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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE
TRANSACTION PERIOD FROM ______________ TO _______________
COMMISSION FILE NUMBER 1-11450
SANTA FE ENERGY TRUST
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 76-6081498
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER
INCORPORATION OR ORGANIZATION) IDENTIFICATION NO.)
CHASE BANK OF TEXAS,
NATIONAL ASSOCIATION
GLOBAL TRUST SERVICES
600 TRAVIS, SUITE 1150
HOUSTON, TEXAS 77002
(ADDRESS OF PRINCIPAL EXECUTIVE (ZIP CODE)
OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 216-5087
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- - ------------------------------------- -------------------------
DEPOSITARY UNITS, EVIDENCED BY SECURE NEW YORK STOCK EXCHANGE
PRINCIPAL ENERGY RECEIPTS
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of 6,300,000 Depositary Units in Santa Fe Energy
Trust held by non-affiliates of the registrant at the closing sales price on
March 1, 2000, of $17 3/4 was $111,825,000.
Depositary Units outstanding at March 1, 2000 -- 6,300,000
DOCUMENTS INCORPORATED BY REFERENCE:
None.
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TABLE OF CONTENTS
PART I
PAGE
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Item 1. Business................................................. 1
Description of the Trust.................................. 1
Description of the Trust Units and Depositary Units....... 7
Description of the Treasury Obligations................... 15
Description of the Royalty Properties..................... 16
Competition and Markets................................... 24
Governmental Regulation................................... 25
Item 2. Properties............................................... 27
Item 3. Legal Proceedings........................................ 27
Item 4. Submission of Matters to a Vote of Security Holders...... 27
PART II
Item 5. Market for the Registrant's Common Equity and Related
Holder Matters.......................................... 28
Item 6. Selected Financial Data.................................. 28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations..................... 28
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk.................................................... 31
Item 8. Financial Statements and Supplementary Data.............. 32
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure..................... 32
PART III
Item 10. Directors and Executive Officers of the Registrant........ 32
Item 11. Executive Compensation.................................... 32
Item 12. Security Ownership of Certain Beneficial Owners and
Management.............................................. 32
Item 13. Certain Relationships and Related Transactions............ 32
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on
Form 8-K................................................ 33
SIGNATURES......................................................... 43
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CERTAIN DEFINITIONS
As used herein, the following terms have the meanings indicated: "Bbl"
means barrel, "MBbl" means thousand barrels, "Mcf" means thousand cubic feet
and "MMcf" means million cubic feet. Natural gas volumes are converted to
"barrels of oil equivalent" using the ratio of 6.0 Mcf of natural gas to 1.0
barrel of crude oil.
PART I
ITEM 1. BUSINESS
DESCRIPTION OF THE TRUST
The Santa Fe Energy Trust (the "Trust"), created under the laws of the
State of Texas, maintains its offices at the office of the Trustee, Chase Bank
of Texas, National Association, formerly Texas Commerce Bank National
Association, (the "Trustee"), 600 Travis, Suite 1150, Houston, Texas 77002.
The telephone number of the Trust is (713) 216-5087.
The Trust was formed pursuant to an Organizational Trust Agreement dated as
of October 22, 1992. Effective November 19, 1992, the Organizational Trust
Agreement was amended and restated by the Trust Agreement of Santa Fe Energy
Trust between Santa Fe Snyder Corporation, formerly Santa Fe Energy Resources,
Inc. (Santa Fe) and Chase Bank of Texas, National Association (the "Trust
Agreement"). Under the terms of the Trust Agreement, Santa Fe conveyed royalty
interests in certain oil and gas properties to the Trust. In exchange for the
conveyance of such royalty interests, the Trust issued 6,300,000 units of
undivided beneficial interest ("Trust Units"). The Trust Units and the
Treasury Obligations (hereinafter defined) were deposited with Chase Bank of
Texas, National Association as depositary (the "Depositary") in exchange for
6,300,000 Depositary Units (hereinafter defined). Each Depositary Unit consists
of beneficial ownership of one Trust Unit and a $20 face amount beneficial
ownership interest in a $1,000 face amount zero coupon United States Treasury
obligation ("Treasury Obligation") maturing on February 15, 2008
("Liquidation Date"). The Depositary Units are evidenced by Secure Principal
Energy Receipts ("SPERs"), which are issued and transferable only in
denominations of 50 Depositary Units or an integral multiple thereof. The
Depositary Units are traded on the New York Stock Exchange under the symbol SFF.
The Trust Units and Treasury Obligations are held by the Depositary for the
holders of Depositary Units ("Holders"). The Treasury Obligations consist of a
portfolio of United States Treasury stripped interest coupons that mature on the
Liquidation Date in the aggregate face amount of $126,000,000, which amount
equals $20 multiplied by the aggregate number of Depositary Units issued and
outstanding. Since Depositary Units may be issued or transferred only in
denominations of 50 or integral multiples thereof, each holder of 50 Depositary
Units owns the entire beneficial interest in a discrete Treasury Obligation, in
a face amount of $1,000, the minimum denomination of such Treasury Obligations.
The Treasury Obligations do not pay current interest. See "Description of Trust
Units and Depositary Units -- Federal Income Tax Matters".
The Trust is a grantor trust formed by Santa Fe to hold royalty interests
in certain oil and gas properties owned by Santa Fe (the "Royalty
Properties"). The principal asset of the Trust consists of (i) two term royalty
interests (the Wasson ODC Royalty and the Wasson Willard Royalty-collectively,
the "Wasson Royalties") conveyed to the Trust out of Santa Fe's royalty
interests in two production units (the Wasson ODC Unit and the Wasson Willard
Unit) in the Wasson Field, and (ii) a net profits royalty interest (the "Net
Profits Royalties") conveyed to the Trust out of Santa Fe's royalty interests
and working interests in a diversified portfolio of oil and gas properties (the
"Net Profits Properties") located in 12 states (collectively, the "Royalty
Interests").
The terms of the Trust Agreement provide, among other things, that: (1) the
Trust cannot acquire any asset other than the Royalty Interests or engage in any
business or investment activity of any kind whatsoever, except that cash being
held by the Trustee as a reserve for liabilities or for distribution at the next
distribution date will be placed in bank accounts or certificates; (2) the
Trustee can establish cash reserves and borrow funds to pay liabilities of the
Trust and can pledge assets of the Trust to
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secure payment of the borrowing; (3) the Trustee will receive the payments
attributable to the Royalty Interests and pay all expenses, liabilities and
obligations of the Trust; (4) the Trustee will make quarterly distributions to
Holders of cash available for distribution in February, May, August and November
of each year; (5) the Trustee is not required to make business decisions
affecting the Trust Units or the Trust assets, but under certain circumstances,
the Trustee may be required to approve or disapprove an extraordinary
transaction affecting the Trust and the Holders; and (6) the Trust will be
liquidated on or prior to the Liquidation Date. The discussion of terms of the
Trust Agreement contained herein is qualified in its entirety by reference to
the Trust Agreement itself, which is an exhibit to this Form 10-K and is
available upon request from the Trustee.
The Trustee is paid an annual fee of approximately $12,500. The Trust is
responsible for paying all legal, accounting, engineering and stock exchange
fees, printing costs and other administrative expenses incurred by or at the
direction of the Trustee. Trustee fees and Trust administrative expenses
totalled $303,000 and $265,000 in 1999 and 1998, respectively, although such
costs could be greater or less in subsequent periods depending on future events.
In addition, the Trust paid Santa Fe an annual fee of $244,000 and $234,000 in
1999 and 1998, respectively. Such fee will increase by 3.5% per year, payable
quarterly, to reimburse Santa Fe for overhead expenses.
The Wasson Royalties were conveyed from Santa Fe to the Trust pursuant to a
single instrument of conveyance (the "Wasson Conveyance"). The Net Profits
Royalties were conveyed from Santa Fe to the Trust pursuant to separate,
substantially similar conveyances (the "Net Profits Conveyances") except with
respect to the Net Profits Royalties in properties located within the State of
Louisiana and its related state waters. Due to the effect of certain Louisiana
laws governing the transfer of properties to trusts, the Louisiana Net Profits
Royalties were conveyed from Santa Fe to the Trust pursuant to a separate
conveyance in the form of a secured interest in proceeds of production from such
properties (the "Louisiana Conveyance"). The Louisiana Conveyance provides the
Trust with the economic equivalent of the Net Profits Royalties determined with
respect to the Net Profits Properties located in Louisiana. The Net Profits
Conveyances, Wasson Conveyance and Louisiana Conveyance are referred to
collectively as the Conveyances.
Santa Fe owns the Royalty Properties subject to and burdened by the Royalty
Interests. Santa Fe will receive all payments relating to the sale of production
from the Royalty Properties and will be required, pursuant to the Conveyances,
to pay to the Trust the portion thereof attributable to the Royalty Interests.
Under the Conveyances, the amounts payable with respect to the Royalty Interests
will be computed with respect to each calendar quarter, and such amounts will be
paid by Santa Fe to the Trust not later than 60 days after the end of each
calendar quarter. The amounts paid to the Trust will not include interest on any
amounts payable with respect to the Royalty Interests which are held by Santa Fe
prior to payment to the Trust. Santa Fe will be entitled to retain any amounts
attributable to the Royalty Properties which are not required to be paid to the
Trust with respect to the Royalty Interests.
The following descriptions of the Wasson Royalties and the Net Profits
Royalties, and the calculation of amounts payable to the Trust in respect
thereof, are subject to and qualified by the more detailed provisions of the
Conveyances included as exhibits to this Form 10-K and available upon request
from the Trustee.
THE WASSON ROYALTIES
THE WASSON ODC ROYALTY. The Wasson ODC Royalty was conveyed out of Santa
Fe's 12.3934% royalty interest in the Wasson ODC Unit and entitles the Trust to
receive quarterly royalty payments with respect to oil production from the
Wasson ODC Unit for each calendar quarter during the period ending on December
31, 2007. The royalties payable with respect to the Wasson ODC Royalty for any
calendar quarter is determined by multiplying (a) the Average Per Barrel Price
(as defined below) received for such quarter with respect to oil production from
the Wasson ODC Unit by (b) the Royalty Production (as defined below) for such
quarter related to the Wasson ODC Royalty.
"Royalty Production" for the Wasson ODC Royalty is defined as 12.3934% of
the lesser of (i) the actual number of gross barrels of oil produced for such
quarter from the Wasson ODC Unit and
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(ii) the applicable maximum quarterly gross production limitation set forth in
the table below. The table also shows the maximum number of barrels of Royalty
Production that may be produced per quarter in respect of the Wasson ODC Royalty
(12.3934% of the quarterly gross production limitation).
WASSON ODC ROYALTY WASSON ODC ROYALTY
CALENDAR QUARTERS QUARTERLY GROSS MAXIMUM NET
IN THE YEAR ENDING PRODUCTION QUARTERLY
DECEMBER 31, LIMITATION (MBBLS) PRODUCTION (MBBLS)
- - ------------------------------------- ------------------ ------------------
2000............................ 522 64.7
2001............................ 504 62.5
2002............................ 530 65.7
2003............................ 582 72.1
2004............................ 604 74.9
2005............................ 536 66.4
2006............................ 502 62.2
2007............................ 486 60.2
The Wasson ODC Royalty will terminate on December 31, 2007. Thus, the
Trustee will make a final quarterly distribution from the Wasson ODC Royalty in
respect of the fourth quarter of 2007 on or about the Liquidation Date.
THE WASSON WILLARD ROYALTY. The Wasson Willard Royalty was conveyed out of
Santa Fe's 6.8355% royalty interest in the Wasson Willard Unit and entitles the
Trust to receive quarterly royalty payments with respect to oil production from
the Wasson Willard Unit for each calendar quarter during the period ending on
December 31, 2003. The royalty payable for any calendar quarter is determined by
multiplying (a) the Average Per Barrel Price (as defined below) received for
such quarter with respect to oil production from the Wasson Willard Unit by (b)
the Royalty Production (as defined below) for such quarter related to the Wasson
Willard Royalty.
"Royalty Production" for the Wasson Willard Royalty is defined as 6.8355%
of the lesser of (i) the actual number of gross barrels of oil produced for such
quarter from the Wasson Willard Unit and (ii) the applicable maximum quarterly
gross production limitation set forth in the table below. The table also shows
the maximum number of barrels of Royalty Production that may be produced per
quarter in respect of the Wasson Willard Royalty (6.8355% of the quarterly gross
production limitation).
WASSON WILLARD WASSON WILLARD
CALENDAR QUARTERS ROYALTY QUARTERLY ROYALTY MAXIMUM
IN THE YEAR ENDING GROSS PRODUCTION NET QUARTERLY
DECEMBER 31, LIMITATION (MBBLS) PRODUCTION (MBBLS)
- - ------------------------------------- ------------------ ------------------
2000............................ 323 22.1
2001............................ 268 18.3
2002............................ 222 15.2
2003............................ 175 12.0
AVERAGE PER BARREL PRICE. The "Average Per Barrel Price" with respect to
the Wasson Royalties for any calendar quarter generally means (a) the aggregate
revenues received by Santa Fe for such quarter from the sale of oil production
from its royalty interest in the Wasson Field production unit to which the
particular Wasson Royalty relates less certain actual costs for such quarter
which consist of post-production costs (including gathering, transporting,
separating, processing, treatment, storing and marketing charges), costs of
litigation concerning title to or operations of the Wasson Royalties, severance
taxes, ad valorem taxes, excise taxes (including windfall profits taxes, if
any), sales taxes and other similar taxes imposed upon the reserves or upon
production, delivery or sale of such production, costs of audits, insurance
premiums and amounts reserved for the foregoing, divided by (b) the aggregate
number of barrels produced for such quarter from its royalty interest in the
Wasson Field production unit to which the particular Wasson Royalty relates.
THE NET PROFITS ROYALTIES
The Net Profits Royalties entitle the Trust to receive, on a quarterly
basis, 90% of the Net Proceeds (as defined in the Net Profits Conveyances) from
the sale of production from the Net Profits
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Properties. The Net Profits Royalties are not limited in term, although under
the Trust Agreement the Trustee is directed to sell the Net Profits Royalties
prior to the Liquidation Date. The definitions, formulas, accounting procedures
and other terms governing the computation of Net Proceeds are detailed and
extensive, and reference is made to the Net Profits Conveyances and the
Louisiana Conveyance for a more detailed discussion of the computation thereof.
CALCULATION OF NET PROCEEDS. "Net Proceeds" generally means, for any
calendar quarter, (a) with respect to Net Profits Properties that are conveyed
from working interests, the excess of Gross Proceeds (as defined below) over all
costs, expenses and liabilities incurred in connection with exploring,
prospecting and drilling for, operating, producing, selling and marketing oil
and gas, including, without limitation, all amounts paid as royalties,
overriding royalties, production payments or other burdens against production
pursuant to permitted encumbrances, delay rentals, payments in connection with
the drilling or deferring of drilling of any well in the vicinity, adjustment
payments to others in connection with contributions upon pooling, unitization or
communitization, rent for use of or damage to the surface, costs under any joint
operating unit or similar agreement, costs incurred with respect to reworking,
drilling, equipping, plugging back, completing and recompleting wells, making
production ready or available for market, constructing production and delivery
facilities, producing, transporting, compressing, dehydrating, separating,
treating, storing and marketing production, secondary or tertiary recovery or
other operations conducted for the purpose of enhancing production, litigation
concerning title to or operation of the working interests, renewals and
extensions of leases, and taxes, and (b) with respect to Net Profits Properties
that are conveyed from royalty interests, the excess of Gross Proceeds over all
costs, expenses and liabilities incurred in making production available or ready
for market, including, without limitation, costs paid for gathering,
transporting, compressing, dehydrating, separating, treating, storing and
marketing oil and gas, litigation concerning title to or operation of royalty
interests, taxes, costs of audits and insurance premiums.
"Gross Proceeds" generally means, for any calendar quarter, the amount of
cash received by Santa Fe during such quarter from the sales of oil and gas
produced from the Net Profits Properties excluding (a) all amounts attributable
to nonconsent operations conducted with respect to any working interest in which
Santa Fe or its assignee is a nonconsenting party and which is dedicated to the
recoupment or reimbursement of penalties, costs and expenses of the consenting
parties, (b) damages arising from any cause other than drainage or reservoir
injury, (c) rental for reservoir use, (d) payments in connection with the
drilling of any well on or in the vicinity of the Net Profits Properties and (e)
all amounts set aside as reserved amounts. Gross Proceeds will not include (x)
consideration for the transfer or sale of the Net Profits Properties (except as
provided below under "Description of the Trust -- Support Payments") or (y)
any amount not received for oil and gas lost in the production or marketing
thereof or used by the owner of the Net Profits 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.
If a dispute arises as to the correct or lawful sales prices of any oil or
gas produced from any of the Net Profits Properties, then for purposes of
determining whether the amounts have been received by the owner of the Net
Profits Properties and therefore constitute Gross Proceeds (a) the amounts
withheld by a purchaser and deposited with an escrow agent shall not be
considered to be received by the owner of the Net Profits Properties until
actually collected, (b) amounts received by the owner of the Net Profits
Properties and promptly deposited with a non-affiliated escrow agent will not be
considered to have been received until disbursed to it by such escrow agent and
(c) amounts received by the owner of the Net Profits Properties and not
deposited with an escrow agent will be considered to have been received.
The Trust is not liable to the owners or operators of the Net Profits
Properties for any operating, capital or other costs or liabilities attributable
to the Net Profits Properties or oil and gas produced therefrom, and the Trustee
is not obligated to return any income received from the Net Profits Royalties.
Overpayments to the Trust will reduce future amounts payable.
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SUPPORT PAYMENTS
The Wasson Conveyance provides that the Trust is entitled to additional
quarterly royalty payments ("Support Payments"), subject to certain
limitations herein described, out of Santa Fe's remaining royalty interests in
the Wasson ODC Unit during the period ending on December 31, 2002 (the "Support
Period") in the event that the net cash available for distribution to Holders
from the Royalty Interests for any calendar quarter during the Support Period is
less than an amount sufficient to distribute to Holders a minimum supported
quarterly royalty per Depositary Unit equal to $0.39 per Depositary Unit (the
"Minimum Quarterly Royalty"). Effective July 1, 1999 and as required by the
Trust Agreement, the Trust released its Net Profits Royalty interest in the
Jeffress field in connection with the sale by Santa Fe of the underlying Net
Profits Property. The Trust received 90% of the net proceeds from this sale in
the fourth quarter 1999 distribution. As a result of this sale, there was a
proportionate reduction of the Minimum Quarterly Royalty from $0.40 per
Depositary Unit to $0.39 per Depositary Unit. Distributions paid in 1994, 1995,
1998 and 1999 included Support Payments of $868,000 (approximately $0.14 per
Depositary Unit), $1,206,000 (approximately $0.19 per Depositary Unit), $94,000
(approximately $0.01 per Depositary Unit), and $2,011,000 (approximately $0.32
per Depositary Unit), respectively. The Support Payments paid in 1994 were
required primarily due to lower realized oil prices and capital expenditures
incurred with respect to the Net Profits Properties, a substantial portion of
which related to the drilling of new wells. The Support Payments paid in 1995
were required primarily due to lower natural gas prices and a continuation of
drilling expenditures. The Support Payments paid in 1998 and 1999 were required
primarily due to lower oil and gas prices realized on the Net Profits
Properties. In 1996, the first six months of 1997, and the fourth quarter of
1999, Santa Fe recouped Support Payments made in prior periods totalling
$1,009,000 (approximately $0.16 per Depositary Unit), $1,065,000 (approximately
$0.17 per Depositary Unit), and $1,831,000 (approximately $0.29 per Depositary
Unit) respectively (see "-- Reduction of Royalty Interests"). In the first
quarter of 2000, Santa Fe recouped the remaining Support Payment balance of
$274,000 (approximately $0.04 per Depositary Unit). Future recoupments will be
made only to the extent of future Support Payments. Depending on factors such as
sales prices and volumes and the level of operating costs and capital
expenditures, Support Payments may be required in subsequent quarters to allow
the Trust to make distributions of $0.39 per Depositary Unit per quarter.
CALCULATION OF AMOUNT OF SUPPORT PAYMENT. Support Payments payable to the
Trust for any calendar quarter during the Support Period shall be equal to the
additional amount necessary to cause the Minimum Quarterly Royalty for such
quarter to be paid by the Trust in respect of all outstanding Trust Units;
provided, that the aggregate amount of Support Payments, net of any amounts
recouped by Santa Fe pursuant to reductions in the royalties payable with
respect to the Royalty Interests as described below, will be limited to $19.4
million (the "Aggregate Support Payment Limitation Amount"), as such amount
may be replenished upon recoupment of certain amounts as described in the
following paragraph. As a result of the Trust's release of its Net Profits
Royalty interest in connection with the sale by Santa Fe of the Jeffress Field
in the fourth quarter of 1999, there was a proportionate reduction in the
Aggregate Support Payment Limitation Amount from $20.0 million to $19.4 million.
REDUCTION OF ROYALTY INTERESTS. In the event Support Payments are paid to
the Trust for any quarter, the royalties payable with respect to the Wasson
Royalties will be reduced in future quarters (including quarters after the
Support Period but prior to the Liquidation Date) after the Trust has received
(or amounts are set aside for payment of) proceeds from all of the Royalty
Interests in amounts sufficient to pay 112.5% of the Minimum Quarterly Royalty
($0.44 per Depositary Unit) on all Trust Units outstanding at the end of such
quarter in order to permit Santa Fe to recoup the aggregate amount of the
Support Payments. As a result of the Trust's release of its Net Profits Royalty
interest in connection with the sale by Santa Fe of the Jeffress Field in the
fourth quarter of 1999, there was a proportionate reduction in the distribution
per Depositary Unit over which Santa Fe is entitled to recoup Support Payments
from $0.45 per Depositary Unit to $0.44 per Depositary Unit. Any such reduction
in royalties payable with respect to the Royalty Interests would be made first
to the Wasson
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ODC Royalty and then, if additional reductions are necessary, from the Wasson
Willard Royalty. The effect of such reductions in the royalties payable with
respect to the Wasson Royalties would be to eliminate distributions in excess of
$0.44 per Depositary Unit until the Support Payments, if any, received by the
Trust have been recouped by Santa Fe through such reductions in the Wasson
Royalties.
PROPORTIONATE REDUCTION OF MINIMUM QUARTERLY ROYALTY AND AGGREGATE SUPPORT
PAYMENT LIMITATION AMOUNT UPON CERTAIN SALES. In the event that Santa Fe causes
the Trust to sell or release a portion of the Net Profits Royalties in
connection with the sale by Santa Fe of underlying Net Profits Properties, the
Minimum Quarterly Royalty and the Aggregate Support Payment Limitation Amount
will be adjusted proportionately downward to equal the product resulting from
multiplying each of the Minimum Quarterly Royalty and the Aggregate Support
Payment Limitation Amount by a fraction, the numerator of which will be the
Remaining Royalty Interests Amount (as defined below) and the denominator of
which will be the Existing Royalty Interests Amount (as defined below). For such
purposes, the "Remaining Royalty Interests Amount" means, at any time, the
Existing Royalty Interests Amount (as defined below) less the present value of
the future net revenues attributable to the portion of the Net Profits Royalties
sold or released by the Trust, determined by reference to the reserve report for
the Royalty Properties prepared in accordance with guidelines of the Securities
and Exchange Commission (the "Commission") as of the December 31 immediately
preceding the date of the sale. The "Existing Royalty Interests Amount" means,
at any time, the then present value of the future net revenues attributable to
the Royalty Interests (including the portion sold or released by the Trust),
determined by reference to the reserve report for the Royalty Properties
prepared in accordance with Commission guidelines as of the December 31
immediately preceding the date of the sale. Following any such sale of Net
Profits Royalties, the Trustee will notify the Holders of the adjusted Minimum
Quarterly Royalty and the adjusted Aggregate Support Payment Limitation Amount.
OTHER MATTERS
Payments to the Trust are attributable to the sale of depleting assets.
Thus, the reserves attributable to the Royalty Properties are expected to
decline over time. Based on the estimated production volumes in the Reserve
Report (hereinafter defined), on a barrel of oil equivalent basis, the oil and
gas production from proved reserves attributable to the Trust in the year
preceding the Liquidation Date is expected to be approximately 42% of the oil
and gas production attributable to the Trust in 1999.
Under the terms of the Conveyances, neither the Trustee, the Trust nor the
Holders will be able to influence or control the operation or future development
of the Royalty Properties. Santa Fe operates only a small number of the Royalty
Properties and is not expected to be able to significantly influence the
operations or future development of the Royalty Properties that are royalty
interests or that consist of relatively small working interests. Such operations
will generally be controlled by persons unaffiliated with the Trustee and Santa
Fe. Santa Fe, however, owns working interests in the Wasson ODC Unit and the
Wasson Willard Unit and may be able to exercise some influence, though not
control, over unit operations.
The tertiary recovery operations in the Wasson Field have required
substantial capital expenditures and will involve future capital expenditures
for CO2 acquisition, particularly in the Wasson Willard Unit. A prolonged oil
price downturn could cause the operators in the Wasson Field to reassess the
economic viability of production operations notwithstanding their substantial
investment. Such decisions will not be in the control of either Santa Fe or the
Trustee and could have the effect of substantially reducing expected production
from the Wasson Field.
The current operators of the Royalty Properties are under no obligation to
continue operating such properties, and neither the Trustee, the Holders nor
Santa Fe will be able to appoint or control the appointment of replacement
operators. The operators of the Net Profits Properties and any transferee have
the right to abandon any well or property on a Net Profits Property, if, in
their opinion, such well
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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 Royalties relating thereto will be extinguished.
The Trust Agreement provides that Santa Fe may sell the Royalty Properties,
subject to and burdened by the Royalty Interests, without the consent of the
Holders. In addition, Santa Fe may, without the consent of the Holders, require
the Trust to release up to $5 million of the Net Profit Royalties in any
12-month period (limited to $15 million in the aggregate for all sales prior to
January 1, 2002) in connection with a sale of the Net Profits Properties
provided that the Trust receives an amount equal to 90% of the net proceeds
received by Santa Fe with respect to the Net Profits Properties so sold and such
cash price represents the fair market value of such properties (which fair
market value for sales in excess of $500,000 will be determined by independent
appraisal). Such sales can be required of the Trust without regard to any dollar
limitation on and after December 31, 2005. Any net sales proceeds paid to the
Trust are distributable to Holders for the quarter in which such proceeds are
received. Pursuant to the Trust Agreement, the Trust may not sell the Wasson ODC
Royalty or the Wasson Willard Royalty without the consent of Santa Fe. Under the
Trust Agreement, Santa Fe has a right of first refusal to purchase any of the
Royalty Interests at fair market value, or if applicable the offered third-party
price, prior to the Liquidation Date.
The Trust has no employees. Administrative functions of the Trust are
performed by the Trustee.
DESCRIPTION OF THE TRUST UNITS AND DEPOSITARY UNITS
The following information is subject to the detailed provisions of the
Custodial Deposit Agreement entered into by Santa Fe, the Trustee, the
Depositary and all holders from time to time of SPERs (the "Deposit
Agreement"), which is an exhibit to this Form 10-K and is available upon
request from the Trustee.
The functions of the Depositary under the Deposit Agreement are custodial
and ministerial in nature and for the benefit of Holders. The Deposit Agreement
and the issuance of SPERs thereunder provide Holders an administratively
convenient form of holding an investment in the Trust and a Treasury Obligation.
Each Depositary Unit is evidenced by a SPER, which is issued by the Depositary
and transferable only in denominations of 50 Depositary Units or an integral
multiple thereof. Accordingly, each Holder of 50 Depositary Units owns a
beneficial interest in 50 Trust Units and the entire beneficial interest in a
discrete Treasury Obligation in a face amount of $1,000, or $20 per Depositary
Unit.
The deposited Trust Units and Treasury Obligations are held solely for the
benefit of the Holders and do not constitute assets of the Depositary or the
Trust. The Depositary has no power to assign, transfer, pledge or otherwise
dispose of any of the Trust Units or Treasury Obligations, except as described
under "Possible Divestiture of Depositary Units and Trust Units".
Generally, the Depositary Units are entitled to participate in
distributions with respect to the Trust Units and such distributions with
respect to the Treasury Obligations and the liquidation of the remaining assets
of the Trust.
Upon the written request of a Holder for withdrawal of Trust Units and
Treasury Obligations evidenced by SPERs in denominations of 50 Depositary Units
or an integral multiple thereof from deposit and the surrender of such Holder's
SPER in compliance with the terms of the Deposit Agreement, the Holder
surrendering such Depositary Units will be entitled to receive the underlying
Trust Units, which will be uncertificated, and whole Treasury Obligation as
described herein. These withdrawn Trust Units will be evidenced on the books of
the Trustee by a transfer of such Trust Units from the name of the Depositary to
the name of the withdrawing Holder. Holders of withdrawn Trust Units will be
entitled to receive Trust distributions and periodic Trust information
(including tax information) directly from the Trustee. Due to the accreting
nature of the value of the zero coupon Treasury Obligations, the withdrawal and
sale of a Treasury Obligation underlying Depositary Units
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prior to its maturity will result in the Holder receiving less than the face
value for its Treasury Obligation investment. The amount a withdrawing Holder
may receive from the sale of a Treasury Obligation prior to its maturity will be
affected by such factors as then current interest rates and the small size of
the Treasury Obligation relative to typical trades in the secondary market for
United States Treasury obligations (which may result in a discount to quoted
market values).
Pursuant to the Trust Agreement and the related transfer application,
withdrawn Trust Units are not transferable except by operation of law. A holder
of withdrawn Trust Units may, however, transfer such Trust Units in
denominations of 50 (or an integral multiple thereof) to the Depositary for
redeposit, together with Treasury Obligations in the face amount equal to $1,000
for each 50 Trust Units redeposited, in exchange for Depositary Units. Such
redeposit may be effected by delivering written notice of such transfer jointly
to the Depositary and the Trustee together with proper documentation necessary
to transfer the requisite Treasury Obligations into the name of the Depositary.
DISTRIBUTIONS
The Trustee determines for each calendar quarter during the term of the
Trust the amount of cash available for distribution to holders of Depositary
Units and the Trust Units evidenced thereby. Such amount (the "Quarterly
Distribution Amount") is equal to the excess, if any, of the cash received by
the Trust from the Royalty Interests then held by the Trust during such quarter,
plus any other cash receipts of the Trust during such quarter, over the
liabilities of the Trust paid during such quarter, subject to adjustments for
changes made by the Trustee during such quarter in any cash reserves established
for the payments of contingent or future obligations of the Trust. Based on
industry practice and the payment procedures relating to the Net Profits
Royalties, cash received by the Trustee in a particular quarter from the Net
Profits Royalties generally represents proceeds from sales of production for the
three months ending two months prior to the end of such quarter with respect to
gas, and one month prior to the end of such quarter with respect to oil. For
example, the royalty income received by the Trust for the third calendar quarter
with respect to gas is attributable to production in the months of May, June and
July (for which Santa Fe would have received payment from the purchasers in
July, August and September, respectively). Since proceeds from the sale of
production from the Wasson Properties are received within one month of
production, payments in respect of the Wasson Royalties are made for production
from the calendar quarter to which the Quarterly Distribution Amount relates.
The Quarterly Distribution Amount for each quarter is payable to Holders of
Depositary Units of record on the 45th day following each calendar quarter (or
the next succeeding business day following such day if such day is not a
business day) or such later date as the Trustee determines is required to comply
with legal or stock exchange requirements (the "Quarterly Record Date"). The
Trustee distributes cash to the Holders within two months after the end of each
calendar quarter to each person who was a Holder of Depositary Units of record
on a Quarterly Record Date.
The net taxable income of the Trust for each calendar quarter is reported
by the Trustee for tax purposes as belonging to the Holders of record to whom
the Quarterly Distribution Amount is distributed. Because under current tax law
the Trust is classified for tax purposes as a "grantor trust" (see "Federal
Income Tax Matters"), each cash-basis Holder's share of the net taxable income
of the Trust is realized by such Holder for tax purposes in the calendar quarter
received by the Trustee, rather than in the quarter distributed by the Trustee.
Taxable income of a Holder may differ from the Quarterly Distribution Amount
because the Treasury Obligations are treated as generating interest income prior
to the time any cash payments are received thereon, a portion of the payments
received on the Wasson Royalties are treated as a nontaxable return of
principal, and cost depletion reduces taxable income but not the Quarterly
Distribution Amount. There may also be minor variances because of the
possibility that, for example, a reserve will be established in one quarter that
will not give rise to a tax deduction until a subsequent quarter, an expenditure
paid for in one quarter will have to be amortized for tax purposes over several
quarters, etc. See "Federal Income Tax Matters."
Each Holder of Depositary Units (including the underlying Trust Units) of
record as of the business day next preceding the Liquidation Date will be
entitled to receive a liquidating distribution
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equal to a pro rata portion of the net proceeds from the sale of the Net Profits
Royalties (to the extent not previously distributed) and a pro rata portion of
the proceeds from the matured Treasury Obligations.
POSSIBLE DIVESTITURE OF DEPOSITARY UNITS AND TRUST UNITS
The Trust Agreement imposes no restrictions based on nationality or other
status of holders of Trust Units. However, the Trust Agreement and the Deposit
Agreement provide that in the event of certain judicial or administrative
proceedings seeking the cancellation or forfeiture of any property in which the
Trust has an interest because of the nationality, citizenship, or any other
status, of any one or more holders of Trust Units including Holders of
Depositary Units, the Trustee will give written notice thereof to each holder
whose nationality, citizenship or other status is an issue in the proceeding,
which notice will constitute a demand that such holder dispose of his Depositary
Units or withdrawn Trust Units within 30 days. If any holder fails to dispose of
his Depositary Units or withdrawn Trust Units in accordance with such notice,
cash distributions on such units are subject to suspension. In the event a
holder fails to dispose of Depositary Units in accordance with such notice, the
Depositary may cancel such holder's Depositary Units and reissue them in the
name of the Trustee, whereupon the Trustee will use its reasonable efforts to
sell the Depositary Units and remit the net sale proceeds to such holder. In the
case of Trust Units withdrawn from deposit with the Depositary, the Trustee
shall redeem such Trust Units not divested in accordance with such notice, for a
cash price equal to the then-current market price of the Depositary Units less
the then-current, over-the-counter bid price of the related, withdrawn Treasury
Obligations. The redemption price will be paid out in quarterly installments
limited to the amount that otherwise would have been distributed in respect of
such redeemed Trust Units.
LIABILITY OF HOLDERS
The Trust is intended to be classified as an "express trust" under Texas
law and thus subject to the Texas Trust Code. Under the Texas Trust Code, a
trust beneficiary will not be held personally liable for obligations incurred by
the Trust except in limited circumstances principally related to wrongful
conduct by the trust beneficiary. It is unclear whether the Trust constitutes an
"express trust" under the Texas Trust Code. If the Trust were held not to be
an express trust, a Holder could be jointly and severally liable for any
liability of the Trust in the event that (i) the satisfaction of such liability
was not by contract limited to the assets of the Trust and (ii) the assets of
the Trust were insufficient to discharge such liability. Examples of such
liability would include liabilities arising under environmental laws and damages
arising from product liability and personal injury in connection with the
Trust's business. Each Holder should weigh this potential exposure in deciding
whether to retain or transfer his Trust Units.
LIQUIDATION OF THE TRUST
The Trust will be liquidated and the Net Profits Royalties will be sold on
or prior to the Liquidation Date. Holders of record as of the business day next
proceeding the Liquidation Date will be entitled to receive a terminating
distribution with respect to each Depositary Unit equal to a pro rata portion of
the net proceeds from the sale of the Net Profits Royalties (to the extent not
previously distributed) and a pro rata portion of the proceeds from the matured
Treasury Obligations. Under the Trust Agreement, Santa Fe has a right of first
refusal to purchase any of the Royalty Interests at fair market value, or if
applicable, the offered third-party price, prior to the Liquidation Date.
FEDERAL INCOME TAX MATTERS
This section is a summary of Federal income tax matters of general
application which addresses all material tax consequences of the ownership and
sale of Depositary Units. Except where indicated, the discussion below describes
general Federal income tax considerations applicable to individuals who are
citizens or residents of the United States. Accordingly, the following
discussion has limited application to domestic corporations and persons subject
to specialized Federal income tax treatment,
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such as tax-exempt entities, regulated investment companies and insurance
companies. The following discussion does not address tax consequences to foreign
persons. It is impractical to comment on all aspects of Federal, state, local
and foreign laws that may affect the tax consequences of the transactions
contemplated hereby and of an investment in Depositary Units as they relate to
the particular circumstances of every Holder. EACH HOLDER SHOULD CONSULT HIS OWN
TAX ADVISOR WITH RESPECT TO HIS PARTICULAR CIRCUMSTANCES.
This summary is based on current provisions of the Internal Revenue Code of
1986, as amended (the Code), existing and proposed regulations thereunder and
current administrative rulings and court decisions, all of which are subject to
changes that may or may not be retroactively applied. Some of the applicable
provisions of the Code have not been interpreted by the courts or the Internal
Revenue Service (IRS).
No ruling has been or will be requested from the IRS with respect to any
matter affecting the Trust or Holders, and thus no assurance can be provided
that the statements set forth herein (which do not bind the IRS or the courts)
will not be challenged by the IRS or will be sustained by a court if so
challenged.
TREATMENT OF DEPOSITARY UNITS
Under current law, a purchaser of a Depositary Unit is treated, for Federal
income tax purposes, as purchasing directly an interest in the Treasury
Obligations and the assets of the Trust. A purchaser is therefore required to
allocate the purchase price of his Depositary Unit between the interest in the
Treasury Obligations and the assets of the Trust in the proportion that the fair
market value of each bears to the fair market value of the Depositary Unit.
Information regarding purchase price allocations is furnished to Holders by the
Trustee.
CLASSIFICATION AND TAXATION OF THE TRUST
Under current law, the Trust is classified for federal income tax purposes
as a grantor trust. As a grantor trust, the Trust is not subject to tax. For tax
purposes, Holders are considered to own and receive the Trust's income and
principal directly as though no trust were in existence. The Trust files an
information return, reporting all items of income, credit or deduction which
must be included in the tax returns of Holders.
DIRECT TAXATION OF HOLDERS
Because under current law the Trust is treated as a grantor trust for
Federal income tax purposes and each Holder is treated, for Federal income tax
purposes, as owning a direct interest in the Treasury Obligations and the assets
of the Trust, each Holder is taxed directly on his pro rata share of the income
attributable to the Treasury Obligations and the assets of the Trust and is
entitled to claim his pro rata share of the deductions attributable to the Trust
(subject to certain limitations discussed below). Income and expenses
attributable to the assets of the Trust and the Treasury Obligations are taken
into account by Holders consistent with their method of accounting and without
regard to the taxable year or accounting method employed by the Trust.
The Trust makes quarterly distributions to Holders of record on each
Quarterly Record Date. The terms of the Trust Agreement seek to assure to the
extent practicable that taxable income attributable to such distributions is
reported by the Holder who receives such distributions, assuming that he is the
owner of record on the Quarterly Record Date. In certain circumstances, however,
a Holder may not receive the distribution attributable to such income. For
example, if the Trustee establishes a reserve or borrows money to satisfy debts
and liabilities of the Trust, income associated with the cash used to establish
that reserve or to repay that loan must be reported by the Holder on his tax
return even though that cash is not distributed to him. In addition, Holders are
required to recognize certain interest income attributable to the Treasury
Obligations even though such interest is not paid currently to the Holders.
The Trust allocates income and deductions to Holders based on record
ownership at Quarterly Record Dates. Such allocation method is intended to cause
the taxable income of the Trust to be
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reported by those persons who are Holders of record on the Quarterly Record Date
for such quarter and, as a result receive the distributions for such quarter. It
is unknown whether the IRS will accept that allocation or will require income
and deductions of the Trust to be determined and allocated daily or require some
method of proration. If the IRS were successful in seeking that the Trust
utilize a different method of allocating taxable income, Trust income might in
certain cases be taxed to Holders other than those who received the distribution
relating to such income, and the Trust might incur additional administrative
expenses in complying with such method of allocation.
TREATMENT OF TRUST UNITS
Because the Trust is treated as a grantor trust for tax purposes, each
Holder is treated as purchasing and owning directly an interest in the Royalty
Interests. The purchaser of a Depositary Unit is required to allocate the
portion of his total purchase price allocated to the Trust Unit among the
Royalty Interests in the proportion that the fair market value of each of the
Royalty Interests bears to the total fair market value of all of the Royalty
Interests. For purposes of making this allocation, the Royalty Interests include
the Wasson ODC Royalty, the Wasson Willard Royalty and the Net Profits
Royalties. Information regarding purchase price allocations is furnished to
Holders by the Trustee.
INTEREST INCOME
Based on representations made by Santa Fe regarding the reserves burdened
by the Wasson Royalties and the expected life of the Wasson Royalties, the
Wasson Royalties are properly treated as "production payments" under Section
636(a) of the Code. Under the rules of such Code section, each Holder is treated
as making a mortgage loan on the Wasson Properties to Santa Fe in an amount
equal to the amount of the purchase price of each Depositary Unit allocated to
the Wasson Royalties. Because production payments are treated as debt
instruments for tax purposes, the Wasson Royalties are subject to the Original
Issue Discount (OID) rules of Sections 1272 through 1275 of the Code. Section
1272 generally requires the periodic inclusion of original issue discount in
income of the purchaser of a debt instrument. Section 1275 provides special
rules and authorizes the IRS to prescribe regulations modifying the statutory
provisions where, by reason of contingent payments, the tax treatment provided
under the statutory provisions does not carry out the purposes of such
provisions. Proposed regulations dealing with contingent payments were issued in
1986 and modified in 1991 (the "Original Proposed Regulations"). During
December 1994, the IRS replaced the Original Proposed Regulations with new
proposed regulations and, during June 1996, the IRS redesignated the 1994
proposed regulations as final regulations (the "New Regulations"). However,
the New Regulations are by their terms applicable only to debt instruments that
are issued on or after August 13, 1996. The New Regulations further provide, in
the case of a contingent debt instrument issued before August 13, 1996, that a
taxpayer may use any reasonable method to account for the debt instrument,
including a method that would have been required under the proposed regulations
when the debt instrument was issued. Because the Original Proposed Regulations
were in effect when the Wasson Royalties were issued to the Trust, the tax
treatment of the Wasson Royalties has been reported to the Holders under the
provisions of the Original Proposed Regulations.
Under the rules set forth in the Original Proposed Regulations, each
payment (at the time the amount of such payment becomes fixed) made to the Trust
with respect to the Wasson Royalties is treated first as consisting of a payment
of interest to the extent of interest deemed accrued under the OID rules (based
on the long term Applicable Federal Rate in effect at the time the amount of
such payment becomes fixed) and the excess (if any) is treated as a payment of
principal. The total amount treated as principal is limited to the amount of the
purchase price of each Depositary Unit allocated to the Wasson Royalties.
Holders are also required to recognize and report OID interest income
attributable to the Treasury Obligations. In general, the total amount of OID
interest income a Holder is required to recognize over the term of the Treasury
Obligations is calculated as the difference between the amount of the purchase
price of a Depositary Unit allocated to the Treasury Obligations and the pro
rata portion of the face
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amount of such Treasury Obligations attributable to the Depositary Unit. The
portion of OID interest income so calculated which is required to be included in
income by a Holder for any particular period is generally determined by
multiplying the Holder's adjusted issue price in the Treasury Obligations by the
yield to maturity of the Treasury Obligations.
ROYALTY INCOME AND DEPLETION
The income from the Net Profits Royalties is royalty income subject to an
allowance for depletion. The depletion allowance must be computed separately by
each Holder for each oil or gas property (within the meaning of Code Section
614). The IRS presently takes the position that a net profits interest carved
out of multiple properties is a single property for depletion purposes.
Accordingly, the Trust has taken the position that the Net Profits Royalties are
a single property for depletion purposes until such time as the issue is
resolved in some other manner.
The allowance 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" (generally persons who are not substantial refiners or retailers of
oil or gas or their primary products) on the equivalent of 1,000 barrels of
production per day. Percentage depletion is a statutory allowance generally
equal to 15% of the gross income from production from a property, subject to a
net income limitation which is 100% of the taxable income from the property,
computed without regard to depletion deductions and certain loss carrybacks. For
tax years beginning after December 31, 1997, and before January 1, 2002, the
100% of taxable income limitation on percentage depletion does not apply to
"marginal production." Additionally, the percentage depletion rate for
"marginal production" is adjusted annually and is generally greater than 15%.
Marginal production includes (i) "stripper well property," generally defined
as a domestic crude oil or natural gas property producing 15 barrel equivalents
or less per day per well, and (ii) "heavy oil," generally defined as domestic
crude oil produced from any property if such crude oil had a weighted average
gravity of 20 degrees API or less. 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 and certain loss carrybacks. 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).
In computing cost depletion for each property for any year, the adjusted
tax basis of that property at the beginning of that year is divided by the
estimated total units (Bbls of oil or Mcf of gas) recoverable from that 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 that property
during the year. Cost depletion for a property cannot exceed the adjusted tax
basis of such property. Since the Trust is taxed as a grantor trust, each Holder
computes cost depletion using his basis in his Trust Units allocated to the Net
Profits Royalties. Information is provided to each Holder reflecting how that
basis should be allocated among each property represented by his Trust Units.
OTHER INCOME AND EXPENSES
The Trust may generate some interest income on funds held as a reserve or
held until the next distribution date. Expenses of the Trust include
administrative expenses of the Trustee. Under the Code, certain miscellaneous
itemized deductions of an individual taxpayer are deductible only to the extent
that in the aggregate they exceed 2% of the taxpayer's adjusted gross income.
Certain administrative expenses attributable to the Trust Units may have to be
aggregated with an individual Holder's other miscellaneous itemized deductions
to determine the excess over 2% of adjusted gross income. The amount of such
expenses has not been, and is not expected to be, significant in relation to the
Trust's income.
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NON-PASSIVE ACTIVITY INCOME AND LOSS
The income and expenses of the Trust are not taken into account in
computing passive activity losses and income under Code Section 469 for a Holder
who acquires and holds Depositary Units as an investment.
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. The income of the Trust will not
constitute 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 Holder 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 DEPOSITARY UNITS
Generally, a Holder will realize gain or loss on the sale or exchange of
his Depositary Units measured by the difference between the amount realized on
the sale or exchange and his adjusted basis for such Depositary Units. Gain or
loss on the sale of Depositary Units by a Holder who is not a dealer with
respect to such Depositary Units and who has a holding period for the Depositary
Units of more than one year may be eligible for lower capital gains rate, except
to the extent of the depletion recapture amount (as described below). Capital
gains of each noncorporate Holder arising from a sale of Depository Units
generally are currently subject to tax at a rate of 20% (10% if the noncorporate
Holder is in the 15% tax bracket) if such Depository Units have been held for
more than 12 months. If a noncorporate Holder has held the Depository Units for
12 months or less, any such capital gain recognized on the sale of such
Depository Units will be subject to tax at ordinary income tax rates (of which
the maximum rate is currently 39.6%).
For Federal income tax purposes, the sale of a Depositary Unit is treated
as a sale by the Holder of his interest in the Treasury Obligations and the
assets of the Trust. Thus, upon the sale of Depositary Units, a Holder must
treat as ordinary income his depletion recapture amount, which is an amount
equal to the lesser of (i) the gain on that sale attributable to disposition of
the Net Profits Royalties or (ii) the sum of the prior depletion deductions
taken with respect to the Net Profits Royalties (but not in excess of the
initial basis of such Depositary Units allocated to the Net Profits Royalties).
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 Depositary Units sold, but which has not been distributed
to the selling Holder.
A Holder's initial basis in his Depositary Units is equal to the amount
paid for such Depositary Units. Such basis is increased by the amount of any OID
interest income recognized by the Holder attributable to the Treasury
Obligations. Such basis is reduced by deductions for depletion claimed by the
Holder (but not below zero). In addition, such basis is reduced by the amount of
any payments attributable to the Wasson Royalties which are treated as payments
of principal under the OID rules. A Holder's basis would also be increased by
any increase in reserves retained by the Trust and would be reduced by any
reduction in such reserves.
SALE OF NET PROFITS ROYALTIES
In certain circumstances, Santa Fe may cause the Trustee, without the
consent of the Holders, to release a portion of the Net Profits Royalties in
connection with a sale by Santa Fe of the underlying Net Profits Properties.
Additionally, the assets of the Trust, including the Net Profits Royalties, will
be sold by the Trustee prior to the Liquidation Date in anticipation of the
termination of the Trust. A sale by the Trust of Net Profits Royalties will be
treated for Federal income tax purposes as a sale of Net Profits Royalties by a
Holder. Thus, a Holder will recognize gain or loss on a sale of Net Profits
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Royalties by the Trust. A portion of that income may be treated as ordinary
income to the extent of depletion recapture. See "Sale of Depositary Units,"
above.
BACKUP WITHHOLDING
In general, distributions of Trust income are not subject to "backup
withholding" unless: (i) the Holder is an individual or other noncorporate
taxpayer and (ii) such Holder fails to furnish and certify as to the correctness
of his taxpayer identification number (which for an individual, would be such
individual's social security number) or such Holder fails to comply with certain
reporting procedures.
TAX SHELTER REGISTRATION
The Trust is registered as a tax shelter with the IRS, as required by Code
Section 6111. The Trust's tax shelter registration number is 92322000636.
A Holder 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 for each such failure.
Holders must disclose the tax shelter registration number of the Trust on IRS
Form 8271 which is required to be attached to each 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 Holder who fails to disclose the tax shelter
registration number on his return, without reasonable cause for such failure,
will be subject to a $250 penalty for each such failure. (Any penalties
discussed herein are not deductible for income tax purposes.)
ISSUANCE OF A TAX SHELTER REGISTRATION NUMBER DOES NOT INDICATE THAT AN
INVESTMENT IN DEPOSITARY UNITS OR TRUST UNITS OR THE CLAIMED TAX BENEFITS HAVE
BEEN REVIEWED, EXAMINED OR APPROVED BY THE IRS.
ERISA CONSIDERATIONS
The Employee Retirement Income Security Act of 1974, as amended
("ERISA"), imposes certain requirements on pension, profit-sharing and other
employee benefit plans ("Plans") to which it applies, and contains standards
on those persons who are fiduciaries with respect to such Plans. In addition,
under the Code, there are similar requirements and standards which are
applicable to certain Plans and individual retirement accounts (whether or not
subject to ERISA) (collectively, together with Plans subject to ERISA, referred
to herein as Qualified Plans).
A fiduciary of a Qualified Plan should carefully consider fiduciary
standards under ERISA regarding the Plan's particular circumstances before
authorizing an investment in Trust Units. A fiduciary should first consider (i)
whether the investment satisfies the prudence requirements of Section
404(a)(1)(B) of ERISA, (ii) whether the investment satisfies the diversification
requirements of Section 404(a)(1)(C) of ERISA and (iii) whether the investment
is in accordance with the documents and instruments governing the Plan as
required by Section 404(a)(1)(D) of ERISA.
In order to avoid the application of certain penalties, a fiduciary must
also consider whether the acquisition of Depositary Units representing Trust
Units and/or operation of the Trust might result in direct or indirect nonexempt
prohibited transactions under Section 406 of ERISA and Code Section 4975. In
determining whether there are such prohibited transactions, a fiduciary must
determine whether there are "plan assets" involved in the transaction.
Department of Labor regulations ("the DOL Regulations") address whether or not
a Qualified Plan's assets (such as a Depositary Unit) would be deemed to include
an interest in the underlying assets of an entity (such as the Trust) for
purposes of the reporting, disclosure and fiduciary responsibility provisions of
ERISA and analogous provisions of the Code, if the Plan acquires an "equity
interest" in such entity. The DOL Regulations provide that the underlying
assets of an entity will not be considered "plan assets" if the interests in
the entity are a publicly offered security. Trust Units represented by
Depositary Units are considered to be "publicly offered" for this purpose if
they are part of a class of securities that is (i) widely held (I.E., owned by
more than 100 investors independent of the issuer and each other), (ii) freely
transferable, and
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(iii) registered under Section 12(b) or 12(g) of the Exchange Act. Although no
assurances can be given, it is believed that these requirements have been
satisfied. Fiduciaries, however, will need to determine whether the acquisition
of Depositary Units representing Trust Units is a nonexempt prohibited
transaction under the general requirements of ERISA Section 406 and Code Section
4975.
Due to the complexity of the prohibited transaction rules and the penalties
imposed upon persons involved in prohibited transactions, it is important that
potential Qualified Plan investors consult with their counsel regarding the
consequences under ERISA and the Code of their acquisition and ownership of
Depositary Units.
STATE TAX CONSIDERATIONS
The following is intended as a brief summary of certain information
regarding state income taxes and other state tax matters affecting individuals
who are Holders. Holders are urged to consult their own legal and tax advisors
with respect to these matters.
Each Holder should consider state and local tax consequences of an
investment in Depositary Units. The Trust owns the Royalty Interests burdening
oil and gas properties located in Alabama, Arkansas, California, Colorado,
Kansas, Louisiana, Mississippi, New Mexico, North Dakota, Oklahoma, Texas and
Wyoming. Of these, all but Texas and Wyoming have income taxes applicable to
individuals. As stated, Texas currently has no individual income tax and the
Reserve Report reflects that more than 50% of the estimated future net cash
inflows generated by the Trust will be attributable to properties located in
Texas. A Holder may be required to file state income tax returns and/or to pay
taxes in those states imposing income taxes and may be subject to penalties for
failure to comply with such requirements. Further, in some states the Trust may
be taxed as a separate entity.
The Depositary currently provides information prepared by the Trustee
concerning the Depositary Units sufficient to identify the income from
Depositary Units that is allocable to each state. Holders of Depositary Units
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 represented by Depositary Units may constitute real
property or an interest in real property under the inheritance, estate and
probate laws of some or all of the states listed above. If the Depositary Units
are held to be real property or an interest in real property under the laws of a
state in which the Royalty Properties are located, the holders of Depositary
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 TREASURY OBLIGATIONS
The Treasury Obligations consist of a portfolio of interest coupons
stripped from United States Treasury Bonds. All of the Treasury Obligations
become due on the Liquidation Date in the aggregate face amount of $126,000,000,
which amount equals $20 per outstanding Depositary Unit. The Treasury
Obligations were purchased on behalf of the Depositary at a deep discount from
face value at a price of $30.733 per hundred dollars, which was approximately
the asked price on the over-the-counter U.S. Treasury market for such
obligations on November 12, 1992 (after adjustment for five-day settlement). The
Treasury Obligations were deposited with the Depositary on November 19, 1992 in
connection with the initial public offering of Depositary Units.
The Treasury Obligations were issued under the Separate Trading of
Registered Interest and Principal of Securities program of the U.S. Treasury,
which permits the trading of the Treasury Obligations in book-entry form. The
Treasury Obligations are held for the benefit of Holders in the name of the
Depositary in book-entry form with a Federal Reserve Bank subject to withdrawal
by a Holder. The deposited Treasury Obligations are not considered assets of the
Depositary or the Trust. In the unlikely event of default by the U.S. Treasury
in the payment of the Treasury Obligations when due, each Holder would have the
right to withdraw a deposited Treasury Obligation in a face amount of
15
<PAGE>
$1,000 for each 50 Depositary Units and, as a real party in interest and as the
owner of the entire beneficial interest in discrete Treasury Obligations,
proceed directly and individually against the United States of America in
whatever manner he deems appropriate without any requirement to act in concert
with the Depositary, other Holders or any other person.
DESCRIPTION OF THE ROYALTY PROPERTIES
THE WASSON PROPERTIES
The Wasson Royalties were conveyed to the trust out of Santa Fe's 12.3934%
royalty interest in the Wasson ODC Unit and its 6.8355% royalty interest in the
Wasson Willard Unit, located in the Wasson Field. Santa Fe also owns working
interests in each of these units. The Wasson Field has been significantly
redeveloped for tertiary recovery operations utilizing CO2 flooding, which
commenced in 1984. Most of the capital expenditures for plant, facilities, wells
and equipment necessary for such tertiary recovery operations have been made,
although ongoing capital expenditures for CO2 acquisition will be required to
complete the flood of the Wasson Field, particularly the Wasson Willard Unit.
The Wasson Royalties are not subject to development costs or operating costs
(including CO2 acquisition costs).
The Wasson ODC Unit and the Wasson Willard Unit are production units formed
by the various interest owners in the Wasson Field to facilitate development and
production of certain geographically concentrated leases. The Wasson ODC Unit
covers approximately 7,840 acres with approximately 315 producing wells and is
operated by Altura Energy, Ltd. The Wasson Willard Unit covers approximately
13,520 acres with approximately 335 producing wells and is operated by a
subsidiary of Atlantic Richfield Company. Production attributable to Santa Fe's
royalty interests in the Wasson ODC Unit and Wasson Willard Unit is marketed by
Santa Fe and in some cases is sold at the wellhead at market responsive prices
that approximate spot oil prices for West Texas Sour crude, and in other cases
is sold at points within common carrier pipeline systems on terms whereby Santa
Fe pays the cost of transporting same to such points. Santa Fe may sell its
royalty interests in the Wasson Field subject to and burdened by the Wasson
Royalties, without the consent of the Trustee of the Trust or the Holders. The
Wasson Royalties may not be sold by the Trust without the consent of Santa Fe.
THE NET PROFITS PROPERTIES
The Royalty Properties burdened by the Net Profits Royalties consist of
royalty and working interests in a diversified portfolio of producing properties
located in established oil and gas producing areas in 12 states. Over 85% of the
discounted present value of estimated future net revenues attributable to the
Net Profits Royalties is generated from Net Profits Properties located in Texas,
Oklahoma and Louisiana and related state waters. Production attributable to the
Net Profits Properties is principally sold at market responsive prices.
Santa Fe owns the Net Profits Properties subject to and burdened by the Net
Profits Royalties, and is entitled to proceeds attributable to its ownership
interest in excess of 90% of the Net Proceeds paid to the Trust. Santa Fe is
required to receive payments representing the sale of production from the Net
Profits Properties, deduct the costs described above and pay 90% of the net
amount to the Trust. Santa Fe may sell the Net Profits Properties subject to and
burdened by the Net Profits Royalties. In addition, Santa Fe may, subject to
certain limitations, cause the Trust to release portions of the Net Profits
Royalties in connection with the sale of the underlying Net Profits Properties.
Santa Fe estimates that as of December 31, 1999, the Net Profits Properties
covered approximately 243,000 gross acres (approximately 36,000 net to Santa
Fe). Productive well information generally is not made available by operators to
owners of royalties and overriding royalties. Accordingly, such information is
unavailable to Santa Fe for the Net Profits Properties.
16
<PAGE>
TITLE TO PROPERTIES
The Conveyances contain a warranty of title, limited to claims by, through
or under Santa Fe, and covering the Wasson Properties and certain of the Net
Profits Properties. The Conveyances contain no title warranty with respect to
the remaining Net Profits Properties. As is customary in the oil and gas
industry, Santa Fe or the operator of its properties performs only a perfunctory
title examination when it acquires leases, except leases covering proved
reserves. Generally, prior to drilling a well, a more thorough title examination
of the drill site tract is conducted and curative work is performed with respect
to significant title defects, if any, before proceeding with operations. The
Royalty Properties are typically subject, to one degree or another, to one or
more of the following: (i) royalties and other burdens and obligations,
expressed and implied, under oil and gas leases; (ii) overriding royalties (such
as the Royalty Interests) and other burdens created by Santa Fe or its
predecessors in title; (iii) a variety of contractual obligations (including, in
some cases, development obligations) arising under operating agreements, farmout
agreements, production sales contracts and other agreements that may affect the
properties or their titles; (iv) liens that arise in the normal course of
operations, such as those for unpaid taxes, statutory liens securing unpaid
suppliers and contractors and contractual liens under operating agreements; (v)
pooling, unitization and communitization agreements, declarations and orders;
and (vi) easements, restrictions, rights-of-way and other matters that commonly
affect property. To the extent that such burdens and obligations affect Santa
Fe's rights to production and production revenues from the Royalty Properties,
they have been taken into account in calculating the Royalty Interests and in
estimating the size and value of the Trust's reserves attributable to the
Royalty Interests.
It is not entirely clear that all of the Royalty Interests would be treated
as fully conveyed real or personal property interests under the laws of each of
the states in which the Royalty Properties are located. The Conveyances (other
than the Louisiana Conveyance) state that the Royalty Interests constitute real
property interests and Santa Fe has recorded the Conveyances (other than the
Louisiana Conveyance) in the appropriate real property records of the states in
which the Royalty Properties are located in accordance with local recordation
provisions. If during the term of the Trust, Santa Fe becomes involved as a
debtor in bankruptcy proceedings, it is not entirely clear that all of the
Royalty Interests would be treated as fully conveyed property interests under
the laws of each of the states in which the Royalty Properties are located. If
in such a proceeding a determination were made that a Royalty Interest (or a
portion thereof) did not constitute fully conveyed property interests under
applicable state law, the Conveyance related to such Royalty Interest (or a
portion thereof) could be subject to rejection as an executory contract (a term
used in the Federal Bankruptcy Code to refer to a contract under which the
obligations of both the debtor and the other party to the contract are so
unsatisfied that the failure of either to complete performance would constitute
a material breach excusing performance of the other) in a bankruptcy proceeding
involving Santa Fe. In such event, the Trust would be treated as an unsecured
creditor of Santa Fe with respect to such Royalty Interest in the pending
bankruptcy. Under Louisiana law, the Louisiana Conveyance constitutes personal
property that could be rejected as an executory contract in a bankruptcy
proceeding involving Santa Fe, although the mortgage on the Royalty Properties
that is burdened by the Louisiana Conveyance and which secures the Trust's
interests in such Royalty Properties should enhance the Trust's position in the
event of such a proceeding. No assurance can be given that the Royalty Interests
would not be subject to rejection in a bankruptcy proceeding as executory
contracts.
RESERVES
A study of the proved oil and gas reserves attributable to the Trust as of
December 31, 1999 has been made by Ryder Scott Company, independent petroleum
consultants. The following letter (Reserve Report) summarizes such reserve
study. The Trust has not filed reserve estimates covering the Royalty Properties
with any other Federal authority or agency.
17
<PAGE>
(RYDER SCOTT LETTERHEAD)
February 9, 2000
Santa Fe Snyder Corporation
840 Gessner, Suite 1400
Houston, Texas 77024
Gentlemen:
Pursuant to your request, we present below our estimates of the net proved
reserves attributable to the interests of the Santa Fe Energy Trust (Trust) as
of December 31, 1999. The Trust is a grantor trust formed to hold interests in
certain domestic oil and gas properties owned by Santa Fe Snyder Corporation
(SFSC). The interests conveyed to the Trust consist of royalty interests in the
Wasson Field, Texas (Wasson Royalties) and a net profits interest derived from
working and royalty interests in numerous other properties (Net Profits
Royalties). The properties included in the Trust are located in the states of
Alabama, Arkansas, California, Colorado, Kansas, Louisiana, Mississippi, New
Mexico, North Dakota, Oklahoma, Texas, Wyoming, and in state waters offshore
Louisiana.
The estimated reserve quantities and future income quantities presented in
this report are related to a large extent to hydrocarbon prices. Hydrocarbon
prices in effect at December 31, 1999 were used in the preparation of this
report as required by Securities and Exchange Commission (SEC) and Financial
Accounting Standards Bulletin No. 69 (FASB 69) guidelines; however, actual
future prices may vary significantly from December 31, 1999 prices for reasons
discussed in more detail in other sections of this report. Therefore, quantities
of reserves actually recovered and quantities of income actually received may
differ significantly from the estimated quantities presented in this report.
<TABLE>
<CAPTION>
SANTA FE ENERGY TRUST
AS OF DECEMBER 31, 1999
---------------------------------------------
ESTIMATED PRESENT
FUTURE NET VALUE
LIQUIDS GAS CASH INFLOWS AT 10%
(MBBLS) (MMCF) (M$) (M$)
------- ------ ------------ --------
<S> <C> <C> <C> <C>
Proved Net Developed and
Undeveloped Wasson ODC Royalty..... 2,114.8 0 47,856.7 33,015.1
Wasson Willard Royalty............. 270.2 0 6,010.9 5,080.5
Net Profits Royalties.............. 1,045.7 6,436 35,552.9 22,540.3
------- ------ ------------ --------
Totals.................... 3,430.7 6,436 89,420.5 60,635.9
======= ====== ============ ========
Proved Net Developed
Wasson ODC Royalty................. 2,114.8 0 47,856.7 33,015.1
Wasson Willard Royalty............. 270.2 0 6,010.9 5,080.5
Net Profits Royalties.............. 1,045.7 6,436 35,552.9 22,540.3
------- ------ ------------ --------
Totals.................... 3,430.7 6,436 89,420.5 60,635.9
======= ====== ============ ========
</TABLE>
The estimated proved reserves and income quantities for the Wasson
Royalties presented in this report are calculated by multiplying the net revenue
interest attributable to each of the Wasson Royalties by the total amount of oil
estimated to be economically recoverable from the respective productive units,
subject to production limitations applicable to the Wasson Royalties and
additional
18
<PAGE>
"Support Payments", which have been described to us by SFSC. For purposes of
this report, the volume of reserves attributable to the Support Payments, if
any, is calculated assuming an additional royalty interest in the Wasson ODC
property.
Reserve quantities are calculated differently for the Net Profits Royalties
because such interests do not entitle the Trust to a specific quantity of oil or
gas but to 90 percent of the Net Proceeds derived therefrom. Accordingly, there
is no precise method of allocating estimates of the quantities of proved
reserves attributable to the Net Profits Royalties between the interest held by
the Trust and the interests to be retained by SFSC. For purposes of this
presentation, the proved reserves attributable to the Net Profits Royalties have
been proportionately reduced to reflect the future estimated costs and expenses
deducted in the calculation of Net Proceeds with respect to the Net Profits
Royalties. Accordingly, the reserves presented for the Net Profits Royalties
reflect quantities of oil and gas that are free of future costs or expenses
based on the price and cost assumptions utilized in this report. The allocation
of proved reserves of the Net Profits Properties between the Trust and SFSC will
vary in the future as relative estimates of future gross revenues and future net
incomes vary. Furthermore, SFSC requested that, for purposes of our report, the
Net Profits Royalties be calculated beyond the Liquidation Date of December 31,
2007, even though by the terms of the Trust Agreement the Net Profits Royalties
will be sold by the Trustee on or about this date and a liquidating distribution
of the sales proceeds from such sale would be made to holders of Trust Units.
SFSC has indicated that the conveyance of the Wasson Royalties to the Trust
provides that the Trust will receive additional income from the Wasson ODC Unit
through Support Payments. Payment of the additional income is subject to
numerous limitations which are detailed in the Conveyance. Based on the
production profiles and pricing assumptions in this report and the terms of the
Conveyance as described to us by SFSC, no additional net cash inflow is required
from future Support Payments as of December 31, 1999. Based on the original
terms of the Conveyance, the Support Payments are limited to a total payment of
$20,000,000 from inception through 2002, which is the time the Support Payments
are terminated. However, with the sale of the Jeffress Field during 1999, this
limitation has been reduced to $19,400,000. As of December 31, 1999, there were
no unrecouped Support Payments so the remaining maximum obligation with respect
to the Support Payments is $19,400,000. In accordance with information provided
by SFSC, we have calculated total estimated net revenue of $22,279,224 to be
available for Support Payments as of December 31, 1999.
The "Liquid" reserves shown above are comprised of crude oil, condensate
and natural gas liquids. Natural gas liquids comprise 3.0 percent of the Trust's
developed liquid reserves and 3.0 percent of the Trust's developed and
undeveloped liquid reserves. All hydrocarbon liquid reserves are expressed in
standard 42 gallon barrels. All gas volumes are sales gas expressed in MMcf at
the pressure and temperature bases of the area where the gas reserves are
located. The estimated future net cash inflows are described later in this
report.
The proved reserves presented in this report comply with the SEC's
Regulation S-X Part 210.4-10 Sec. (a) as clarified by subsequent Commission
Staff Accounting Bulletins, and are based on the following definitions and
criteria:
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions, i.e., prices and costs as of the
date the estimate is made. Prices include consideration of changes in existing
prices provided only by contractual arrangements, but not on escalation based on
future conditions. Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation tests. In certain
instances, proved reserves are assigned on the basis of a combination of core
analysis and electrical and other type logs which indicate the reservoirs are
analogous to reservoirs in the same field which are producing or have
demonstrated the ability to produce on a formation test. The area of a
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
19
<PAGE>
reservoir considered proved includes (1) that portion delineated by drilling and
defined by fluid contacts, if any, and (2) the adjoining portions not yet
drilled that can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of data on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir. Reserves that can be produced economically
through the application of improved recovery techniques are included in the
proved classification when these qualifications are met: (1) successful testing
by a pilot project or the operation of an installed program in the reservoir
provides support for the engineering analysis on which the project or program
was based, and (2) it is reasonably certain the project will proceed. Improved
recovery includes all methods for supplementing natural reservoir forces and
energy, or otherwise increasing ultimate recovery from a reservoir, including
(1) pressure maintenance, (2) cycling, and (3) secondary recovery in its
original sense. Improved recovery also includes the enhanced recovery methods of
thermal, chemical flooding, and the use of miscible and immiscible displacement
fluids. Proved natural gas reserves are comprised of non-associated, associated,
and dissolved gas. An appropriate reduction in gas reserves has been made for
the expected removal of natural gas liquids, for lease and plant fuel, and the
exclusion of non-hydrocarbon gases if they occur in significant quantities and
are removed prior to sale. Estimates of proved reserves do not include crude
oil, natural gas, or natural gas liquids being held in underground or surface
storage. Proved reserves are estimates of hydrocarbons to be recovered from a
given date forward. They may be revised as hydrocarbons are produced and
additional data become available.
Proved developed oil and gas reserves are reserves that can be expected to
be recovered through existing wells with existing equipment and operating
methods. Additional oil and gas expected to be obtained through the application
of fluid injection or other improved recovery techniques for supplementing the
natural forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the
operation of an installed program has confirmed through production response that
increased recovery will be achieved. Developed reserves may be subcategorized as
follows:
PRODUCING
Reserves sub-categorized as producing are expected to be recovered from
completion intervals which are open and producing at the time of the
estimate. Improved recovery reserves are considered producing only after
the improved recovery project is in operation.
NON-PRODUCING
Reserves sub-categorized as non-producing include shut-in and behind
pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but
which have not started producing, (2) wells which were shut-in for
market conditions or pipeline connections, or (3) wells not capable of
production for mechanical reasons. Behind pipe reserves are expected to
be recovered from zones in existing wells, which will require additional
completion work or future recompletion prior to the start of production.
Proved undeveloped oil and gas reserves are reserves that are expected to
be recovered from new wells on undrilled acreage, or from existing wells
where a relatively major expenditure is required for recompletion. Reserves
on undrilled acreage shall be limited to those drilling units offsetting
productive units that are reasonably certain of production when drilled.
Proved reserves for other undrilled units can be claimed only where it can
be demonstrated with reasonable certainty that there is continuity of
production from the existing productive formation. Estimates for proved
undeveloped reserves are attributable to any acreage for which an
application of fluid injection or other improved technique is contemplated,
only when such techniques have been proved effective by actual tests in the
area in the same reservoir.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
20
<PAGE>
Because of the direct relationship between quantities of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled and reserves assigned to the undeveloped portions of
secondary or tertiary projects which we have been assured will definitely be
developed.
In accordance with the requirements of FASB 69, our estimates of future
cash inflows, future costs, and future net cash inflows before income tax, as
well as our estimated reserves quantities, as of December 31, 1999 from this
report are presented below:
<TABLE>
<CAPTION>
SANTA FE ENERGY TRUST
AS OF DECEMBER 31, 1999
--------------------------------------------------------------
NET PROFITS ROYALTIES
-----------------------------------
ROYALTY WORKING WASSON
INTERESTS INTERESTS TOTALS ROYALTIES TOTALS
--------- ------- ---------- --------- ----------
<S> <C> <C> <C> <C> <C>
Total Proved
Future Cash Inflows (M$)........... 18,549.7 17,003.2 35,552.9 58,168.0 93,720.9
Future Costs
Production (M$)................. 0 0 0 4,300.4 4,300.4
Development (M$)................ 0 0 0 0 0
--------- ------- ---------- --------- ----------
Total Costs (M$).......... 0 0 0 4,300.4 4,300.4
Future Net Cash Inflows Before
Income Tax (M$)................. 18,549.7 17,003.2 35,552.9 53,867.6 89,420.5
Present Value at 10% Before
Income Tax (M$)................. 10,666.7 11,873.6 22,540.3 38,095.6 60,635.9
</TABLE>
<TABLE>
<CAPTION>
SANTA FE ENERGY TRUST
AS OF DECEMBER 31, 1999
-------------------------------------------------------------
NET PROFITS ROYALTIES
----------------------------------
ROYALTY WORKING WASSON
INTERESTS INTERESTS TOTALS ROYALTIES TOTALS
--------- ------- ------ --------- ------
<S> <C> <C> <C> <C> <C>
Proved Net Developed Reserves
Liquids (MBbls).................... 599.7 446.0 1,045.7 2,385.0 3,430.7
Gas (MMCF)......................... 2,708 3,728 6,436 0 6,436
Proved Net Undeveloped Reserves
Liquids (MBbls).................... 0 0 0 0 0
Gas (MMCF)......................... 0 0 0 0 0
Total Proved Net Reserves
Liquids (MBbls).................... 599.7 446.6 1,045.7 2,385.0 3,430.7
Gas (MMCF)......................... 2,708 3,728 6,436 0 6,436
</TABLE>
In the case of the Wasson Royalties, the future cash inflows are gross
revenues after gathering and transportation costs where applicable, but before
any other deductions. The production costs are based on current data and include
production taxes and ad valorem taxes provided by SFSC.
In the case of the Net Profits Royalties, the future cash inflows are, as
described previously, after consideration of future costs or expenses based on
the price and cost assumptions utilized in this report. Therefore, the future
cash inflows are the same as the future net cash inflows.
SFSC furnished us gas prices in effect at December 31, 1999 and with its
forecasts of future gas prices which take into account Securities and Exchange
Commission guidelines, current market prices, regulations under the Natural Gas
Policy Act of 1978 and the Gas Decontrol Act of 1989, contract prices and fixed
and determinable price escalations where applicable. In accordance with
Securities
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
21
<PAGE>
and Exchange Commission guidelines, the future gas prices used in this report
make no allowances for future gas price increases which may occur as a result of
inflation nor do they account for seasonal variations in gas prices which are
likely to cause future yearly average gas prices to be different than December
gas prices. In those cases where contract market-out has occurred, the current
market price was held constant to depletion of the reserves. In those cases
where market-out has not occurred, contract gas prices including fixed and
determinable escalations, exclusive of inflation adjustments, were used until
the contract expires and then reduced to the current market price for similar
gas in the area and held at this reduced price to depletion of the reserves.
SFSC furnished us with liquid prices in effect at December 31, 1999 and
these prices were held constant to depletion of the properties. In accordance
with Securities and Exchange Commission guidelines, changes in liquid prices
subsequent to December 31, 1999 were not considered in this report.
Operating costs for the leases and wells in this report were provided by
SFSC and include only those costs directly applicable to the leases or wells.
When applicable, the operating costs include a portion of general and
administrative costs allocated directly to the leases and wells under terms of
operating agreements. Development costs were furnished to us by SFSC and are
based on authorizations for expenditure for the proposed work or actual costs
for similar projects. The current operating and development costs were held
constant throughout the life of the properties. The estimated net costs of
abandonment after salvage was included for all properties where abandonment
costs net of salvage, as estimated by SFSC, are significant. The estimates of
the net abandonment costs furnished by SFSC were accepted without independent
verification.
No deduction was made for indirect costs such as general administration and
overhead expenses, loan repayments, interest expenses, and exploration and
development prepayments. No attempt has been made to quantify or otherwise
account for any accumulated gas production imbalances that may exist.
Our reserve estimates are based upon a study of the properties in which the
Trust has interests; however, we have not made any field examination of the
properties. No consideration was given in this report to potential environmental
liabilities which may exist nor were any costs included for potential liability
to restore and clean up damages, if any, caused by past operating practices.
SFSC informed us that it has furnished us all of the accounts, records,
geological and engineering data and reports and other data required for our
investigation. The ownership interest, terms of the Trust, prices, taxes, costs,
and other factual data furnished to us in connection with our investigation were
accepted as represented. The estimates presented in this report are based on
data available through August 1999.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered.
Estimates of proved reserves may increase or decrease as a result of future
operations of SFSC. Moreover, due to the nature of the Support Payments and the
Net Profits Royalties, a change in the future costs, or prices, or capital
expenditures different from those projected herein may result in a change in the
computed reserves and the Net Proceeds to the Trust even if there are no
revisions or additions to the gross reserves attributed to the property.
The future production rates from properties now on production may be more
or less than estimated because of changes in market demand or allowables set by
regulatory bodies. In general, we estimate that gas production rates will
continue to be the same as the average rate for the latest available 12 months
of actual production until such time that the well or wells are incapable of
producing at this rate. The well or wells are then projected to decline at their
decreasing delivery capacity rate. Our general policy on estimates of future gas
production rates is adjusted when necessary to reflect actual gas market
conditions in specific cases. Properties which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
22
<PAGE>
The future prices received for the sale of the production may be higher or
lower than the prices used in this report as described above, and the operating
costs and other costs relating to such production may also increase or decrease
from existing levels; however, such possible changes in prices and costs were,
in accordance with rules adopted by the Securities and Exchange Commission,
omitted from consideration in preparing this report.
Neither Ryder Scott Company nor any of its employees has any interest in
the subject properties and neither the employment to make this study nor the
compensation is contingent on our estimates of reserves and future cash inflows
for the subject properties.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
Fred W. Ziehe, P.E.
Senior Vice President
RYDER SCOTT COMPANY PETROLEUM ENGINEERS
23
<PAGE>
The value of the Depositary Units and the Trust Units evidenced thereby are
substantially dependent upon the proved reserves and production levels
attributable to the Royalty Interests. There are many uncertainties inherent in
estimating quantities and 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 actual quantities and values
of oil and gas are likely to differ from the estimated amounts set forth herein.
In addition, the discounted present values shown herein were prepared using
guidelines established by the Commission for disclosure of reserves and should
not be considered representative of the market value of such reserves or the
Depositary Units or the Trust Units evidenced thereby. A market value
determination would include many additional factors.
Distributions to Holders could be adversely affected if any of the hazards
typically associated with the development, 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 from any of the foregoing will directly reduce payments to the Trust
from those Royalty Properties that are working interests, and will reduce
payments to the Trust from those Royalty Properties that are royalties and
overriding royalties to the extent such damages reduce the volumes of oil and
gas produced.
In contrast to the Net Profits Royalties, which have no contractually
imposed production limitations, the Wasson Royalties have been structured with
quarterly production limitations. Thus, the Trust and Holders will not receive
cash distributions from oil production from the two Wasson production units
burdened by the Wasson Royalties in excess of such amounts. While the Wasson ODC
Unit is expected to produce at levels substantially in excess of the applicable
production limitations, failure of actual production from either of the two
Wasson production units to meet or exceed the applicable quarterly production
limitations will reduce amounts payable in respect of the Wasson Royalties.
PROCEEDS, PRODUCTION AND AVERAGE PRICES
Reference is made to "Results of Operations" under Item 7 of this Form
10-K.
ASSETS
Reference is made to Item 6 of this Form 10-K for information relating to
the assets of the Trust.
COMPETITION AND MARKETS
COMPETITION. The oil and gas industry is highly competitive in all of its
phases. Santa Fe and the other operators of the Royalty Properties will
encounter competition from major oil and gas companies, international energy
organizations, independent oil and gas concerns, and individual producers and
operators. Many of these competitors have greater financial and other resources
than Santa Fe and the other operators of the Royalty Properties. Competition may
also be presented by alternative fuel sources, including heating oil and other
fossil fuels.
MARKETS. Production attributable to Santa Fe's royalty interests in the
Wasson ODC Unit and the Wasson Willard Unit is marketed by Santa Fe and is in
some cases sold at the wellhead at market responsive prices that approximate
spot oil prices for West Texas sour crude, and in other cases is traded at
points within common carrier pipeline systems.
With respect to the Net Profits Properties, where such properties consist
of royalty interests, the operators of the properties will make all decisions
regarding the marketing and sale of oil and gas production. Although Santa Fe
generally has the right to market oil and gas produced from the Royalty
Properties that are working interests, Santa Fe generally relies on the
operators of the properties to market the production. The ability of the
operators to market the oil and gas produced from the Royalty Properties will
depend upon numerous factors beyond their control, including the extent of
domestic production and imports of oil and gas, the proximity of the gas
production to gas pipelines, the
24
<PAGE>
availability of capacity in such pipelines, the demand for oil and gas by
utilities and other end-users, the effects of inclement weather, state and
Federal regulation of oil and gas production and Federal regulation of gas sold
or transported in interstate commerce. There is no assurance that such operators
will be able to market all of the oil or gas produced from the Royalty
Properties or that favorable prices can be obtained for the oil and gas
produced.
In view of the many uncertainties affecting the supply and demand for oil,
gas and refined petroleum products, Santa Fe is unable to make reliable
predictions of future oil and gas prices and demand or the overall effect they
will have on the Trust. Santa Fe does not believe that the loss of any of its
purchasers would have a material adverse effect on the Trust, since
substantially all of the oil and gas sales from the Royalty Properties are made
on the spot market at market responsive prices.
GOVERNMENTAL REGULATION
OIL AND GAS REGULATION
The production, transportation and sale of oil and gas from the Royalty
Properties are subject to or affected by Federal and state governmental
regulation, including regulations concerning maximum allowable rates of
production, regulation of the terms of service and tariffs charged by gatherers
and pipelines, taxes, the prevention of waste, the conservation of oil and gas,
pollution controls and various other matters. The United States has governmental
power to permit increases in the amount of oil imported from other countries and
to impose pollution control measures.
FEDERAL REGULATION OF GAS. The Net Profits Properties are subject to or
affected by the jurisdiction of the Federal Energy Regulatory Commission
("FERC") and the Department of Energy with respect to various aspects of oil
and gas operations including marketing and production of oil and gas. Under the
Natural Gas Act of 1938, the FERC regulates the interstate transportation and
the sale in interstate commerce for resale of natural gas. The FERC's
jurisdiction over interstate natural gas sales was substantially modified by the
Natural Gas Policy Act, under which the FERC continued to regulate the maximum
selling prices of certain categories of gas sold in "first sales" in
interstate and intrastate commerce. Effective January 1, 1993, however, the
Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural
gas prices for all "first sales" of natural gas. Because "first sales"
include typical wellhead sales by producers, all natural gas produced from the
Net Profits Properties is being sold at market prices, subject to the terms of
any private contracts which may be in effect. The FERC's jurisdiction over
natural gas transportation was not affected by the Decontrol Act.
Sales of natural gas from the Net Profits Properties are affected by
intrastate and interstate gas transportation regulation. Beginning in 1985, the
FERC adopted regulatory changes that have significantly altered the
transportation and marketing of natural gas. These changes were intended by the
FERC to foster competition by, among other things, transforming the role of
interstate pipeline companies from wholesale marketers of gas to the primary
role of gas transporters. All gas marketing by the pipelines was required to be
divested to a marketing affiliate, which operates separately from the
transporter and in direct competition with all other merchants. As a result of
the various omnibus rulemaking proceedings in the late 1980s and the individual
pipeline restructuring proceedings of the early to mid-1990s, the interstate
pipelines are now required to provide open and nondiscriminatory transportation
and transportation-related services to all producers, gas marketing companies,
local distribution companies, industrial end users and other customers seeking
service. Through similar orders affecting intrastate pipelines that provide
similar interstate services, the FERC expanded the impact of open access
regulations to intrastate commerce.
More recently, the FERC has pursued other policy initiatives that have
affected natural gas marketing. Most notable are (i) the large-scale divestiture
of interstate pipeline-owned gas gathering facilities to affiliated or
non-affiliated companies, (ii) further development of rules governing the
relationship of the pipelines with their marketing affiliates, (iii) the
publication of standards relating to the use of electronic bulletin boards and
electronic data exchange by the pipelines to make available transportation
information on a timely basis and to enable transactions to occur on a purely
electronic basis, (iv) further review of the role of the secondary market for
released pipeline capacity and its relationship to open access service in the
primary market and (v) development of policy and
25
<PAGE>
promulgation of orders pertaining to its authorization of market-based rates
(rather than traditional cost-of-service based rates) for transportation or
transportation-related services upon the pipeline's demonstration of lack of
market control in the relevant service market. It remains to be seen what effect
the FERC's other activities will have on the access to markets, the fostering of
competition and the cost of doing business.
As a result of these changes, sellers and buyers of gas have gained direct
access to the particular pipeline services they need and are better able to
conduct business with a larger number of counterparties. Santa Fe believes these
changes generally have improved the access to markets for the gas from the Net
Profits Properties while, at the same time, substantially increasing competition
in the natural gas marketplace. Santa Fe cannot predict what new or different
regulations the FERC and other regulatory agencies may adopt, or what effect
subsequent regulations may have on production and marketing of gas from the Net
Profits Properties.
In the past, Congress has been very active in the area of gas regulation.
However, as discussed above, the more recent trend has been in favor of
deregulation and the promotion of competition in the gas industry. Thus, in
addition to "first sale" deregulation, Congress also repealed incremental
pricing requirements and gas use restraints previously applicable. There are
other legislative proposals pending in the Federal and state legislatures which,
if enacted, would significantly affect the petroleum industry. At the present
time, it is impossible to predict 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 production and marketing of gas from the Net
Profits Properties. Similarly, and despite the trend toward federal deregulation
of the natural gas industry, whether or to what extent that trend will continue,
or what the ultimate effect will be on the production and marketing of gas from
the Net Profits Properties, cannot be predicted.
FEDERAL REGULATION OF PETROLEUM. Sales of oil and natural gas liquids from
the Royalty Properties are not regulated and are at market prices. The price
received from the sale of these products is affected by the cost of transporting
the products to market. Much of that transportation is through interstate common
carrier pipelines. Effective as of January 1, 1995, the FERC implemented
regulations generally grandfathering all previously approved interstate
transportation rates and establishing an indexing system for those rates by
which adjustments are made annually based on the rate of inflation, subject to
certain conditions and limitations. These regulations may tend to increase the
cost of transporting oil and natural gas liquids by interstate pipeline,
although the annual adjustments may result in decreased rates in a given year.
These regulations have generally been approved on judicial review. Every five
years, the FERC will examine the relationship between the annual change in the
applicable index and the actual cost changes experienced in the oil pipeline
industry. The first such review is scheduled for this year (2000), but any
changes made would not take effect until July 2001. Santa Fe is not able to
predict with certainty what effect, if any these relatively new federal
regulations will have on it.
STATE REGULATION. Many state jurisdictions have at times imposed
limitations on the production of gas premised on conservation concerns and the
protection of correlative rights by such methods as restricting the rate of flow
for gas wells below their actual capacity to produce and by imposing acreage
limitations for the drilling of a well. States may also impose additional
regulation of these matters. Most states regulate the production and sale of oil
and gas, including requirements for obtaining drilling permits, the method of
developing new fields, provisions for the unitization or pooling of oil and gas
properties, the spacing, operation, plugging and abandonment of wells and the
prevention of waste of oil and gas resources. The rate of production may be
regulated and the maximum daily production allowable from oil and gas wells may
be established on a market demand or conservation basis or both.
ENVIRONMENTAL REGULATION
GENERAL. Activities on the Royalty Properties are subject to existing
Federal, state and local laws and regulations governing environmental quality
and pollution control. Santa Fe cannot predict what effect this or additional
regulation or legislation, enforcement policies thereunder, and claims for
damages to property, employees, other persons and the environment resulting from
operations on the
26
<PAGE>
Royalty Properties could have on the Trust. Environmental matters have an effect
on the Trust only to the extent of revenues attributable to the Trust's
interests in the Royalty Properties.
SOLID AND HAZARDOUS WASTE. The Royalty Properties include numerous
properties that have produced oil and gas for many years and hydrocarbons or
other solid wastes may have been disposed or released on or under the Royalty
Properties. State and Federal laws applicable to oil and gas wastes and
properties have become increasingly more stringent. Under these new laws, Santa
Fe or an operator of the Royalty Properties could be required to remove or
remediate previously disposed wastes or property contamination (including
groundwater contamination) or to perform remedial plugging operations to prevent
future contamination.
The operators of the Royalty Properties may generate wastes that are
subject to the Federal Resource Conservation and Recovery Act and comparable
state statutes. The Environmental Protection Agency (EPA) has limited the
disposal options for certain hazardous wastes and is considering the adoption of
more stringent disposal standards for nonhazardous wastes. Furthermore, it is
anticipated that additional wastes (which could include certain wastes generated
by oil and gas operations) will be designated as "hazardous wastes", which are
subject to more rigorous and costly disposal requirements.
SUPERFUND. The Comprehensive Environmental Response, Compensation and
Liability Act ("CERCLA"), also known as the "superfund" law, imposes
liability, without regard to fault or the legality of the original conduct, on
certain classes of persons that contributed to the release of a "hazardous
substance" into the environment. These persons include the owner and operator
of a site and companies that disposed or arranged for the disposal of the
hazardous substance found at a site. CERCLA also authorizes the EPA and, in some
cases, third parties to take actions in response to threats to the public health
or the environment and to seek to recover from the responsible classes of
persons the costs of such action. In the course of their operations, the
operators of the Royalty Properties have generated and will generate wastes that
may fall within CERCLA's definition of "hazardous substances." Santa Fe or the
operators of the Royalty Properties may be responsible under CERCLA for all or
part of the costs to clean up sites at which such wastes have been disposed.
AIR EMISSIONS. The operators of the Royalty Properties are subject to
Federal, state and local regulations concerning the control of emissions from
sources of air pollution. Administrative enforcement actions for failure to
comply strictly with air regulations or permits are generally resolved by
payment of a monetary penalty and correction of any identified deficiencies.
Alternatively, regulatory agencies could require the operators to forego
construction or operation of certain air pollution emission sources.
OSHA. The operators of the Royalty Properties are subject to the
requirements of the Federal Occupational Safety and Health Act ("OSHA") and
comparable state statutes. The OSHA hazard communication standard, the EPA
community right-to-know regulations under Title III of the Federal Superfund
Amendment and Reauthorization Act and similar state statutes require an operator
to organize information about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state and
local government authorities and local citizens.
ITEM 2. PROPERTIES.
Reference is made to Item 1 of this Form 10-K.
ITEM 3. LEGAL PROCEEDINGS.
The Royalty Properties related to the Trust are the subject of lawsuits and
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of lawsuits or other proceedings involving the
Royalty Properties cannot be predicted with certainty, these matters are not
expected to have a material adverse effect on the financial position or cash
proceeds and distributable cash of the Trust.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
There were no matters submitted to a vote of security holders during the
year ended December 31, 1999.
27
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED HOLDER MATTERS.
The Depositary Units are traded on the New York Stock Exchange -- ticker
symbol SFF. The high and low closing sales prices and distributions for each
quarter in the years ended December 31, 1998 and 1999 were as follows (in
dollars):
CLOSING SALES
PRICES
----------------- DISTRIBUTION
LOW HIGH PAID
--------- ------- ------------
1998
First Quarter...................... 20 1/16 21 $0.48539
Second Quarter..................... 19 1/8 20 7/16 0.43820
Third Quarter...................... 17 13/16 20 3/16 0.40009
Fourth Quarter..................... 17 1/4 19 7/16 0.40000
1999
First Quarter...................... $16 1/2 $17 15/16 $0.40000
Second Quarter..................... 16 7/8 18 1/4 0.40000
Third Quarter...................... 17 1/2 18 7/16 0.40000
Fourth Quarter..................... 16 5/8 17 7/8 0.46689
At March 1, 2000, the 6,300,000 Depositary Units outstanding were held by
287 holders of record.
ITEM 6. SELECTED FINANCIAL DATA.
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
(THOUSANDS, EXCEPT PER UNIT DATA)
Period Ended December 31,:
Distributable Cash................. $ 10,501 $ 10,859 $ 12,354 $ 11,063 $ 10,080
Distributable Cash per Trust
Unit............................ 1.66689 1.72368 1.96096 1.75610 1.60000
At December 31,:
Investment in Royalty Interests,
net............................. $ 26,387 $ 32,218 $ 39,874 $ 48,274 $ 57,675
Trust Corpus....................... 26,446 32,280 40,051 48,420 57,654
</TABLE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
GENERAL; LIQUIDITY AND CAPITAL RESOURCES
Santa Fe Energy Trust (the "Trust") was formed on October 22, 1992 with
Chase Bank of Texas, National Association, formerly Texas Commerce Bank,
National Association as trustee (the "Trustee"), to acquire and hold certain
royalty interests (the "Royalty Interests") in certain properties (the
"Royalty Properties") conveyed to the Trust by Santa Fe Snyder Corporation,
formerly Santa Fe Energy Resources, Inc. ("Santa Fe"). The Trust is a passive
entity with the Trustee's primary responsibility being the collection and
distribution of proceeds from the Royalty Interests and the payment of Trust
liabilities and expenses (see Note 1 to the financial statements of the Trust).
The Royalty Interests consist of two term royalty interests in two production
units (the Wasson ODC Unit and the Wasson Willard Unit) in the Wasson field in
west Texas (the "Wasson Royalties") and a net profits royalty interest (the
"Net Profits Royalties") in certain royalty and working interest properties in
a diversified portfolio of properties located predominantly in Texas, Louisiana
and Oklahoma (the "Net Profits Properties"). Under the terms of the Trust
Agreement, the Trustee cannot engage in any other business or commercial
activity or acquire any asset other than the Royalty Interests initially
conveyed to the Trust. Therefore, the Royalty Interests are the sole source of
funds for the Trust from which to pay expenses and liabilities and make
distributions to the holders of the Trust Units. The Trust will be liquidated on
or before February 15, 2008 (the "Liquidation Date").
The Wasson Royalties are fixed percentage royalty interests in specified
levels of quarterly maximum production from the underlying properties in each
year during the term of the respective royalty. The Wasson ODC Royalty and the
Wasson Willard Royalty terminate on December 31, 2007 and December 31, 2003,
respectively. The Net Profits Royalties are life-of-property interests which
28
<PAGE>
will be sold by the Trust prior to the Liquidation Date. The Net Profits
Royalties entitle the Trust to receive 90% of the net proceeds (after deducting,
among other things, the costs of production and marketing and capital
expenditures) from the sale of production from the Net Profits Properties. The
Net Profits Properties are generally mature producing oil and gas properties and
the production and reserves attributable to such properties are expected to
decline substantially over the life of the Trust. The Net Profits Royalties are
expected to have a relatively small liquidation value at the Liquidation Date.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments ("Support Payments") to the extent it
needs such payments to distribute $0.39 per Trust Unit per quarter. Effective
July 1, 1999 and as required by the Trust Agreement, the Trust released its Net
Profits Royalty interest in the Jeffress field in connection with the sale by
Santa Fe of the underlying Net Profits Property. The Trust received 90% of the
net proceeds from this sale in the fourth quarter 1999 distribution. As a result
of this sale, there was a proportionate reduction of the Minimum Quarterly
Royalty from $0.40 per Depositary Unit to $0.39 per Depositary Unit, a
proportionate reduction of the Aggregate Support Payment Limitation Amount from
$20.0 million to $19.4 million and a proportionate reduction in the distribution
per Depositary Unit over which Santa Fe is entitled to recoup Support Payments
from $0.45 per Depositary Unit to $0.44 per Depositary Unit. Such Support
Payments are limited to Santa Fe's remaining royalty interest in the Wasson ODC
Unit. If Support Payments are received, certain proceeds otherwise payable to
the Trust in subsequent quarters may be reduced to recoup the amount of such
Support Payments. The aggregate amount of Support Payments, net of any amounts
recouped, is limited to $19.4 million on a revolving basis. From inception
through the end of 1999, the Trust received Support Payments totalling $4.2
million. During 1996, the first six months of 1997, and the fourth quarter of
1999, Santa Fe recouped $3.9 million of such payments. In the first quarter of
2000, Santa Fe recouped the remaining Support Payment balance of $274,000.
Future recoupments will be made only to the extent of future support payments.
Depending on factors such as sales prices and volumes and the level of operating
costs and capital expenditures, Support Payments may be required in subsequent
quarters to allow the Trust to make distributions of $0.39 per Trust Unit per
quarter.
Trust expenses include accounting, engineering, legal and other
professional fees, Trustee fees, an administrative fee paid to Santa Fe and
other out-of-pocket expenses. From time to time Santa Fe may, at its sole
discretion and without any obligation to do so, advance funds to the Trust for
the timely payment of such expenses and receive reimbursement therefor in later
periods. In addition, the Trustee is authorized to borrow funds required to pay
liabilities of the Trust, provided that such borrowings are repaid in full prior
to making further distributions to the holders of the Trust Units. Currently
there are no such borrowings outstanding or contemplated other than the
above-described advances which Santa Fe has made or may make.
The Trust's results of operations are dependent upon the sales prices and
quantities of oil and gas produced from the Royalty Properties, the costs of
producing such resources and the amount of capital expenditures made with
respect to such properties. Royalty income is recorded by the Trust when
received, generally during the quarter following the end of the quarter in which
revenues are received and costs and expenses are paid by Santa Fe. Cash proceeds
from the Royalty Properties may fluctuate from quarter to quarter due to the
timing of receipts and payments of revenues and expenses as well as changes in
prices and production volumes. In addition, amounts for future exploration and
development costs may be reserved from time to time.
Since, on an equivalent basis, the majority of the Trust's proved reserves
are crude oil, even relatively modest changes in crude oil prices may
significantly affect the Trust's revenues and results of operations. Crude oil
prices are subject to significant changes in response to fluctuations in the
domestic and world supply and demand and other market conditions as well as the
world political situation as it affects OPEC and other producing countries. In
addition, a substantial portion of the Trust's revenues come from properties
which produce sour (i.e., high sulfur content) crude oil which sells at prices
lower than sweeter (i.e., low sulfur content) crude oils. The Trust's weighted
average crude oil sales price (excluding the effect of Support Payments and
recoupments) for 1999 was $13.47 compared with $13.93 for 1998 (see Results of
Operations).
29
<PAGE>
Natural gas prices fluctuate due to weather conditions, the level of
natural gas in storage, the relative balance between supply and demand and other
economic factors. The Trust's weighted average price for natural gas in 1999 was
$1.89 per Mcf, compared with the $2.37 per Mcf received in 1998.
RESULTS OF OPERATIONS
Royalty income is recorded by the Trust when received, generally during the
quarter following the end of the quarter in which revenues are received and
costs and expenses are paid by Santa Fe. Cash proceeds from the Royalty
Properties may fluctuate from quarter to quarter due to the timing of receipts
and payments of revenues and costs and expenses as well as changes in prices and
production volumes. The following table reflects pertinent information with
respect to the cash proceeds from the Royalty Properties and the net
distributable cash of the Trust. The information presented with respect to the
first quarter of 2000 reflects revenues received and costs and expenses paid by
Santa Fe in the fourth quarter of 1999. In the first quarter of 2000 the Trust
received a payment of $3,461,875 and on February 29, 2000 made a cash
distribution of $3,361,875, or $.53 per Trust Unit, to unitholders of record on
February 14, 2000.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, FIRST
---------------------------------------- QUARTER
1999 1998 1997 2000
------------ ------------ ------------ -----------
(UNAUDITED)
<S> <C> <C> <C> <C>
VOLUMES AND PRICES
Oil Volumes (Bbls)
Wasson ODC Royalty.............. 274,400 264,500 265,000 69,500
Wasson Willard Royalty.......... 110,000 120,800 125,700 26,700
Net Profits Royalties........... 245,509 265,420 301,218 56,763
Support Payments................ 165,301 7,709 -- --
Gas Volumes (Mcf):
Net Profits Royalties........... 2,265,233 2,886,839 2,495,347 465,740
Oil Average Prices ($/Bbl) per unit
data
Wasson ODC Royalty.............. $ 14.65 $ 14.08 $ 19.60 $ 23.26
Wasson Willard Royalty.......... 14.45 14.12 19.65 23.20
Net Profits Royalties........... 11.72 13.68 18.69 19.16
Support Payments................ 12.17 12.18 -- --
Gas Average Prices ($/Mcf):
Net Profits Royalties........... 1.89 2.37 2.36 2.51
CASH PROCEEDS AND DISTRIBUTABLE CASH
(IN THOUSANDS OF DOLLARS, EXCEPT AS
NOTED)
Wasson ODC Royalty:
Sales........................... $ 4,021 $ 3,726 $ 5,195 $ 1,617
Operating Expenses.............. (358) (315) (536) (119)
------------ ------------ ------------ -----------
3,663 3,411 4,659 1,498
------------ ------------ ------------ -----------
Wasson Willard Royalty:
Sales........................... 1,589 1,705 2,469 619
Operating Expenses.............. (115) (107) (212) (43)
------------ ------------ ------------ -----------
1,474 1,598 2,257 576
------------ ------------ ------------ -----------
Net Profits Royalties:
Sales........................... 7,327 10,476 11,601 2,259
Proceeds From the Sale of
Property...................... 1,813 -- -- --
Operating Expenses.............. (2,641) (3,022) (3,346) (375)
Capital Expenditures............ (772) (1,314) (1,226) (160)
------------ ------------ ------------ -----------
5,727 6,140 7,029 1,724
------------ ------------ ------------ -----------
Support Payment (Recoupments)...... 181 94 (1,065) (274)
------------ ------------ ------------ -----------
Total Royalties.................... 11,045 11,243 12,880 3,524
Administrative Fee to Santa Fe..... (244) (234) (226) (62)
------------ ------------ ------------ -----------
Payment Received................... 10,801 11,009 12,654 3,462
Cash Advance From Santa Fe......... -- -- 250 --
Repayment of Cash Advance from
Santa Fe........................ -- -- (150) --
Cash Withheld for Trust Expenses... (300) (150) (400) (100)
------------ ------------ ------------ -----------
Distributable Cash................. $ 10,501 $ 10,859 $ 12,354 $ 3,362
============ ============ ============ ===========
Distributable Cash Per Unit........ $ 1.66689 $ 1.72368 $ 1.96096 $ .53363
============ ============ ============ ===========
</TABLE>
30
<PAGE>
The Trust's weighted average crude oil sales prices were $14.60 per barrel
for the Wasson Royalties and $11.72 per barrel for the Net Profits Royalties in
1999 compared with $14.10 per barrel and $13.68 per barrel, respectively, in
1998. Weighted average crude oil prices in the first quarter of 2000 were $23.24
per barrel for the Wasson Royalties and $19.16 per barrel for the Net Profits
Royalties.
The weighted average natural gas price in 1999 was $1.89 per Mcf compared
with $2.37 per Mcf in 1998. Natural gas sales prices averaged $2.51 per Mcf in
the first quarter of 2000.
Cash proceeds in 1996 and 1997 were reduced by $1,009,000 and $1,065,000,
respectively, as Santa Fe recouped all Support Payments made in prior periods.
Cash proceeds in the fourth quarter of 1998, and the first, second and third
quarters of 1999 included Support Payments of $94,000, $779,000, $691,000 and
$541,000, respectively. Cash proceeds in the fourth quarter of 1999 were reduced
by $1,831,000 as Santa Fe recouped the 1998 Support Payment of $94,000 and
$1,737,000 of the 1999 Support Payments. Cash proceeds in the first quarter 2000
were reduced by $274,000 as Santa Fe recouped the remaining Support Payments.
Proceeds from the Net Profits Royalties are net of capital expenditures
with respect to the exploration and development of the Net Profits Properties.
Capital expenditures for 1999 totalled $772,000 compared to $1,314,000 in 1998.
Capital expenditures are expected to be approximately $425,000 in 2000.
Operating expenses for the Net Profits Royalties averaged $4.24 per barrel of
oil equivalent ("BOE") in 1999 compared to $3.78 per BOE in 1998. Operating
expenses averaged $2.79 per BOE in the first quarter of 2000. Operating expenses
may fluctuate from quarter to quarter due to the timing of payments.
YEAR 2000
Many computer systems were built using software that processes transactions
using two digits to represent the year. This type of software generally required
modifications to function properly with dates after December 31, 1999 (or, to
become "Y2K" compliant). To date, Santa Fe has not encountered any significant
problems and has not experienced any significant problems with unrelated third
party vendors.
FORWARD LOOKING STATEMENTS
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain statements (other than statements of historical
fact) that constitute forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. When used herein, the words "anticipates," "expects," "believes,"
"intends" or "projects" and similar expressions are intended to identify
forward-looking statements. It is important to note that actual results could
differ materially from those projected by such forward-looking statements.
Although it is believed that the expectations reflected in such forward-looking
statements are reasonable and such forward-looking statements are based on the
best data available at the time this report is filed with the Securities and
Exchange Commission, no assurance can be given that such expectations will prove
correct. Factors that could cause results to differ materially from the results
discussed in such forward-looking statements include, but are not limited to,
the following: production variances from expectations, volatility of oil and gas
prices, the need to develop and replace reserves, the capital expenditures
required to fund operations, environmental risks, uncertainties about estimates
of reserves, completion and government regulation and political risks. All such
forward-looking statements in this document are expressly qualified in their
entirety by the cautionary statements in this paragraph.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
DISCLOSURES ABOUT MARKET RISK
Production attributable to Santa Fe's royalty interest in the Wasson ODC
Unit and the Wasson Willard Unit is marketed by Santa Fe and is in some cases
sold at the wellhead at market responsive prices and in other cases is traded at
points within common carrier pipeline systems.
31
<PAGE>
With regard to the Net Profits Properties, where such properties consist of
royalty interests, the operators of the properties will make all decisions
regarding the marketing and sale of oil and gas production. The ability of the
operators to market the oil and gas produced from the Royalty Properties will
depend upon numerous factors beyond their control, including the proximity of
the gas production to gas pipelines, the availability of capacity in such
pipelines, state and Federal regulation of oil and gas production and Federal
regulation of gas sold or transported in interstate commerce. There is no
assurance that such operators will be able to market all of the oil or gas
produced from the Royalty Properties or that favorable prices can be obtained
for the oil and gas produced.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
See Item 14 on page 33 herein for the Exhibits, Financial Statement
Schedules, Supplementary Data and reports on Form 8-K.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
There are no directors or executive officers of the Registrant. The Trustee
is a corporate trustee which may be removed by the affirmative vote of Holders
of a majority of the Trust Units then outstanding at a meeting of the Holders of
the Trust at which a quorum is present.
ITEM 11. EXECUTIVE COMPENSATION.
Not applicable.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Security Ownership of Certain Beneficial Owners.
Not Applicable.
(b) Security Ownership of Management.
Not applicable.
(c) Changes in Control.
The Registrant knows of no arrangements, including the pledge of securities
of the Registrant, the operation of which may at a subsequent date result in a
change in control of the Registrant.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None
32
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(A)(1) FINANCIAL STATEMENTS
The following financial statements are included in this Annual Report on
Form 10-K on the pages as indicated:
PAGE IN
THIS
FORM 10-K
---------
Audited Financial Statements
Report of Independent Accountants......................... 34
Statement of Cash Proceeds and Distributable Cash for the
Years Ended December 31, 1999, 1998 and 1997............ 35
Statement of Assets and Trust Corpus as of December 31,
1999 and 1998........................................... 35
Statement of Changes in Trust Corpus for the Years Ended
December 31, 1999, 1998 and 1997........................ 36
Notes to Financial Statements............................. 37
Unaudited Financial Information
Supplemental Information to the Financial Statements...... 40
(A)(2) SCHEDULES
Schedules have been omitted because they are not required, not applicable
or the information required has been included elsewhere herein.
(A)(3) EXHIBITS
(Asterisk indicates exhibit previously filed with the Securities and
Exchange Commission and incorporated herein by reference.)
SEC FILE OR
REGISTRATION EXHIBIT
NUMBER NUMBER
------------- -------
3(a)* Form of Trust Agreement of Santa Fe
Energy Trust........................... 33-51760 3.1
4(a)* Form of Custodial Deposit
Agreement.............................. 33-51760 4.2
4(b)* Form of Secure Principal Energy
Receipt (included as
Exhibit A to Exhibit 4(a))............. 33-51760 4.1
10(a)* Form of Net Profits Conveyance
(Multi-State).......................... 33-51760 10.1
10(b)* Form of Wasson Conveyance.............. 33-51760 10.2
10(c)* Form of Louisiana Mortgage............. 33-51760 10.3
27 Financial Data Schedule................ 33-51760 27
(B) REPORTS ON FORM 8-K
None
33
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Trustee and Unitholders
of the Santa Fe Energy Trust
We have audited the financial statements listed in the accompanying index
appearing under Item 14(a)(1) on page 33. These financial statements are the
responsibility of the Trustee. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by the Trustee, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
As described in Note 2, these financial statements have been prepared on the
basis of cash receipts and disbursements, which is a comprehensive basis of
accounting other than accounting standards generally accepted in the United
States.
In our opinion, the financial statements audited by us present fairly, in all
material respects, the financial position of the Santa Fe Energy Trust at
December 31, 1999 and 1998, and the cash proceeds and distributable cash and the
changes in trust corpus for each of the three years in the period ended December
31, 1999, on the basis of accounting described in Note 2.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
February 25, 2000
34
<PAGE>
SANTA FE ENERGY TRUST
STATEMENT OF CASH PROCEEDS AND DISTRIBUTABLE CASH
(IN THOUSANDS, EXCEPT PER UNIT DATA)
YEAR ENDED DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- ----------- -----------
Royalty Income
ODC Royalty........................ $ 3,663 $ 3,411 $ 4,659
Willard Royalty.................... 1,474 1,598 2,257
Net Profits Royalty................ 5,727 6,140 7,029
Support payment (recoupment)....... 181 94 (1,065)
----------- ----------- -----------
Total Royalties......................... 11,045 11,243 12,880
Administrative Fee to Santa Fe Snyder
Corporation........................... (244) (234) (226)
Advance from Santa Fe Snyder
Corporation........................... -- -- 250
Repayment of Advances from Santa Fe
Snyder Corporation.................... -- -- (150)
Cash Withheld for Trust Expenses........ (300) (150) (400)
----------- ----------- -----------
Distributable Cash...................... $ 10,501 $ 10,859 $ 12,354
=========== =========== ===========
Distributable Cash per Trust Unit (in
dollars).............................. $ 1.66689 $ 1.72368 $ 1.96096
=========== =========== ===========
Trust Units Outstanding................. 6,300 6,300 6,300
=========== =========== ===========
STATEMENT OF ASSETS AND TRUST CORPUS
(IN THOUSANDS)
DECEMBER 31,
------------------------
1999 1998
----------- -----------
ASSETS
Current Assets
Cash........................................ $ 59 $ 62
----------- -----------
59 62
----------- -----------
Investment in Royalty Interests, at
cost.......................................... 87,276 87,276
Less: Accumulated Amortization.................. (60,889) (55,058)
----------- -----------
26,387 32,218
----------- -----------
$ 26,446 $ 32,280
=========== ===========
TRUST CORPUS
Trust Corpus, 6,300,000 Trust Units
issued and outstanding........................ $ 26,446 $ 32,280
=========== ===========
The accompanying notes are an integral part
of the financial statements.
35
<PAGE>
SANTA FE ENERGY TRUST
STATEMENT OF CHANGES IN TRUST CORPUS
(IN THOUSANDS)
Balance at December 31, 1996....................... $ 48,420
Cash Proceeds.................................... 12,654
Cash Distributions............................... (12,354)
Trust Expenses................................... (269)
Amortization of Royalty
Interests..................................... (8,400)
-----------
Balance at December 31, 1997....................... 40,051
Cash Proceeds.................................... 11,009
Cash Distributions............................... (10,859)
Trust Expenses................................... (265)
Amortization of Royalty
Interests..................................... (7,656)
-----------
Balance at December 31, 1998....................... 32,280
Cash Proceeds.................................... 10,801
Cash Distributions............................... (10,501)
Trust Expenses................................... (303)
Amortization of Royalty
Interests..................................... (5,831)
-----------
Balance at December 31, 1999....................... $ 26,446
===========
The accompanying notes are an integral part
of the financial statements.
36
<PAGE>
SANTA FE ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS
(1) THE TRUST
Santa Fe Energy Trust (the "Trust") was formed on October 22, 1992, with
Chase Bank of Texas, National Association as trustee (the "Trustee"), to
acquire and hold certain royalty interests (the "Royalty Interests") in
certain properties (the "Royalty Properties") conveyed to the Trust by Santa
Fe Snyder Corporation, formerly Santa Fe Energy Resources, Inc. ("Santa Fe").
The Royalty Interests consist of two term royalty interests in two production
units in the Wasson field in west Texas (the "Wasson Royalties") and a net
profits royalty interest in certain royalty and working interests in a
diversified portfolio of properties located in twelve states (the "Net Profits
Royalties"). The Royalty Interests are passive in nature and the Trustee has no
control over or responsibility relating to the operation of the Royalty
Properties. The Trust will be liquidated on February 15, 2008 (the "Liquidation
Date").
In November 1992, 5,725,000 Depositary Units, each consisting of beneficial
ownership of one unit of undivided beneficial interest in the Trust ("Trust
Units") and a $20 face amount beneficial ownership interest in a $1,000 face
amount zero coupon United States Treasury obligation maturing on or about
February 15, 2008, were sold in a public offering for $20 per Depositary Unit. A
total of $114.5 million was received from public investors, of which $38.7
million was used to purchase the Treasury obligations and $5.7 million was used
to pay underwriting commissions and discounts. Santa Fe received the remaining
$70.1 million and 575,000 Depositary Units. In the first quarter of 1994 Santa
Fe sold in a public offering the 575,000 Depositary Units which it held.
The trust agreement under which the Trust was formed (the "Trust
Agreement") provides, among other things, that:
o the Trustee shall not engage in any business or commercial
activity or acquire any asset other than the Royalty Interests
initially conveyed to the Trust;
o the Trustee may not sell all or any portion of the Wasson
Royalties or substantially all of the Net Profits Royalties
without the prior consent of Santa Fe;
o Santa Fe may sell the Royalty Properties, subject to and burdened
by the Royalty Interests, without consent of the holders of the
Trust Units; following any such transfer, the Royalty Properties
will continue to be burdened by the Royalty Interests and after
any such transfer the royalty payment attributable to the
transferred property will be calculated separately and paid by
the transferee;
o the Trustee may establish a cash reserve for the payment of any
liability which is contingent, uncertain in amount or that is not
currently due and payable;
o the Trustee is authorized to borrow funds required to pay
liabilities of the Trust, provided that such borrowings are
repaid in full prior to further distributions to the holders of
the Trust Units;
o the Trustee will make quarterly cash distributions to the holders
of the Trust Units.
(2) BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the cash basis of
accounting for revenues and expenses. Royalty income is recorded when received
(generally during the quarter following the end of the quarter in which the
income from the Royalty Properties is received by Santa Fe) and is net of any
cash basis exploration and development expenditures and amounts reserved for any
future exploration and development costs. Expenses of the Trust, which will
include accounting, engineering, legal, and other professional fees, Trustee
fees, an administrative fee paid to Santa Fe and out-of-pocket expenses, are
recognized when paid. Under generally accepted accounting principles, revenues
and expenses would be recognized on an accrual basis. Amortization of the
Trust's investment in
37
<PAGE>
SANTA FE ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Royalty Interests is recorded using the unit-of-production method in the period
in which the cash is received with respect to such production; therefore, a
statement of cash flows is not presented.
The conveyance of the Royalty Interests to the Trust was accounted for as a
purchase transaction. The $87,276,000 reflected in the Statement of Assets and
Trust Corpus as Investment in Royalty Interests represents 6,300,000 Trust Units
valued at $20 per unit less the $38,724,000 paid for the Treasury obligations.
The carrying value of the Trust's investment in the Royalty Interests is not
necessarily indicative of the fair value of such Royalty Interests.
The Trust is a grantor trust and as such is not subject to income taxes and
accordingly no recognition has been given to income taxes in the Trust's
financial statements. The tax consequences of owning Trust Units are included in
the income tax returns of the individual Trust Unit holders.
In 1997, Santa Fe advanced the Trust $250,000 to pay Trust expenses. Such
advances were repaid in 1997 and at December 31, 1999 and 1998, respectively, no
advance repayments were due to Santa Fe from the Trust.
The preparation of the Trust's financial statements requires the use of
certain estimates. Actual results may differ from such estimates.
(3) THE ROYALTY INTERESTS
The Wasson Royalties consist of interests conveyed out of Santa Fe's
royalty interest in the Wasson ODC Unit (the "ODC Royalty") and the Wasson
Willard Unit (the "Willard Royalty"). The ODC Royalty entitles the Trust to
receive quarterly royalty payments with respect to 12.3934% of the actual gross
oil production from the Wasson ODC Unit, subject to certain quarterly
limitations set forth in the conveyance agreement, for the period from November
1, 1992 to December 31, 2007. The Willard Royalty entitles the Trust to receive
quarterly royalty payments with respect to 6.8355% of the actual gross oil
production from the Wasson Willard Unit, subject to certain quarterly
limitations set forth in the conveyance agreement, for the period from November
1, 1992 to December 31, 2003.
The Net Profits Royalties entitle the Trust to receive, on a quarterly
basis, 90% of the net proceeds, as defined in the conveyance agreement, from the
sale of production from the properties subject to the conveyance agreement. The
Net Profits Royalties are not limited in term, although the Trustee is required
to sell such royalties prior to the Liquidation Date.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments ("Support Payments") from Santa Fe to
the extent it needs such payments to distribute $0.39 per Trust Unit per
quarter. Effective July 1, 1999 and as required by the Trust Agreement, the
Trust released its Net Profits Royalty interest in the Jeffress field in
connection with the sale by Santa Fe of the underlying Net Profits Property. The
Trust received 90% of the net proceeds from this sale in the fourth quarter 1999
distribution. As a result of this sale, there was a proportionate reduction of
the Minimum Quarterly Royalty from $0.40 per Depositary Unit to $0.39 per
Depositary Unit, a proportionate reduction of the Aggregate Support Payment
Limitation Amount from $20.0 million to $19.4 million and a proportionate
reduction in the distribution per Depositary Unit over which Santa Fe is
entitled to recoup Support Payments from $0.45 per Depositary Unit to $0.44 per
Depositary Unit. Such Support Payments are limited to Santa Fe's remaining
royalty interest in the Wasson ODC Unit. If such Support Payments are received,
certain proceeds otherwise payable to the Trust in subsequent quarters may be
reduced to recoup the amount of such Support Payments. The aggregate of the
Support Payments, net of any amounts recouped, will be limited to $19,400,000 on
a revolving basis. From inception through the end of 1999 the Trust received
Support Payments totalling $4,179,000. During 1996, the first six months of 1997
and the fourth quarter of 1999, Santa Fe recouped $3,905,000 of such payments.
In the first quarter of 2000, Santa Fe recouped the remaining
38
<PAGE>
SANTA FE ENERGY TRUST
NOTES TO FINANCIAL STATEMENTS -- (CONTINUED)
Support Payment balance of $274,000. Future recoupment will be made only to the
extent of future Support Payments.
(4) DISTRIBUTIONS TO TRUST UNIT HOLDERS
The Trust has received royalty payments net of administrative fees paid to
Santa Fe and made distributions as follows:
ROYALTY DISTRIBUTIONS
PAYMENT -------------------------
RECEIVED AMOUNT PER TRUST UNIT
-------- ------- --------------
(IN THOUSANDS, EXCEPT PER UNIT DATA)
1999
First quarter................... $ 2,520(a) $ 2,520 $0.40000
Second quarter.................. 2,695(b) 2,520 0.40000
Third quarter................... 2,570(c) 2,520 0.40000
Fourth quarter.................. 3,016(d) 2,941 0.46689
-------- ------- --------------
10,801 10,501 1.66689
======== ======= ==============
1998
First quarter................... $ 3,108 $ 3,058 $0.48539
Second quarter.................. 2,861 2,761 0.43820
Third quarter................... 2,520 2,520 0.40009
Fourth quarter.................. 2,520(e) 2,520 0.40000
-------- ------- --------------
11,009 10,859 1.72368
======== ======= ==============
1997
First quarter................... $ 2,985(f) $ 2,835 $0.45000
Second quarter.................. 3,881(g) 3,831 0.60812
Third quarter................... 2,870 2,820 0.44757
Fourth quarter.................. 2,918 2,868 0.45527
-------- ------- --------------
12,654 12,354 1.96096
======== ======= ==============
- - ------------
(a) Includes Support Payment of $779,000, or $0.12363 per Trust Unit.
(b) Includes Support Payment of $691,000, or $0.10981 per Trust Unit.
(c) Includes Support Payment of $541,000, or $0.08583 per Trust Unit.
(d) Reduced by recoupment of Support Payment of $1,831,000, or $0.29071 per
Trust Unit.
(e) Includes Support Payment of $94,000, or $0.014904 per Trust Unit.
(f) Reduced by recoupment of Support Payment of $912,000, or $0.14473 per Trust
Unit.
(g) Reduced by recoupment of Support Payment of $153,000, or $0.02429 per Trust
Unit.
(5) COMMITMENTS AND CONTINGENCIES
The Royalty Properties related to the Trust are the subject of lawsuits and
governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of lawsuits or other proceedings involving the
Royalty Properties cannot be predicted with certainty, these matters are not
expected to have a material adverse effect on the financial position or cash
proceeds and distributable cash of the Trust.
39
<PAGE>
SUPPLEMENTAL INFORMATION TO FINANCIAL STATEMENTS (UNAUDITED)
OIL AND GAS RESERVES
The following table sets forth the Royalty Interests' proved oil and gas
reserves (all located in the United States) at December 31, 1999, 1998, 1997 and
1996 prepared by Ryder Scott Company, independent petroleum consultants. Proved
reserve quantities for each of the Wasson Royalties are calculated by
multiplying the net revenue interest attributable to each of the Wasson
Royalties in effect for a given year by the total amount of oil estimated to be
economically recoverable from the respective production units, subject to
quarterly production limitations and additional "Support Payments." The volume
of reserves attributable to the Support Payments is calculated assuming an
additional royalty interest in the Wasson ODC property. Reserve quantities are
calculated differently for the Net Profits Royalties because such interests do
not entitle the Trust to a specific quantity of oil or gas but to the Net
Proceeds derived therefrom. Proved reserves attributable to the Net Profits
Royalties are calculated by deducting from estimated quantities of oil and gas
reserves an amount of oil and gas sufficient, if sold at the prices used in
preparing the reserve estimates for the Net Profits Royalties, to pay the future
estimated costs and expenses deducted in the calculation of Net Proceeds with
respect to the Net Profits Royalties. Accordingly, the reserves presented for
the Net Profits Royalties reflect quantities of oil and gas that are free of
future costs or expenses if the price and cost assumptions set forth in the
applicable reserve report occur.
The following estimates of proved and proved developed reserve quantities
and related standardized measure of discounted net cash flows are estimates
only, and do not purport to reflect realizable values or fair market values of
the Trust's reserves. It is emphasized that reserve estimates are inherently
imprecise and that estimates of new discoveries are more imprecise than those of
producing oil and gas properties. Accordingly, these estimates are expected to
change as future information becomes available.
CRUDE OIL AND NATURAL GAS
LIQUIDS (MBBLS) (MMCF)
--------------- -----------
(UNAUDITED)
Proved reserves at December 31, 1996 ................ 4,875 8,908
Revisions of previous estimates ................ 598 (952)
Extensions, discoveries
and additions ............................... 23 1,463
Production ..................................... (678) (2,675)
------ ------
Proved reserves at December 31, 1997 ................ 4,818 6,744
Revisions of previous estimates ................ 1,148 2,780
Extensions, discoveries
and additions ............................... 9 487
Production ..................................... (723) (2,644)
------ ------
Proved reserves at December 31, 1998 ................ 5,252 7,367
Revision of previous estimates ................. (1,085) 2,062
Sales of minerals-in-place ..................... (18) (833)
Extensions, discoveries
and additions ............................... 0 0
Production ..................................... (718) (2,160)
------ ------
Proved reserves at December 31, 1999 ................ 3,431 6,436
====== ======
Proved developed reserves at December 31,
1996 ........................................... 4,875 8,908
1997 ........................................... 4,816 6,655
1998 ........................................... 5,252 7,367
1999 ........................................... 3,431 6,436
Proved reserves are estimated quantities of crude oil and natural gas which
geological and engineering data indicate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions. Proved developed reserves are proved reserves which can be
expected to be recovered through existing wells with existing equipment and
operating methods.
40
<PAGE>
The information presented relates to the operations of the Royalty
Properties for the calendar years ended December 31, 1999, 1998 and 1997.
Proceeds from the sales of production were received by the Trust during the
second, third and fourth quarters of the year indicated and the first quarter of
the subsequent year.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES
The standardized measure of discounted future net cash flows is computed by
applying year-end prices of oil and gas (with consideration of price changes
only to the extent provided by contractual arrangements) to the estimated future
production of proved oil and gas reserves, less estimated future expenditures
(based on year-end costs) to be incurred in developing and producing the proved
reserves and assuming continuation of existing economic conditions. The
estimated future net cash flows are then discounted using a rate of 10 percent a
year to reflect the estimated timing of the future cash flows.
Estimated future cash flows represent an estimate of future net revenues
from the production of proved reserves using estimated sales prices and
estimates of the production costs, ad valorem and production taxes, and future
development costs necessary to produce such reserves. No deduction has been made
for depletion, depreciation or any indirect costs such as professional and
administrative fees.
The sales prices used in the calculation of estimated future net cash flows
are based on the prices in effect at year end with consideration of price
changes only to the extent provided by contractural arrangements in existence at
year-end.
Operating costs and ad valorem and production taxes are estimated based on
current costs with respect to producing oil and gas properties. Future
development costs are based on the best estimate of such costs assuming current
economic and operating conditions.
The information presented with respect to estimated future net revenues and
cash flows and the present value thereof is not intended to represent the fair
value of oil and gas reserves. Actual future sales prices and production and
development costs may vary significantly from those in effect at December 31,
1999, 1998 and 1997 and actual future production may not occur in the periods or
amounts projected. This information is presented to allow a reasonable
comparison of reserve values prepared using standardized measurement criteria
and should be used only for that purpose.
The standardized measure of discounted future net cash flows from the
Royalty Interests' proved oil and gas reserve quantities at December 31, 1999,
1998 and 1997 are presented in the following table (in thousands of dollars):
DECEMBER 31,
-------------------------------------
1999 1998 1997
----------- ----------- -----------
(UNAUDITED)
Net future cash flows................ 89,421 61,153 87,909
Discount at 10% for timing of cash
flows.............................. (28,785) (18,701) (30,143)
----------- ----------- -----------
Standardized measure of discounted
future net cash flows for proved
reserves........................... 60,636 42,452 57,766
=========== =========== ===========
As of December 31, 1999 total estimated future net cash flows available for
Support Payments were approximately $22.3 million.
41
<PAGE>
The following table sets forth the changes in the standardized measure of
discounted future net cash flows from proved reserves (in thousands of dollars):
1999 1998 1997
----------- ----------- -----------
(UNAUDITED)
Balance at beginning of year......... 42,452 57,766 92,170
----------- ----------- -----------
Production, net of related
property taxes(a)............ (12,852) (11,369) (15,077)
Extensions, discoveries and
other additions.............. 0 984 3,359
Sales of minerals-in-place...... (1,735) 0 0
Net changes in prices and
costs........................ 49,405 (20,540) (37,442)
Revisions of previous
estimates.................... (20,455) 10,181 6,382
Interest factor -- accretion of
discount..................... 3,821 5,430 8,374
----------- ----------- -----------
18,184 (15,314) (34,404)
----------- ----------- -----------
Balance at end of year............... 60,636 42,452 57,766
=========== =========== ===========
- - ------------
(a) Relates to the operations of the Royalty Properties for the calendar years
ended December 31, 1999, 1998 and 1997. The proceeds related to such
operations were received by the Trust during the second, third and fourth
quarters of the year indicated and the first quarter of the subsequent year.
42
<PAGE>
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED ON THIS 13TH DAY OF
MARCH, 2000.
SANTA FE ENERGY TRUST
By CHASE BANK OF TEXAS, NATIONAL
ASSOCIATION, TRUSTEE
By /s/ PETE FOSTER
PETE FOSTER
SENIOR VICE PRESIDENT
& TRUST OFFICER
The Registrant, Santa Fe Energy Trust, has no principal executive officer,
principal financial officer, controller or principal accounting officer, board
of directors or persons performing similar functions. Accordingly, no additional
signatures are available and none have been provided.
43
<PAGE>
THIS ANNUAL REPORT ON FORM 10-K WAS DISTRIBUTED TO HOLDERS AS AN ANNUAL
REPORT. ADDITIONAL COPIES OF THIS ANNUAL REPORT WILL BE PROVIDED, WITHOUT
CHARGE, AND COPIES OF EXHIBITS HERETO WILL BE PROVIDED, UPON PAYMENT OF A
REASONABLE FEE, UPON WRITTEN REQUEST FROM ANY HOLDER TO:
Santa Fe Energy Trust
Chase Bank of Texas, National Association, Trustee
Attention: Letha Glover, Global Trust Services
P.O. Box 4717
Houston, Texas 77210-4717
<TABLE>
<S> <C> <C>
INDEPENDENT ACCOUNTANTS COUNSEL TRANSFER AGENT AND REGISTRAR
PricewaterhouseCoopers LLP Baker & Botts, L.L.P. Chase Bank of Texas, N.A.
Houston, Texas Houston, Texas Houston, Texas
</TABLE>
SANTA FE ENERGY TRUST
P.O. Box 4717
Houston, Texas 77210-4717
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THE FINANCIAL DATA SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED
FROM THE THE TRUSTS FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 59
<SECURITIES> 0
<RECEIVABLES> 0
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 59
<PP&E> 87,276
<DEPRECIATION> 60,889
<TOTAL-ASSETS> 26,446
<CURRENT-LIABILITIES> 0
<BONDS> 0
0
0
<COMMON> 0
<OTHER-SE> 26,446
<TOTAL-LIABILITY-AND-EQUITY> 26,446
<SALES> 0
<TOTAL-REVENUES> 11,045
<CGS> 0
<TOTAL-COSTS> 0
<OTHER-EXPENSES> 544
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 0
<INCOME-PRETAX> 0
<INCOME-TAX> 0
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 10,501
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
