma............... 74 1,865 2,309 5,326 3,080
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Total............... 731 37,886 42,272 71,871 35,650
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75% Net Profits
Interests
Texas.................. 583 229 3,727 8,605 4,475
Oklahoma............... 382 127 2,419 5,523 3,371
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Total............... 965 356 6,146 14,128 7,846
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Total Net Profits
Interests.............. 1,696 38,242 48,418 $85,999 $43,496
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Per Trust Unit.......... $ 14.33 $ 7.25
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(a) Based on oil and natural gas prices as of December 31, 1997, which were
$15.50 per Bbl of oil (West Texas Intermediate crude oil posted price,
referred to hereinafter as "WTI"), and averaged $1.76 per Mcf of natural
gas at the wellhead. For further information regarding Trust proved
reserves, see "The Net Profits Interests and the Underlying Properties--Oil
and Gas Reserves."
(b) Since the Trust holds defined net profits interests, the Trust does not own
a specific ownership percentage of the oil and gas reserves. Trust reserve
quantities are determined using an allocation formula, and, therefore, 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 (and the tax benefit of the estimated Section 29 coal
seam income tax credit and depletion deduction) since future net revenues
are not subject to taxation at the Trust level.
(d) Discounted at an annual rate of 10%.
ADDITIONAL DEVELOPMENT
The Company estimates that the underlying royalties in the San Juan Basin
from which certain of the 90% interests were carved include more than 2,000
gross (approximately 30 net) wells on 60,000 gross acres. Most of these wells
are operated by Amoco Production Company and Burlington Resources Oil & Gas
Company. Gas was first produced in the San Juan Basin in 1921 and today it is
considered to be the second largest gas producing area in the United States.
The San Juan Basin is characterized by multiple productive formations,
including the Fruitland Coal, Pictured Cliffs, Mesaverde and Dakota.
Development has taken place in several phases, including 160-acre infill
drilling of the Mesaverde starting in 1977 and of the Dakota starting in 1979.
The most recent development phase from 1980 to the present has been in the
Fruitland Coal because of the incentive of the
5
Section 29 federal income tax credit applicable to gas produced from coal seam
gas wells drilled prior to January 1, 1993. However, advanced technology and
improved operating procedures have allowed further Fruitland Coal development
after the expiration of the tax credit drilling eligibility period. Operators
have reported continued development in additional horizons and the use of
enhanced recovery techniques in existing productive formations, but it is not
known if this activity has affected or will affect Trust reserves or
distributions.
The Underlying Properties from which the 75% Net Profits Interests were
carved are working interests in developed properties which are undergoing
systematic secondary and enhanced recovery operations. Any increase or decrease
in costs from such activities will directly affect the Net Proceeds payable to
the Trust under the applicable 75% Net Profits Interests. As a result of a
project to convert one of the Texas properties to carbon dioxide injection, the
Company has advised the Trustee that, unless oil prices significantly increase,
costs are expected to continue to exceed revenues until the project has been
completed. Such excess costs plus accrued interest must be recovered before the
Texas 75% Net Profits Interests can again contribute to Trust distributions.
The Texas 75% Net Profits Interests contributed $0.18 per Trust Unit to 1997
royalty income and $0.015 per Trust Unit to first quarter 1998 royalty income.
See "Risk Factors--Development Costs." For a summary of development and
operating costs over the last five years associated with the working interest
properties, see "Selected Financial Data."
The Underlying Properties from which the 90% Net Profits Interests were
carved also include royalties in approximately 200,000 gross (3,000 net) acres
in non-producing properties located primarily in Texas and Oklahoma. The
Company owns the fee mineral interest for approximately 97% of the net acres
from which these royalties were carved and since their acquisition has made
these properties available for lease to others for development, although no
assurances can be made that these properties will be developed. Net Proceeds
payable to the Trust, however, will not be reduced by the development and
production costs associated with any development and operation of these
properties. There has been no significant development of the nonproducing
properties since the Trust's inception. See "The Net Profits Interests and the
Underlying Properties--Non-Producing Acreage."
OWNERSHIP OF THE UNDERLYING PROPERTIES
The Company currently owns the Underlying Properties, subject to and burdened
by the Net Profits Interests, and is entitled to any proceeds received by
reason of such ownership in excess of the Net Proceeds paid to the Trust. The
Company's duties under the Conveyances creating the Net Profits Interests are
ministerial in nature. For the 90% Net Profits Interests, the Company is
required to receive payments from the sale of production from the Underlying
Properties, deduct taxes and pay 90% of such amount to the Trustee for
distribution to Trust Unitholders. For the 75% Net Profits Interests, the
Company is required to receive payments representing its share of the sale of
production, deduct taxes and costs invoiced by the operators of such Underlying
Properties and pay 75% of the net amount to the Trust. The Company may sell the
Underlying Properties, subject to and burdened by the Net Profits Interests,
without the consent of the Trustee or the Trust Unitholders. Following any such
sale, the purchaser of the Underlying Properties would be required to calculate
and pay to the Trust the Net Proceeds and to otherwise perform all of the
Company's duties under the Conveyances. The Company does not currently intend
to sell the Underlying Properties.
6
HISTORICAL TRUST DISTRIBUTIONS AND RELATED DATA
Trust Units were initially sold to the public at $10.00 per unit in February
1992. Annual cash distributions paid, Section 29 federal income tax credits
available per Trust Unit, cost depletion factor (the percentage of Trust Unit
cost allowed as a cost depletion deduction for federal income tax purposes),
and the total present value (discounted at 10%) of estimated future net
revenues at December 31 of each year were as follows:
TOTAL PRESENT
SECTION 29 VALUE OF
TAX CREDITS ESTIMATED
CASH PER COST FUTURE NET
DISTRIBUTIONS TRUST DEPLETION REVENUES
PER TRUST UNIT(a) UNIT(b) FACTOR AT DECEMBER 31(c)
----------------- ----------- --------- -----------------
1992.................... $1.217402 $ .092 7.0% $54,589,000
1993.................... 1.282923 .150 7.0 40,911,000
1994.................... 1.124811 .203 8.5 41,241,000
1995.................... .929705 .180 8.1 42,243,000
1996.................... 1.346162 .189 9.5 76,847,000(d)
1997.................... 1.734541 .212 8.8 43,496,000
1998 (through May 31,
1998).................. .563809 .071(e) 3.5 --
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$8.199353 $1.097
========= ======
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(a) Distributions of distributable income of the Trust are made monthly.
(b) The Section 29 coal seam federal income tax credit provides a dollar-for-
dollar reduction in a taxpayer's federal income tax liability (but not
below his alternative minimum tax liability). See "Federal Income Tax
Consequences--Section 29 Coal Seam Gas Tax Credit."
(c) Estimated Future Net Revenues are estimated as of each year-end using oil
and gas prices and production and development costs as of December 31 of
each year, without escalation.
(d) Oil and gas prices at December 31, 1996 were $24.25 per Bbl (WTI) and $2.64
per Mcf at the wellhead, respectively. Comparatively, oil and gas prices
were $18.00 per Bbl and $1.37 per Mcf, respectively, at December 31, 1995,
and were $15.50 per Bbl and $1.76 per Mcf, respectively, at December 31,
1997.
(e) Estimated based on qualifying sales volumes and the factors used in the
calculation of the 1997 Section 29 coal seam gas tax credit.
For additional financial information regarding the Trust, see "Selected
Financial Data."
7
THE OFFERING
Trust Units offered(1)...... 1,200,000 Trust Units are being offered by the
Company.
Trust Units outstanding..... 6,000,000 Trust Units are currently outstanding.
Use of Proceeds............. No proceeds from the sale of Trust Units will be
deposited in the Trust. The Company will receive
the net proceeds from the sale of its Trust
Units, anticipated to be approximately $ and
will reinvest the proceeds in its new core areas
of operations.
NYSE Symbol................. CRT
Cash distributions.......... Distributions of available cash will be made by
the Trust on the tenth business day of each month
to holders of record of Trust Units on the last
business day of the prior month. Net Proceeds
from the Net Profits Interests are generally
received by the Trust two to three months
following production of oil and gas. Because the
Net Proceeds paid to the Trust are generated by
depleting assets, a portion of such distributions
may be analogous to a return of capital.
Federal income tax
consequences of
distributions.............. The income from the Net Profits Interests will be
taxed as oil and gas royalty income directly to
the Trust Unitholders. Trust Unitholders will be
entitled to a deduction for depletion and Trust
administrative expenses. Trust Unitholders may
also claim the tax credit (the "Section 29 tax
credit") for coal seam gas production provided in
Section 29 of the Internal Revenue Code of 1986,
as amended (the "Code"). The Section 29 tax
credit provides a dollar-for-dollar reduction in
a taxpayer's regular federal income tax liability
(but not below the taxpayer's alternative minimum
tax), and therefore is a greater benefit than a
deduction which merely reduces the amount of a
taxpayer's taxable income. To the extent Section
29 tax credits are limited by the taxpayer's
alternative minimum tax computation, the limited
credits can be carried forward indefinitely to
offset any future excess of the taxpayer's
regular federal income tax over the taxpayer's
alternative minimum tax each year. The total
amount of Section 29 tax credit applicable to
Trust Units will vary every year based on the
volume of qualifying coal seam gas production
attributable to the Trust. It is anticipated that
the Section 29 tax credit for sales of 1998
production attributable to the Trust Unit will be
approximately $0.17 per Trust Unit, based on
qualifying coal seam gas production of 1,066,000
Mcf as estimated in the Reserve Report and on an
estimated credit of $1.08 per MMBtu. The greater
of cost or percentage depletion is generally
available to Trust Unitholders as an income tax
deduction. The available depletion deduction has
historically been greater under the cost
depletion method, which is dependent upon the
Trust Unitholder's cost of Trust Units, purchase
date and prior allowable depletion. The effect of
the foregoing tax credits and deductions is to
shelter a portion of income attributable to Trust
distributions from federal income taxation. To
the extent the depletion deduction exceeds cash
distributions per Trust Unit, such excess can be
deducted from the taxpayer's other sources of
taxable income. Income distributed from the Trust
to Trust Unitholders that are tax-exempt
organizations does not constitute unrelated
business taxable income for such organizations,
provided the Trust Units are not debt-financed
within the meaning of Section 514 of the Code.
See "Federal Income Tax Consequences."
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(1) Excluding 160,000 Trust Units subject to purchase upon exercise by the
Underwriters of their over-allotment option.
RISK FACTORS
An investment in the Trust Units involves certain risks that should be
carefully considered. See "Risk Factors" beginning on page 9.
8
FORWARD-LOOKING STATEMENTS
Certain statements made by the Company that are contained in this Prospectus
under "Federal Income Tax Consequences--Section 29 Coal Seam Gas Tax Credit,"
and "Hypothetical Annual Cash Distributions," in addition to certain
statements contained elsewhere in this Prospectus, are "Forward-Looking
Statements" and are thus prospective. Such forward-looking statements are
subject to risks, uncertainties and other factors which could cause actual
results to differ materially from future results expressed or implied by such
forward-looking statements. The most significant of such risks, uncertainties
and other factors are discussed under "Risk Factors" below, and prospective
investors are urged to carefully consider such factors.
RISK FACTORS
EFFECT OF CHANGING OIL AND GAS PRICES
The Trust's distributions have been and will continue to be dependent on the
prices received for oil and natural gas production from the Underlying
Properties and, in the case of Underlying Properties that are working
interests, the costs of producing and developing such oil and natural gas.
Prices for oil and natural gas are subject to wide fluctuations in response to
relatively minor changes in supply, market uncertainty and a variety of
additional factors that are beyond the control of the Trust and the Company.
These factors include political conditions in the Middle East, activities of
OPEC, the foreign supply of oil and gas, the price of foreign imports, the
level of consumer product demand, the severity of weather conditions,
government regulations, the price and availability of alternative fuels,
worldwide energy conservation measures and overall economic conditions, among
others. Oil and natural gas prices have historically been volatile and are
likely to continue to be volatile in the future. Such volatility makes it
difficult to estimate the future levels of cash distributions to Trust
Unitholders or the value of the Trust Units. Lower oil and gas prices may
reduce the amount of oil and gas that is economic to produce.
CONTROL OF OPERATIONS AND DEVELOPMENT
Under the terms of the Conveyances creating the Net Profits Interests,
neither the Trustee nor the Trust Unitholders will be able to influence or
control the operation or future development of the Underlying Properties.
Additionally, the Company does not operate or control any of the Underlying
Properties, with the exception of approximately 20 overriding royalty
interests in the San Juan Basin in which the Company acquired the underlying
working interest in December 1997 and became operator. The Company is not
expected to operate a substantial portion of the Underlying Properties or to
be able to significantly influence the operations or future development of
such Underlying Properties. All such operations will be controlled by persons
unaffiliated with the Trustee and the Company.
Most of the producing Underlying Properties are currently operated by major
oil companies or established independent energy companies. The current
operators of the producing Underlying Properties are under no obligation to
continue operating the properties, and the Trustee, Trust Unitholders and the
Company will be unable to appoint or control the appointment of a replacement
operator. Although no assurances can be given, the Company does not currently
anticipate that the operator of any material property will change. See "The
Net Profits Interests and the Underlying Properties--Producing Acreage, Wells
and Drilling."
PRODUCTION EXPENSES
The Underlying Properties include royalty and overriding royalty interests
and working interests. In general, the owner of a royalty or overriding
royalty interest receives a specified portion of the gross sales proceeds of
oil and gas production (less taxes and certain marketing costs) regardless of
the production expenses necessary to produce such oil and gas. Production
expenses typically include labor, fuel, repairs, hauling, pumping, insurance,
storage, and supervision and administration. Although production expenses may
influence the decision of the operator as to the volume of oil or gas to
produce from a property or the decision to shut-in or abandon a well,
9
production expenses will not reduce the amount a royalty or overriding royalty
owner receives for the oil and gas actually produced. Accordingly, the amount
received by the Trust from the 90% Net Profits Interests, which are carved
from royalty interests, will not be directly affected by changes in production
costs. A working interest owner, however, is obligated for its proportionate
share of production expenses. Accordingly, higher or lower production expenses
on the Underlying Properties that are working interests will directly decrease
or increase the amount received by the Trust from the 75% Net Profits
Interests. For a summary of such costs for the last five years see "Selected
Financial Data."
As of December 31, 1997, approximately 82% of the discounted present value
of estimated future net revenues attributable to the Net Profits Interests
(using constant prices at December 31, 1997 based on a price of $15.50 per Bbl
of oil (WTI) and the weighted average gas price at December 31, 1997 of $1.76
per Mcf at the wellhead) is allocable to the 90% Net Profits Interests and 18%
of such present value is allocable to the 75% Net Profits Interests.
DEVELOPMENT COSTS
The Underlying Properties also include all of the Company's working
interests in seven producing properties located in Texas and Oklahoma. Each of
these properties has been unitized for the purpose of conducting secondary
recovery operations to increase or maintain production levels. Under the terms
of the agreements establishing the units, if the requisite percentage of
working interest holders in the unit approves a development project, all such
holders are required to pay their proportionate share of development costs.
The working interests owned by the Company do not constitute a sufficient
interest in any of the units to veto or control a development decision. Under
the terms of the Conveyances creating the 75% Net Profits Interests in these
Underlying Properties, the Trust will not be liable for any development costs,
but the amount of such development costs will be deducted when computing Net
Proceeds payable to the Trust from such properties.
The Net Proceeds payable to the Trust with respect to production from such
properties will be reduced by the costs of all development, and if materially
increased levels of development were to occur on such properties,
distributions from the Trust would be materially and adversely affected. To
the extent such development costs and production expenses exceed the proceeds
of production from such properties, the Trust would not receive payments with
respect to such properties until the proceeds from production exceed the
cumulative excess of such costs and expenses plus accrued interest during such
deficit period. The computation of Net Proceeds is made separately under each
Conveyance creating the 75% Net Profits Interests from working interest
properties in each of Texas and Oklahoma. Accordingly, any excess development
costs and production expenses on working interest properties in one state will
not reduce the Net Proceeds payable from working interest properties in the
other state.
For example, as a result of a project to convert one of the Texas properties
underlying the 75% Net Profits Interests to carbon dioxide injection, the
Company has advised the Trustee that, unless oil prices significantly
increase, costs are expected to continue to exceed revenues until the project
has been completed. Any such excess costs plus accrued interest would then
need to be recovered from future net proceeds of the Texas 75% Net Profits
Interests before it could again contribute to royalty income. The Texas 75%
Net Profits Interests contributed approximately $0.18 per Trust Unit to 1997
royalty income, or 10% of total 1997 distributions, and contributed
approximately $0.015 per Trust Unit to first quarter 1998 royalty income, or
4% of first quarter 1998 distributions. Excess development costs have also
occurred twice in the past. Development costs and production expenses exceeded
the proceeds of production from the working interest properties in Texas from
January to April 1994; such costs were recovered from May to August 1994.
Development costs and production expenses exceeded the proceeds of production
from the working interest properties in Oklahoma from October 1993 to June
1994; such costs were recovered from July to September 1994.
RESERVE ESTIMATES AND PRODUCTION RISKS
The value of the Trust Units will be substantially dependent upon the proved
reserves attributable to the Net Profits Interests owned by the Trust. There
are many uncertainties inherent in estimating quantities and
10
values of proved reserves and in projecting future rates of production and the
timing of development expenditures. The reserve data set forth herein,
although prepared by independent engineers in a manner customary in the
industry, are estimates only, and quantities and estimated values of oil and
gas may differ from the amounts set forth herein. In addition, the present
values shown herein were prepared using guidelines established for disclosure
of reserves with the Securities and Exchange Commission (the "Commission") and
should not be considered representative of the market value of such reserves
or the Trust Units. A market value determination would include many additional
factors. As of December 31, 1997, the estimated future net revenues from
proved reserves, discounted at 10% per annum, was $7.25 per Trust Unit. For a
description of hypothetical distributions, see "Hypothetical Annual Cash
Distributions."
Trust distributions could be adversely affected if any of the hazards
typically associated with the drilling for and the production and
transportation of oil and gas were to occur, including personal injuries,
property damage, damage to productive formations or equipment and
environmental damages. Uninsured costs for damages for any of the foregoing
will directly reduce the Net Proceeds payable to the Trust from Underlying
Properties that are working interests, and will reduce Net Proceeds from
Underlying Properties that are royalties and overriding royalties to the
extent such damages reduce the volume of oil and gas produced.
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 the Company in the Underlying Properties. Since the
Trust has defined net profits interests, the Trust does not own a specific
ownership percentage of the oil and gas reserve quantities. Accordingly,
reserves allocated to the Trust pertaining to its 75% Net Profits Interests
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.
OWNERSHIP OF DEPLETING ASSETS
The Net Proceeds paid to the Trust are attributable to the sale of depleting
assets. Thus, in certain circumstances, distributions to Trust Unitholders may
be analogous to a return of capital to the extent of the amount of depletion.
The effect of depletion may be measured in various ways. If measured in proved
reserve quantities, proved reserves attributable to the Underlying Properties
at December 31, 1997 are 78% of proved reserves at December 31, 1992, on an
Mcfe basis. The quantity of proved reserves ultimately recoverable from the
Underlying Properties will be affected by, among other things, future
maintenance and development projects on the Underlying Properties. These
projects will be dependent on the market prices of oil and natural gas. If
operators of the properties do not implement additional maintenance and
development projects, the future decline rate of proved reserves may be higher
than the rate during the past five years. For federal income tax purposes,
depletion is reflected as a deduction, which is anticipated to be $1.48 per
Trust Unit in 1998 based on a Trust Unit price of $16.00. See "Federal Income
Tax Consequences--Royalty Income and Depletion."
FIDUCIARY RESPONSIBILITY OF TRUSTEE
The Trustee is responsible to the Trust Unitholders as a fiduciary and, as
such, under Texas law is required to act in the best interests of the Trust
Unitholders at all times and to exercise the judgment and care in supervising
and managing the Trust's assets exercised by persons of ordinary prudence,
discretion and intelligence. In this regard, the Trustee's duties are similar
to the duty of care owed by directors of a corporation to the corporation and
its shareholders. The Trust Indenture ("Indenture") provides, however, that
the Trustee will not be personally liable to the Trust Unitholders for the
failure to exercise such standard of judgment and care, unless such failure is
the result of fraud or acts or omissions in bad faith.
TRANSFER OF UNDERLYING PROPERTIES AND NET PROFITS INTERESTS; ABANDONMENT
The Company currently owns the Underlying Properties, subject to and
burdened by the Net Profits Interests. Although the Company does not currently
intend to transfer the Underlying Properties, it has the right
11
to transfer all or a portion of its working, royalty, overriding royalty or
fee mineral interests comprising the Underlying Properties. The Trust
Unitholders will not be entitled to vote on, consent to or approve any such
transfer, and Trust Unitholders will not be entitled to any proceeds of such
transfer. Following any such transfer, the Underlying Properties will continue
to be burdened by the Net Profits Interests, and after any such transfer the
Conveyances require that the Net Proceeds attributable to the transferred
property be calculated separately and paid by the transferee. The Net Profits
Interests constitute real property interests. The Conveyances have been
recorded in the appropriate real property records so as to give notice of the
Net Profits Interests to the Company's creditors and transferees, who would
take subject to the Net Profits Interests and whose interests would be
subsequent and inferior to the Net Profits Interests. Any transferee will
succeed to the responsibilities of the Company as to the interests so
transferred, including the payment duties and corresponding liabilities to the
Trust for damages caused by breach of such responsibilities. The Trust
Indenture does not provide a specific mechanism whereby Trust Unitholders may
compel the Trustee to institute action against the Company or a transferee of
an Underlying Property for damages caused by a delay or reduction in the
payment of Net Proceeds to the Trust.
The Trustee may cause the sale of the Net Profits Interests if the holders
of 80% or more of the Trust Units approve such sale. The Trustee is required
to sell the Net Profits Interests if the aggregate annual Net Proceeds are
less than $1,000,000 for two consecutive years. Sale of the Net Profits
Interests will terminate the Trust. The net proceeds of any sale will be
distributed to the Trust Unitholders. See "Description of the Trust
Indenture--Duration of the Trust; Sale of Net Profits Interests."
The Company and any transferees will have the right to abandon any well or
property on an Underlying Property that is a working interest if, in its
opinion, such well or property ceases to produce or is not capable of
producing in commercially paying quantities. Upon termination of any such
lease, that portion of the Net Profits Interests relating thereto will be
extinguished.
MARKET FOR NATURAL GAS
Approximately 69% of the estimated proved reserves of the Underlying
Properties at December 31, 1997 are composed of natural gas, based on the
discounted present value of estimated future net revenues of proved reserves.
The revenues of the Trust and the amount of cash distributions made by the
Trust will be dependent upon, among other things, the volume of natural gas
produced and the price at which such natural gas is sold.
Due to the seasonal nature of demand for natural gas and its effect on sales
prices and production volumes, the cash distributions by the Trust may vary
substantially on a seasonal basis. Generally, gas production volumes and
prices tend to be higher during the first and fourth quarters of the calendar
year. Because of the lag between the Company's receipt of revenues related to
the Underlying Properties and the dates on which distributions are made to
Trust Unitholders, however, the seasonality that affects production and prices
generally should be reflected in distributions by the Trust in later periods.
See "Computation of Net Proceeds."
LIMITED VOTING RIGHTS OF TRUST UNITHOLDERS
While Trust Unitholders have certain voting rights pursuant to the terms of
the Trust Indenture, these rights are more limited than those of stockholders
of most public corporations. For example, there is no requirement for annual
meetings of Trust Unitholders or for an annual or other periodic re-election
of the Trustee.
CERTAIN AGREEMENTS AFFECTING THE UNDERLYING PROPERTIES
Certain instruments creating or governing some of the Underlying Properties
that are royalties and overriding royalties in the San Juan Basin contain
provisions that purportedly either reduce the overriding royalty interest or
convert the royalty or overriding royalty interest into a working interest
when gas production falls below specified levels. The Company believes these
provisions were included in these instruments because of a federal regulation,
that has since been repealed, limiting the amount of royalties and overriding
royalties placed
12
on federal leases in the San Juan Basin. No assurances can be made, however,
that these provisions will not have an adverse effect on the Trust. The
Company and other royalty interest owners filed a lawsuit, later joined by the
Trust in 1993, to recover revenues suspended by working interest owners based
on their interpretation of these reduction or conversion provisions. The
Trust, the Company and the other royalty owners settled this lawsuit in 1996.
Pursuant to the settlement, the Company received $750,000 in exchange for
reducing its 7.5% overriding royalty interest in these properties to a 1.875%
overriding royalty interest that does not convert to a working interest. The
Trust received $675,000 or $0.1125 per Trust Unit as its portion of the
settlement, which was distributed on January 15, 1997 to Unitholders of record
on December 31, 1996. Other Underlying Properties in the San Juan Basin are
subject to similar provisions. One other working interest owner who asserted
this claim subsequently withdrew it.
AMENDMENT OF THE TRUST INDENTURE
Except for certain amendments that are prohibited (see "Description of the
Trust Indenture--Creation and Organization of the Trust; Amendments"), the
Trust Indenture may be amended by a vote of the holders of 80% or more of the
outstanding Trust Units. Any such amendment will be binding on all Trust
Unitholders, regardless of whether they vote for or against such amendment.
LIABILITY OF TRUST UNITHOLDERS
The Indenture provides that the Trustee is required to ensure that all
contractual liabilities of the Trust are limited to the assets of the Trust
and that the Trustee will be liable for such contractual liabilities if it
fails to do so. Under the laws of Texas, however, it is unclear whether a
Trust Unitholder would be jointly and severally liable for any liability of
the Trust in the event that the following conditions were to occur: (i) the
satisfaction of such liability was not by contract limited to the assets of
the Trust; and (ii) insurance proceeds and the assets of the Trust or Trustee
were insufficient to discharge such liability. The Company believes that
because of the value and passive nature of the Trust assets and the
restrictions in the Indenture on the power of the Trustee to incur
liabilities, the imposition of any liability on a Trust Unitholder is remote.
TAX CONSIDERATIONS
The Trust has received an opinion of Tax Counsel (as hereinafter defined)
that the Trust is a "grantor trust" for federal income tax purposes, and that
each Trust Unitholder will be taxed directly on his pro rata share of the
income of the Trust, and will be entitled to claim depletion deductions equal
to the greater of percentage depletion or cost depletion (computed on the
basis of his Trust Units) and his pro rata share of other deductions of the
Trust and to claim the Section 29 tax credit with respect to gas produced from
coal seams. See "Federal Income Tax Consequences." Tax Counsel believes that
its opinion is in accordance with the present position of the Internal Revenue
Service (the "IRS") regarding such trusts. Neither the Company nor the Trustee
has requested a ruling from the IRS regarding these tax questions. There can
be no assurances that the Company or the Trust would be granted such a ruling
if requested or that the IRS will not change its position in the future. The
tax treatment of the Trust and Trust Unitholders could be different from that
described above if the IRS were to successfully challenge that treatment.
13
PRICE RANGE OF TRUST UNITS AND DISTRIBUTIONS
The Trust Units are traded on the NYSE under the symbol "CRT." The following
table sets forth, for the periods indicated, the high and low prices of the
Trust Units as reported on the New York Stock Exchange Composite Tape and the
amount of distributions per Trust Unit.
SALES PRICE CASH
--------------- DISTRIBUTIONS
LOW HIGH PER TRUST UNIT
------- ------- --------------
1996:
First Quarter.............................. $ 9.625 $11.000 $.254087
Second Quarter............................. 9.750 10.750 .309984
Third Quarter.............................. 10.375 12.500 .299200
Fourth Quarter............................. 11.750 15.750 .482891
1997:
First Quarter.............................. $13.625 $15.750 $.511589
Second Quarter............................. 14.250 16.750 .536106
Third Quarter.............................. 16.000 17.750 .353022
Fourth Quarter............................. 16.000 18.500 .333824
1998:
First Quarter.............................. $13.563 $17.250 $.382494
Second Quarter (through June 15, 1998)..... 13.750 17.688 .181315
The closing price of the Trust Units on the NYSE on June 15, 1998, was $14
7/16. As of May 31, 1998, there were 6,000,000 Trust Units outstanding and
approximately 191 Trust Unitholders of record.
USE OF PROCEEDS
The Trust will not receive any proceeds from the sale of the Trust Units
offered hereby. The Company will receive proceeds (net of underwriting
discount and costs of the offering paid by the Company) from the sale of its
Trust Units offered hereby of approximately $ . The Company intends to
reinvest these net proceeds in its new core areas of operations.
14
SELECTED FINANCIAL DATA
The following table presents, as of the dates and for the periods indicated,
summary financial information for the Trust and the Net Profits Interests. The
financial information for each of the five years in the period ended December
31, 1997 has been derived from the Trust's audited financial statements. This
financial data should be read in conjunction with "Trustee's Discussion and
Analysis" and the Trust's financial statements and the notes thereto,
incorporated herein by reference.
THREE MONTHS ENDED
MARCH 31
YEAR ENDED DECEMBER 31 (UNAUDITED)
-------------------------------------------------- -------------------
1993 1994 1995 1996(a) 1997(b) 1997 1998
--------- --------- --------- --------- --------- --------- ---------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
STATEMENT OF
DISTRIBUTABLE INCOME
DATA
Royalty income.......... $ 7,906 $ 6,934 $ 5,740 $ 8,270 $ 10,550 $ 3,115 $ 2,335
Interest income......... 7 7 8 11 16 4 4
--------- --------- --------- --------- --------- --------- ---------
Total income.......... 7,913 6,941 5,748 8,281 10,566 3,119 2,339
Administration expense.. 215 192 170 204 159 49 44
--------- --------- --------- --------- --------- --------- ---------
Distributable income.... $ 7,698 $ 6,749 $ 5,578 $ 8,077 $ 10,407 $ 3,070 $ 2,295
========= ========= ========= ========= ========= ========= =========
Distributable income per
Trust Unit............. $1.282923 $1.124811 $0.929705 $1.346162 $1.734541 $0.511589 $0.382494
========= ========= ========= ========= ========= ========= =========
SECTION 29 TAX CREDIT
PER TRUST UNIT......... $0.149924 $0.202803 $0.180246 $0.189374 $0.212340 $0.052155 $ 0.037(c)
========= ========= ========= ========= ========= ========= =========
COMPUTATION OF ROYALTY
INCOME
90% Net Profits
Interests
Revenues
Oil sales.............. $ 1,670 $ 1,354 $ 1,380 $ 1,663 $ 1,853 $ 490 $ 411
Gas sales.............. 6,855 6,930 4,410 6,414 8,799 2,318 2,115
--------- --------- --------- --------- --------- --------- ---------
Total................. 8,525 8,284 5,790 8,077 10,652 2,808 2,526
--------- --------- --------- --------- --------- --------- ---------
Costs
Taxes on production and
property.............. 828 800 620 734 955 232 212
Other expenses......... 82 131 62 43 12 9 --
--------- --------- --------- --------- --------- --------- ---------
Total................. 910 931 682 777 967 241 212
--------- --------- --------- --------- --------- --------- ---------
Net proceeds.......... 7,615 7,353 5,108 7,300 9,685 2,567 2,314
--------- --------- --------- --------- --------- --------- ---------
Royalty Income--90% Net
Profits Interests..... 6,854 6,618 4,597 6,570 8,716 2,311 2,083
--------- --------- --------- --------- --------- --------- ---------
75% Net Profits
Interests
Revenues
Oil sales.............. 6,040 5,068 5,339 6,461 6,289 1,895 1,280
Gas sales.............. 161 145 154 212 226 74 45
--------- --------- --------- --------- --------- --------- ---------
Total................. 6,201 5,213 5,493 6,673 6,515 1,969 1,325
--------- --------- --------- --------- --------- --------- ---------
Costs
Taxes on production and
property.............. 743 574 599 535 556 128 136
Production and other
expenses.............. 3,180 3,015 2,620 2,707 2,645 609 706
Development costs...... 993 1,072 750 1,164 869 160 147
Net (excess costs)
excess cost recovery
and interest.......... (117) 131 -- -- -- -- --
--------- --------- --------- --------- --------- --------- ---------
Total................. 4,799 4,792 3,969 4,406 4,070 897 989
--------- --------- --------- --------- --------- --------- ---------
Net proceeds.......... 1,402 421 1,524 2,267 2,445 1,072 336
--------- --------- --------- --------- --------- --------- ---------
Royalty Income--75% Net
Profits Interests..... 1,052 316 1,143 1,700 1,834 804 252
--------- --------- --------- --------- --------- --------- ---------
Total Royalty Income.. $ 7,906 $ 6,934 $ 5,740 $ 8,270 $ 10,550 $ 3,115 $ 2,335
========= ========= ========= ========= ========= ========= =========
OIL AND GAS SALES
VOLUMES
Net Profits Interests
Oil Sales (Bbls)....... 147 100 149 168 177 56 37
Gas Sales (Mcf)........ 3,137 3,556 2,992 3,829 3,878 835 726
Underlying Properties
Oil Sales (Bbls)....... 474 467 441 437 424 106 105
Gas Sales (Mcf)........ 3,668 4,179 3,513 4,385 4,419 946 836
AVERAGE PRICES
Oil per Bbl............ $ 16.28 $ 13.76 $ 15.25 $ 18.60 $ 19.20 $ 22.62 $ 16.15
Gas per Mcf............ $ 1.91 $ 1.69 $ 1.30 $ 1.51 $ 2.04 $ 2.53 $ 2.59
15
THREE MONTHS ENDED
MARCH 31
YEAR ENDED DECEMBER 31 (UNAUDITED)
---------------------------------------- --------------------
1993 1994 1995 1996 1997 1997 1998
------- ------- ------- -------- ------- --------- ---------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
PROVED RESERVES(d)(e)
Net Profits Interests
Oil (Bbls)............. 1,287 1,691 1,950 2,486 1,696 -- --
Gas (Mcf).............. 43,762 41,600 41,326 40,371 38,242 -- --
Estimated future net
cash flows............ $85,102 $85,197 $83,991 $154,315 $85,999 -- --
Present value of
estimated future net
cash flows, discounted
at 10%................ $40,911 $41,241 $42,243 $ 76,847 $43,496 -- --
Underlying Properties
Oil (Bbls)............. 3,456 4,732 5,030 5,282 4,418 -- --
Gas (Mcf).............. 49,800 47,669 47,529 46,422 44,075 -- --
Estimated future net
cash flows............ $95,884 $97,861 $98,235 $181,550 $99,196 -- --
Present value of
estimated future net
cash flows, discounted
at 10%................ $46,082 $47,487 $49,579 $ 90,683 $50,394 -- --
- --------
(a) Royalty income includes the effect of lawsuit settlement proceeds of
$675,000, or $0.113 per Trust Unit. See "The Net Profits Interests and the
Underlying Properties--Certain Provisions Affecting San Juan Basin Royalty
Interests." Gas sales volumes from the Underlying Properties related to
this settlement were 609,000 Mcf. The average gas price without the effect
of this settlement would have been $1.56 per Mcf.
(b) Royalty income includes the effect of lawsuit settlement proceeds of
$733,000, or $0.122 per Trust Unit. Gas sales volumes from the Underlying
Properties related to this settlement were 636,000 Mcf. The average gas
price without the effect of this settlement would have been $2.15 per Mcf.
(c) Estimated based on qualifying sales volumes and the factors used in the
calculation of the 1997 Section 29 tax credit.
(d) Proved reserves and estimated future net cash flows from proved reserves
are estimated as of each year-end using oil and gas prices and production
and development costs as of December 31 of each year, without escalation.
Proved reserves 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.
(e) Oil and gas prices at December 31, 1996 were $24.25 per Bbl (WTI) and
$2.64 per Mcf at the wellhead, respectively. Comparatively, oil and gas
prices were $18.00 per Bbl and $1.37 per Mcf, respectively, at December
31, 1995, and were $15.50 per Bbl and $1.76 per Mcf, respectively, at
December 31, 1997.
16
TRUSTEE'S DISCUSSION AND ANALYSIS
YEARS ENDED DECEMBER 31, 1995, 1996 AND 1997
Royalty income for 1997 was $10,550,000, as compared with $8,270,000 for
1996 and $5,740,000 for 1995. The 28% increase in royalty income from 1996 to
1997 was primarily because of higher gas prices. The 44% increase in royalty
income from 1995 to 1996 was primarily because of higher oil and gas prices
and increased gas sales volumes related to a lawsuit settlement. See "The Net
Profits Interests and the Underlying Properties--Certain Provisions Affecting
San Juan Basin Royalty Interests." During 1995, 1996 and 1997, 62%, 64% and
69%, respectively, of royalty income was derived from gas sales.
Trust administration expense was $159,000 in 1997 as compared to $204,000 in
1996 and $170,000 for 1995. Interest income was $8,000, $11,000 and $16,000
during 1995, 1996 and 1997, respectively.
Royalty income is recorded when received by the Trust, which is the month
following receipt by the Company, and generally two months after oil
production and three months after gas production. Royalty income is generally
affected by three major factors: 1) oil and gas sales volumes, 2) oil and gas
sales prices and 3) costs deducted in the calculation of royalty income.
Volumes
Primarily because of natural production decline, underlying oil sales
volumes decreased 3% from 1996 to 1997, as compared to a 1% decline from 1995
to 1996. The decline from 1995 to 1996 was largely offset by production
increases related to infill drilling on some of the underlying working
interest properties.
Underlying gas sales volumes for 1997 and 1996 include 636,000 Mcf and
609,000 Mcf, respectively, attributable to lawsuit settlement proceeds
received by the Trust. Primarily because of these lawsuit settlement volumes,
underlying gas sales volumes increased 1% from 1996 to 1997, compared with a
25% increase from 1995 to 1996. Increased gas volumes from 1995 to 1996 also
include the effect of partially curtailed production in 1995 because of lower
prices.
Prices
The 1997 average oil price of $19.20 was 3% higher than the 1996 average
price of $18.60, which was 22% higher than the 1995 average price of $15.25.
Because of the two-month interval between oil production and receipt by the
Trust of related royalty income, the 1997 average price includes the effect of
higher oil prices in November and December 1996, and excludes the effect of
lower December 1997 prices. Increased global production and reduced
consumption caused oil prices to further decline in first quarter 1998, with
an average posted West Texas Intermediate price of $14.22 per barrel for
January and February.
The 1997 average gas price was $2.04, or 35% above the 1996 average price of
$1.51, which was 16% above the 1995 average price of $1.30. Prices remained
depressed for the first half of this three-year period, primarily because of
gas oversupplies in California, the primary market for San Juan Basin gas.
During third quarter 1996, however, San Juan Basin prices rose to two-year
highs, reflecting increased demand and reduced supplies in California, as well
as the effects of additional eastward bound pipeline capacity from the San
Juan Basin. Increased weather-related demand caused prices to further improve
in late 1996 and early 1997. Because of the three-month interval between
production and the Trust's receipt of royalty income, higher fourth quarter
1996 prices were received in 1997. Gas prices remained relatively higher
through 1997 as compared to 1996 and 1995. The average fourth quarter 1997
price, related to first quarter 1998 Trust royalty income, was $2.51.
Costs
Because properties underlying the 90% Net Profits Interests are royalty and
overriding royalty interests, the calculation of royalty income from these
interests only includes deductions for production and property taxes,
17
legal costs, and marketing and transportation charges. In addition to these
costs, the calculation of royalty income from the 75% Net Profits Interests
includes deductions for production and development costs since the related
Underlying Properties are working interests. If monthly costs exceed revenues
for any of the five Conveyances under which the Net Profits Interests were
conveyed to the Trust, such excess costs cannot reduce royalty income from
other Conveyances, but must be recovered, with accrued interest, from future
net proceeds of that Conveyance.
Total costs deducted in the calculation of royalty income were $4,651,000,
$5,183,000 and $5,037,000 during 1995, 1996 and 1997, respectively. The 3%
decrease in costs from 1996 to 1997 was primarily the result of decreased
development costs after completion of infill drilling on some of the
properties underlying the 75% Net Profits Interests. Partially offsetting
decreased development costs were increased production taxes resulting from
higher oil and gas sales. The 11% increase in costs from 1995 to 1996 was
primarily the result of increased development and production costs related to
infill drilling that began in December 1995 on certain properties underlying
the 75% Net Profits Interests, partially offset by decreased charges from a
1995 waterflood project. Production taxes also increased because of higher oil
and gas sales.
Budgeted development costs for 1998 and 1999 include $900,000 and $600,000,
respectively, related to a carbon dioxide injection project on one of the
Texas properties underlying the 75% Net Profits Interests. The Company has
advised the Trustee that, unless oil prices significantly increase (see
"Prices" above), costs are expected to exceed revenues for the Texas
conveyance of the 75% Net Profits Interests until this project has been
completed. See "--Three Months Ended March 31, 1997 and 1998--Excess Costs."
The Company anticipates such increased costs in the second quarter of 1998.
The Texas 75% Net Profits Interests contributed approximately $0.18 per Trust
Unit to 1997 royalty income, or 10% of total 1997 distributions.
Year 2000
The Trustee has been advised by the Company that timely modification of its
computer systems for year 2000 compliance is not considered a material risk to
the Trust and that no costs of such modifications will be incurred by the
Trust. The Company currently does not have information regarding year 2000
compliance of major product purchasers and operators of the Underlying
Properties. If these parties do not achieve timely year 2000 compliance,
timely Trust distributions to Trust Unitholders could be adversely affected.
Since the Trust does not use the Trustee's computer systems in any significant
capacity, the Trustee's year 2000 compliance should not affect the Trust.
THREE MONTHS ENDED MARCH 31, 1997 AND 1998
For the quarter ended March 31, 1998, royalty income was $2,335,000,
compared with $3,115,000 for the first quarter of 1997. This 25% decrease in
royalty income is primarily the result of significantly lower oil prices and
decreased gas sales volumes.
After considering interest income of $4,000 and administration expense of
$44,000, distributable income for first quarter 1998 was $2,295,000, or
$0.382494 per Unit of beneficial interest. Distributions of $0.148984,
$0.143942 and $0.089568 per Trust Unit were made to Unitholders of record on
January 30, February 27 and March 31, 1998, respectively. Distributable income
for first quarter 1997 was $3,070,000, or $0.511589 per Trust Unit.
Volumes
Oil sales volumes decreased 1% from first quarter 1997 to 1998 because of
natural production decline, partially offset by the timing of cash receipts.
Gas sales volumes decreased 12% from first quarter 1997 to 1998, primarily
because of volume adjustments related to prior periods and the timing of cash
receipts. Excluding such prior period adjustments and cash receipt timing
differences, gas sales volumes declined approximately 2% from
18
first quarter 1997 to 1998. Such 2% decline includes an estimated 4% natural
decline in gas production, partially offset by a 2% increase in gas sales
volumes related to new wells drilled during 1997 on some of the Texas 90% Net
Profits Interests.
Prices
The average oil price received by the Trust for first quarter 1998 was
$16.15 per barrel, a decrease of 29% from the first quarter 1997 average price
of $22.62. Because of the two-month interval between oil production and
receipt by the Trust of related royalty income, the first quarter 1997 average
price reflects the rise in oil prices to six-year highs in December 1996 and
January 1997. Similarly, the first quarter 1998 average oil price includes two
months of lower prices following the sharp decline in oil prices that began in
December 1997. The average posted West Texas Intermediate oil price for
February through April 1998 (related to royalty income to be received by the
Trust in second quarter 1998) was $13.26.
The first quarter 1998 average gas price was $2.59 per Mcf, or 2% above the
first quarter 1997 price of $2.53. The Company has advised the Trustee that it
expects the average gas price for first quarter 1998 production (related to
royalty income to be received by the Trust in second quarter 1998) to decline
to approximately $1.90 because of reduced demand during a milder than normal
winter.
Costs
Costs deducted in the calculation of first quarter 1998 royalty income
increased 5% or $63,000 from total costs for first quarter 1997. This was a
result of a 14% or $88,000 increase in production and other expenses,
partially offset by an 8% or $13,000 decrease in development costs and a 4% or
$12,000 decrease in production and property taxes. Changes in production
expense and development costs are primarily related to the timing of
maintenance and development projects on the underlying working interest
properties. Decreased Oklahoma drilling costs offset costs related to a carbon
dioxide injection project that began on one of the Texas underlying working
interest properties in 1998. See "Excess Costs" below. Production taxes
decreased with decreased oil and gas revenues, partially offset by increased
estimated property taxes.
Excess Costs
The Company has advised the Trustee that, in the calculation of Trust
royalty income for the month of April 1998, costs exceeded revenues by $93,000
for the Texas Conveyance of the 75% Net Profits Interests. Such excess costs
are the result of lower oil prices and increased development costs related to
the carbon dioxide injection project that began during the first quarter.
Excess costs from one Conveyance cannot reduce royalty income computed under
another Conveyance; therefore, cumulative excess costs plus accrued interest
must be recovered from future Net Proceeds of the underlying Texas working
interest properties before these properties can again contribute to Trust
royalty income. The Texas 75% Net Profits Interests contributed approximately
$0.07 per Trust Unit to first quarter 1997 royalty income, or 14% of first
quarter 1997 distributions. Primarily because of lower oil prices in December
1997 and January 1998, the Texas 75% Net Profits Interests contributed only
$0.015 per Trust Unit to first quarter 1998 royalty income, or 4% of first
quarter 1998 distributions.
19
THE TRUST
The Trust was formed on February 12, 1991 pursuant to the Trust Indenture
between NationsBank, N.A. (formerly NationsBank of Texas, N.A. and NCNB Texas
National Bank), as trustee, and the Company. In connection with the formation
of the Trust, the Company carved the Net Profits Interests out of the
Underlying Properties and conveyed the Net Profits Interests to the Trust in
exchange for an aggregate of 6,000,000 Trust Units.
The Company currently owns the Underlying Properties, subject to and
burdened by the Net Profits Interests. Accordingly, the Company, as owner of
the Underlying Properties, receives payments from purchasers of production or
the operators of such properties. The Company aggregates these payments,
deducts costs and expenses where applicable, and makes payments to the Trustee
each month for the amounts due to the Trust.
FEES AND EXPENSES
The following is a description of certain fees and expenses anticipated to
be paid or borne by the Trust, including all fees expected to be paid to the
Company, the Trustee or their affiliates.
Overhead Fee. In calculating Net Proceeds of the 75% Net Profits Interests,
the Company deducts and retains $233,000 per year (subject to annual
adjustment) to monitor the Underlying Properties. Such monitoring activities
include various engineering, accounting and administrative functions. This fee
is deducted from the gross proceeds attributable to the Underlying Properties
that are working interests. Because the Trust receives 75% of the Net Proceeds
from such properties, the effect of the overhead fee is to reduce the Net
Proceeds payable to the Trust by $174,750 per year. This amount will increase
or decrease each year based on increases or decreases in the year-end index of
average weekly earnings of crude petroleum and gas workers.
Interest. The Company will not pay interest on any amounts received from the
Underlying Properties prior to payment to the Trust.
Loan Fees and Deposits. The Trustee is entitled to cause the Trust to borrow
money to pay expenses that cannot be paid out of cash held by the Trust. The
Trustee may borrow such amounts from itself. Because the Trustee is a
fiduciary, the terms of such borrowing must be fair to the Trust Unitholders.
The Trustee may also deposit funds awaiting distribution in an account with
the Trustee, provided the interest paid thereon equals the amount paid by the
Trustee on similar deposits.
Trust Administrative Expenses. The Trustee will be paid 1/20th of 1% of the
Net Proceeds paid to the Trust. The Trustee will also receive a fee if the
Trust is terminated and in certain other circumstances. See "Description of
the Trust Indenture--Compensation of the Trustee." The Trust will also incur
legal, accounting and engineering fees, printing costs and other expenses.
Total Trust administrative expenses were $159,000 in 1997; in the future, such
costs could be greater or less depending on future events.
20
HYPOTHETICAL ANNUAL CASH DISTRIBUTIONS
Estimated proved reserves of the Underlying Properties are composed of
approximately 31% oil and 69% natural gas, based on the discounted present
value of estimated future net revenues as of December 31, 1997 (based on
constant prices at December 31, 1997 using a West Texas Intermediate crude oil
posted price of $15.50 per Bbl of oil and the weighted average gas price of
$1.76 per Mcf). The amount of Trust revenues and cash distributions to Trust
Unitholders will be directly dependent on the sales prices for both its oil
and natural gas, the volume of oil and gas sold and, for the 75% Net Profits
Interests in Underlying Properties that are working interests, the cost of
production and development of such oil and gas. The following unaudited tables
were prepared by the Company and demonstrate the hypothetical effect that
changes in the prices for oil and gas could have on Trust distributions. The
tables below set forth the hypothetical annual cash distributions per Trust
Unit for calendar year 1998 on the accrual or production basis; the resulting
hypothetical annual cash distributions per Trust Unit as a percentage of the
purchase price of the Trust Unit ("Hypothetical Pre-Tax Yield"); and the
resulting hypothetical annual yield following payment of all federal income
tax at the highest individual tax rate of 39.6% ("Hypothetical After-Tax
Yield") based upon (i) an assumed purchase price of $16.00 per Trust Unit,
(ii) various hypothetical oil and gas sales prices, and (iii) the assumptions
described below under "--Assumptions and Methodology." The hypothetical prices
of oil and gas production shown have been chosen solely for illustrative
purposes. See "The Net Profits Interests and the Underlying Properties--Oil
and Gas Production" for historical weighted average oil and gas prices. THE
TABLES ARE NOT A PROJECTION OR FORECAST OF THE ACTUAL OR ESTIMATED RESULTS
FROM AN INVESTMENT IN THE TRUST UNITS. THE PURPOSE OF THE TABLES IS TO
ILLUSTRATE THE SENSITIVITY OF CASH DISTRIBUTIONS AND HYPOTHETICAL PRE-TAX AND
HYPOTHETICAL AFTER-TAX YIELDS TO VARIATIONS IN THE PRICE OF OIL AND GAS. NO
ASSURANCE IS OR CAN BE PROVIDED THAT THE ASSUMPTIONS SET FORTH BELOW WILL
OCCUR OR THAT THE PRICE OF OIL OR GAS WILL NOT DECLINE OR WILL NOT INCREASE BY
SOME AMOUNT OTHER THAN THOSE USED FOR PURPOSES OF THE TABLES. Due to the
varying demand for natural gas, the amount of monthly cash distributions from
the Trust may vary on a seasonal basis. Additionally, month-to-month
distributions will vary based on the timing of development expenditures on the
working interest Underlying Properties and the net revenues, if any, generated
by development projects.
Because of natural production decline, production estimates generally show
decreases in production from year to year. Accordingly, the hypothetical cash
distributions attributable to 1998 production are not necessarily indicative
of yields for future years.
21
THE UNAUDITED AMOUNTS SET FORTH IN THE TABLES BELOW ARE NOT NECESSARILY
INDICATIVE OF FUTURE RESULTS.
HYPOTHETICAL ANNUAL CASH DISTRIBUTIONS PER TRUST UNIT ATTRIBUTABLE TO ESTIMATED
1998 PRODUCTION
HYPOTHETICAL POSTED
OIL PRICE PER BBL(a) HYPOTHETICAL WELLHEAD GAS PRICE PER MCF(b)
-------------------- -------------------------------------------
$1.50 $2.00 $2.50 $3.00
---------- ---------- ---------- ----------
$10.00........................... $ 0.69 $ 0.89 $ 1.10 $ 1.31
$15.00........................... 0.78 1.00 1.21 1.43
$20.00........................... 1.02 1.24 1.45 1.67
$25.00........................... 1.26 1.48 1.69 1.91
HYPOTHETICAL PRE-TAX YIELD AT A TRUST UNIT PRICE OF $16.00
ATTRIBUTABLE TO ESTIMATED 1998 PRODUCTION(c)
HYPOTHETICAL POSTED
OIL PRICE PER BBL(a) HYPOTHETICAL WELLHEAD GAS PRICE PER MCF(b)
-------------------- -------------------------------------------
$1.50 $2.00 $2.50 $3.00
---------- ---------- ---------- ----------
$10.00........................... 4.3% 5.6% 6.9% 8.2%
$15.00........................... 4.9% 6.3% 7.6% 8.9%
$20.00........................... 6.4% 7.8% 9.1% 10.4%
$25.00........................... 7.9% 9.3% 10.6% 11.9%
HYPOTHETICAL AFTER-TAX YIELD AT A TRUST UNIT PRICE OF $16.00
ATTRIBUTABLE TO ESTIMATED 1998 PRODUCTION(c)
HYPOTHETICAL POSTED
OIL PRICE PER BBL(a) HYPOTHETICAL WELLHEAD GAS PRICE PER MCF(b)
-------------------- -------------------------------------------
$1.50 $2.00 $2.50 $3.00
---------- ---------- ---------- ----------
$10.00........................... 7.3% 8.1% 8.9% 9.7%
$15.00........................... 7.7% 8.5% 9.3% 10.1%
$20.00........................... 8.6% 9.4% 10.2% 11.0%
$25.00........................... 9.5% 10.3% 11.1% 11.9%
- --------
(a) Oil prices shown are hypothetical WTI. Posted price is the price paid for
oil at a specific point, unadjusted for gravity and other conditional
factors. These prices differ from the average or actual price received for
production from the Underlying Properties, which takes into account
gravity, quality, transportation and marketing costs. In the computation of
hypothetical distributions, $0.44 per barrel is deducted from the
hypothetical posted oil price for the foregoing adjustments. See "--
Assumptions and Methodology--Oil and Gas Prices," below.
(b) Gas prices shown are hypothetical wellhead gas prices for conventional
natural gas produced from the Underlying Properties. Wellhead price is the
net price received for gas and natural gas liquids after all deductions for
transportation, marketing and gathering. The weighted average price of
conventional natural gas production from the Underlying Properties in 1997
was $2.47 per Mcf, which was approximately the same as the average NYMEX
near month natural gas futures contract price for 1997. However, if
location, quality and other differentials that have occurred in the past
occur again in the future, there may be significant differences between the
conventional natural gas price received from the Underlying Properties and
the NYMEX price. For the first quarter of 1998, the difference between the
weighted average price of conventional natural gas production from the
Underlying Properties and the average NYMEX near month natural gas futures
contract was $0.06 per Mcf. Certain differentials from wellhead gas prices
have been factored into the hypothetical analyses for coal seam gas
production in the San Juan Basin. See "--Assumptions and Methodology--Oil
and Gas Prices," below.
(c) Because the Trust Units are a depleting asset, a portion of this yield is
effectively a return of capital.
22
The following table shows the calculations of the hypothetical 1998 cash
distribution per Trust Unit, pre-tax and after-tax yields, based on the
assumptions described under "Assumptions and Methodology" below and assuming a
$15.00 WTI, a $2.00 wellhead gas price and a $16.00 Trust Unit price:
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS
--------------------------- ----------------------------
VOLUMES AMOUNT VOLUMES AMOUNT
------------- ------------- ------------- --------------
(IN THOUSANDS, EXCEPT PER TRUST UNIT AND PERCENTAGES)
TOTAL TRUST:
Oil(a)................ 88 $ 1,285 303 $ 4,414
Gas(b)................ 3,457 6,076 119 238
------------- --------------
Total Revenues...... 7,361 4,652
------------- --------------
Production and
property taxes(c).... 763 523
Production
expenses(d).......... -- 2,605
Development costs..... -- 1,200
------------- --------------
Total Expenses...... 763 4,328
------------- --------------
Net Proceeds.......... 6,598 324
Net profits percent-
age.................. 90% 75%
------------- --------------
Royalty income........ $ 5,938(X) $ 243(Y)
============= ==============
Total royalty income
(X)+(Y).............. $ 6,181
Trust administrative
expense.............. 200
-------------
Trust distributable
income............... $ 5,981
=============
ANNUAL
AMOUNT YIELD(e)
------ --------
PER TRUST UNIT (6,000,000
Trust Units):
Total distributions..... $1.00 6.3%
===
Cost depletion
deduction(f)........... (1.48)
-----
Taxable income (loss)... (0.48)
Income tax rate......... 39.6%
-----
Income tax benefit...... 0.19
Coal seam tax
credit(g).............. 0.17
-----
Total tax benefit....... 0.36
-----
Total distributions af-
ter tax................ $1.36 8.5%
===== ===
- --------
(a) Volumes are in Bbls. Oil price is $14.56 per Bbl ($15.00 WTI less quality
and location adjustment of $0.44).
(b) Volumes are in Mcf. Wellhead gas price is $2.00 per Mcf, with the
exception of 1,196,000 Mcf of coal seam gas for which the gas price is
$1.30 per Mcf ($2.00 less a 35% quality and processing adjustment).
(c) Includes production taxes, calculated by multiplying oil and gas revenues
by estimated tax rates, and estimated property taxes.
(d) Includes overhead fee of $233,000 deducted by the Company.
(e) Because the Trust Units are a depleting asset, a portion of this yield is
effectively a return of capital.
(f) Cost depletion is recaptured upon sale of the Trust Units, resulting in
the taxation of any gain on sale as ordinary income (as opposed to capital
gain) up to the amount of cost depletion previously deducted.
(g) The coal seam tax credit will expire January 1, 2003. This credit may not
reduce the Trust Unitholder's regular tax liability below his tentative
minimum tax, subject to certain carryover provisions. See "Federal Income
Tax Consequences--Section 29 Coal Seam Gas Tax Credit."
23
ASSUMPTIONS AND METHODOLOGY
Timing of Actual Distributions. In preparing the hypothetical distribution
amounts and percentages set forth in the tables above, the revenues and
expenses of the Trust were calculated in accordance with the terms and
provisions of the Conveyances creating the Net Profits Interests as described
under "Computation of Net Proceeds," except that they are calculated on an
accrual or production basis rather than the cash basis prescribed by the
Conveyances. As a result, the proceeds attributable to production sold in the
final two or three months of 1998, and reflected in the tables above, will
actually enter into the calculation of net profits to be received by the Trust
in 1999. Similarly, Net Proceeds from production sold during the final two or
three months of 1997 were in fact distributed from the Trust in 1998.
Accordingly, the hypothetical cash distributions attributable to 1998
production represent hypothetical cash distributions from the Trust from March
or April 1998 through February or March 1999.
Production Estimates. Production estimates for 1998 were based on the
Reserve Report for the Underlying Properties. Such Reserve Report assumed
constant prices at December 31, 1997, based on a WTI of $15.50 per Bbl and the
weighted average wellhead gas price at December 31, 1997 of $1.76 per Mcf.
Based on such Reserve Report, production from the Underlying Properties for
1998 was estimated to be 391,000 Bbls of oil and 3,576,000 Mcf of gas. See
"Oil and Gas Prices" below for a description of changes in production due to
price variations. Actual sales in 1997 were 424,000 Bbls of oil and 4,419,000
Mcf of gas. Approximately 636,000 Mcf of 1997 gas sales were attributable to a
lawsuit settlement. For purposes of computing the amount of Section 29 tax
credit, coal seam gas production from the Underlying Properties is estimated
to be 1,196,000 Mcf during 1998 (1,066,000 Mcf net to the Trust). Differing
levels of production will result in different levels of distributions and
yields.
Oil and Gas Prices. Oil prices shown in the above tables are hypothetical
posted oil prices. Posted price is the price paid for oil at a specific point,
unadjusted for gravity and other factors. Published benchmark prices are
typically based upon West Texas Intermediate crude, a light, sweet oil of a
particular gravity. These prices differ from the average or actual price
received by the Company, which takes into account gravity, quality,
transportation and marketing costs. A substantial portion of the oil
production from the Underlying Properties is sour crude which will generally
have gravity, quality and transportation considerations leading to a reduced
price. Differentials between posted oil prices and the prices actually
received for oil production from the Underlying Properties may also vary
significantly due to market conditions. In the computation of hypothetical
distributions in the above tables, $0.44 per barrel, representing the average
difference between the posted price of West Texas Intermediate crude and the
price received by the Company during 1997, is deducted from the hypothetical
posted oil price to reflect these adjustments. Pro forma average oil prices
for Trust production which appear in this prospectus are wellhead oil prices
which are prices net of all adjustments and deductions.
Gas prices shown in the above tables are hypothetical wellhead prices for
conventional natural gas. Wellhead price is the net price received for gas and
natural gas liquids after all deductions for transportation, marketing and
gathering. The weighted average price of conventional natural gas production
from the Underlying Properties in 1997 was $2.47 per Mcf, which was
approximately the same as the average NYMEX near month natural gas futures
contract price for 1997. However, if location, quality and other differentials
that have occurred in the past occur again in the future, there may be
significant differences between the conventional natural gas price received
from the Underlying Properties and the NYMEX price. For the first quarter of
1998, the difference between the weighted average price of conventional
natural gas production from the Underlying Properties and the average NYMEX
near month natural gas futures contract was $0.06 per Mcf. Coal seam gas
produced from the San Juan Basin has been assumed to sell at a 35% discount to
the sales price of conventional natural gas because of differences in
processing and gathering costs and liquids content.
The foregoing decrements and increments to posted oil prices and wellhead
gas prices applied in the hypothetical distribution and yield analyses are
based upon an analysis by the Company of the historic price differentials for
production from the Underlying Properties with consideration given to other
factors that may affect such differentials in 1998. There is no assurance that
such assumed differentials will approximate the actual price differentials
that may be experienced by the Trust in 1998.
24
When oil and gas prices decline, the operators of the Underlying Properties
may elect to reduce or completely suspend production. No adjustments have been
made to estimated 1998 production to reflect such potential reductions or
suspensions of production.
Production Expenses and Development Costs. Production expenses and
development costs for 1998 on the Underlying Properties that are working
interests are estimated to be $2,605,000 (including the $233,000 overhead fee
for monitoring the working interest Underlying Properties which is deducted by
the Company in calculating Net Proceeds) and $1,200,000, respectively. For a
description of production expenses and development costs, see "Computation of
Net Proceeds--75% Net Profits Interests."
Administrative Expenses. Trust administrative expenses for 1998 are assumed
to be $200,000 ($0.033 per Trust Unit). See "The Trust--Fees and Expenses."
Hypothetical After-Tax Yield at $16.00 Purchase Price (Note: Because the
Trust Units are a depleting asset, a portion of this yield is effectively a
return of capital). The Hypothetical After-Tax Yield was computed by
determining the amount of federal income tax that would be paid on the
hypothetical distributions at the highest individual marginal tax rate for
1998 (39.6%) after taking into account cost depletion deduction of $1.48 per
Trust Unit and the Section 29 tax credit of $0.17 per Trust Unit based on coal
seam gas production of 1,066,000 Mcf as estimated in the Reserve Report for
the Net Profits Interests and on an estimated Section 29 tax credit of $1.08
per MMBtu, or approximately $0.98 per Mcf. This amount is then subtracted from
the hypothetical cash distribution per Trust Unit, and the result divided by
$16.00 per Trust Unit for the Hypothetical After-Tax Yield. When the
hypothetical distributions are less than $1.92 per Trust Unit, the
Hypothetical After-Tax Yield would be the same or greater than the
Hypothetical Pre-Tax Yield because of cost depletion and the Section 29 tax
credit. In all instances, it is assumed that the taxpayer has a regular
federal income tax liability sufficient to utilize the Section 29 tax credit
and the depletion deduction. Alternative minimum tax implications have not
been considered. The Section 29 tax credit cannot be used to reduce a
taxpayer's regular tax below his tentative minimum tax. See "Federal Income
Tax Consequences--Section 29 Coal Seam Gas Tax Credit."
25
THE NET PROFITS INTERESTS AND THE UNDERLYING PROPERTIES
GENERAL
The Net Profits Interests are composed of:
--the 90% Net Profits Interests which are carved from:
(i) the Company's interest in certain producing royalty and
overriding royalty interest properties in Texas, Oklahoma and New
Mexico ("underlying royalties"), and
(ii) an 11.11% non-participating royalty interests in the Company's
interest in certain nonproducing properties located primarily in Texas
and Oklahoma ("underlying nonproducing royalties")
--the 75% Net Profits Interests which are carved from the Company's
interest in certain non-operated working interests in four properties in
Texas and three properties in Oklahoma ("underlying working interest
properties").
All underlying royalties, underlying nonproducing royalties and underlying
working interest properties (collectively, the "Underlying Properties") are
currently owned by the Company, subject to the Net Profits Interests conveyed
to the Trust. The Company may sell all or any portion of the Underlying
Properties at any time, subject to and burdened by the Net Profits Interests.
The Net Profits Interests entitle the Trust to receive either 90% or 75% of
the Net Proceeds from the sale of oil and gas produced from the Underlying
Properties. In general, Net Proceeds equal the Gross Proceeds (as defined)
received by the Company from the sale of production less designated costs. For
a description of Gross Proceeds, see "Computation of Net Proceeds--90% Net
Profits Interests" and "--75% Net Profits Interests." Gross Proceeds received
by the Company are generally the wellhead price received from the sale of oil
and natural gas, net of transportation and marketing costs. For each 90% Net
Profits Interest in royalties and overriding royalties, such designated costs
include applicable production and property taxes, but generally do not include
other significant operating or development costs. For each 75% Net Profits
Interest in working interests, such costs include operating and development
costs and production and property taxes. The computation of Net Proceeds is
more specifically described in the Conveyances. See "Computation of Net
Proceeds."
The 90% Net Profits Interests were created under three Conveyances from
Underlying Properties located in Texas, New Mexico and Oklahoma, respectively.
The 75% Net Profits Interests were created under two Conveyances from
Underlying Properties located in Oklahoma and Texas, respectively.
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 31.7 Bcf of natural gas at
December 31, 1997, or approximately 83% of the Trust's total gas reserves at
that date. The Company 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 and Burlington Resources Oil & Gas Company. Production from
conventional gas wells is primarily from the Dakota, Mesaverde and Pictured
Cliffs formations.
Development of coal seam gas reserves in the Fruitland formation was the
most significant recent development activity in the San Juan Basin until the
drilling period for the federal income tax credit expired on January 1, 1993
(see "Regulation--Coal Seam Tax Credit"). Since that date, operators in the
San Juan Basin have continued to report development of coal seam gas reserves
without the incentive of the federal income tax credit. It is not known
whether any of this development activity has directly affected Trust royalties
attributable
26
to such reserves or production. A significant recent activity in the San Juan
Basin was the completion of additional eastward pipeline capacity during 1996,
reducing the dependence of San Juan Basin gas on California markets.
The underlying royalties also include royalties in the Sand Hills field of
Crane County, Texas. Most of these properties are operated by Exxon Company,
U.S.A. and 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. Information regarding the number of wells on
royalty properties is generally not made available to royalty interest owners.
Accordingly, an accurate well count for all underlying royalties cannot be
provided.
Underlying Working Interest Properties. The underlying working interest
properties, detailed below, are developed properties undergoing secondary or
tertiary recovery operations:
OWNERSHIP OF
CROSS TIMBERS
OIL COMPANY
-----------------
NET
WORKING REVENUE
UNIT COUNTY/STATE OPERATOR INTEREST INTEREST
---- --------------- -------- -------- --------
North Central Mobil Producing Texas and New Mexico, Inc. 3.2% 2.1%
Levelland.............. Hockley/Texas
North Cowden............ Ector/Texas Altura Production Company 1.7% 1.4%
Penwell................. Ector/Texas Texaco Exploration and Production, Inc. 5.2% 4.6%
Sharon Ridge Canyon..... Borden/Texas Exxon Company, U.S.A. 4.3% 2.8%
Hewitt.................. Carter/Oklahoma Exxon Company, U.S.A. 11.3% 9.9%
South Graham Deese...... Carter/Oklahoma Maynard Oil Company 8.2% 7.0%
Wildcat Jim Penn........ Carter/Oklahoma Texaco Exploration and Production, Inc. 8.6% 7.5%
The underlying working interest properties consist of 60,154 gross (2,290
net) producing acres. As of December 31, 1997, there were 1,639 gross (76.5
net) productive oil wells, 1,127 gross (41.9 net) injection wells and no wells
in process of drilling on these properties. During 1997, 15 gross (1.5 net)
producing wells were drilled, as compared to 36 gross (2.9 net) producing
wells during 1996, and 24 gross (1.5 net) producing wells during 1995.
OIL AND GAS PRODUCTION
Trust production is recognized in the period royalty income is received. 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, 1997 are as follows (in thousands, except per unit data):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
-------------------- -------------------- --------------------
1995 1996 1997 1995 1996 1997 1995 1996 1997
------ ------ ------ ------ ------ ------ ------ ------ ------
PRODUCTION
Underlying Properties
Oil--Sales (Bbls)...... 86 90 95 355 347 329 441 437 424
Gas--Sales (Mcf)....... 3,403 4,275 4,302 110 110 117 3,513 4,385 4,419
Net Profits Interests
Oil--Sales (Bbls)...... 71 77 83 78 91 94 149 168 177
Gas--Sales (Mcf)....... 2,968 3,798 3,844 24 31 34 2,992 3,829 3,878
AVERAGE PRICE
Underlying Properties
Oil (per Bbl).......... $16.08 $18.56 $19.41 $15.05 $18.61 $19.14 $15.25 $18.60 $19.20
Gas (per Mcf).......... $ 1.30 $ 1.50 $ 2.05 $ 1.40 $ 1.92 $ 1.93 $ 1.30 $ 1.51 $ 2.04
27
Oil and gas production and average sales prices attributable to the
Underlying Properties and the Net Profits Interests for the three months ended
March 31, 1997 and 1998 are as follows (in thousands, except per unit data):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
----------------- ----------------- -------------
1997 1998 1997 1998 1997 1998
-------- -------- -------- -------- ------ ------
PRODUCTION
Underlying Properties
Oil--Sales (Bbls)............ 22 25 84 80 106 105
Gas--Sales (Mcf)............. 921 809 25 27 946 836
Net Profits Interests
Oil--Sales (Bbls)............ 19 21 37 16 56 37
Gas--Sales (Mcf)............. 825 720 10 6 835 726
AVERAGE PRICE
Underlying Properties
Oil (per Bbl)................ $ 22.93 $ 16.62 $ 22.54 $ 16.00 $22.62 $16.15
Gas (per Mcf)................ $ 2.52 $ 2.62 $ 3.04 $ 1.67 $ 2.53 $ 2.59
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. The Company 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.
PRICING AND SALES INFORMATION
Oil and gas are generally sold from the Underlying Properties at posted and
spot prices, respectively. 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 the Company as a royalty owner, or to the Trust.
OIL AND GAS RESERVES
General
Miller and Lents has estimated oil and gas reserves attributable to the Net
Profits Interests as of December 31, 1994, 1995, 1996 and 1997. 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 the Company in the subject properties. Since the
Trust has defined net profits interests, the Trust does not own a specific
ownership percentage of the oil and gas reserve quantities. Accordingly,
reserves allocated to the Trust pertaining to its 75% net profits interest 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
28
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.
Oil prices used to determine the standardized measure at December 31, 1994,
1995, 1996 and 1997 were based on WTI of $16.00, $18.00, $24.25 and $15.50 per
Bbl, respectively. The weighted average year-end wellhead gas prices used to
determine the standardized measure at December 31, 1994, 1995, 1996 and 1997
were $1.51, $1.37, $2.64 and $1.76 per Mcf, respectively.
Proved Reserves
The following table reconciles the change in proved reserves attributable to
the Net Profits Interests from December 31, 1994 through December 31, 1997 (in
thousands):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
-------------------- ------------------- -----------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
--------- ---------- --------- -------- ------- --------
Balance, December 31,
1994................... 684.2 41,257.5 1,006.4 342.9 1,690.6 41,600.4
Extensions, discoveries
and other additions... 4.2 296.7 10.0 -0- 14.2 296.7
Revisions of prior es-
timates............... 52.4 2,299.0 341.5 121.1 393.9 2,420.1
Production............. (71.3) (2,967.7) (77.8) (23.8) (149.1) (2,991.5)
------- ---------- --------- -------- ------- --------
Balance, December 31,
1995................... 669.5 40,885.5 1,280.1 440.2 1,949.6 41,325.7
Extensions, discoveries
and other additions... 7.7 174.6 17.1 -0- 24.8 174.6
Revisions of prior es-
timates............... 81.3 2,418.2 598.5 281.5 679.8 2,699.7
Production............. (77.7) (3,797.7) (90.7) (31.2) (168.4) (3,828.9)
------- ---------- --------- -------- ------- --------
Balance, December 31,
1996................... 680.8 39,680.6 1,805.0 690.5 2,485.8 40,371.1
Extensions, discoveries
and other additions... 107.9 270.0 -0- -0- 107.9 270.0
Revisions of prior es-
timates............... 25.5 1,779.7 (745.8) (301.5) (720.3) 1,478.2
Production............. (82.7) (3,844.1) (94.5) (33.4) (177.2) (3,877.5)
------- ---------- --------- -------- ------- --------
Balance, December 31,
1997................... 731.5 37,886.2 964.7 355.6 1,696.2 38,241.8
======= ========== ========= ======== ======= ========
During 1995, 1996 and 1997, revisions of prior estimates of the 90% Net
Profits Interests' proved gas reserves were primarily because of lower than
anticipated production declines. Revisions of prior estimates of the 75% Net
Profits Interests' proved reserves in each of these years were primarily the
result of changes in the year-end oil prices used in estimating proved
reserves. See "General" above.
Proved Developed Reserves
The following are estimated quantities of proved developed oil and gas
reserves as of December 31, 1994 and each following year-end through December
31, 1997 (in thousands):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
------------------- ----------------------------------
OIL GAS OIL GAS OIL GAS
(BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF)
------------------- --------- --------------- --------
December 31, 1994......... 678.4 38,708.1 939.6 334.4 1,618.0 39,042.5
======= ========== ========= ======= ======= ========
December 31, 1995......... 665.2 38,866.6 1,203.5 429.3 1,868.7 39,295.9
======= ========== ========= ======= ======= ========
December 31, 1996......... 676.6 37,705.7 1,701.2 675.7 2,377.8 38,381.4
======= ========== ========= ======= ======= ========
December 31, 1997......... 727.9 35,947.4 908.6 346.8 1,636.5 36,294.2
======= ========== ========= ======= ======= ========
Changes in proved developed reserves are explained under "Proved Reserves"
above.
29
Standardized Measure of Discounted Future Net Cash Flows from Proved Reserves
The following are summary calculations of the standardized measure of
discounted future net cash flows as of December 31, 1995, 1996 and 1997 (in
thousands):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
---------------------------- -------------------------- ----------------------------
DECEMBER 31, DECEMBER 31, DECEMBER 31,
---------------------------- -------------------------- ----------------------------
1995 1996 1997 1995 1996 1997 1995 1996 1997
-------- -------- -------- ------- -------- ------- -------- -------- --------
Future cash inflows..... $ 67,576 $119,971 $ 77,217 $22,295 $ 45,237 $14,975 $ 89,871 $165,208 $ 92,192
Future production
taxes.................. (4,628) (8,282) (5,346) (1,252) (2,611) (847) (5,880) (10,893) (6,193)
-------- -------- -------- ------- -------- ------- -------- -------- --------
Future net cash flows... 62,948 111,689 71,871 21,043 42,626 14,128 83,991 154,315 85,999
10% discount factor..... (31,880) (56,805) (36,221) (9,868) (20,663) (6,282) (41,748) (77,468) (42,503)
-------- -------- -------- ------- -------- ------- -------- -------- --------
Standardized measure.... $ 31,068 $ 54,884 $ 35,650 $11,175 $ 21,963 $ 7,846 $ 42,243 $ 76,847 $ 43,496
======== ======== ======== ======= ======== ======= ======== ======== ========
Changes in Standardized Measure of Discounted Future Net Cash Flows from
Proved Reserves
The following reconciles the changes during 1995, 1996 and 1997 in the
standardized measure (in thousands):
90% NET 75% NET
PROFITS INTERESTS PROFITS INTERESTS TOTAL
-------------------------- ------------------------- --------------------------
1995 1996 1997 1995 1996 1997 1995 1996 1997
------- ------- -------- ------- ------- ------- ------- ------- --------
Standardized measure,
January 1.............. $33,754 $31,068 $ 54,884 $ 7,487 $11,175 $21,963 $41,241 $42,243 $ 76,847
Extensions, discoveries
and other additions.... 388 460 1,311 41 178 -0- 429 638 1,311
Accretion of discount... 3,099 2,767 4,861 692 1,012 1,980 3,791 3,779 6,841
Revisions of prior
estimates, changes in
price and other........ (1,576) 27,159 (16,689) 4,098 11,298 (14,264) 2,522 38,457 (30,953)
Royalty income.......... (4,597) (6,570) (8,717) (1,143) (1,700) (1,833) (5,740) (8,270) (10,550)
------- ------- -------- ------- ------- ------- ------- ------- --------
Standardized measure,
December 31............ $31,068 $54,884 $ 35,650 $11,175 $21,963 $ 7,846 $42,243 $76,847 $ 43,496
======= ======= ======== ======= ======= ======= ======= ======= ========
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 summarizes
the estimated coal seam tax credit attributable to the 90% Net Profits
Interests at December 31, 1995, 1996 and 1997. Such estimates are based on
projected coal seam gas production through the year 2002 as estimated by
independent engineers, the current year estimated Btu content and the coal
seam tax credit of $1.01, $1.03 and $1.05 per MMBtu at December 31, 1995, 1996
and 1997, respectively. See "Regulation--Coal Seam Tax Credit."
DECEMBER 31,
--------------------
1995 1996 1997
------ ------ ------
(IN THOUSANDS)
Undiscounted........................................... $4,125 $3,946 $3,390
====== ====== ======
Discounted present value at 10%........................ $3,214 $3,150 $2,784
====== ====== ======
CERTAIN PROVISIONS AFFECTING SAN JUAN BASIN ROYALTY INTERESTS
Certain instruments creating or governing some of the Underlying Properties
that are royalties and overriding royalties in the San Juan Basin contain
provisions that purportedly either reduce the overriding royalty interest or
convert the royalty or overriding royalty interest into a working interest
when gas production falls below specified levels. The Company believes these
provisions were included in these instruments because of a federal regulation,
that has since been repealed, limiting the amount of royalties and overriding
royalties placed on federal leases in the San Juan Basin. No assurances,
however, can be made regarding the effect of these provisions on the Trust.
The Company and other royalty interest owners filed a lawsuit, later joined by
the Trust
30
in 1993, to recover revenues suspended by working interest owners based on
their interpretation of these reduction or conversion provisions. The Trust,
the Company and the other royalty owners settled this lawsuit in 1996.
Pursuant to the settlement, the Company received $750,000 in exchange for
reducing its 7.5% overriding royalty interest in these properties to a 1.875%
overriding royalty interest that does not convert to a working interest. The
Trust received $675,000 or $0.1125 per Trust Unit as its portion of the
settlement, which was distributed on January 15, 1997, to Trust Unitholders of
record on December 31, 1996. Other Underlying Properties in the San Juan Basin
are subject to similar provisions. One other working interest owner who
asserted this claim subsequently withdrew it.
REGULATION
Natural Gas Regulation
The interstate transportation and sale for resale of natural gas is subject
to federal regulation, including transportation rates, storage tariffs and
various other matters, primarily by the Federal Energy Regulatory Commission
("FERC"). Federal price controls on wellhead sales of domestic natural gas
terminated on January 1, 1993, although the FERC's jurisdiction over natural
gas transportation and storage was unaffected. Sales of natural gas are
affected by the availability, terms and cost of transportation, and the price
and terms for access to pipeline transportation remain subject to extensive
federal and state regulation. The FERC continues to promulgate revisions to
various aspects of regulations affecting the natural gas industry,
particularly for interstate natural gas transmission, which in certain
circumstances may also affect the intrastate transportation of natural gas.
Many aspects of the regulatory developments have not become final and are
still pending judicial and FERC final decisions. 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.
Sales of crude oil, condensate and natural gas liquids are not currently
regulated and are made at market prices. The FERC implemented regulations on
January 1, 1995, to establish an indexing system for transportation rates for
oil that could increase the cost of transporting oil to the purchaser. The
Trust is not able to predict what effect, if any, these regulations may have.
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 royalty income from coal seam wells. Under Section 29 of
the Code, coal seam gas produced prior to January 1, 2003 from wells drilled
after December 31, 1979 and before January 1, 1993, qualifies for the federal
income tax credit for producing nonconventional fuels. This tax credit for
1997 was approximately $1.05 per MMBtu. Such credit, calculated based on the
Trust Unitholder's pro rata share of qualifying production, may not reduce the
Trust Unitholder's regular tax liability (after the foreign tax credit and
certain other nonrefundable credits) below his alternative minimum tax. Any
part of the Section 29 tax credit not allowed for the tax year solely because
of this limitation is subject to certain carryover provisions.
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. The Company
has advised the Trustee that it does not believe that compliance with these
laws will have any material adverse effect upon the Trust Unitholders.
31
COMPUTATION OF NET PROCEEDS
The definitions, formulas, accounting procedures and other terms governing
the computation of the Net Proceeds are detailed and extensive, and the
following description of the Net Profits Interests and the computation of Net
Proceeds with respect to such interests is subject to and qualified by the
more detailed provisions of the Conveyances filed as exhibits to the
Registration Statement. See "Available Information."
The Net Profits Interests are defined net profits interests carved out of
specific oil and gas interests comprising the Underlying Properties. Each Net
Profits Interest entitles the Trust to receive a portion of the Net Proceeds
from the sale of oil and natural gas produced from the Underlying Properties.
The amounts paid to the Trust with respect to the Net Profits Interests are
based on the definitions of Gross Proceeds and Net Proceeds as set forth in
the Conveyances and described below. Under the Conveyances, Net Proceeds are
computed monthly (a "Computation Period"). The Company pays either 90% or 75%
of the aggregate Net Proceeds attributable to a Computation Period to the
Trust on the last business day of the month immediately following such
Computation Period. The amount paid to the Trust does not include interest on
the Net Proceeds held by the Company prior to payment to the Trust. The
Trustee makes distributions to Trust Unitholders monthly. See "Description of
the Trust Units--Distributions and Income Computations."
Net Proceeds generally means, for any Computation Period, the excess of
Gross Proceeds received during such Computation Period over certain designated
costs attributable to the Computation Period. Gross Proceeds and costs are
calculated on a cash basis, except that certain costs, primarily ad valorem
taxes and expenditures of a material amount, may be determined on an accrual
basis.
The Net Profits Interests were created pursuant to two forms of Conveyance.
One form of Conveyance created the 90% Net Profits Interests in the Underlying
Properties that are royalties and overriding royalties entitling the Trust to
receive 90% of the Net Proceeds from such Underlying Properties. The second
form of Conveyance created the 75% Net Profits Interests in the Underlying
Properties that are working interests entitling the Trust to receive 75% of
the Net Proceeds from such Underlying Properties. The definition of Net
Proceeds for the 90% Net Profits Interests and the 75% Net Profits Interests
differ, primarily because of the different costs associated with owning
royalty and overriding royalty interests compared to working interests. In
addition, for convenience in complying with state tax laws, a separate
Conveyance was prepared for each state in which any of the Underlying
Properties was located. As a result, five Conveyances (a 90% interest
conveyance for each of Texas, New Mexico and Oklahoma, and a 75% interest
conveyance for each of Texas and Oklahoma) were used to transfer the Net
Profits Interests to the Trust. Net Proceeds are calculated separately for
each Conveyance.
90% NET PROFITS INTERESTS
For the 90% Net Profits Interests, Net Proceeds is defined as the excess of
Gross Proceeds received over Royalty Costs. Gross Proceeds means, for any
Computation Period, the amounts received by the Company during such
Computation Period from sales of oil and gas produced from the Underlying
Properties subject to the 90% Net Profits Interests, net of all general
property (ad valorem), production, severance, sales, gathering, excise and
other taxes which are deducted or excluded from the proceeds of sales. Gross
Proceeds does not include (i) consideration for the transfer or sale of the
Underlying Properties or (ii) any amount which the Company, as owner of the
Underlying Properties, is not entitled to receive, which generally includes
oil and gas lost in the production and marketing thereof or used for drilling,
production and plant operations (including gas injection, secondary recovery,
pressure maintenance, repressuring, cycling operations, plant fuel or
shrinkage). Gross Proceeds includes any amount which the Company, as owner of
the Underlying Properties, receives from any of the following: shut-in gas
well royalties or payments; minimum royalties; payments for gas not taken;
advance or prepaid payments; amounts received for refraining from drilling an
offset well; damages arising from any cause; and any other payments in
connection with the drilling or the deferring of drilling of any well.
In general, Royalty Costs means, for any Computation Period, on a cash
basis, any taxes paid in connection with ownership of the Underlying
Properties, to the extent not deducted in calculating Gross Proceeds,
including estimated and accrued ad valorem and other property taxes. Royalty
Costs also include all other costs, expenses
32
and liabilities of, or borne in connection with the ownership of, such
property and amounts previously included in Gross Proceeds but subsequently
paid as a refund, interest or penalty. None of such costs has been or is
expected to be material.
75% NET PROFITS INTERESTS
For the 75% Net Profits Interests, Net Proceeds equal the excess of Gross
Proceeds received over Production Costs and Excess Production Costs. Gross
Proceeds means, for any Computation Period, the amounts received by the
Company during such Computation Period from sales of oil and gas produced from
the Underlying Properties subject to the 75% Net Profits Interests, net of (i)
all general property (ad valorem), production, severance, sales, gathering,
excise and other taxes which are deducted or excluded from the proceeds of
sales; (ii) any amounts attributable to nonconsent-operations as to which the
Company, as owner of the Underlying Properties, is a nonconsenting party and
which are dedicated to the reimbursement of costs and expenses of the
consenting party; and (iii) any payment made to the owner of the Underlying
Properties for gas not taken (but to the extent such payments are allocated to
gas taken in the future, such payments shall be included, without interest, in
Gross Proceeds when such gas is taken), damages (other than drainage or
reservoir injury), rental for reservoir use and payments made to the owner of
the Underlying Properties in connection with the drilling of any well. Gross
Proceeds does not include (i) consideration for the transfer or sale of the
Underlying Properties or (ii) any amount not received for oil and gas lost in
the production or marketing thereof or used by the owner of the Underlying
Properties in drilling, production and plant operations. Gross Proceeds
includes payments for future production to the extent they are not subject to
repayment in the event of insufficient subsequent production.
Production Costs means, in general, for any Computation Period, on a cash
basis, the sum of the following costs relating to the Underlying Properties
subject to such 75% Net Profits Interests: (i) all royalties or other burdens
against production, delay rentals, shut-in gas payments, minimum royalty or
other payments in connection with drilling or deferring drilling; (ii) any
taxes paid by the owner of the Underlying Properties to the extent not
deducted in calculating Gross Proceeds, including estimated and accrued ad
valorem and other property taxes; (iii) costs paid by the Company, as owner of
the Underlying Properties, under any joint operating agreement; (iv) all other
costs, expenses and liabilities of exploring for, drilling, operating and
producing oil and gas (net of dry and bottom hole payments received by the
owner of the Underlying Properties); (v) costs of manufacturing, refining and
processing gas; (vi) certain interest costs; (vii) an overhead charge; (viii)
amounts previously included in Gross Proceeds but subsequently paid as a
refund, interest or penalty; (ix) costs and expenses for renewals or
extensions of leases; and (x) at the option of the owner of the Underlying
Properties, accruals for costs approved under authorizations for expenditure.
Excess Production Costs are the excess of Production Costs over Gross Proceeds
for the period beginning with the end of the most recent month in which there
were Net Proceeds, plus interest accrued at the prime rate. Therefore, if
Production Costs exceed Gross Proceeds for a Computation Period for a Net
Profits Interest in Underlying Properties that are working interests, the
Trust will receive no payment for that period from such Net Profits Interest,
and Excess Production Costs, together with interest thereon at the prime rate,
will be carried over to the following month as a Production Cost for that
month in determining the excess of Gross Proceeds for that month over
Production Costs.
The computation of Net Proceeds is made separately by Conveyance (i.e.,
separately for working interests located in Texas and Oklahoma). Therefore,
Excess Production Costs in one state cannot reduce Net Proceeds from the
other.
GENERAL
If a controversy or possible controversy exists as to the correct or lawful
sales price of any oil or gas produced from an Underlying Property, then for
purposes of determining whether amounts have been received by the owner of the
Underlying Property and therefore are Gross Proceeds: (i) amounts withheld by
a purchaser or deposited by it with an escrow agent shall not be considered to
be received by the owner of the Underlying Property until actually collected;
(ii) amounts received by the owner of the Underlying Property and promptly
33
deposited with a nonaffiliated escrow agent will not be considered to have
been received until disbursed to it by such escrow agent; and (iii) amounts
received by the owner of the Underlying Property and not deposited with an
escrow agent will be considered to have been received.
The Trust is not liable to the owner of the Underlying Properties or the
operators for any operating, capital or other costs or liabilities
attributable to the Underlying Properties or oil or gas produced therefrom,
and the Trustee is not obligated to return any income received from the Net
Profits Interests. Overpayments made to the Trust will reduce future amounts
payable.
The Conveyances provide that the Company has the right to assign all or any
part of its interests in the Underlying Properties, subject to the Net Profits
Interests and the terms and provisions of the Conveyances. The Trust
Unitholders will not be entitled to vote on, consent to or approve of any such
transfer, and Trust Unitholders will not be entitled to any proceeds of such
transfer. Following any such transfer, the Underlying Properties will continue
to be burdened by the Net Profits Interests, and after any such transfer the
Conveyances require that the Net Proceeds attributable to the transferred
property be calculated separately by the transferee. The Conveyances have been
recorded in the appropriate real property records so as to give notice of the
Net Profits Interests to the Company's creditors and transferees, who would
take subject to the Net Profits Interests and whose interests would be
subsequent and inferior to the Net Profits Interests. Any transferee will
succeed to the responsibilities of the Company as to the interests so
transferred, including the payment duties. In the case of a transfer of a
portion of the Underlying Properties, the Conveyances require that the Net
Proceeds attributable to the transferred property be calculated separately by
the transferee.
The Company and any transferees will have the right to abandon any well or
property on an Underlying Property that is a working interest if, in its
opinion, such well or property ceases to produce or is not capable of
producing in commercially paying quantities, and upon termination of any such
lease, that portion of the Net Profits Interests relating thereto will be
extinguished.
The Company is required to maintain books and records sufficient to
determine the amounts payable with respect to the Net Profits Interests. The
Company is required to deliver to the Trustee a statement of the computation
of the Net Proceeds attributable to each Computation Period quarterly and
annually. The Company will cause the annual computation of Net Proceeds to be
audited. The cost of such audit will be borne by the Trust.
FEDERAL INCOME TAX CONSEQUENCES
This section summarizes the principal federal income tax consequences of the
ownership and sale of the Trust Units. The laws, regulations, court decisions
and IRS interpretations on which this summary is based are subject to change
by future legislation, regulations or new interpretations by the courts or the
IRS, which could have an adverse effect on the ownership of Trust Units. The
Trust will not request advance rulings from the IRS dealing with the tax
consequences of ownership of Trust Units but will rely on the opinion of
Butler & Binion, L.L.P. ("Tax Counsel") regarding the classification of the
Trust and certain federal income tax consequences described below.
Consummation of the offering is conditioned upon the confirmation of Tax
Counsel's opinion at the time of the closing. Tax Counsel believes that its
opinion is in accordance with the present position of the IRS regarding such
trusts. Such opinion is not binding on the IRS or the courts, however, and no
assurance can be given that the IRS or the courts will agree with such
opinion.
CLASSIFICATION AND TAXATION OF THE TRUST
In the opinion of Tax Counsel, under current law, the Trust will be taxable
as a grantor trust and not as an association taxable as a corporation. As a
grantor trust, the Trust will not be subject to tax at the trust level. For
tax purposes, the grantors (in this case, the Trust Unitholders) will be
considered to own the Trust's income and principal as though no trust were in
existence. A grantor trust simply files an information return, reporting all
items of income, credit or deductions which must be included in the tax
returns of the grantors. If, contrary to
34
the opinion of Tax Counsel, the Trust was determined to be an unincorporated
business entity, it would be taxable as a partnership unless it elected to be
taxed as a corporation. Certain publicly traded partnerships are taxable as
corporations. However, an exception exists for partnerships which derive at
least 90% of their gross income from oil and gas production, interest and
certain other types of passive income. If the Trust were taxable as a
partnership, it would fall within this exception. Thus, the principal tax
consequence from treatment of the Trust as a partnership would be that all
Trust Unitholders would report income from the partnership on the accrual
method of accounting for reporting their share of the Trust's income.
DIRECT TAXATION OF TRUST UNITHOLDERS
Since the Trust will be treated as a grantor trust for federal income tax
purposes, each Trust Unitholder will be taxed directly on his pro rata share
of the income of the Trust and will be entitled to claim his pro rata share of
the deductions of the Trust. The income of the Trust will be deemed to have
been received or accrued by the Trust Unitholders at the time such income is
received or accrued by the Trust and not when distributed by the Trust. Income
and expenses of the Trust will be taken into account by Trust Unitholders
consistent with their method of accounting and without regard to the taxable
year or accounting method employed by the Trust.
REPORTING OF TRUST INCOME AND EXPENSES
Unless otherwise advised by Tax Counsel or the IRS, the Trustee intends to
treat each royalty payment it receives as the taxable income of the Trust
Unitholders of record on the day of receipt (i.e., the last business day of
each calendar month). Similarly, the Trustee intends to pay expenses only on
the day it receives a royalty payment and to treat all expenses paid on a
royalty receipt day as the expenses of the Trust Unitholder to whom the
royalty income received on that date is distributed. Interest earned on a
distribution amount will be treated as belonging to the Trust Unitholder to
whom the distribution amount is paid. In most cases, therefore, the income and
expenses of the Trust for a period will be reported as belonging to the Trust
Unitholder to whom the distribution is made for such period and the amount of
the distribution for a Trust Unit will equal the net income allocated in
respect of such Trust Unit, determined without regard to depletion. Such
correlation may not exist if, for example, the Trustee establishes a cash
reserve to pay estimated future expenses or pays an expense with borrowed
funds. Moreover, it is possible that the IRS will attempt to impute income to
persons who are Trust Unitholders when a royalty payment on the Net Profits
Interests accrues, to disallow administrative expenses to persons who are not
Trust Unitholders when the expenses are incurred, or both. If the IRS did
attempt to impute such income, an accrual basis Trust Unitholder might realize
royalty income in a tax year earlier than that reported by the Trustee.
ROYALTY INCOME AND DEPLETION
In the opinion of Tax Counsel, the income from the Net Profits Interests
will be royalty income subject to an allowance for the greater of cost
depletion or percentage depletion. Both the percentage depletion allowance and
the cost depletion allowance must be computed separately by each Trust
Unitholder for each oil or gas property (within the meaning of Code Section
614). Tax Counsel understands that the IRS is presently taking the position
that a net profits interest carved out of multiple properties is a single
property for depletion purposes. Accordingly, the Trust intends to take the
position that the Net Profits Interest transferred to the Trust by each
Conveyance is a single property ("Property") for depletion purposes until such
time as the issue is resolved definitively in some other manner.
The deduction for depletion with respect to a Property is determined
annually and is the greater of "cost" depletion or, if allowable, "percentage"
depletion. Percentage depletion is generally available to "independent
producers" on the equivalent of 1,000 barrels of production per day. Prior to
the Revenue Reconciliation Act of 1990 ("1990 Act"), however, the benefit of
percentage depletion generally did not extend to "independent producers" as
defined in the Code (generally persons who are not substantial refiners or
retailers of oil or gas or their primary products) who were transferees of a
"proven" oil or gas property with respect to production from that property. As
a result of the 1990 Act, this rule will not be applicable in the case of
transfers of "proven"
35
properties after October 11, 1990. Accordingly, royalty income from production
attributable to Trust Units purchased pursuant to this offering by
"independent producers" will qualify for percentage depletion. Percentage
depletion is a statutory allowance equal to 15% of the gross income from
production from a property, subject to a net income limitation which, as a
result of the 1990 Act, was increased from fifty percent to one hundred
percent of the taxable income from the property, computed without regard to
depletion deductions and certain loss carrybacks. The depletion deduction
attributable to percentage depletion for a taxable year is limited to 65% of
the taxpayer's taxable income for the year before allowance of "independent
producers" percentage depletion. Unlike cost depletion, percentage depletion
is not limited to the adjusted tax basis of the property, although it reduces
such adjusted tax basis (but not below zero). With respect to domestic
stripper or heavy oil production from wells held by independent producers or
royalty owners, the statutory percentage depletion rate is increased under the
1990 Act by one percent (up to a maximum rate increase of ten percent) for
each whole dollar that the average domestic wellhead price of crude oil for
the immediately preceding year is less than $20 per barrel.
The Company believes that Trust Unitholders who purchase Trust Units
pursuant to this offering will derive a substantially greater benefit from
cost depletion than from percentage depletion.
In computing cost depletion for each property for any year, the adjusted tax
basis of such property at the beginning of such year is divided by the
estimated total units (e.g., Bbls of oil or Mcf of gas) recoverable from such
property to determine the per-unit allowance for such property. The per-unit
allowance is then multiplied by the number of units produced and sold from
such property during the year. Cost depletion for a property cannot exceed the
adjusted tax basis of such property. Since the Trust will be taxed as a
grantor trust, each Trust Unitholder will compute cost depletion using his
basis in his Trust Units. Information will be provided to each Trust
Unitholder reflecting how such basis should be allocated among each property
represented by his Trust Units. To the extent the depletion tax deduction
exceeds cash distributions per Trust Unit, such excess can be deducted from
the taxpayer's other sources of taxable income.
OTHER INCOME AND EXPENSES
It is anticipated that the only other income of the Trust will be interest
income earned on funds held as a reserve or held until the next distribution
date. Other expenses of the Trust will include any state and local taxes
imposed on the Trust and administrative expenses of the Trustee. Although the
issue has not been definitively resolved, Tax Counsel believes that all or
substantially all of such expenses are deductible in computing adjusted gross
income and, therefore, are not the type of miscellaneous itemized deductions
that are allowable only to the extent that the aggregate of such deductions
exceeds 2% of adjusted gross income.
ALTERNATIVE MINIMUM TAX
All taxpayers are subject to an alternative minimum tax on alternative
minimum taxable income ("AMTI"). AMTI is the taxpayer's taxable income
recomputed with various "adjustments" plus "items of tax preference," which,
in the case of persons other than "independent producers," include the excess
of the aggregate percentage depletion deductions with respect to an oil or gas
property over the adjusted tax basis of such property. The alternative minimum
tax rate for individual taxpayers filing a joint return is 26% up to $175,000
and 28% over $175,000 of AMTI in excess of an exemption amount, which
exemption amount is based upon a number of factors and varies between $45,000
and zero. Alternative minimum tax ("AMT") is the excess of a taxpayer's
"tentative minimum tax" for a tax year over his "regular" tax for that year.
The tentative minimum tax is determined by multiplying the excess of AMTI over
the applicable exemption amount by 26% up to $175,000 and 28% over $175,000
and subtracting the AMT foreign tax credit. Reduced maximum AMT tax rates may
apply to net capital gains and certain other gains.
Since the effect of the AMT varies depending upon each Trust Unitholder's
personal tax and financial position, each prospective investor is advised to
consult with his own tax advisor concerning the effect of the AMT on him.
36
SECTION 29 COAL SEAM GAS TAX CREDIT
Certain of the production attributable to the Net Profits Interests is from
coal seam gas. Provided a number of statutory requirements are met, taxpayers
are entitled to the Section 29 tax credit for production and sale of certain
qualified fuels produced from nonconventional sources, which include gas
produced from coal seams. The Section 29 tax credit applies to coal seam gas
produced and sold to an unrelated party prior to January 1, 2003 from wells
drilled after December 31, 1979 and prior to January 1, 1993. The Section 29
tax credit is equal to $3.00 per barrel of oil equivalent (i.e., 5.8 MMBtu)
adjusted for inflation since 1979 by the GNP annual implicit price deflator.
Thus, the credit was $6.10 per barrel of oil equivalent for 1997. The credit
is reduced by a fraction the numerator of which is the excess of the reference
price for the calendar year of sale ($17.24 for 1997) over $23.50 adjusted for
inflation ($47.78 for 1997) and the denominator of which is $6.00 adjusted for
inflation ($12.20 for 1997). The annual reference price is the Secretary of
the Treasury's estimate of the average wellhead price per barrel for all
domestic crude oil produced in that year. Since the calendar year 1997
reference price did not exceed $23.50 multiplied by the inflation adjustment
factor, the credit was not reduced in 1997. The Section 29 tax credit
available for gas produced in 1997 was $1.05 per MMBtu and in 1998 is
estimated to be $1.08 per MMBtu. In the opinion of Tax Counsel, if the
requisite statutory requirements are met, the Trust Unitholders will be
eligible to claim the Section 29 tax credit with respect to sales of qualified
coal seam gas production included in the calculation of the Net Profits
Interests.
The Section 29 tax credit allowable for any taxable year cannot exceed the
excess (if any) of the taxpayer's regular tax liability for such taxable year,
as reduced by the taxpayer's foreign tax credits and certain nonrefundable
credits, over the taxpayer's tentative minimum tax liability for that year.
Any amount of Section 29 tax credit disallowed for the tax year solely because
of this limitation will increase his credit for prior year minimum tax
liability, which may be carried forward indefinitely as a credit against the
taxpayer's regular tax liability, subject, however, to the limitation
described in the preceding sentence. There is no provision for the carryback
or carryforward of the Section 29 tax credit in any other circumstances.
Hence, a Trust Unitholder may not receive the full benefit of such credit
depending on his particular circumstances.
NON-PASSIVE ACTIVITY INCOME AND LOSS
The income and expenses of the Trust and the Section 29 tax credit will not
be taken into account in computing the passive activity losses and income
under Code Section 469 for a Trust Unitholder who acquires and holds Trust
Units as an investment. Section 29 tax credits generated by an investment in
the Trust Units, therefore, can be utilized to offset regular tax liability on
income from any source, subject to the limitations discussed in "Section 29
Coal Seam Gas Tax Credit" above.
UNRELATED BUSINESS TAXABLE INCOME
Certain organizations that are generally exempt from tax under Code Section
501 are subject to tax on certain types of business income defined in Code
Section 512 as unrelated business income. In the opinion of Tax Counsel, the
income of the Trust will not be unrelated business taxable income within the
meaning of Code Section 512 so long as the Trust Units are not "debt-financed
property" within the meaning of Code Section 514(b). In general, a Trust Unit
would be debt-financed if the Trust Unitholder incurs debt to acquire a Trust
Unit or otherwise incurs or maintains a debt that would not have been incurred
or maintained if such Trust Unit had not been acquired.
SALE OF TRUST UNITS; DEPLETABLE BASIS
Generally, a Trust Unitholder will realize gain or loss on the sale or
exchange of his Trust Units measured by the difference between the amount
realized on the sale or exchange and his adjusted basis for such Trust Units.
Gain or loss on the sale of Trust Units by a Trust Unitholder who is not a
dealer with respect to such Trust Units and who has a holding period for the
Trust Units of more than 12 months but not more than 18 months will be treated
as a mid-term capital gain (taxable at a maximum rate of 28%) or a holding
period of more than 18 months will be treated as a long-term capital gain
(taxable at a maximum rate of 20%), except to the extent of the depletion
recapture amount explained below. A Trust Unitholder's basis in his Trust
Units will be equal to the
37
amount paid for such Trust Units pursuant to this offering or pursuant to
market transactions. Such basis will be reduced by deductions for depletion
claimed by the Trust Unitholder (but not below zero). Upon the sale of the
Trust Units, a Trust Unitholder must treat as ordinary income his depletion
recapture amount, which is an amount equal to the lesser of (i) the gain on
such sale or (ii) the sum of the prior depletion deductions taken with respect
to the Trust Units (but not in excess of the initial basis of such Trust
Units). It is possible that the IRS would take the position that a portion of
the sales proceeds is ordinary income to the extent of any accrued income at
the time of sale allocable to the Trust Units sold, but which is not
distributed to the selling Trust Unitholder.
TAXATION OF FOREIGN HOLDERS
Unless the election described below is made, a nonresident alien individual,
foreign corporation, or foreign estate or trust ("Foreign holder") will be
subject to a 30% federal income withholding tax on his share of gross royalty
income from the Net Profits Interests (or tax treaty rates, if lower), without
any deductions, but gain realized on a sale of a Trust Unit will not be
subject to federal income tax unless: (i) the gain is otherwise effectively
connected with business conducted by the Foreign holder in the United States;
(ii) the Trust Unitholder is an individual who is present in the United States
for at least 183 days in the year of the sale; (iii) the Trust Unitholder owns
more than a 5% interest in the Trust; or (iv) the Trust Units cease to be
regularly traded on an established securities exchange. Gain realized by a
Foreign holder upon the sale by the Trust of all or any part of the Net
Profits Interests would be subject to federal income tax.
The Trust Unitholders who are Foreign holders may elect under Code Section
871 or Section 882 or similar provisions of applicable treaties to treat
income attributable to the Net Profits Interests as effectively connected with
the conduct of a trade or business in the United States. Such a Foreign holder
will be taxed at regular federal income tax rates on the net income
attributable to the Net Profits Interests (including gain recognized on the
disposition of Trust Units). Absent a treaty exception, the net income of a
corporate Foreign holder which has made such an election will also be subject
to the "branch profits tax" imposed under Code Section 884. To claim the
deductions allowable in computing net income, including cost depletion, an
electing Foreign holder will have to file a United States income tax return.
The election, once made, is irrevocable (unless an applicable treaty allows
the election to be made annually) and is applicable to all income and gain
realized by the Foreign holder with respect to any real property interests
located in the United States (including those interests held through
partnerships, fixed investment trusts, and other pass-through entities).
BACKUP WITHHOLDING
In general, distributions of Trust income will not be subject to "backup
withholding" unless: (i) the Trust Unitholder is an individual or other
noncorporate taxpayer and (ii) such Trust Unitholder fails to comply with
certain reporting procedures.
TAX SHELTER REGISTRATION
Code Section 6111 requires a tax shelter organizer to register a "tax
shelter" with the IRS by the first day on which interests in the tax shelter
are offered for sale. A "tax shelter," for purposes of the registration
requirement, is an investment with respect to which a person could reasonably
infer, from the representations made in connection with any offer for sale of
any interest in the investment, that the "tax shelter ratio" for any investor
may be greater than two to one as of the close of any of the first five years
ending after the date on which the investment is offered for sale. The term
"tax shelter ratio," with respect to an investment means the ratio that the
aggregate amount of gross deductions for any investor, determined without
regard to income derived from the investment, plus 350% of the credits that
are potentially available to an investor bears to the investment base for the
year. The "investment base" is equal to the cash, plus the adjusted basis
(which may be less than the fair market value) of any other property invested.
Certain borrowings, however, including those from other participants in the
venture, are excluded from the investment base. While the Company has no
knowledge of any such borrowings, it is possible that, due to such borrowings,
the investment base of an investor would be substantially reduced or
eliminated.
38
The Company has calculated the tax shelter ratio for an interest in the
Trust for the first five years of the Trust pursuant to the regulations
promulgated under Code Section 6111 and has determined that the tax shelter
ratio during such period is not expected to exceed two to one for investors
whose investment base is not reduced by borrowing. However, because it is
possible that the tax shelter ratio test could be exceeded for an investor who
had his investment base reduced due to borrowings, the Trust has been
registered as a tax shelter with the IRS. The tax shelter registration number
for the Trust will be furnished promptly to each investor. A Trust Unitholder
who sells or otherwise transfers a Trust Unit in a subsequent transaction must
furnish the tax shelter registration number to the transferee. The penalty for
failure of the transferor of a Trust Unit to furnish such tax shelter
registration number to a transferee is $100.00 for each such failure. It is
anticipated that the Trustee will furnish the tax shelter registration number
to transferees. Trust Unitholders must disclose the tax shelter registration
number of the Trust on Form 8271 to be attached to the tax return on which any
deduction, loss, credit or other benefit generated by the Trust is claimed or
income of the Trust is included. A Trust Unitholder who fails to disclose the
tax shelter registration number on his return, without reasonable cause for
such failure, will be subject to a $50 penalty for each such failure. (Any
penalties discussed herein are not deductible for federal income tax
purposes.)
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THIS
INVESTMENT OR THE CLAIMED TAX BENEFITS HAVE BEEN REVIEWED, EXAMINED OR
APPROVED BY THE IRS.
REPORTS
The Trustee will furnish to Trust Unitholders of record quarterly and annual
reports in order to permit computation of their tax liability. See
"Description of the Trust Units--Periodic Reports."
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information
regarding state income taxes and other state tax matters affecting the Trust
and the Trust Unitholders. Trust Unitholders are urged to consult their own
legal and tax advisors with respect to these matters.
Texas presently does not have a state income tax on resident or nonresident
individuals. The Texas franchise tax imposes, in effect, an income tax on
corporations and limited liability companies which qualify to do business or
actually do business in Texas. Trust Unitholders that are corporations or
limited liability companies may be subject to Texas franchise taxes on income
from the Net Profits Interests.
New Mexico and Oklahoma impose income taxes upon residents and nonresidents.
In the case of nonresidents, in both states income derived from tangible
property within the state is subject to tax. The income tax laws of New Mexico
and Oklahoma are both based on federal income tax laws. Thus, assuming the
Trust is taxed as a grantor trust for federal income tax purposes, the Trust
Unitholders will be subject to New Mexico income tax on their share of income
from the New Mexico Net Profits Interest and to Oklahoma income tax on income
from the Oklahoma Net Profits Interests. Nonresidents of New Mexico and
Oklahoma, however, may not be taxed in those states on gains from sales of
Trust Units. Trust Unitholders may also be subject to tax by the state in
which they reside on income derived from the Trust.
The Trustee will provide information concerning the Trust sufficient to
identify the income of the Trust allocable to each state. Trust Unitholders
should consult their own tax advisors to determine their income tax filing
requirements with respect to their share of income of the Trust allocable to
states imposing an income tax on such income.
The Trust Units may constitute real property or an interest in real property
under the inheritance, estate and probate laws of Texas, New Mexico and
Oklahoma. If the Trust Units are held to be real property or an interest
39
in real property under the laws of a state in which the Underlying Properties
are located, the Trust Units may be subject to devolution, probate and
administration laws, and inheritance or estate and similar taxes, under the
laws of such state.
DESCRIPTION OF THE TRUST INDENTURE
The following information and the information set forth under "Description
of the Trust Units" are subject to the detailed provisions of the Trust
Indenture between the Company and NationsBank, N.A., which acts as Trustee for
the Trust. NationsBank, N.A. is co-agent under the Company's $750,000,000
revolving credit facility and currently holds 7.8% of the Company's aggregate
outstanding credit loans. The following is a general description of the basic
framework of the Trust, and is qualified by the detailed provisions concerning
the Trust set forth in the Trust Indenture, a copy of which was filed as an
exhibit to the Registration Statement. See "Available Information." For a
description of the fiduciary responsibility of the Trustee, including remedies
available for the breach of these duties, see "--Fiduciary Responsibility and
Liability of the Trustee," below.
CREATION AND ORGANIZATION OF THE TRUST; AMENDMENTS
Pursuant to the Conveyances, the Net Profits Interests were conveyed by the
Company to the Trust in exchange for 12,000,000 Trust Units. Subsequently, the
12,000,000 Trust Units were converted to 6,000,000 outstanding Trust Units.
The Trust was created under Texas law pursuant to the terms of the Trust
Indenture to acquire and hold the Net Profits Interests for the benefit of the
Trust Unitholders. The Net Profits Interests are passive in nature and the
Trustee will have no control over and no responsibility for costs relating to
the operation of the Underlying Properties. Neither the Company nor the
operators of the Underlying Properties have any contractual commitments to the
Trust to conduct further drilling on the Underlying Properties or to maintain
their ownership interest in any of such properties. For a description of the
Underlying Properties and other information relating to such properties, see
"The Net Profits Interests and the Underlying Properties."
The beneficial interest in the Trust created by the Trust Indenture is
divided into 6,000,000 Trust Units, which represent equal undivided portions.
For additional information concerning the Trust Units, see "Description of the
Trust Units."
The Trust Indenture may be amended by a vote of holders of 80% of the Trust
Units. No provision of the Trust Indenture, however, may be amended that would
increase the power of the Trustee to engage in business or investment
activities or to alter the rights of the Trust Unitholders as among
themselves.
ASSETS OF THE TRUST
The only assets of the Trust, other than cash and temporary investments
being held for the payment of expenses and liabilities and for distribution to
the Trust Unitholders, are the Net Profits Interests. See "The Net Profits
Interests and the Underlying Properties."
DUTIES AND LIMITED POWERS OF THE TRUSTEE
The duties of the Trustee are specified in the Trust Indenture and by the
laws of the State of Texas. The basic duties of the Trustee are to collect
income attributable to the Net Profits Interests, to pay out of the Trust's
income and assets all expenses, charges and obligations and to distribute the
distributable income to the Trust Unitholders. The Trustee is authorized to
take such action as in its judgment is necessary or advisable to best achieve
the purposes of the Trust.
With respect to any liability that is contingent or uncertain in amount or
that otherwise is not currently due and payable, the Trustee has the
discretion to establish a cash reserve for the payment of such liability. If
at any time the cash on hand and to be received by the Trustee is not, in the
Trustee's judgment, sufficient to pay
40
liabilities of the Trust as they become due, the Trustee is authorized to
borrow the funds required to pay such liabilities, in which event no further
distributions will be made to Trust Unitholders until such borrowing has been
repaid. The Trustee is permitted to borrow such funds from any person,
including itself. To secure payment of any such indebtedness, the Trustee is
authorized to mortgage, pledge, grant security interests in or otherwise
encumber assets of the Trust, or any portion thereof, including the Net
Profits Interests, and to carve out and convey production payments.
After payment of or provision for Trust expenses and obligations, the
Trustee will make monthly distributions to the Trust Unitholders of all the
proceeds received from the Net Profits Interests and not theretofore
distributed. The Trustee will submit periodic financial reports to the Trust
Unitholders as described under "Description of the Trust Units--Periodic
Reports."
The Trust Indenture provides that cash being held by the Trustee as a
reserve for liabilities or for distribution at the next distribution date will
be invested in interest-bearing obligations of the United States government,
repurchase agreements secured by such obligations or certificates of deposit
in certain banks, but the Trustee is otherwise prohibited from acquiring any
asset other than the Net Profits Interests or engaging in any business or
investment activity of any kind whatsoever.
In the event the Trustee determines it to be in the best interest of the
Trust Unitholders, the Trustee may sell for cash all or any part of the Net
Profits Interests only if approved by the Trust Unitholders. If the Net
Profits Interests to be sold constitute a material part of the assets of the
Trust, then the sale must be approved by a vote of holders of 80% or more of
the outstanding Trust Units; otherwise, the sale must be approved by a vote of
a majority in interest of Trust Unitholders constituting a quorum at a meeting
of Trust Unitholders. The Trustee is directed to effect such a sale (without
any such vote) upon termination of the Trust, which will occur if gross
revenues of the Trust for each of two consecutive years are less than
$1,000,000, and in certain other events. The Trustee must distribute the net
proceeds of such sale to the Trust Unitholders.
The Trust Indenture also provides that in the event of certain judicial or
administrative proceedings seeking the cancellation or forfeiture of any
property included in the Underlying Properties or asserting the invalidity of
or otherwise challenging the Net Profits Interests held by the Trust because
of the nationality, or any other status, of any one or more Trust Unitholders,
the Trustee will have the right to require such holder to dispose of his Trust
Units, and if such person fails to dispose of his Trust Units, the Trustee
will have the right to purchase such Trust Units.
To achieve the purposes of the Trust, the Trustee is also authorized to
agree to modifications of the terms of the Conveyances or to settle disputes
with respect thereto, so long as such modifications or settlements do not
alter the nature of the Net Profits Interests as to rights to receive a share
of the proceeds of oil or gas produced from the Underlying Properties, free of
any expense or other cost, which do not possess any operating rights or
obligations.
LIABILITIES OF THE TRUST
Because of the passive nature of the Trust assets and the restrictions on
the power of the Trustee to incur obligations, the only liabilities the Trust
has incurred have been those for routine administrative expenses, such as the
Trustee's fees and accounting, engineering, legal and other professional fees.
It is anticipated that the only liabilities that the Trust will incur in the
future will be for similar expenses.
FIDUCIARY RESPONSIBILITY AND LIABILITY OF THE TRUSTEE
The Trustee is a fiduciary with respect to the Trust Unitholders and under
Texas law, the Trustee is required to act in the best interests of the Trust
Unitholders at all times and to exercise the judgment and care in supervising
and managing the Trust's assets exercised by persons of ordinary prudence,
discretion and intelligence. Under Texas law, the Trustee's duties to the
Trust Unitholders are similar to the duty of care owed
41
by a corporate director to the corporation and its shareholders, except that
the legal presumption protecting business decisions made by directors from
challenge, generally referred to as the business judgment rule, is
inapplicable to decisions by the Trustee.
Due to the passive nature of the Trust, the Trustee has not been required to
make business decisions affecting the assets of the Trust. Therefore,
substantially all of the Trustee's functions under the Trust Indenture are
expected to continue to be ministerial in nature. See "--Duties and Limited
Powers of the Trustee," above. Under Texas law, the Trustee may not profit
from any transaction with the Trust. The Trust Indenture, however, permits the
Trustee to charge for its services as trustee and as transfer agent (see "--
Compensation of the Trustee"), to retain funds to pay anticipated future
expenses and to deposit such funds with the Trustee and to borrow funds at
commercial rates from the Trustee to pay expenses of the Trust. The Trustee is
also entitled to receive reimbursement of out-of-pocket expenses incurred in
administering the Trust.
In discharging its fiduciary duty to the Trust Unitholders, the Trustee may
act in its discretion and will be personally or individually liable to the
Trust Unitholders only for fraud or acts or omissions constituting bad faith.
The Trustee will not be liable for any act or omission of any agent or
employee of the Trustee unless the Trustee acted in bad faith in the selection
and retention of such agent or employee. The Trustee will be indemnified for
any liability, expense, claim, damage or other loss incurred by it
individually or as Trustee in the administration of the Trust or for any act
or omission on account of it being Trustee, unless resulting from fraud or bad
faith, and the Trustee will have a lien upon the assets of the Trust as
security for such indemnification and reimbursement and for compensation to be
paid to the Trustee. The Trustee is not entitled to indemnification from Trust
Unitholders. See "Description of the Trust Units--Liability of Trust
Unitholders." The Trustee is required to ensure that all contractual
liabilities of the Trust are limited to the assets of the Trust and will be
liable for such contractual liabilities if it fails to do so.
Under Texas law, if the Trustee, in bad faith, were to fail to collect
amounts owed to the Trust or distribute cash held by the Trust for
distribution, or otherwise, in bad faith, take or omit to take any action that
is in the best interest of the Trust Unitholders, the Trustee would be liable
to the Trust Unitholders for damages caused by any such act or omission,
including any loss or depreciation in value of the Trust assets or failure to
make a profit from such assets caused by such act or omission. Texas law
permits Trust Unitholders to file an action seeking other remedies for such
acts or omissions in addition to damages, including removal of the Trustee,
specific performance, appointment of a receiver, an accounting by the Trustee
to the Trust Unitholders, exemplary damages and other remedies. The
availability of these remedies provided by Texas law is explicitly
incorporated into the Indenture. Under the Indenture, the Trustee may be
removed by the Trust Unitholders, with or without cause, by the affirmative
vote of the holders of a majority of the Trust Units.
DURATION OF THE TRUST; SALE OF NET PROFITS INTERESTS
The Trust will be terminated upon the sale by the Trust of all or
substantially all of the Net Profits Interests, which sale may be effected
only as described under "--Duties and Limited Powers of the Trustee," above.
The Trust may also be terminated by a vote of holders of 80% or more of the
Trust Units outstanding or upon operation of the provision of the Trust
Indenture intended to permit the Trust to comply with the "rule against
perpetuities." Upon termination of the Trust, the Trustee will sell for cash
in one or more sales (which may be public auctions) all of the assets then
constituting the Trust estate. After paying all liabilities of the Trust and
establishing any reserves that the Trustee deems appropriate for contingent
liabilities, the Trustee will distribute the proceeds of such sales and any
other cash in the Trust estate to Trust Unitholders according to their
respective interests. The Trustee will not be required to obtain approval of
Trust Unitholders prior to conducting any sales upon termination of the Trust.
The Trustee may cause the sale of the Net Profits Interests if the holders
of 80% or more of the Trust Units approve such sale. The net proceeds of any
such sale will be distributed to the Trust Unitholders. The Trustee is
required to sell the Net Profits Interests if the Net Proceeds are less than
$1,000,000 for each of two consecutive years. Sale of the Net Profits
Interests will terminate the Trust.
42
COMPENSATION OF THE TRUSTEE
The Trust Indenture provides that the Trustee will be compensated for its
services, out of the Trust assets, in an annual amount of 1/20th of 1% of the
Net Proceeds, plus specified charges for certain officer time in excess of 300
hours annually, and fees ($9,500 annual minimum) to act as the transfer agent
for the Trust Units. The Trustee has contracted with ChaseMellon Shareholder
Services, LLC to provide the transfer agent services. The Trustee will also be
entitled to reimbursement for its out-of-pocket expenses. The Indenture also
provides that the Trustee is entitled to a termination fee if the Trust is
terminated. Such termination fee is required to be commensurate with services
performed by the Trustee in the termination of the Trust and in no event more
than 10% of the proceeds of the sale of the Trust's assets.
MISCELLANEOUS
The Trust Indenture provides that the Trustee may, but is not required to,
consult with counsel (which may be counsel to the Company or its successors),
accountants, geologists, engineers and other parties deemed by the Trustee to
be qualified as experts on the matters submitted to them, and the Trustee is
authorized and protected with respect to any action taken by the Trustee in
good faith in reliance upon and in accordance with the opinion of any such
party.
DESCRIPTION OF THE TRUST UNITS
GENERAL
Each Trust Unit represents an undivided share of beneficial interest in the
Trust and entitles its holder to the same rights as the holder of any other
Trust Unit. The Trust has 6,000,000 Trust Units outstanding.
DISTRIBUTIONS AND INCOME COMPUTATIONS
The Trustee determines for each monthly period (the "Monthly Period") the
amount available for distribution. Such amount (the "Monthly Distribution
Amount") is equal to the excess, if any, of the cash received by the Trust
from the Net Profits Interests during such Monthly Period, plus any other cash
receipts of the Trust (other than interest on a Monthly Distribution Amount
for a prior month) during such Monthly Period, over the liabilities of the
Trust paid during such Monthly Period. The Monthly Distribution Amount also
includes adjustments for changes made by the Trustee during such Monthly
Period in any cash reserves established for the payment of contingent or
future obligations of the Trust. Cash received by the Trust in a particular
Monthly Period from the Net Profits Interests generally represents net
proceeds from sales of production received by the Company in the immediately
preceding month. The Monthly Distribution Amount for each Monthly Period is
payable to the Trust Unitholders of record on the monthly record date (the
"Monthly Record Date"), which is the close of business on the last business
day of such Monthly Period or such date as the Trustee determines is required
to comply with legal or stock exchange requirements. On or before the 10th
business day after the Monthly Record Date, the Trustee will distribute pro
rata to each person who was a Trust Unitholder of record on such Monthly
Record Date the Monthly Distribution Amount for that month, together with
estimated interest earned on such Monthly Distribution Amount from the Monthly
Record Date for such month to the payment date.
Unless otherwise advised by counsel or the IRS, the income and expenses of
the Trust for each Monthly Period will be reported by the Trustee for tax
purposes as belonging to the Trust Unitholders of record on the Monthly Record
Date. The income and expenses will be recognized by the Trust Unitholders for
tax purposes in the Monthly Period received or paid by the Trust, rather than
in the Monthly Period distributed by the Trust. Net income, apart from any
depletion to which a Trust Unitholder may be entitled, is expected to be
essentially the same as the Monthly Distribution Amount. There may be minor
variances, however, because of the possibility that, for example, a reserve
will be established in one Monthly Period that will not give rise to a tax
deduction until a subsequent Monthly Period or an expenditure paid in one
Monthly Period will have to be amortized for tax purposes over several Monthly
Periods. See "Federal Income Tax Consequences."
43
TRANSFER OF TRUST UNITS
Trust Units are transferable on the records of the Trustee upon the
surrender of the certificate therefor in proper form for transfer as required
by the Trustee. No service charge will be made to the transferor or transferee
for any transfer of a Trust Unit, but the Trustee may require payment of a sum
sufficient to cover any tax or other governmental charge that may be imposed
in connection with such transfer. Until any such transfer, the Trustee may
treat the owner of any Trust Unit as shown by its records as the owner of the
Trust Unit evidenced thereby, and the Trustee shall not be charged with notice
of any claim or demand respecting such Trust Units by any other party. Any
such transfer of a Trust Unit will, as to the Trustee, transfer to the
transferee as of the close of business on the date of transfer, all right,
title and interest of the transferor in and to the Trust; provided, that a
transfer of a Trust Unit after any Monthly Record Date will not transfer to
the transferee the right of the transferor to the Monthly Distribution Amount
relating to such date. The laws of the State of Texas will govern all matters
affecting the title, ownership, warranty or transfer of Trust Units.
PERIODIC REPORTS
As promptly as practicable following the end of each of the first three
calendar quarters of each year, the Trustee will mail to each Trust Unitholder
of record on a Monthly Record Date during such quarter a report which shows
the assets and liabilities and receipts and disbursements of the Trust for
such quarter. Within 120 days following the end of each fiscal year or such
shorter period as may be required by the rules of any securities exchange on
which the Trust Units are listed for trading, the Trustee will mail to the
Trust Unitholders of record as of a date to be selected by the Trustee an
annual report containing audited financial statements of the Trust.
The Trustee will file all returns for federal income tax purposes as in its
judgment are required to comply with applicable law, and the Trustee will
prepare and mail to the Trust Unitholders quarterly and annually reports as
are necessary to permit each Trust Unitholder to report correctly his share of
the income and deductions of the Trust. The Trustee intends to treat all
income and deductions recognized during each Monthly Period as having been
recognized by holders of record on the last business day of such Monthly
Period unless otherwise advised by counsel or the IRS.
Each Trust Unitholder and his duly authorized agents and attorneys have the
right during reasonable business hours to examine and inspect records of the
Trust and the Trustee, including a list of the Trust Unitholders.
LIABILITY OF TRUST UNITHOLDERS
The Indenture provides that the Trustee is required to ensure that all
contractual liabilities of the Trust are limited to the assets of the Trust
and that the Trustee will be liable for such contractual liabilities if it
fails to do so. Texas law, however, is unclear whether a Trust Unitholder
would be jointly and severally liable for any liability of the Trust in the
event that the satisfaction of such liability was not by contract limited to
the assets of the Trust and insurance proceeds, and the assets of the Trust or
Trustee were insufficient to discharge such liability. The Company believes
that because of the value and passive nature of the Trust assets and the
restrictions in the Indenture on the power of the Trustee to incur
liabilities, the imposition of any liability on a Trust Unitholder is remote.
VOTING RIGHTS OF TRUST UNITHOLDERS
While Trust Unitholders have certain voting rights, such rights differ from
and are more limited than those of stockholders of most public corporations.
For example, there is no requirement for annual meetings of Trust Unitholders
or for annual or other periodic reelection of the Trustee.
Meetings of Trust Unitholders may be called by the Trustee or Trust
Unitholders owning not less than 15% of the outstanding Trust Units. All such
meetings must be held in Fort Worth, Texas, and written notice setting forth
the time and place of such meeting and the matters proposed to be acted upon
must be given to all of the
44
Trust Unitholders of record not more than 60 days nor less than 20 days before
such meeting. The presence in person or by proxy of Trust Unitholders
representing a majority of Trust Units outstanding is necessary to constitute
a quorum. Unless otherwise required by the Trust Indenture, any matter may be
approved by holders of a majority of Trust Unitholders constituting a quorum,
although less than a majority of the Trust Units then outstanding. Each Trust
Unitholder is entitled to one vote for each Trust Unit owned.
The Trustee may be removed, with or without cause, by a vote of the holders
of a majority of the outstanding Trust Units. The affirmative vote of the
holders of 80% of the outstanding Trust Units is required to (i) terminate the
Trust, (ii) amend the Trust Indenture or (iii) approve the sale of all or any
part of the assets of the Trust. The sale of all or any part of the assets of
the Trust requires the prior consent of the Trustee except in connection with
the termination of the Trust.
SELLING TRUST UNITHOLDER
The following table sets forth certain information regarding the Trust Units
held by the Selling Unitholder and the amount to be sold in the offering.
TRUST UNITS TRUST UNITS
BENEFICIALLY OWNED BENEFICIALLY OWNED
BEFORE AFTER
THE OFFERING TRUST UNITS THE OFFERING
-------------------- TO BE SOLD -------------------
NUMBER IN THIS NUMBER
NAME OF UNITS PERCENTAGE OFFERING(a) OF UNITS PERCENTAGE
---- --------- ---------- ----------- -------- ----------
Cross Timbers Oil Compa-
ny...................... 1,360,000 22.7% 1,360,000 0 0%
- --------
(a) Assumes the Underwriters' 30-day over-allotment option to purchase 160,000
Trust Units is exercised in full.
45
UNDERWRITING
Subject to the terms and conditions set forth in the Purchase Agreement (the
"Purchase Agreement") among the Company, Merrill Lynch, Pierce, Fenner & Smith
Incorporated ("Merrill Lynch") and Dain Rauscher Wessels, a division of Dain
Rauscher Incorporated ("Dain Rauscher Wessels"), the Company has agreed to
sell to each of the Underwriters, and each of such Underwriters severally has
agreed to purchase from the Company, the number of Trust Units set forth
opposite its name below:
NUMBER OF
UNDERWRITERS TRUST UNITS
------------ -----------
Merrill Lynch, Pierce, Fenner & Smith
Incorporated................................................
Dain Rauscher Wessels............................................
---------
Total....................................................... 1,200,000
=========
The Underwriters have advised the Company that they propose initially to
offer the Trust Units to the public at the public offering price set forth on
the cover page of this Prospectus, and to certain dealers at such price less a
concession not in excess of $ per Trust Unit. The Underwriters may allow,
and such dealers may reallow, a discount not in excess of $ per Trust Unit
to certain other dealers. After the Offering, the public offering price,
concession and discount may be changed.
The Company has granted the Underwriters an option to purchase up to an
aggregate of 160,000 additional Trust Units at the public offering price set
forth on the cover page of this Prospectus, less the underwriting discount.
Such option, which expires 30 days after the date of this Prospectus, may be
exercised solely to cover over-allotments. To the extent that the Underwriters
exercise such option, each of the Underwriters will be obligated, subject to
certain conditions, to purchase approximately the same percentage of the
option Trust Units that the number of Trust Units to be purchased initially by
that Underwriter bears to the total number of Trust Units to be purchased
initially by the Underwriters.
The Company has agreed to indemnify the Underwriters against certain
liabilities including liabilities under the Securities Act, or to contribute
to payments the Underwriters may be required to make in respect thereof.
In the event that the Underwriters do not purchase all of the Company's
existing Trust Units, the Company and its executive officers and directors
have agreed that for a period of 90 days from the date of this Prospectus they
will not, without the prior written consent of Merrill Lynch, (i) directly or
indirectly, offer, pledge, sell, contract to sell, sell any option or contract
to purchase, purchase any option or contract to sell, grant any option, right
or warrant to purchase or otherwise transfer or dispose of any Trust Unit or
any securities convertible into or exercisable or exchangeable for Trust Units
or file any registration statement under the Securities Act with respect to
any of the foregoing or (ii) enter into any swap or any other agreement or any
transaction that transfers, in whole or in part, directly or indirectly, the
economic consequence of ownership of the Trust Units, whether any such swap or
transaction described in clause (i) or (ii) above is to be settled by delivery
of Trust Units or such other securities, in cash or otherwise. The foregoing
restrictions do not apply, however, to the Trust Units being sold hereunder,
any Trust Units issued upon the exercise of an option or warrant or the
conversion of a security outstanding on the date hereof and referred to
herein, any Trust Units issued or options to purchase Trust Units granted
pursuant to existing employee benefit plans of the Company or any Trust Units
issued pursuant to any non-employee option plan.
Until the distribution of the Trust Units is completed, rules of the
Commission may limit the ability of the Underwriters and certain selling group
members to bid for and purchase the Trust Units. As an exception to these
rules, the Underwriters are permitted to engage in certain transactions that
stabilize the price of the Trust Units. Such transactions consist of bids or
purchases for the purpose of pegging, fixing or maintaining the price of the
Trust Units.
46
If the Underwriters create a short position in the Trust Units in connection
with the Offering, i.e., if they sell more Trust Units than are set forth on
the cover page of this Prospectus, the Underwriters may reduce that short
position by purchasing Trust Units in the open market. The Underwriters may
also elect to reduce any short position by exercising all or part of the over-
allotment option described above.
In general, purchases of a security for the purpose of stabilization or to
reduce a short position could cause the price of the security to be higher
than it might be in the absence of such purchases. The imposition of a penalty
bid might also have an effect on the price of a security to the extent that it
were to discourage resales of the security.
Neither the Company nor any of the Underwriters makes any representation or
prediction as to the direction or magnitude of any effect that the
transactions described above may have on the price of the Trust Units. In
addition, neither the Company nor any of the Underwriters makes any
representation that the Underwriters will engage in such transactions or that
such transactions, once commenced, will not be discontinued without notice.
VALIDITY OF SECURITIES
The validity of the Trust Units offered hereby will be passed upon for the
Company by Kelly, Hart & Hallman, P.C., Fort Worth, Texas, and for the
Underwriters by Andrews & Kurth L.L.P., Houston, Texas. Butler & Binion,
L.L.P., will give the tax opinion set forth herein. Certain members of Kelly,
Hart and Hallman, P. C. currently own 4,027 Trust Units. Certain partners of
Butler & Binion, L.L.P. currently own 10,189 Trust Units.
EXPERTS
Certain information appearing in this Prospectus regarding the estimated
quantities of reserves of the oil and gas properties owned by the Trust, the
future net revenues from such reserves and the present values thereof is based
on estimates of such reserves and present values prepared by Miller and Lents,
Ltd., an independent petroleum engineering firm.
The audited financial statements incorporated by reference in this
Prospectus have been audited by Arthur Andersen, LLP, independent public
accountants, as stated in their reports with respect thereto, and are
incorporated by reference herein in reliance upon such reports given upon the
authority of that firm as experts in accounting and auditing.
47
AVAILABLE INFORMATION
The Trust and the Company are subject to the informational requirements of
the Securities Exchange Act of 1934, as amended (the "Exchange Act"), and in
accordance therewith file periodic reports, proxy statements and other
information with the Commission. Reports, proxy statements and other
information may be inspected and copied at the public reference facilities
maintained by the Commission at Room 1024, 450 Fifth Street, N.W., Judiciary
Plaza, Washington, D.C. 20549 and at the regional offices of the Commission
located at 7 World Trade Center, 13th Floor, New York, New York 10048 and
Suite 1400, Citicorp Center, 14th Floor, 500 West Madison Street, Chicago,
Illinois 60661. Copies of such material may also be obtained at prescribed
rates by writing to the Commission, Public Reference Section, 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549, and such information
may also be inspected at the offices of the New York Stock Exchange, 20 Broad
Street, New York, New York 10005. The Commission maintains a Web site that
contains reports, proxy and information statements and other information
regarding registrants that file electronically with the Commission. Such
reports, proxy and information statements and other information may be found
on the Commission's Web site address, http://www.sec.gov.
The Trust and the Company have filed with the Securities and Exchange
Commission, Washington, D.C. (the "Commission"), a registration statement on
Form S-3 ("Registration Statement"), under the Securities Act of 1933, as
amended ("Securities Act"), with respect to the Trust Units offered hereby.
This prospectus, which is a part of the Registration Statement ("Prospectus"),
omits certain of the information contained in the Registration Statement in
accordance with the rules and regulations of the Commission, and reference is
hereby made to the Registration Statement and the exhibits thereto for further
information with respect to the Trust and the Trust Units. Statements made in
this Prospectus concerning the provisions of any document are not necessarily
complete and, in each instance, reference is made hereby to the copy of such
document filed as an exhibit to the Registration Statement. Each such
statement is qualified in its entirety by such references.
NationsBank, N.A. is Trustee of the Trust. The Trustee's address is 500 W.
Seventh Street, Suite 1300, Fort Worth, Texas, 76102 and its telephone number
is (817) 390-6592. The Company's principal office is located at 810 Houston
Street, Suite 2000, Fort Worth, Texas 76102 and its telephone number is (817)
870-2800.
INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The Trust and the Company incorporate herein by reference the following
documents:
(a) Annual Report of the Trust on Form 10-K for the fiscal year ended
December 31, 1997;
(b) Annual Report of the Company on Form 10-K for the year ended December
31, 1997;
(c) Quarterly Report of the Trust on Form 10-Q for the quarter ended March
31, 1998;
(d) Quarterly Report of the Company on Form 10-Q for the quarter ended
March 31, 1998;
(e) Current Reports of the Company on Form 8-K dated December 1, 1997
(Amendment No. 1, filed on February 17, 1998), February 18, 1998,
February 25, 1998, April 13, 1998, April 17, 1998, February 12, 1998
(filed on April 21, 1998), April 21, 1998 and April 24, 1998;
(f) Description of Trust Units contained in the Trust's Registration
Statement on Form 8-A, filed January 10, 1992;
(g) All other reports of the Trust or the Company filed pursuant to Section
13(a) or 15(d) of the Exchange Act since December 31, 1997; and
(h) All other documents filed by the Trust or the Company pursuant to
Section 13(a), 13(c), 14 or 15(d) of the Exchange Act subsequent to the
date hereof and prior to termination of the offering made hereby.
Any statement contained herein or in a document all or a portion of which is
incorporated by or deemed to be incorporated by reference herein shall be
deemed to be modified or superseded for purposes of this Prospectus
48
to the extent that a statement contained herein or in any other subsequently
filed document that also is or is deemed to be incorporated by reference
herein modifies or supersedes such statement. Any such statement so modified
or superseded shall not be deemed, except as so modified or superseded, to
constitute a part of this Prospectus.
Statements contained in this Prospectus as to the contents of any contract
or other document referred to are not necessarily complete and in each
instance reference is made to such contract or other document, copies of which
are available without charge from the Trust or the Company as described under
"Available Information," each such statement being qualified in all respects
by such reference.
The Trust or the Company will provide without charge to each person to whom
this Prospectus is delivered, upon written or oral request, a copy of any
documents incorporated by reference herein, other than exhibits thereto unless
specifically incorporated by reference into such documents. Such requests
should be directed to Cross Timbers Oil Company, 810 Houston Street, Suite
2000, Fort Worth, Texas 76102, Attention: Investor Relations, telephone (817)
870-2800.
49
GLOSSARY OF CERTAIN OIL AND GAS TERMS
Wherever used herein, the following terms shall have the meanings specified.
Bbl--One stock tank barrel, or 42 US gallons liquid volume, used herein in
reference to crude oil or other liquid hydrocarbons.
Bcf--One billion cubic feet of natural gas.
Btu--A British Thermal Unit, a common unit of energy measurement.
Estimated Future Net Revenues--Also referred to herein as "estimated future
net cash flows." Computational result of applying current prices of oil and
gas (with consideration of price changes only to the extent provided by
existing contractual arrangements) to estimated future production from oil and
gas reserves as of the date of the latest balance sheet presented, less
estimated future expenditures (based on current costs) to be incurred in
developing and producing the proved reserves. Estimated future net revenues do
not include the effects of the coal seam tax credit, since the Trust is not a
taxable entity and the credit inures directly to the benefit of the Trust
Unitholder (see "The Net Profits Interests and the Underlying Properties--Oil
and Gas Reserves--Discounted Present Value of the Coal Seam Tax Credit").
Gas Revenue--Includes revenue related to the sale of natural gas, natural
gas liquids and plant products.
MBbl--One thousand Bbls.
Mcf--One thousand cubic feet of natural gas.
Mcfe--One thousand cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis of one Bbl equals six Mcf.
MMBtu--One million British Thermal Units (Btus).
MMcf--One million cubic feet of natural gas.
MMcfe--One million cubic feet of natural gas equivalent, computed on an
approximate energy equivalent basis of one Bbl equals six Mcf.
Net Oil and Gas Wells or Acres--Determined by multiplying "gross" oil and
gas wells or acres by the interest in such wells or acres represented by the
Underlying Properties.
Oil Revenue--Includes revenue related to the sale of oil and condensate
production.
Proved Developed Reserves--Proved reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Proved Reserves--The estimated quantities of crude oil, natural gas and
natural gas liquids which, upon analysis of geological and engineering data,
appear with reasonable certainty to be recoverable in the future from known
oil and gas reservoirs under existing economic and operating conditions.
Proved Undeveloped Reserves--Proved reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required.
Reserve-to-Production Index--An estimate, expressed in years, of the total
estimated proved reserves (on a BOE basis) attributable to a producing
property as set forth in reserve reports prepared by Miller and Lents, Ltd.,
an independent petroleum engineering firm ("Miller and Lents") divided by the
forecasted rate of production
50
(on an BOE basis) for the 12 months following December 31, 1997, as set forth
in the Miller and Lents reserve reports.
Royalty or Overriding Royalty Interest--A real property interest entitling
the owner to receive a specified portion of the gross proceeds of the sale of
oil and gas production or, if the conveyance creating the interest provides, a
specific portion of oil and gas produced, without any deduction for the costs
to explore for, develop or produce such oil and gas. A royalty or overriding
royalty interest owner has no right to consent to or approve the operation and
development of the property, while the owners of the working interest have the
exclusive right to exploit the mineral on the land.
Standardized Measure of Discounted Future Net Cash Flows--Also referred to
herein as "standardized measure." It is the present value of estimated future
net revenues computed by discounting estimated future net revenues at a rate
of 10% annually.
Working Interest--A real property interest entitling the owner to receive a
specified percentage of the proceeds of the sale of oil and gas production or
a percentage of such production, but requiring the owner of the working
interest to bear the cost to explore for, develop and produce such oil and
gas. A working interest owner who owns a portion of the working interest may
participate either as operator or by voting his percentage interest to approve
or disapprove the appointment of an operator and certain activities in
connection with the development and operation of a property. Because the
Underlying Properties that are working interests are small percentage
interests, they will not permit the Company to control or significantly
influence the operation or development of such properties.
51
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
NO DEALER, SALES PERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED OR IN-
CORPORATED BY REFERENCE IN THIS PROSPECTUS IN CONNECTION WITH THE OFFERING
MADE HEREBY, AND IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATIONS MUST
NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED BY THE COMPANY OR ANY UNDERWRIT-
ER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL, OR A SOLICITATION OF
ANY OFFER TO BUY, THE TRUST UNITS IN ANY JURISDICTION WHERE, OR TO ANY PERSON
TO WHOM, IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION IN SUCH JURISDIC-
TION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER
SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT SUBSEQUENT TO THE
DATE HEREOF THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE TRUST SINCE SUCH
DATE.
---------------
TABLE OF CONTENTS
PAGE
----
Prospectus Summary......................................................... 3
Forward Looking Statements................................................. 9
Risk Factors............................................................... 9
Price Range of Trust Units and Distributions............................... 14
Use of Proceeds............................................................ 14
Selected Financial Data.................................................... 15
Trustee's Discussion and Analysis.......................................... 17
The Trust.................................................................. 20
Hypothetical Annual Cash Distributions..................................... 21
The Net Profits Interests and the Underlying Properties.................... 26
Computation of Net Proceeds................................................ 32
Federal Income Tax Consequences............................................ 34
State Tax Considerations................................................... 39
Description of the Trust Indenture......................................... 40
Description of the Trust Units............................................. 43
Selling Trust Unitholder................................................... 45
Underwriting............................................................... 46
Validity of Securities..................................................... 47
Experts.................................................................... 47
Available Information...................................................... 48
Incorporation of Certain Documents by Reference............................ 48
Glossary of Certain Oil and Gas Terms...................................... 50
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
1,200,000 TRUST UNITS
CROSS TIMBERS ROYALTY TRUST
---------------
P R O S P E C T U S
---------------
MERRILL LYNCH & CO.
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
, 1998
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus forming a
part of this Registration Statement.
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION
Except for the Registration Fee and the NASD Filing Fee, the following
itemized table sets forth estimates of those expenses payable by the Company
in connection with the offer and sale of the securities offered hereby:
Registration Fee................................................... $ 5,817
NASD Filing Fee.................................................... 3,000
Printing and Engraving Expenses.................................... 110,000
Legal Fees and Expenses............................................ 130,000
Accountants' Fees and Expenses..................................... 25,000
Miscellaneous Fees and Expenses.................................... 76,183
--------
Total............................................................ $350,000
========
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS
Section 6.02 of the Trust Indenture provides that the Trustee will be
indemnified by the Trust estate against and from any and all liability,
expense, claims, damages or loss incurred by it individually or as Trustee in
the administration of the Trust and the Trust estate, or in the doing of any
act done or performed or omission occurring on account of it being Trustee
except for any liability, expense, claims, damages or loss for fraud or for
acts or omissions in bad faith.
The Company is incorporated in Delaware. Under Section 145 of the Delaware
General Corporation Law (the "DGCL"), a Delaware corporation has the power,
under specified circumstances, to indemnify its directors, officers, employees
and agents in connection with actions, suits or proceedings brought against
them by a third party or in the right of the corporation, by reason that they
were or are such directors, officers, employees or agents, against expenses
and liabilities incurred in any such action, suit or proceeding so long as
they acted in good faith and in a manner that they reasonably believed to be
in, or not opposed to, the best interests of such corporation, and with
respect to any criminal action, that they had no reasonable cause to believe
their conduct was unlawful. With respect to suits by or in the right of such
corporation, however, indemnification is generally limited to attorneys' fees
and other expenses and is not available if such person is adjudged to be
liable to such corporation unless the court determines that indemnification is
appropriate. A Delaware corporation also has the power to purchase and
maintain insurance for such persons. Article Nine of the Certificate of
Incorporation of the Registrant permits indemnification of directors and
officers to the fullest extent permitted by Section 145 of the DGCL. Reference
is made to the Certificate of Incorporation of the Registrant.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for
breach of fiduciary duty as a director, provided that such provisions may not
eliminate or limit the liability of a director (i) for any breach of the
director's duty of loyalty to the corporation or its stockholders, (ii) for
acts or omissions not in good faith or which involve intentional misconduct or
a knowing violation of law, (iii) under Section 174 (relating to liability for
unauthorized acquisitions or redemptions of, or dividends on, capital stock)
of the DGCL or (iv) for any transaction from which the director derived an
improper personal benefit. Article Ten of the Registrant's Certificate of
Incorporation contains such a provision.
The above discussion of the Registrant's Certificate of Incorporation and of
Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is
qualified in its entirety by such Certificate of Incorporation and statutes.
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Additionally, the Company has acquired directors' and officers' insurance in
the amount of $10 million, which provides an exclusion from coverage for
liability under the federal securities laws.
ITEM 16. EXHIBITS.
EXHIBIT
NUMBER DESCRIPTION
------- -----------
1.1* --Form of Purchase Agreement.
4.1 --Cross Timbers Royalty Trust Restated Royalty Trust Indenture,
incorporated by reference from Exhibit 3.1 to Amendment No. 1 to the
Trust's Registration Statement on Form S-1 (Reg. No. 33-44385), filed
January 24, 1992.
5.1* --Opinion of Kelly, Hart & Hallman, P.C. as to legality of the
securities registered hereby.
8.1* --Opinion of Butler & Binion, L.L.P. regarding tax matters.
10.1 --Form of 90% Net Overriding Royalty Conveyance and Corrections,
incorporated by reference from Exhibits 10.1--10.4 to Amendment No. 1
to the Trust's Registration Statement on Form S-1 (Reg. No. 33-
44385), filed January 24, 1992.
10.2 --Form of 75% Net Overriding Royalty Conveyance, incorporated by
reference from Exhibit 10.5 to Amendment No. 1 to the Trust's
Registration Statement on Form S-1 (Reg. No. 33-44385), filed January
24, 1992.
15.1 --Awareness letter of Arthur Andersen LLP.
15.2 --Awareness letter of Arthur Andersen LLP.
23.1 --Consent of Arthur Andersen LLP.
23.2 --Consent of Miller and Lents, Ltd.
23.3* --Consent of Kelly, Hart & Hallman, P.C., (set forth in their opinion
filed as Exhibit 5.1).
23.4* --Consent of Butler & Binion, L.L.P. (set forth in their opinion filed
as Exhibit 8.1).
24.1 --Powers of attorney (set forth on the signature page hereof).
- --------
* To be filed by amendment
ITEM 17. UNDERTAKINGS.
(a) The undersigned hereby further undertake that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
Trust's and the Company's annual reports pursuant to Section 13(a) or 15(d) of
the Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to Section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such
securities at that time shall be deemed to be the initial bona fide offering
thereof.
(b) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the Registrant pursuant to the foregoing provisions, or otherwise, the Trustee
and the Company have been advised that in the opinion of the Commission such
indemnification is against public policy as expressed in the Act and is,
therefore unenforceable. In the event that claim for indemnification against
such liabilities (other than the payment by the Trust or Company of expenses
incurred or paid by a director, officer or controlling person in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities
being registered the Trust or Company will, unless in the opinion of its
counsel the matter has been settled by controlling precedent, submit to a
court of appropriate jurisdiction the question whether such indemnification by
it is against public policy as expressed in the Act and will be governed by
the final adjudication of such issue.
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SIGNATURES
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, EACH REGISTRANT
CERTIFIES THAT IT HAS REASONABLE GROUNDS TO BELIEVE THAT IT MEETS ALL THE
REQUIREMENTS FOR FILING ON FORM S-3 AND HAS DULY CAUSED THIS REGISTRATION
STATEMENT TO BE SIGNED ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY
AUTHORIZED, IN THE CITY OF FORT WORTH, STATE OF TEXAS, ON , 1998.
Cross Timbers Royalty Trust
By: NATIONSBANK, N.A., as Trustee
By: _________________________________
Joe B. Grissom
Vice President
Cross Timbers Oil Company
By: _________________________________
Bob R. Simpson
Chairman of the Board
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES ACT OF 1933, THIS
REGISTRATION STATEMENT HAS BEEN SIGNED BY THE FOLLOWING PERSONS IN THE
CAPACITIES AND ON THE DATES INDICATED. EACH PERSON WHOSE SIGNATURE APPEARS
BELOW HEREBY AUTHORIZES AND APPOINTS J. RICHARD SEEDS AND LOUIS G. BALDWIN,
AND EACH OF THEM, ANY ONE OF WHOM MAY ACT WITHOUT THE JOINDER OF THE OTHER, AS
HIS ATTORNEY-IN-FACT TO SIGN ON HIS BEHALF INDIVIDUALLY AND IN THE CAPACITY
STATED BELOW ALL AMENDMENTS AND POST-EFFECTIVE AMENDMENTS TO THIS REGISTRATION
STATEMENT, AND ANY RELATED REGISTRATION STATEMENT FILED PURSUANT TO RULE
462(B) UNDER THE SECURITIES ACT OF 1933 AND ALL AMENDMENTS AND POST-EFFECTIVE
AMENDMENTS THERETO, AS SUCH ATTORNEY-IN-FACT MAY DEEM NECESSARY OR
APPROPRIATE.
SIGNATURE TITLE DATE
Director, Chairman , 1998
- ------------------------------------- of the Board and
BOB R. SIMPSON Chief Executive
Officer (Principal
Executive Officer)
Director, Vice , 1998
- ------------------------------------- Chairman of the
STEFFEN E. PALKO Board and President
Director and , 1998
- ------------------------------------- Executive Vice
J. RICHARD SEEDS President
Director , 1998
- -------------------------------------
J. LUTHER KING, JR.
Director , 1998
- -------------------------------------
JACK P. RANDALL
Director , 1998
- -------------------------------------
SCOTT G. SHERMAN
Senior Vice , 1998
- ------------------------------------- President and Chief
LOUIS G. BALDWIN Financial Officer
(Principal
Financial Officer)
Senior Vice , 1998
- ------------------------------------- President and
BENNIE G. KNIFFEN Controller
(Principal
Accounting Officer)
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