<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON APRIL 26, 1994
REGISTRATION NO. 33-52849
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------------------
Amendment No. 1
to
FORM S-3
REGISTRATION STATEMENT
UNDER THE
SECURITIES ACT OF 1933
------------------------------------
SANTA FE ENERGY RESOURCES, INC.
(Exact name of Registrant as specified in charter)
<TABLE>
<S> <C>
DELAWARE 36-2722169
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
</TABLE>
1616 SOUTH VOSS ROAD, SUITE 1000, HOUSTON, TEXAS 77057 (713) 783-2401
(Address, including zip code, and telephone number, including area code, of
Registrant's principal executive offices)
DAVID L. HICKS, 1616 SOUTH VOSS ROAD, SUITE 1000, HOUSTON, TEXAS 77057
(713) 783-2401
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
------------------------------------------------------
COPIES TO:
<TABLE>
<S> <C>
G. Michael O'Leary Marc S. Rosenberg
or Robert V. Jewell Cravath, Swaine & Moore
Andrews & Kurth L.L.P. Worldwide Plaza
4200 Texas Commerce Tower 825 Eighth Avenue
Houston, Texas 77002 New York, New York 10019
(713) 220-4200 (212) 474-1000
</TABLE>
------------------------------------------------------
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. / /
If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. / /
------------------------------------------------------
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(A),
MAY DETERMINE.
<PAGE> 2
EXPLANATORY NOTE
This Registration Statement contains two forms of Prospectus: one to be
used in connection with the offering of Senior Subordinated Debentures Due 2004
(the "Debenture Offering Prospectus") and the other to be used in connection
with a concurrent offering of Series A Convertible Preferred Stock (the
"Preferred Stock Offering Prospectus"). The closing of the offering being made
pursuant to the Debenture Offering Prospectus (the "Debenture Offering") is not
conditioned on the closing of the offering being made pursuant to the Preferred
Stock Offering Prospectus (the "Preferred Stock Offering"), and the closing of
the Preferred Stock Offering is not conditioned on the closing of the Debenture
Offering. The form of Debenture Offering Prospectus immediately follows this
page and is followed by the form of Preferred Stock Offering Prospectus.
<PAGE> 3
****************************************************************************
* INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. *
* A REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED *
* WITH THE SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY *
* NOT BE SOLD NOR MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE *
* REGISTRATION STATEMENT BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT *
* CONSTITUTE AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY *
* NOR SHALL THERE BE ANY SALE OF THESE SECURITIES IN ANY STATE IN *
* WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE UNLAWFUL PRIOR TO *
* REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS OF ANY *
* SUCH STATE. *
****************************************************************************
SUBJECT TO COMPLETION
APRIL 26, 1994
PROSPECTUS
$100,000,000
SANTA FE ENERGY RESOURCES, INC.
% SENIOR SUBORDINATED DEBENTURES DUE 2004
The % Senior Subordinated Debentures Due 2004 (the "Debentures") of Santa
Fe Energy Resources, Inc. (the "Company") are being offered (the "Offering") by
the Company. The Debentures will mature on , 2004. Interest on the
Debentures will be payable semi-annually on and of each
year, beginning on , 1994. The Debentures are not redeemable prior to
, 1999. At any time on or after , 1999, the Debentures are
redeemable at the option of the Company, in whole at any time or from time to
time in part, at the redemption prices set forth herein plus accrued and unpaid
interest, if any, to the date of redemption. See "Description of the
Debentures--Optional Redemption." The holders of the Debentures may require the
Company to purchase the Debentures, in whole or in part, upon the occurrence of
a Change of Control (as defined) and a subsequent Rating Decline (as defined) at
a purchase price equal to 101% of the principal amount thereof, plus accrued and
unpaid interest thereon, if any, to the date of purchase. See "Description of
the Debentures--Mandatory Repurchase upon Change of Control and Subsequent
Rating Decline."
The offering made hereby is part of a refinancing by the Company, consisting of
this Offering and a concurrent offering (the "Concurrent DECS Offering") of
10,700,000 shares of Dividend Enhanced Convertible StockSM--DECSSM (the "DECS").
This Offering is not conditioned on the Concurrent DECS Offering, and the
Concurrent DECS Offering is not conditioned on this Offering.
The Debentures will be general unsecured senior subordinated obligations of the
Company. The Debentures will rank subordinate in right of payment to all
existing and future Senior Indebtedness (as defined), pari passu with any future
senior subordinated indebtedness and senior to any future junior subordinated
indebtedness of the Company. After adjustment for application of the net
proceeds of this Offering and the Concurrent DECS Offering, Senior Indebtedness
at December 31, 1993 would have been $289.4 million. The Debentures will be
structurally subordinated to all liabilities of the Company's subsidiaries,
which would have totaled $58.8 million at December 31, 1993 after giving effect
to the application of the net proceeds from this Offering and the Concurrent
DECS Offering. See "Use of Proceeds."
The Company does not intend to list the Debentures on any securities exchange.
No assurance can be given that any market for the Debentures will develop or, if
such market develops, as to the liquidity of such market. See "Investment
Considerations--Absence of a Previous Market for the Debentures."
SEE "INVESTMENT CONSIDERATIONS" FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD
BE CONSIDERED BY PROSPECTIVE INVESTORS BEFORE DECIDING TO INVEST IN THE
DEBENTURES.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC(1) DISCOUNT COMPANY(1)(2)
<S> <C> <C> <C>
Per Debenture....................... % % %
Total............................... $ $ $
</TABLE>
- --------------------------------------------------------------------------------
(1) Plus accrued interest, if any, from May , 1994 to the date of delivery.
(2) Before deducting expenses payable by the Company estimated to be $500,000.
The Debentures are offered subject to receipt and acceptance by the
Underwriters, to prior sale and to the Underwriters' right to reject any order
in whole or in part and to withdraw, cancel or modify the offer without notice.
It is expected that delivery of the Debentures will be made at the office of
Salomon Brothers Inc, Seven World Trade Center, New York, New York, or through
the facilities of The Depository Trust Company, on or about May , 1994.
SALOMON BROTHERS INC
DILLON, READ & CO. INC.
LAZARD FRERES & CO.
CHEMICAL SECURITIES INC.
The date of this Prospectus is May , 1994.
<PAGE> 4
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS THAT STABILIZE OR MAINTAIN THE MARKET PRICE OF THE DEBENTURES
OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended, and the rules and regulations promulgated
thereunder (the "Exchange Act") and, in accordance therewith, files reports,
proxy statements and other information with the Securities and Exchange
Commission (the "Commission"). Reports, proxy statements and other information
filed by the Company with the Commission may be inspected and copied at the
public reference facilities maintained by the Commission at Room 1024, 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549-1004, and at the following
Regional Offices of the Commission: Chicago Regional Office, Citicorp Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60621-2511; and New York
Regional Office, 7 World Trade Center, 13th Floor, New York, New York 10048.
Copies of such material may also be obtained at prescribed rates from the Public
Reference Section of the Commission at its principal office at 450 Fifth Street,
N.W., Judiciary Plaza, Washington, D.C. 20549-1004. The Company's common stock,
par value $0.01 per share (the "Common Stock"), and its Convertible Preferred
Stock, Series 7%, are listed for trading on the New York Stock Exchange. The
Company's registration statements, reports, proxy statements and other
information may also be inspected at the offices of the New York Stock Exchange,
20 Broad Street, New York, New York 10005.
DOCUMENTS INCORPORATED BY REFERENCE
The following documents heretofore filed by the Company with the Commission
pursuant to Section 13 of the Exchange Act are incorporated herein by reference:
(i) the Company's Annual Report on Form 10-K for the year ended December 31,
1993 and (ii) the Company's Current Report on Form 8-K dated February 8, 1994.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of this Offering shall be deemed to be incorporated by reference
into this Prospectus and to be a part hereof from the date of filing of such
documents. Any statement contained in a document incorporated or deemed to be
incorporated by reference herein shall be deemed to be modified or superseded
for purposes of this Prospectus to the extent that a statement contained herein
or in any other subsequently filed document which also is or is deemed to be
incorporated by reference herein modifies or supersedes such statement. Any such
statement so modified or superseded shall not be deemed, except as so modified
or superseded, to constitute a part of this Prospectus.
Any person receiving a copy of this Prospectus may obtain without charge,
upon written or oral request, a copy of any of the documents incorporated by
reference herein, except for the exhibits to such documents (unless such
exhibits are specifically incorporated by reference into such documents).
Requests should be addressed to Mark A. Older, Senior Counsel and Secretary,
Santa Fe Energy Resources, Inc., 1616 South Voss Road, Suite 1000, Houston,
Texas 77057 (telephone (713) 783-2401).
CERTAIN DEFINITIONS
As used herein, the following terms have the specific meanings set out:
"Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl" means million
barrels, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf"
means billion cubic feet, "BOE" means barrel of oil equivalent, "MBOE" means
thousand barrels of oil equivalent and "MMBOE" means million barrels of oil
equivalent. 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. Unless otherwise
indicated in this Prospectus, natural gas volumes are stated at the official
temperature and pressure bases of the area in which the reserves are located.
"Finding cost" refers to a fraction, of which the numerator is equal to the
costs incurred by the Company for property acquisition, exploration and
development and of which the denominator is equal to proved reserve additions
from extensions, discoveries, improved recovery, acquisitions and revisions of
previous estimates. "Improved recovery," "enhanced oil recovery" and "EOR"
include all methods of supplementing natural reservoir forces and energy, or
otherwise increasing ultimate recovery from a reservoir, such as waterfloods,
cyclic steam, steam drive and CO2 (carbon dioxide) injection and fireflood
projects. "Heavy oil" is low gravity, high viscosity crude oil.
2
<PAGE> 5
PROSPECTUS SUMMARY
The following information is a summary of the more detailed information and
financial statements appearing elsewhere or incorporated by reference in this
Prospectus and is qualified in its entirety by reference thereto. Unless
otherwise indicated or required by the context, references to "Santa Fe" and the
"Company" include its consolidated subsidiaries.
THE COMPANY
GENERAL
Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") is engaged in
the exploration, development and production of oil and natural gas in the
continental United States and in certain foreign areas. At December 31, 1993,
the Company had estimated worldwide proved reserves of oil and natural gas
totaling 292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and
approximately 263.0 Bcf of natural gas), of which approximately 93% were
domestic reserves and approximately 7% were foreign reserves. During 1993, the
Company's worldwide production aggregated approximately 94.3 MBOE per day, of
which approximately 71% was crude oil and approximately 29% was natural gas. A
substantial portion of the Company's domestic oil production is in long-lived
fields with well-established production histories. Pursuant to the Company's
corporate restructuring program, the Company has focused its activities on its
three domestic core areas--the Permian Basin in Texas and New Mexico, the
offshore Gulf of Mexico and the San Joaquin Valley of California--as well as in
Argentina and Indonesia.
For the five years ended December 31, 1993, the Company has replaced 172%
of its production at an average finding cost of $4.80 per BOE. Over the last
four years, the Company has increased overall production by increasing
production from existing properties and through acquisitions. In addition, the
Company has reduced its overall cost structure. For example, over the four-year
period ended December 31, 1993, Santa Fe has increased its average daily
production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993
attributable to production from non-core assets sold pursuant to the corporate
restructuring program) and has reduced its average production costs (including
related production, severance and ad valorem taxes) from $6.22 per BOE in 1990
to $5.39 per BOE in 1993.
CORPORATE RESTRUCTURING PROGRAM
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program designed to improve its earnings and cash flow while
increasing production and replacing reserves in the long-term. The restructuring
program is the result of an intensive review of the Company's operations and
cost structure and focuses on the concentration of capital spending in the
Company's core operating areas and the disposition of non-core assets. The
restructuring program also includes an evaluation of the Company's capital and
cost structures in an effort to identify and implement ways to increase
flexibility and strengthen the Company's financial performance.
The Company's capital program will be concentrated in its three domestic
core areas, as well as in its productive areas in Argentina and Indonesia. In
October 1993, Santa Fe announced that its 1994 capital expenditures could
increase to up to $240 million. However, as a result of the depressed crude oil
prices that have prevailed since November 1993, the Company, consistent with
industry practice, has determined to defer certain of its capital projects in
order to prudently manage available cash flow in the near term. Based on current
market conditions, the Company has authorized up to $130 million of capital
expenditures during 1994, a level which should allow the Company to replace its
estimated 1994 production, although no assurance can be given regarding such
replacement. The Company intends to continue to monitor its capital expenditure
program throughout the balance of 1994 and may, in response to industry
conditions, including, without limitation, prevailing oil and natural gas prices
and the outlook therefor, revise such program.
3
<PAGE> 6
The non-core asset dispositions identified by the Company's restructuring
program included the sale of its natural gas gathering and processing assets for
securities as well as the sales of non-core oil and gas properties consisting of
approximately 16.7 MMBOE of estimated proved reserves and undeveloped leasehold
acreage for approximately $91.4 million. In addition, during the first quarter
of 1994, the Company sold its remaining interest in the Santa Fe Energy Trust
for $11.3 million and its interest in certain oil and gas properties for $8.3
million. As a result of these transactions, the Company has disposed of
substantially all of its inventory of non-core assets.
Based on a review of its capital structure, the Company determined to
proceed with a refinancing of certain of the Company's indebtedness (the
"Refinancing") in the belief that it would increase the Company's financial
flexibility, strengthen the Company's financial position and permit the Company
to pursue aggressively its operating strategy. See "--Financial Strategy." The
evaluation of the Company's cost structure resulted in the announcement on April
25, 1994 of the implementation of a cost reduction program designed to reduce
the Company's expenses by approximately $30.0 million from the 1993 level (which
reduction includes approximately $5.0 million of non-recurring costs).
Substantially all of this cost reduction program is expected to be implemented
by year end 1994.
As part of its restructuring program, the Company adopted the following
operating, financial and cost reduction strategies that should position it to
continue to efficiently replace its production and increase its reserves even in
a low oil price environment.
OPERATING STRATEGY
Santa Fe's operating strategy is designed to replace reserves and increase
its production in a cost effective manner by (i) exploiting its inventory of
lower risk, higher return projects in its domestic core areas, (ii) increasing
its light crude oil and natural gas reserves and production, and (iii)
increasing its international operations.
Develop Domestic Properties in Core Areas. A principal focus of the
Company's corporate restructuring program is the concentration of capital
spending in the Company's core domestic areas-- the Permian Basin of Texas and
New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of
California. In these areas, the Company has identified a significant number of
attractive development opportunities. Selection and timing of projects will
depend upon factors such as oil and natural gas prices and availability of
funds. In southeastern New Mexico, the Company has targeted for accelerated
development a light oil prospect in the Delaware formation and a light oil and
gas project in the Cisco-Canyon zone. The Company has conducted extensive
operations in these areas and has identified in excess of 150 development well
locations and 20 exploratory prospects to be drilled over the next several
years. During 1993, several new fields or field additions in the offshore Gulf
of Mexico area were placed on production, and the Company expects to further
develop identified prospects in 1994. In the San Joaquin Valley, reservoir
engineering studies prepared on behalf of the Company indicate that significant
additions to proved reserves can be made through additional EOR and development
projects in several of the Company's long-lived fields with well-established
production histories.
Increase Light Crude Oil and Natural Gas. A substantial part of the
Company's domestic oil reserves consists of "heavy" oil, which is generally more
expensive to produce than, and sells at a significant discount to, lighter crude
oils such as the benchmark West Texas Intermediate. See "Investment
Considerations--Effects of Heavy Oil Production" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations--General." One of
the principal components of the Company's strategy is to reduce the proportion
of heavy oil in its reserves by increasing its lighter crude oil and natural gas
reserves, primarily through development drilling of its existing project
inventory (such as the Permian Basin and offshore Gulf of Mexico, as discussed
above) and selective acquisitions. The acquisition of Adobe Resources
Corporation ("Adobe") in May 1992 added significantly to the Company's lighter
crude oil and natural gas reserves.
Increase International Operations. The Company is actively engaged in
exploration and development activities in two foreign areas, Argentina and
Indonesia. The Company believes that it can continue
4
<PAGE> 7
to identify and pursue other projects with the potential for increased reserves
and production in these and possibly other foreign areas. Revenues from sales of
oil and gas production in these areas have increased from approximately $3.7
million in 1991 to $35.6 million in 1993, with average daily production volumes
from these areas increasing from 0.6 MBOE per day in 1991 to 6.5 MBOE per day in
1993. The Company made a significant exploration discovery in 1993--the Sierra
Chata natural gas discovery in Argentina. To date, six gross (1.3 net) wells
have been drilled with no dry holes. In 1994, the Company plans additional
development drilling to further define the limits of the field, and to construct
a gas processing plant and a 40-mile pipeline. First sales of production from
this discovery are expected in early 1995.
FINANCIAL STRATEGY
The Company's financial strategy is to provide additional flexibility in
the current low oil price environment thereby allowing the Company to further
implement its operating strategy. This Offering is part of the Refinancing,
consisting of this Offering and the Concurrent DECS Offering. DECS are
convertible preferred stock that, if not previously converted or redeemed, will
be mandatorily converted into Common Stock on March 31, 1998. The net proceeds
from the Refinancing will be utilized to repay a portion of Senior Indebtedness
and certain subsidiary debt (on a pro forma basis at December 31, 1993, an
aggregate of approximately $180 million of such indebtedness would be repaid
with such net proceeds). See "Use of Proceeds."
Completion of the Refinancing will extend the average life of the Company's
debt from approximately 4.5 years to approximately 7.5 years, reduce the
Company's overall leverage and reduce required debt amortization in 1994, 1995
and 1996 to $3.8 million, $5.2 million, and $9.6 million, respectively (on a pro
forma basis at December 31, 1993). The Refinancing will also provide additional
liquidity by increasing the total amount available for borrowing under the
Company's existing bank credit facilities and by increasing cash flow in the
near term.
COST REDUCTION STRATEGY
On April 25, 1994, the Company announced the implementation of a major cost
reduction program aimed at reducing its expenses by approximately $30.0 million
from the 1993 level (which reduction includes approximately $5.0 million of
non-recurring costs). The Company intends to reduce its field expenses by
approximately $10.0 million, reduce its salaried work force by approximately
20%, significantly improve the efficiency of its information systems activities
and substantially reduce other general and administrative costs. Substantially
all of this cost reduction program is expected to be implemented by year end
1994. The Company recorded a $7.0 million charge during the quarter ended March
31, 1994 in connection with implementation of the cost reduction program. See
"--Recent Operating Results."
5
<PAGE> 8
THE DEBENTURE OFFERING
<TABLE>
<S> <C>
Securities Offered............ $100,000,000 principal amount of % Senior Subordinated
Debentures Due 2004.
Maturity Date................. , 2004.
Interest Payment Dates........ and of each year, commencing , 1994.
Optional Redemption........... The Debentures are not redeemable prior to , 1999.
At any time on or after , 1999, the Debentures are
redeemable at the option of the Company, in whole or from
time to time in part, at the redemption prices set forth
herein plus accrued and unpaid interest, if any, to the date
of redemption. See "Description of the Debentures--Optional
Redemption."
Mandatory Redemption.......... Upon the occurrence of a Change of Control (as defined) and a
subsequent Rating Decline (as defined), the Company will be
required to offer to repurchase the Debentures at 101% of the
principal amount thereof, plus accrued and unpaid interest
due thereon, if any, to the date of purchase. See
"Description of the Debentures--Mandatory Repurchase upon
Change of Control and Subsequent Rating Decline."
Ranking....................... The Debentures will be general unsecured senior subordinated
obligations of the Company. The Debentures will rank
subordinate in right of payment to all existing and future
Senior Indebtedness, pari passu with any future senior
subordinated indebtedness and senior to any future junior
subordinated indebtedness of the Company. At December 31,
1993, the Company's outstanding Senior Indebtedness was
$469.4 million. After adjustment for application of the net
proceeds from this Offering and the Concurrent DECS Offering,
Senior Indebtedness at December 31, 1993 would have been
$289.4 million. The Debentures will be structurally
subordinated to all liabilities of the Company's
subsidiaries, which would have totaled $58.8 million at
December 31, 1993, after giving effect to the application of
the net proceeds from this Offering and the Concurrent DECS
Offering.
Principal Covenants........... The Indenture for the Debentures contains restrictions on (i)
the ability of the Company to Incur additional Indebtedness,
(ii) the payment of dividends on the Capital Stock of the
Company and the purchase, redemption or retirement of Capital
Stock of the Company, (iii) the making of certain
investments, (iv) the Incurrence of certain Liens, (v) Asset
Sales, (vi) certain transactions with Affiliates, (vii)
payment restrictions affecting Restricted Subsidiaries and
(viii) certain consolidations, mergers and transfers of
assets. All of these limitations will be subject to a number
of important qualifications. See "Description of the
Debentures."
Use of Proceeds............... The net proceeds to the Company from the sale of the
Debentures offered hereby are estimated to be $97.0 million.
Such net proceeds will be used to repay certain existing
Senior Indebtedness. See "Use of Proceeds."
</TABLE>
6
<PAGE> 9
SUMMARY FINANCIAL INFORMATION
The following table presents summary historical financial information for
the periods presented and should be read in conjunction with the historical
consolidated financial statements, including the notes thereto, and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." The following table also presents summary pro forma financial
information as of and for the year ended December 31, 1993 after giving effect
to the consummation of this Offering and the Concurrent DECS Offering and the
application of the estimated net proceeds therefrom as described in "Use of
Proceeds." The summary pro forma financial information is unaudited.
<TABLE>
<CAPTION>
PRO YEAR ENDED DECEMBER 31,
FORMA ---------------------------------------------------------
1993(A) 1993 1992 1991 1990 1989
-------- -------- -------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues.................... $ 436.9 $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9
Production and operating
expenses................. 163.8 163.8 153.4 134.6 135.5 107.1
Exploration expenses........ 31.0 31.0 25.5 18.7 21.0 19.4
General and
administrative........... 32.3 32.3 30.9 27.8 25.6 28.6
Depreciation, depletion and
amortization............. 152.7 152.7 146.3 106.6 105.2 99.4
Impairment of oil and gas
properties............... 99.3(b) 99.3(b) -- -- 1.4 1.1
Restructuring charges....... 38.6(c) 38.6(c) -- -- -- --
Income (loss) from
operations............... (113.0) (113.0) 57.5 64.4 69.4 45.5
Interest expense(d)......... 40.7 45.8 55.6 47.3 57.1 30.5
Net income (loss)........... (73.9) (77.1) (1.4) 18.5 17.0 49.8
Earnings (loss) to Common
Stock.................... (87.3) (84.1) (5.7) 18.5 17.0 49.8
Earnings (loss) per share of
Common Stock............. $ (0.97) $ (0.94) $ (0.07) $ 0.29 $ 0.28 --
CASH FLOW DATA:
Net cash provided by
operating activities..... $ 154.3 $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1
Capital expenditures........ 127.0 127.0 76.8 108.1 117.0 93.7
Preferred dividends......... 13.4 7.0 2.6 -- -- --
Common Stock dividends(e)... 14.3 14.3 12.3 10.2 5.1 --
BALANCE SHEET DATA (AT END OF
PERIOD):
Properties and equipment,
net...................... $ 832.7 $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6
Total assets................ 1,079.0 1,076.9 1,337.2 911.9 911.1 881.8
Long-term debt.............. 365.9 405.4 492.8 440.8 417.2 124.7
Convertible Preferred Stock,
Series 7%................ 80.0 80.0 80.0 -- -- --
Shareholders' equity........ 414.8 323.6 416.6 225.1 215.8 228.1
</TABLE>
7
<PAGE> 10
<TABLE>
<CAPTION>
PRO YEAR ENDED DECEMBER 31,
FORMA -------------------------------------------------------
1993(A) 1993 1992 1991 1990 1989
-------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
OTHER DATA:
EBITDA (in millions)(f)........ $ 178.0 $ 178.0 $ 188.0 $ 173.3 $ 186.1 $ 153.8
EBITDA/Interest expense........ 4.4 x 3.9x 3.4x 3.7x 3.3x 5.0x
EBITDA/Preferred dividends and
interest expense............ 3.3 x 3.4x 3.1x 3.7x 3.3x 5.0x
Ratio of earnings to combined
fixed charges and preferred
dividends(g)................ (h ) (h) (h) 1.5x 1.3x 2.2x
</TABLE>
---------------
(a) Pro forma for the consummation of this Offering and the Concurrent DECS
Offering and the application of the net proceeds therefrom as described
under "Use of Proceeds." Assumes 10,700,000 DECS are sold at a price of
$8 7/8 per share.
(b) Reflects a non-cash charge of $99.3 million for the impairment of oil and
gas properties recorded as of December 31, 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and Note 1 of the Notes to the Company's Consolidated Financial Statements
included elsewhere in this Prospectus.
(c) Reflects a non-cash, non-recurring charge of $38.6 million recorded in 1993
in conjunction with the implementation of the Company's restructuring
program, comprised of (i) losses on property dispositions of $27.8 million;
(ii) long-term debt prepayment penalties of $8.6 million; and (iii)
accruals for certain personnel benefits and related costs of $2.2 million.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 2 of the Notes to the Company's
Consolidated Financial Statements included elsewhere in this Prospectus.
(d) Includes capitalized interest of $4.3 million, $4.9 million, $7.7 million,
$10.6 million and $13.8 million for 1993, 1992, 1991, 1990 and 1989,
respectively.
(e) Represents dividends paid subsequent to the Company's initial public
offering in March 1990. Prior to such time, the Company was a wholly owned
subsidiary of the Santa Fe Pacific Corporation, and dividends paid to its
parent are not considered relevant in the context of its dividend policy
subsequent to the initial public offering. As part of the Company's 1993
restructuring program, in October 1993, the Company eliminated its $0.04
per share quarterly dividend on Common Stock. See "Management's Discussion
and Analysis of Financial Condition and Results of Operation."
(f) EBITDA is presented because it is a widely accepted financial indication of
a company's ability to service and incur debt. EBITDA has the same meaning
as in the Indenture since it excludes EBITDA of Unrestricted Subsidiaries
(as defined). EBITDA should not be considered by an investor as an
alternative to earnings (loss) as an indicator of the Company's operating
performance or to cash flows as a measure of liquidity. EBITDA for the
Company largely results from sales of oil and gas produced from the
Company's properties, which production, if not replaced, will result in
depletion of the Company's assets and a reduction of the Company's ability
to service and incur debt at constant or declining prices. The calculation
of EBITDA for 1993 reflects an average sales price (unhedged) by the
Company of $12.93 per barrel of oil. For the three months ended March 31,
1994, the average sales price (unhedged) for the Company's 1994 oil
production was $10.00 per barrel. If such lower oil prices prevail
throughout 1994, the Company's EBITDA for 1994 will be significantly lower
than that for 1993. See "--Recent Operating Results."
(g) For the purpose of calculating such ratios, (i) earnings consist of income
(loss) before income taxes plus fixed charges and (ii) fixed charges
consist of interest expense (including amortization of deferred debt
issuance costs) and the amount of pre-tax earnings required to cover
preferred stock dividend requirements.
(h) Earnings for the years ended December 31, 1993 and 1992 were insufficient
to cover combined fixed charges and preferred dividends by $166.0 million
and $12.8 million, respectively. Pro forma earnings for the year ended
December 31, 1993, after giving effect to the consummation of this
Offering and the Concurrent DECS Offering and the application of the
estimated net proceeds therefrom as described in "Use of Proceeds," would
have been insufficient to cover fixed charges by $171.4 million.
8
<PAGE> 11
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------------------------------
1993 1992 1991 1990 1989
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Production of oil (MBbls per day)(a)...... 66.7(d) 62.5 55.5 52.0 50.7
Production of natural gas (MMcf per
day)(a)................................. 165.4(d) 126.3 95.2 102.5 81.6
Production of oil equivalent
(MBOE per day)(a)....................... 94.3(d) 83.6 71.4 69.1 64.3
Average sales price:
Oil (per Bbl)........................ $ 12.93 $ 14.54 $ 14.09 $ 17.90 $ 14.11
Natural gas (per Mcf)................ $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72
Production costs (including related
production, severance and ad valorem
taxes) per BOE.......................... $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69
Five-year average finding cost per
BOE(b).................................. $ 4.80 $ 4.05 $ 3.66 $ 3.73 $ 4.31
Annual reserve replacement ratio(c)....... 121% 262% 127% 108% 251%
Estimated reserve life (in years)......... 8.5(d) 9.9 9.9 10.0 10.7
</TABLE>
- ---------------
(a) Includes production attributable to certain net profits interests sold by
the Company to unaffiliated persons, which interests burden the Company's
working or royalty interests held in certain properties.
(b) Reflects the average finding cost per BOE during the five years ended
December 31 as of the year reflected in the column.
(c) The annual reserve replacement ratio is a fraction, of which the numerator
is the estimated number of reserves added during a year through additions
of estimated proved reserves from exploratory and development drilling,
acquisitions of proved properties and revisions of previous estimates,
excluding property sales, and of which the denominator is the oil and
natural gas produced during that year.
(d) Includes production attributable to the properties sold to Vintage
Petroleum, Inc. ("Vintage") (closed in November 1993) and Bridge Oil
(U.S.A.) Inc. ("Bridge") (closed in April 1994). Production attributable to
such properties during 1993 totaled approximately 4.1 MBbls of oil and 21.7
MMcf of natural gas per day (7.7 MBOE per day).
RECENT OPERATING RESULTS
For the three months ended March 31, 1994, the Company reported a net loss
to common shares of $4.3 million, or $0.05 per share, compared to a net loss to
common shares of $2.2 million, or $0.02 per share, in the same period in 1993.
Revenues for the first quarter of 1994 totaled $90.3 million compared to $115.3
million in the same period in 1993. The decline in revenues primarily reflects a
$3.73 per barrel decline in the Company's average sales price for its crude oil
and liquids as compared to its average sales price for the first quarter of
1993. Revenues from the properties sold to Vintage included in the 1993 period
totaled $5.4 million. The Company's costs and expenses totaled $90.3 million in
the first quarter of 1994 compared to $103.3 million in the first quarter of
1993. Lower production and operating costs (down $2.1 million, primarily
reflecting the effect of the Vintage sale), exploration expenses (down $2.1
million) and depreciation, depletion and amortization ("DD&A") expense (down
$5.6 million, primarily reflecting the effect of impairments taken in the fourth
quarter of 1993) and the recognition of a $9.4 million gain from the disposition
of oil and gas properties were the principal factors in the reduction in costs
and expenses. Costs and expenses for the first quarter of 1994 include $7.0
million in restructuring charges related to the Company's cost reduction
program. The restructuring charges, designed to reduce expenses by approximately
$30.0 million from the 1993 level (which reduction includes approximately $5.0
million of non-recurring costs), relate to severance, benefits and relocation
expenses associated with a cost reduction program that includes a 20% reduction
in the Company's
9
<PAGE> 12
salaried workforce, a reduction in other general and administrative expenses and
a $10.0 million reduction in field expenses. Substantially all of this cost
reduction program is expected to be implemented by year end 1994. Net cash
provided by operating activities declined from $41.6 million in the first
quarter of 1993 to $14.3 million in the first quarter of 1994, primarily
reflecting the factors described above.
The Company's production during the first quarter of 1994 totaled 5.9
MMBbls of crude oil and liquids and 14.0 Bcf of natural gas compared to 6.0
MMBbls of crude oil and liquids and 16.0 Bcf of natural gas in the first quarter
of 1993. Natural gas production for the first quarter of 1993 included a 1.5 Bcf
positive adjustment attributable to prior periods. Crude oil and liquids sales
prices (unhedged) averaged $10.00 per barrel in the first quarter of 1994
compared to $13.73 per barrel in the first quarter of 1993. Natural gas sales
prices (unhedged) averaged $2.10 per Mcf in the first quarter of 1994 compared
to $1.96 per Mcf in the first quarter of 1993.
SUMMARY OIL AND GAS RESERVE INFORMATION
The following table sets forth summary information with respect to the
Company's proved oil and gas reserves as of the dates indicated. For additional
information relating to reserves, see "Business and Properties -- Reserves."
<TABLE>
<CAPTION>
NET PROVED RESERVES AS OF DECEMBER 31,(A)
------------------------------------------------------------
1993(B) 1992 1991 1990 1989
---------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Crude oil, condensate and natural gas
liquids (MMBbls).................... 248.2 255.1 229.2 222.3 219.8
Natural gas (Bcf)..................... 263.0 277.5 170.8 185.9 188.0
Proved reserves (MMBOE)............... 292.0 301.5 257.7 253.3 251.1
Proved developed reserves (MMBOE)..... 225.5 248.4 210.3 205.0 204.0
Present value of pre-tax future net
cash
flows (in millions)(c).............. $ 567.8 $ 915.2 $ 602.6 $1,231.4 $1,090.1
</TABLE>
- ---------------
(a) Includes estimated proved reserves attributable to certain net profits
interests sold by the Company to unaffiliated persons, which interests
burden the Company's working or royalty interests held in certain
properties.
(b) The estimates set forth in this table for 1993 give effect to the sale by
the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which
sale closed in April 1994.
(c) Represents the present value (discounted at 10%) of the future net cash
flows estimated to result from production of the Company's estimated proved
reserves using estimated sales prices and estimates of production costs, ad
valorem and production taxes and future development costs necessary to
produce such reserves. The sales prices used in the determination of proved
reserves and of estimated future net cash flows are based on the prices in
effect at year end, and for 1993 averaged $9.27 per barrel for oil and
$2.17 per Mcf for natural gas. The average sales prices (unhedged) realized
by the Company for its production during 1993 was $12.93 per barrel for oil
and $2.03 per Mcf for natural gas. The average sales prices (unhedged)
realized by the Company for its production during the three months ended
March 31, 1994 were $10.00 per barrel of oil and $2.10 per Mcf of natural
gas. See "--Recent Operating Results."
10
<PAGE> 13
INVESTMENT CONSIDERATIONS
Before deciding to invest in the Debentures offered hereby, prospective
investors should carefully consider all of the information contained in this
Prospectus, and in particular the investment considerations described in the
following paragraphs.
EFFECTS OF CHANGING PRODUCT PRICES
The Company's profitability is determined in large part by the difference
between the prices received for the oil and natural gas that it produces and the
costs of finding and producing such resources. Prices for oil and gas have been
subject to wide fluctuations, which continue to reflect imbalances in supply and
demand as well as other market conditions and the world political situation as
it affects OPEC, the Middle East (including the current embargo of Iraqi crude
oil from worldwide markets) and other producing countries. Moreover, the price
of oil and natural gas may be affected by the price and availability of
alternative sources of energy, weather conditions and the general state of the
economy. Even relatively modest changes in oil and gas prices may significantly
change the Company's revenues, results of operations, cash flows and proved
reserves. Since the Company is primarily an oil producer, a change in the price
paid for its oil production more significantly affects its results of operations
than a change in natural gas prices. For example, the Company estimates that a
change of $1.00 per barrel in its average realized oil price would have resulted
in a change of $21.6 million in its 1993 operating income and $16.2 million in
its 1993 cash flow from operating activities, based on its 1993 operating
results. The foregoing estimates do not give effect to changes in any other
factors, such as the effect of the Company's hedging program or depreciation and
depletion, that would result from a change in oil prices. In recent months, spot
oil prices have reached their lowest levels in over five years, and no assurance
can be given that oil prices will not remain at these levels for the foreseeable
future or decline further.
The Company's cash flow from operating activities is a function of the
volumes of oil and gas produced from the Company's properties and the sales
prices realized therefor. Crude oil and natural gas are depleting assets.
Therefore, unless the Company replaces over the long term the oil and natural
gas produced from the Company's properties, the Company's assets will be
depleted over time and its ability to service and incur debt at constant or
declining prices will be reduced. The Company's cash flow from operations for
1993 reflects an average sales price (unhedged) for the Company's 1993 oil
production of $12.93 per barrel. For the three months ended March 31, 1994, the
average sales price (unhedged) for the Company's 1994 oil production was $10.00
per barrel. If such lower oil prices prevail throughout 1994, the Company's cash
flow from operating activities for 1994 will be significantly lower than that
for 1993.
EFFECTS OF HEAVY OIL PRODUCTION
A substantial portion of the Company's oil production consists of heavy oil
produced from the Midway-Sunset Field. The market for such heavy crude oil
production differs substantially from the remainder of the domestic crude oil
market, due principally to the higher transportation and refining costs
associated with heavy crude. As a result, the profit margin realized from the
sale of heavy oil is generally lower than that realized from the sale of light
oil, because the costs to produce heavy oil are generally higher, and the price
paid for heavy crude oil is generally lower, than the price paid for light
crudes. Furthermore, there is currently an oversupply of crude oil in the
California market that has had an adverse effect on the prices paid for crude
oil in that market. See "Business and Properties--Current Markets for Oil and
Gas."
POSSIBLE IMPAIRMENT OF OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for its oil
and gas exploration and production activities. Under this method, costs (both
tangible and intangible) of productive wells and development dry holes, as well
as the costs of prospective acreage, are capitalized. The costs of drilling and
equipping exploratory wells which do not result in proved reserves are expensed
upon the
11
<PAGE> 14
determination that the well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs and delay rentals,
are charged to expense as incurred.
The Company periodically reviews individual proved properties to determine
if the carrying value of the field as reflected in its accounting records
exceeds the estimated undiscounted future net revenues from proved oil and gas
reserves attributable to the field. Based on this review and the continuing
evaluation of development plans, economics and other factors, if appropriate,
the Company records impairments (additional depletion and depreciation) to the
extent that the carrying value exceeds the estimated undiscounted future net
revenues. Such impairments constitute a charge to earnings which does not impact
the Company's cash flow from operating activities. However, such writedowns
impact the amount of the Company's stockholders' equity and, therefore, the
ratio of debt-to-equity. The risk that the Company will be required to write
down the carrying value of its oil and natural gas properties increases when oil
and natural gas prices are depressed. In 1993, the Company recorded impairments
of $99.3 million. No assurance can be given that the Company will not experience
additional impairments in the future.
SUBORDINATION OF DEBENTURES
The Indenture pursuant to which the Debentures will be issued (the
"Indenture") will limit, but not prohibit, the Incurrence by the Company of
additional Indebtedness, including Indebtedness that is senior in right of
payment to the Debentures (including by reason of structural subordination to
liabilities of the Company's subsidiaries). In the event of bankruptcy,
liquidation, reorganization or other winding up of the Company, the assets of
the Company will be available to pay the Company's obligations on the Debentures
offered hereby only after all Senior Indebtedness has been paid in full, and
there may not be sufficient assets remaining to pay amounts due on the
Debentures. In addition, under certain circumstances, no payments may be made
with respect to principal of, premium, if any, or interest on the Debentures if
a default exists with respect to any Senior Indebtedness. See "Description of
the Debentures--Subordination."
FUNDING OF CHANGE OF CONTROL OFFER
In the event of a Change of Control (as defined) and a subsequent Rating
Decline (as defined), the Company will be required, subject to certain
conditions, to offer to purchase all outstanding Debentures at a price equal to
101 percent of the principal amount of the Debentures, plus accrued and unpaid
interest. Certain Senior Indebtedness also includes, and future Indebtedness of
the Company may include, change of control provisions pursuant to which the
Company would be required to offer to repurchase, or the lender could demand
repayment of, upon a change in control of the Company (as defined thereunder),
the Indebtedness due thereunder. Upon such an occurrence, redemption or
repayment of Senior Indebtedness would be required to be made before the offer
to repurchase Debentures could be consummated. As a result, no assurance can be
given that the Company would have available sufficient funds to repurchase
Debentures that may be tendered for repurchase upon a Change of Control and a
subsequent Rating Decline. As of December 31, 1993, after giving effect to this
Offering and the Concurrent DECS Offering and the application of the net
proceeds therefrom as described in "Use of Proceeds," the Company would not have
sufficient funds available to purchase all of the outstanding Debentures were
they to be tendered in response to an offer made as a result of a Change of
Control and a subsequent Rating Decline. See "Description of the
Debentures--Mandatory Repurchase upon Change of Control and Subsequent Rating
Decline."
SUBSTANTIAL LEVERAGE
The Company is, and after the Refinancing will continue to be, highly
leveraged. At December 31, 1993, the Company had total indebtedness of $449.7
million and shareholders' equity of $323.6 million. After giving effect to the
Offering, the Concurrent DECS Offering and the application of the estimated net
proceeds therefrom as described in "Use of Proceeds," the Company would have
had, on a pro forma basis at December 31, 1993, total indebtedness of $369.7
million and shareholders' equity of
12
<PAGE> 15
$414.8 million. If this Offering is completed but the Concurrent DECS Offering
is not consummated, the Company's pro forma total indebtedness and shareholders'
equity at December 31, 1993 would have been $458.8 million and $323.3 million,
respectively. The Company's high degree of leverage will have important
consequences to holders of the Debentures, including the following: (i) the
ability of the Company to obtain additional financing in the future for working
capital, acquisitions, capital expenditures and other general corporate purposes
may be impaired; (ii) a substantial portion of the Company's cash flow from
operations will be required to be dedicated to the payment of the Company's
interest expense and principal repayment obligations; (iii) the Company is more
highly leveraged than many of its competitors, which may place it at a
competitive disadvantage; and (iv) the Company's degree of leverage may make it
more vulnerable to a downturn in its business or the economy generally. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The Company's activities are subject to various federal, state and local
laws and regulations covering the discharge of material into the environment or
otherwise relating to protection of the environment. In particular, the
Company's oil and gas exploration, development, production and EOR operations,
its activities in connection with storage and transportation of liquid
hydrocarbons and its use of facilities for treating, processing, recovering or
otherwise handling hydrocarbons and waste therefrom are subject to stringent
environmental regulation by governmental authorities. Such regulations have
increased the costs of planning, designing, drilling, installing, operating and
abandoning the Company's oil and gas wells and other facilities.
The Company has expended significant resources, both financial and
managerial, to comply with environmental regulations and permitting requirements
and anticipates that it will continue to do so in the future. Although the
Company believes that its operations and facilities are in general compliance
with applicable environmental regulations, risks of substantial costs and
liabilities are inherent in oil and gas operations, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future. Moreover, it is possible that other developments, such as increasingly
strict environmental laws, regulations and enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in substantial costs and
liabilities in the future. See "Business and Properties--Other Business
Matters--Environmental Regulation."
UNCERTAINTIES IN ESTIMATES OF PROVED RESERVES
Proved reserves of crude oil and natural gas are estimated quantities that
geological and engineering data demonstrate with reasonable certainty to be
economically producible under existing conditions. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures.
All reserve estimates are to some degree speculative and various classifications
of reserves only constitute attempts to define the degree of speculation
involved. The accuracy of any reserve estimate is a function of the quality of
available data and engineering and geological interpretation and judgment and
the assumptions used regarding prices for crude oil, natural gas liquids and
natural gas. Results of drilling, testing and production and changes in crude
oil, natural gas liquids and natural gas prices after the date of the estimate
may require substantial upward or downward revisions. Although a substantial
portion of the Company's proved oil reserves is in long-lived fields with
well-established production histories where EOR and other development projects
are employed to produce such reserves, the external factors discussed above will
directly affect the Company's determination to proceed with any of such projects
and, therefore, the quantity of reserves in these fields classified as proved.
The reserve estimates included and incorporated by reference in this Prospectus
were prepared as of December 31, 1993 and could be materially different from the
quantities of crude oil, natural gas liquids and natural gas that ultimately
will be recovered from the Company's properties.
13
<PAGE> 16
In addition, actual future net cash flows from production of the Company's
reserves will be affected by factors such as actual production, supply and
demand for oil and natural gas, curtailments or increases in consumption by
natural gas purchasers, changes in governmental regulations or taxation and the
impact of inflation on costs. The timing of actual future net revenue from
proved reserves, and thus their actual present value, can be affected by the
timing of the incurrence of expenditures in connection with development of oil
and gas properties. The 10% discount factor, which is required by the Commission
to be used to calculate present value for reporting purposes, is not necessarily
the most appropriate discount factor based on interest rates in effect from time
to time and risks associated with the oil and gas industry. Discounted present
value, no matter what discount rate is used, is materially affected by
assumptions as to the amount and timing of future production, which may and
often do prove to be inaccurate.
INDUSTRY CONSIDERATIONS
The Company's business is the exploration for, and the development and
production of, oil and natural gas. Exploration for oil and natural gas involves
many risks, which even a combination of experience, knowledge and careful
evaluation may not be able to overcome. In addition, there is strong competition
relating to all aspects of the oil and gas industry, and in particular in the
exploration and development of new oil and gas reserves. The Company must
compete with a substantial number of other oil and natural gas companies, many
of which have significantly greater financial resources.
All of the Company's oil and gas activities are subject to the risks
normally incident to exploration for and production of oil and gas, including
blowouts, cratering, spillage and fires, each of which could result in damage to
life and property. Offshore operations are subject to usual marine perils,
including hurricanes and other adverse weather conditions, and governmental
regulations as well as interruption or termination by governmental authorities
based on environmental and other considerations. In accordance with customary
industry practices, the Company carries insurance against some, but not all, of
the risks associated with the Company's business. Losses and liabilities arising
from such events would reduce revenues and increase costs to the Company to the
extent not covered by insurance.
Another risk inherent in the oil and gas industry is the risk that a well
will be a dry hole or a marginal producer that will not, in either case, repay
the entire cost of drilling, testing, completing and equipping the well. There
can be no assurance, therefore, that the Company's future exploration and
development wells will be financially successful.
INTERNATIONAL OPERATIONS
Foreign properties, operations or investment may be adversely affected by
local political and economic developments, exchange controls, currency
fluctuations, royalty and tax increases, retroactive tax claims, expropriation,
import and export regulations and other foreign laws or policies as well as by
laws and policies of the United States affecting foreign trade, taxation and
investment. In addition, in the event of a dispute arising from foreign
operations, the Company may be subject to the exclusive jurisdiction of foreign
courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in the United States. The Company may also be hindered or
prevented from enforcing its rights with respect to a governmental
instrumentality because of the doctrine of sovereign immunity.
ABSENCE OF A PREVIOUS MARKET FOR THE DEBENTURES
The Debentures are a new issue of securities with no established trading
market and the Company does not intend to apply for listing of the Debentures on
any securities exchange. The Company has been advised by the Underwriters that,
subject to applicable laws and regulations, each of them currently intends to
make a market in the Debentures; however, they are not obligated to do so and
may discontinue any such market making at any time without notice. No assurance
can be given as to the development or liquidity of any trading market in the
Debentures. If an active market does not develop, the market price and liquidity
of the Debentures may be adversely affected.
14
<PAGE> 17
RATIOS OF EARNINGS TO FIXED CHARGES
The following table sets forth the historical ratios of earnings to fixed
charges and earnings to combined fixed charges and preferred stock dividends of
the Company for the periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Earnings to Fixed Charges.......................... (a) (a) 1.5x 1.3x 2.2x
Earnings to Combined Fixed Charges and Preferred
Dividends........................................ (b) (b) 1.5x 1.3x 2.2x
</TABLE>
- ---------------
(a) Earnings during 1993 and 1992 were insufficient to cover fixed charges
(excluding dividends on preferred stock) by $154.5 million and $5.8
million, respectively.
(b) Earnings during 1993 and 1992 were insufficient to cover combined fixed
charges and preferred dividends by $166.0 million and $12.8 million,
respectively.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the Debentures offered
hereby are estimated to be approximately $97.0 million. Such net proceeds will
be used to prepay $65.0 million principal amount of the Company's Senior Notes
with scheduled maturities in 1995 (Series C, $30.0 million) and 1996 (Series D,
$35.0 million), together with prepayment penalties aggregating approximately
$6.1 million. The Series C Notes bear interest at 10.04% per year and the Series
D Notes bear interest at 10.14% per year. The remaining net proceeds from this
Offering and the net proceeds from the Concurrent DECS Offering (estimated to be
approximately $91.6 million) will be used (i) to repay the floating rate debt
borrowed under the Company's Amended and Restated Revolving Credit Agreement
("Bank Facility"), the balance of which was $30.0 million at April 25, 1994 and
which currently bears interest at 5.5% per year; (ii) to repay approximately
$30.0 million principal amount of debt previously incurred by Santa Fe Energy
Operating Partners, L.P., (plus a prepayment penalty equal to approximately $2.5
million) with a current interest rate of 8.3% per year, $6.0 million of which
matures in 1994 and $8.0 million of which is scheduled to mature during each of
the succeeding three years; (iii) to repay approximately $12.3 million principal
amount of debt of Mission Resources, Inc. assumed by the Company in connection
with a property acquisition, with a current interest rate of 9.0% and a
scheduled maturity in 1995; and (iv) for working capital purposes.
After the application of the net proceeds from the Offering and the
Concurrent DECS Offering, the Company will have approximately $245.0 million
principal amount of Senior Notes outstanding, none of which matures before 1996.
15
<PAGE> 18
CAPITALIZATION
The following table sets forth the Company's consolidated capitalization at
December 31, 1993 on a historical basis and as adjusted as indicated below. See
"Use of Proceeds."
<TABLE>
<CAPTION>
DECEMBER 31, 1993
----------------------------------------
AS ADJUSTED
--------------------------
DEBENTURES
DEBENTURES AND
ACTUAL ONLY(a) DECS(b)
-------- ---------- ----------
(IN MILLIONS)
<S> <C> <C> <C>
SHORT-TERM DEBT:
Current portion of long-term debt.................. $ 44.3 $ 43.0 $ 3.8
-------- -------- --------
-------- -------- --------
LONG-TERM DEBT:
Senior notes....................................... 310.0 245.0 245.0
Revolving and term credit agreement................ 48.7 24.1 9.6
Notes payable to bank.............................. 11.3 11.3 11.3
Term loan.......................................... 11.4 11.4 --
Partnership credit agreement....................... 24.0 24.0 --
Senior subordinated debentures..................... -- 100.0 100.0
-------- -------- --------
Total long-term debt............................ 405.4 415.8 365.9
-------- -------- --------
CONVERTIBLE PREFERRED STOCK, SERIES 7%:.............. 80.0 80.0 80.0
-------- -------- --------
SHAREHOLDERS' EQUITY:
DECS............................................... -- -- 91.6
Common stock....................................... 0.9 0.9 0.9
Paid-in capital.................................... 496.9 496.9 496.9
Accumulated deficit................................ (173.8) (174.1) (174.2)
Other.............................................. (0.4) (0.4) (0.4)
-------- -------- --------
Total shareholders' equity...................... 323.6 323.3 414.8
-------- -------- --------
Total capitalization............................... $ 809.0 $ 819.1 $ 860.7
-------- -------- --------
-------- -------- --------
</TABLE>
- ---------------
(a) Pro forma for the issuance of the Debentures only. Net proceeds from the
Offering will be applied to prepay $65.0 million of the Senior Notes, fund
$6.1 million of prepayment penalties and repay approximately $25.9 million
of floating rate debt borrowed under the Bank Facility. If the Concurrent
DECS Offering is not consummated, approximately $89.1 million additional
Senior Indebtedness and subsidiary debt will remain outstanding.
(b) Pro forma for the issuance of both the Debentures and the DECS and the
application of the net proceeds therefrom (estimated to be $188.6 million)
as described in "Use of Proceeds." Assumes 10,700,000 DECS are sold at a
price of $8 7/8 per share.
16
<PAGE> 19
SELECTED FINANCIAL AND OPERATING DATA
The following data has been derived from the Company's consolidated
financial statements audited by Price Waterhouse, independent accountants. The
selected historical financial data should be read in conjunction with the
consolidated financial statements of the Company, including the notes thereto.
The Company's consolidated balance sheets at December 31, 1992 and 1993 and the
related consolidated statements of operations, of cash flows and of
shareholders' equity for the three years ended December 31, 1993 are included
elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1993 1992(A) 1991 1990 1989
-------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN MILLIONS, EXCEPT AS NOTED)
INCOME STATEMENT DATA:
Revenues............................... $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9
Operating expenses
Production and operating............ 163.8 153.4 134.6 135.5 107.1
Oil and gas systems and pipelines... 4.2 3.2 -- -- --
Exploration, including dry hole
costs............................. 31.0 25.5 18.7 21.0 19.4
Depletion, depreciation and
amortization...................... 152.7 146.3 106.6 105.2 99.4
Impairment of oil and gas
properties(b)..................... 99.3 -- -- 1.4 1.1
General and administrative.......... 32.3 30.9 27.8 25.6 28.6
Taxes (other than income)........... 27.3 24.3 27.2 22.0 22.3
Restructuring charges(c)............ 38.6 -- -- -- --
Loss (gain) on disposition of oil
and gas properties................ 0.7 (13.6) 0.5 2.8 (0.5)
-------- -------- ------- ------- -------
Total operating expenses............... 549.9 370.0 315.4 313.5 277.4
-------- -------- ------- ------- -------
Operating income (loss)................ (113.0) 57.5 64.4 69.4 45.5
Other income (expense)................. (4.8) (10.0) 5.6 (0.3) 18.2
Interest income........................ 9.1 2.3 2.3 5.2 4.3
Interest expense....................... (45.8) (55.6) (47.3) (57.1) (30.5)
Interest capitalized................... 4.3 4.9 7.7 10.6 13.8
-------- -------- ------- ------- -------
Income (loss) before income taxes and
cumulative effect of accounting
change.............................. (150.2) (0.9) 32.7 27.8 51.3
Income taxes benefit (expense)......... 73.1 (0.5) (14.2) (10.8) (26.0)
-------- -------- ------- ------- -------
Income (loss) before cumulative effect
of accounting change................ (77.1) (1.4) 18.5 17.0 25.3
Cumulative effect of accounting
change.............................. -- -- -- -- 24.5
-------- -------- ------- ------- -------
Net income (loss)...................... (77.1) (1.4) 18.5 17.0 49.8
Preferred dividend requirement......... (7.0) (4.3) -- -- --
-------- -------- ------- ------- -------
Earnings (loss) attributable to Common
Stock............................... $ (84.1) $ (5.7) $ 18.5 $ 17.0 $ 49.8
-------- -------- ------- ------- -------
-------- -------- ------- ------- -------
Per share data (in dollars):
Income (loss) before cumulative
effect of accounting change....... $ (0.94) $ (0.07) $ 0.29 $ 0.28 $ 0.48
Cumulative effect of change in
accounting for income taxes....... -- -- -- -- 0.47
Earnings (loss) to Common Stock........ (0.94) (0.07) 0.29 0.28 0.95
Weighted average number of shares
outstanding (in millions)........... 89.7 79.0 63.8 61.7 52.1
STATEMENT OF CASH FLOW DATA:
Net cash provided by operating
activities.......................... $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1
Net cash used in investing
activities.......................... 121.4 15.9 117.2 108.2 86.8
</TABLE>
(Table continued on following page)
17
<PAGE> 20
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1993 1992(A) 1991 1990 1989
-------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN MILLIONS, EXCEPT AS NOTED)
BALANCE SHEET DATA (AT PERIOD END):
Properties and equipment, net.......... $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6
Total assets........................... 1,076.9 1,337.2 911.9 911.1 881.8
Long-term debt......................... 405.4 492.8 440.8 417.2 124.7
Convertible Preferred Stock, Series
7%.................................. 80.0 80.0 -- -- --
Shareholders' equity................... 323.6 416.6 225.1 215.8 228.1
SELECTED OPERATING DATA:
Daily average production(d):
Crude oil and liquids (MBbls/day)
Domestic.......................... 60.2 58.3 54.9 52.0 50.7
Argentina......................... 2.4 2.4 0.6 -- --
Indonesia......................... 4.1 1.8 -- -- --
-------- -------- ------- ------- -------
66.7 62.5 55.5 52.0 50.7
-------- -------- ------- ------- -------
-------- -------- ------- ------- -------
Natural gas (MMcf/day).............. 165.4 126.3 95.2 102.5 81.6
Total production (MMBOE)............ 94.3 83.6 71.4 69.1 64.3
Average sales prices:
Crude oil and liquids ($/Bbl)
Unhedged
Domestic....................... $ 12.70 $ 14.38 $ 14.07 $ 17.90 $ 14.11
Argentina...................... 14.07 15.99 16.24 -- --
Indonesia...................... 15.50 17.51 -- -- --
Total.......................... 12.93 14.54 14.09 17.90 14.11
Hedged............................ 12.93 14.96 16.16 17.34 14.11
Natural Gas ($/Mcf)
Unhedged.......................... $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72
Hedged............................ 1.89 1.70 1.49 1.57 1.72
Proved reserves at year end(e):
Crude oil, condensate and natural
gas liquids (MMBbls).............. 248.2 255.1 229.2 222.3 219.8
Natural gas (Bcf)................... 263.0 277.5 170.8 185.9 188.0
Proved reserves (MMBOE)............. 292.0 301.5 257.7 253.3 251.1
Proved developed reserves (MMBOE)... 225.5 248.4 210.3 205.0 204.0
Production costs (including related
production, severance and ad valorem
taxes) per BOE (in dollars)......... $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69
</TABLE>
- ---------------
(a) On May 19, 1992, Adobe was merged with and into the Company.
(b) Reflects a non-cash charge of $99.3 million for the impairment of oil and
gas properties recorded as of December 31, 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and Note 1 of the Notes to the Company's Consolidated Financial Statements
included elsewhere in this Prospectus.
(c) Includes losses on property dispositions of $27.8 million, long-term debt
repayment penalties of $8.6 million and accruals of certain personnel
benefits and related costs of $2.2 million.
(d) Includes production attributable to the properties sold to Vintage (closed
in November 1993) and Bridge (closed in April 1994). Production
attributable to such properties during 1993 totaled approximately 4.1 MBbls
of oil per day and 21.7 MMcf of natural gas per day (7.7 MBOE per day).
(e) The estimates set forth in this table for 1993 give effect to the sale by
the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which
sale closed in April 1994.
18
<PAGE> 21
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
As an independent oil and gas producer, the Company's results of operations
are dependent upon the difference between the prices received for oil and gas
and the costs of finding and producing such resources. A substantial portion of
the Company's crude oil production is from long-lived fields where EOR methods
are being utilized. The market price of the heavy (i.e., low gravity, high
viscosity) and sour (i.e., high sulfur content) crude oils produced in these
fields is lower than sweeter, light (i.e., low sulfur and low viscosity) crude
oils, reflecting higher transportation and refining costs. The lower price
received for the Company's domestic heavy and sour crude oil is reflected in the
average sales price of the Company's domestic crude oil and liquids (excluding
the effect of hedging transactions) for 1993 of $12.70 per barrel, compared to
$16.94 per barrel for West Texas Intermediate ("WTI") crude oil (an industry
posted price generally indicative of spot prices for sweeter light crude oil).
In addition, the lifting costs of heavy crude oils are generally higher than the
lifting costs of light crude oils. As a result of these narrower margins, even
relatively modest changes in crude oil prices may significantly affect the
Company's revenues, results of operations, cash flows and proved reserves. In
addition, prolonged periods of high or low oil prices may have a material effect
on the Company's financial position.
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, the
Middle East and other producing countries. See "Business and Properties--Current
Markets for Oil and Gas." The period since mid-1990 has included some of the
largest fluctuations in oil prices in recent times, primarily due to the
political unrest in the Middle East. The actual average sales price (unhedged)
received by the Company ranged from a high of $23.92 per barrel in the fourth
quarter of 1990 to a low of $10.00 per barrel during the three months ended
March 31, 1994. The Company's average sales price for its 1993 oil production
was $12.93 per barrel. Based on operating results of 1993, the Company estimates
that a $1.00 per barrel increase or decrease in average oil sales prices would
have resulted in a corresponding $21.6 million change in 1993 income from
operations and a $16.2 million change in 1993 cash flow from operating
activities. The Company also estimates that a $0.10 per Mcf increase or decrease
in average natural gas sales prices would have resulted in a corresponding $5.8
million change in 1993 income from operations and a $4.4 million change in 1993
cash flow from operating activities. The foregoing estimates do not give effect
to changes in any other factors, such as the effect of the Company's hedging
program or depreciation and depletion, that would result from a change in oil
and natural gas prices.
During 1992 and 1993, certain significant events occurred which affect the
comparability of prior periods, including the merger of Adobe with and into the
Company in May 1992, the formation of the Santa Fe Energy Trust (the "Trust") in
November 1992 and implementation of the corporate restructuring program adopted
in October 1993. The corporate restructuring program includes (i) the
concentration of capital spending in the Company's core operating areas, (ii)
the disposition of non-core assets, (iii) the elimination of the $0.04 per share
quarterly Common Stock dividend and (iv) the recognition of $38.6 million of
restructuring charges. See Note 2 of the Notes to the Company's Consolidated
Financial Statements included elsewhere in this Prospectus and "Business and
Properties--Corporate Restructuring Program." In addition, the Company's results
of operations for 1993 include a charge of $99.3 million for the impairment of
oil and gas properties.
The Company's capital program will be concentrated in three domestic core
areas--the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico
and the San Joaquin Valley of California--as well as its productive areas in
Argentina and Indonesia. The domestic program includes development activities in
the Delaware and Cisco-Canyon formations in west Texas and southeast New Mexico,
a development drilling program for the offshore Gulf of Mexico natural gas
properties and relatively low risk infill drilling in the San Joaquin Valley of
California. Internationally, the program includes development of the Company's
Sierra Chata discovery in Argentina with gas sales expected to commence in early
1995
19
<PAGE> 22
and the Salawati Basin Joint Venture in Indonesia. See "Business and
Properties--Domestic Development Activities" and "--International Development
Activities."
The Company's non-core asset disposition program includes the sale of its
natural gas gathering and processing assets to Hadson Corporation ("Hadson")
(completed in December 1993), the sale to Vintage of certain southern California
and Gulf Coast oil and gas producing properties (completed in November 1993) and
the sale to Bridge of certain Mid-Continent and Rocky Mountain oil and gas
producing properties and undeveloped acreage (completed in April 1994). See
"Business and Properties--Corporate Restructuring Program" for a description of
the transactions with Hadson, Vintage and Bridge. In the first quarter of 1994,
the Company sold the remaining 575,000 Depositary Units which it held in the
Trust for $11.3 million and its interest in certain other oil and gas properties
for $8.3 million. As a result of the Vintage and Bridge dispositions described
above, the Company has sold properties having combined production during 1993 of
4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and estimated
proved reserves of approximately 16.7 MMBOE.
The restructuring program also includes an evaluation of the Company's
capital and cost structures to examine ways to increase flexibility and
strengthen the Company's financial performance. Based upon that evaluation, the
Company determined to proceed with the Refinancing to accomplish its financial
strategy. The evaluation of the Company's cost structure is designed to continue
the Company's efforts to reduce its operating costs and general and
administrative expenses. During the quarter ended March 31, 1994, the Company
recorded $7.0 million in restructuring charges reflecting the estimated costs of
such cost reduction program. See "--Recent Operating Results" and "--Liquidity
and Capital Resources."
In May 1992, Adobe, an oil and gas exploration and production company, was
merged with and into the Company (the "Adobe Merger"). The acquisition was
accounted for as a purchase and the results of operations of the properties
acquired (the "Adobe Properties") are included in the Company's results of
operations effective June 1, 1992. Pursuant to the Adobe Merger, the Company
issued 25,020,117 shares of Common Stock and 5,000,000 shares of its Convertible
Preferred Stock, Series 7%, and assumed approximately $175.0 million of
long-term debt and other liabilities. Pursuant to the Adobe Merger, the Company
also acquired Adobe's proved reserves and inventory of undeveloped acreage. As
of December 31, 1991, Adobe's estimated proved reserves totaled approximately
53.2 MMBOE (net of 6.9 MMBOE attributable to Adobe's ownership in certain gas
plants), of which approximately 58% was natural gas (approximately 66% of
Adobe's estimated domestic proved reserves were natural gas). Approximately 72%
of the discounted future net cash flow of Adobe's estimated domestic proved
reserves was concentrated in three areas of operation--offshore Gulf of Mexico,
onshore Louisiana and in the Spraberry Trend in west Texas. In addition, Adobe's
international operations consisted of certain production sharing arrangements in
Indonesia, in respect of which approximately 6.0 MMBOE of estimated proved
reserves had been attributed to Adobe's interest as of December 31, 1991. The
location of the Adobe Properties enhanced the Company's existing domestic
operations and added significant operations to the Company's international
program.
In November 1992, 5,725,000 Depositary Units ("Depositary Units")
consisting of interests in the Trust were sold in a public offering. After
payment of certain costs and expenses, the Company received net proceeds of
$70.1 million and 575,000 Depositary Units. For any calendar quarter ending on
or prior to December 31, 2002, the Trust will receive additional royalty
payments to the extent necessary to distribute $0.40 per Depositary Unit per
quarter. The source of such payments, if needed, will be limited to the
Company's remaining royalty interest in certain of the properties conveyed to
the Trust. The aggregate amount of such payments are limited to $20.0 million on
a revolving basis. The Company was required to make an additional royalty
payment of $362,000 with respect to the distribution made by the Trust for
operations during the quarter ended December 31, 1993. On April 21, 1994, the
Trust announced that a distribution of $0.40 per Depositary Unit would be paid
for the calendar quarter ended March 31, 1994 to Unitholders of record on May
16, 1994, which distribution will include an additional royalty payment by the
Company of $505,700. See "Business and Properties--Santa Fe Energy Trust."
20
<PAGE> 23
RECENT OPERATING RESULTS
For the three months ended March 31, 1994,the Company reported a net loss
to common shares of $4.3 million, or $0.05 per share, compared to a net loss to
common shares of $2.2 million, or $0.02 per share, in the same period in 1993.
Revenues for the first quarter of 1994 totaled $90.3 million compared to $115.3
million in the same period in 1993. The decline in revenues primarily reflects a
$3.73 per barrel decline in the Company's average sales price for its crude oil
and liquids as compared to its average sales price for the first quarter of
1993. Revenues from the properties sold to Vintage included in the 1993 period
totaled $5.4 million. The Company's costs and expenses totaled $90.3 million in
the first quarter of 1994 compared to $103.3 million in the first quarter of
1993. Lower production and operating costs (down $2.1 million, primarily
reflecting the effect of the Vintage sale), exploration expenses (down $2.1
million) and DD&A expense (down $5.6 million, primarily reflecting the effect of
impairments taken in the fourth quarter of 1993) and the recognition of a $9.4
million gain from the disposition of oil and gas properties were the principal
factors in the reduction in costs and expenses. Costs and expenses for the first
quarter of 1994 include $7.0 million in restructuring charges related to the
Company's cost reduction program. The restructuring charges, designed to reduce
expenses by approximately $30.0 million from the 1993 level (which reduction
includes approximately $5.0 million of non-recurring costs), relate to
severance, benefits and relocation expenses associated with a cost reduction
program that includes a 20% reduction in the Company's salaried work force, a
reduction in other general and administrative expenses and a $10.0 million
reduction in field expenses. Substantially all of this cost reduction program is
expected to be implemented by year end 1994. Net cash provided by operating
activities declined from $41.6 million in the first quarter of 1993 to $14.3
million in the first quarter of 1994, primarily reflecting the factors described
above.
The Company's production during the first quarter of 1994 totaled 5.9
MMBbls of crude oil and liquids and 14.0 Bcf of natural gas compared to 6.0
MMBbls of crude oil and liquids and 16.0 Bcf of natural gas in the first quarter
of 1993. Natural gas production for the first quarter of 1993 included a 1.5 Bcf
positive adjustment attributable to prior periods. Crude oil and liquids sales
prices (unhedged) averaged $10.00 per barrel in the first quarter of 1994
compared to $13.73 per barrel in the first quarter of 1993. Natural gas sales
prices (unhedged) averaged $2.10 per Mcf in the first quarter of 1994 compared
to $1.96 per Mcf in the first quarter of 1993.
RESULTS OF OPERATIONS
The following table sets forth, on the basis of the BOE produced by the
Company during the applicable annual period, certain of the Company's costs and
expenses for each of the years in the three-year period ended December 31, 1993.
<TABLE>
<CAPTION>
1993 1992 1991
------ ------ ------
<S> <C> <C> <C>
Production and operating costs per BOE (a)................... $ 4.76 $ 5.02 $ 5.17
Exploration, including dry hole costs per BOE................ 0.90 0.84 0.72
Depletion, depreciation and amortization per BOE............. 4.44 4.79 4.09
General and administrative costs per BOE..................... 0.94 1.01 1.07
Taxes other than income per BOE (b).......................... 0.79 0.80 1.05
Interest, net, per BOE (c)................................... 0.94 1.58 1.43
</TABLE>
- ---------------
(a) Excluding related production, severance and ad valorem taxes.
(b) Includes production, severance and ad valorem taxes.
(c) Reflects interest expense less amounts capitalized and interest income.
1993 Compared with 1992
Total revenues increased approximately 2% from $427.5 million in 1992 to
$436.9 million in 1993, principally due to an increase in oil and natural gas
production offset by a decline in average oil prices. Average daily oil
production increased 7% from 62.5 MBbls in 1992 to 66.7 MBbls in 1993,
principally due
21
<PAGE> 24
to increased domestic and Indonesian production. The average price realized per
barrel of oil during 1993 was $12.93, a decrease of 14% versus the average price
of $14.96 in 1992. Natural gas production increased 31% from 126.3 MMcf per day
in 1992 to 165.4 MMcf per day in 1993, primarily reflecting the effect of a full
year's production from the Adobe Properties. Average natural gas prices realized
increased approximately 11% from $1.70 per Mcf in 1992 to $1.89 per Mcf in 1993.
Production and operating costs increased $10.4 million in 1993, primarily
reflecting the effect of a full year's costs for the Adobe Properties; however,
on a BOE basis such costs declined from $5.02 per barrel in 1992 to $4.76 per
barrel in 1993. Exploration costs were $5.5 million higher than in 1992
primarily reflecting higher geological and geophysical costs and higher dry hole
costs. DD&A increased $6.4 million in 1993 primarily reflecting a full year's
expense on Adobe Properties partially offset by reduced amortization rates with
respect to certain unproved properties. DD&A for 1993 includes $12.1 million
with respect to the properties sold to Vintage and Bridge. On a BOE basis, DD&A
decreased by $0.35 per barrel, from $4.79 to $4.44 per barrel. General and
administrative costs increased $1.4 million principally due to a $1.8 million
charge related to the adoption of Statement of Financial Standards No.
112--"Employer's Accounting for Postemployment Benefits." Taxes (other than
income) increased by $3.0 million in 1993 primarily reflecting the effect of the
Adobe Properties.
Costs and expenses for 1993 also include $99.3 million in impairments of
oil and gas properties and $38.6 million in restructuring charges. The Company
estimates that the impairments taken in 1993 will result in a $20.0 million
reduction in DD&A in 1994. The restructuring charges include losses on property
dispositions of $27.8 million, long-term debt repayment penalties of $8.6
million and accruals of certain personnel benefits and related costs of $2.2
million. In connection with the property dispositions effected during 1993 (see
"--Liquidity and Capital Resources"), the Company sold properties having
combined production during 1993 of 4.1 MBbls of oil per day and 21.7 MMcf of
natural gas per day and combined estimated proved reserves of approximately 16.7
MMBOE. The Company's income from operations for 1993 includes $8.5 million with
respect to such properties.
Interest income in 1993 includes $6.8 million related to a $10 million
refund received as a result of the completion of the audit of the Company's
federal income tax returns for 1971 through 1980. The decrease in interest
expenses during 1993 reflects a decrease in the Company's debt outstanding and a
$5.7 million credit related to a revision to a tax sharing agreement with the
Company's former parent. Other income and expenses of 1993 includes a $4.0
million charge related to the accrual of a contingent loss with respect to the
operations of a former affiliate of Adobe.
1992 Compared with 1991
Total revenues increased approximately 13% from $379.8 million in 1991 to
$427.5 million in 1992 principally due to an increase of approximately $53.2
million attributable to production from properties acquired in the Adobe Merger
and an increase of approximately $10.7 million and $10.2 million in revenues
from the Company's domestic and Argentine properties, respectively, offset in
part by a decline of $32.0 million in crude oil hedging revenues. Oil production
increased 13% from 55.5 MBbls per day in 1991 to 62.5 MBbls per day in 1992,
reflecting a 3.4 MBbl per day increase in domestic oil production and a 3.6 MBbl
per day increase in production in Argentina and Indonesia. The average price
realized per barrel of oil during 1992 decreased to $14.96, a decrease of 7%
versus the average price of $16.16 in 1991, primarily reflecting a $32.0 million
decrease in hedging revenues. Natural gas production increased 33% from 95.2
MMcf per day in 1991 to 126.3 MMcf per day in 1992 as a result of properties
acquired in the Adobe Merger. Average natural gas prices realized increased
approximately 14% from $1.49 per Mcf in 1991 to $1.70 per Mcf in 1992.
Total operating expenses of the Company increased $54.6 million from $315.4
million in 1991 to $370.0 million in 1992 primarily reflecting costs associated
with the Adobe Merger. Production and operating costs in 1992 were $18.8 million
higher than in 1991, primarily reflecting costs related to the Adobe Properties
and increased fuel costs associated with the Company's EOR projects. On a BOE
basis, production and operating costs declined from $5.17 per barrel in 1991 to
$5.02 per barrel in 1992,
22
<PAGE> 25
primarily reflecting the lower cost structure of the Adobe Properties.
Exploration costs were $6.8 million higher than in 1991 primarily reflecting
higher geological and geophysical costs with respect to foreign projects.
Depletion, depreciation and amortization costs were $39.7 million higher in 1992
due to the acquisition of the Adobe Properties and, to a lesser extent,
adjustments to oil and gas reserves with respect to certain producing
properties. General and administrative costs increased $3.1 million principally
due to a $1.2 million charge related to certain stock awards which fully vested
upon consummation of the Adobe Merger and certain other merger-related costs.
Taxes (other than income) decreased by $2.9 million in 1992, as a result of
lower accruals with respect to property taxes. The $13.6 million gain on the
disposition of properties in 1992 primarily relates to the sale of certain
royalty interest properties, in which the Company had no remaining financial
basis.
The increase in interest expense during 1992 reflects the increase in debt
as a result of the Adobe Merger. Other income and expenses for 1992 includes a
$10.9 million charge for costs incurred by Adobe in connection with the Adobe
Merger and paid by Santa Fe.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company has generally funded capital and exploration
expenditures and working capital requirements from cash provided by operating
activities. Depending upon the future levels of operating cash flows, which are
significantly affected by oil and gas prices, the restrictions on additional
borrowings included in certain of the Company's debt agreements, together with
debt service requirements and dividends, may limit the cash available for future
exploration, development and acquisition activities. Net cash provided by
operating activities totaled $160.2 million in 1993, $141.5 million in 1992 and
$128.4 million in 1991; net cash used in investing activities in such periods
totaled $121.4 million, $15.9 million and $117.2 million, respectively.
The Company's cash flow from operating activities is a function of the
volumes of oil and gas produced from the Company's properties and the sales
prices realized therefor. Crude oil and natural gas are depleting assets.
Therefore, unless the Company replaces over the long term the oil and natural
gas produced from the Company's properties, the Company's assets will be
depleted over time and its ability to service and incur debt at constant or
declining prices will be reduced. The Company's cash flow from operations for
1993 reflects an average sales price (unhedged) for the Company's 1993 oil
production of $12.93 per barrel. For the three months ended March 31, 1994, the
average sales price (unhedged) for the Company's 1994 oil production was $10.00
per barrel. If such lower oil prices prevail throughout 1994, the Company's cash
flow from operating activities for 1994 will be significantly lower than that
for 1993.
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program that focuses on the concentration of capital spending in
core areas and the disposition of non-core assets. The Company's asset
disposition program adopted in connection with the 1993 restructuring program
has been substantially completed by the asset sales to Hadson, Vintage and
Bridge, the sale of the 575,000 Depositary Units in the Trust and the sale of
its interest in certain other oil and gas properties. As a result of such sales,
the Company sold a total of 16.7 MMBOE of proved reserves and undeveloped
acreage for a total of approximately $111.0 million, and sold certain gas
gathering and processing facilities for Hadson securities.
In conjunction with the 1993 restructuring program, the Company also
determined to undertake a review of its capital and cost structures. Based upon
such review of its capital structure, the Company determined to proceed with the
Refinancing in the belief that it will increase the Company's financial
flexibility, strengthen the Company's financial condition and permit the Company
to pursue aggressively its operating strategy. The net proceeds from the
Refinancing will be used to repay existing indebtedness of the Company. See "Use
of Proceeds." The evaluation of the Company's cost structure is designed to
continue the Company's efforts to reduce its operating costs and general and
administrative expenses. During the quarter ended March 31, 1994, the Company
recorded $7.0 million in restructuring charges reflecting the estimated costs of
such cost reduction program. See "--Recent Operating Results."
23
<PAGE> 26
Under the most restrictive covenant in the Company's existing credit
agreements, as of December 31, 1993 the Company could incur up to $64.0 million
of additional indebtedness. After giving effect as of December 31, 1993 to the
consummation of this Offering and the Concurrent DECS Offering and the
application of the net proceeds therefrom, the Company would have been able to
incur up to $149.6 million of additional indebtedness under its most restrictive
covenant. At December 31, 1993, under the Company's most restrictive covenant,
the Company had the ability to pay $26.1 million in dividends on its capital
stock. Pro forma for this Offering and the Concurrent DECS Offering, the Company
would have had the capacity to pay dividends of up to $117.7 million in the
aggregate on its capital stock, including its Convertible Preferred Stock,
Series 7%, and the DECS. However, pursuant to the terms of the Debentures, upon
completion of this Offering and the Concurrent DECS Offering the Company would
have the ability to pay only up to $50.0 million on its Common Stock. The amount
permitted under these covenants to be used to pay dividends will vary over time
depending, among other things, on the Company's earnings and any issuances of
capital stock. The Indenture does not restrict the Company from paying preferred
dividends on the Convertible Preferred Stock, Series 7%, or the DECS; however,
payment of such preferred dividends reduces the Company's capacity under the
Indenture to pay Common Stock dividends.
As a part of the 1993 restructuring program, the Company eliminated its
$0.04 per share quarterly dividend on its Common Stock and announced that it
might spend up to $240 million in 1994 on an accelerated capital program.
However, as a result of the depressed crude oil prices that have prevailed since
November 1993, the Company, consistent with industry practice, has determined to
defer certain of its capital projects in order to prudently manage cash flow in
the near term. Based on current market conditions, the Company has authorized up
to $130 million of capital expenditures during 1994, a level which should allow
the Company to replace its estimated 1994 production, although no assurance can
be given regarding such replacement. The Company intends to continue to monitor
its capital expenditure program throughout the balance of 1994 and may, in
response to industry conditions, including, without limitation, prevailing oil
and natural gas prices and the outlook therefor, revise such program.
The Company is a party to several long-term and short-term credit
agreements which restrict the Company's ability to take certain actions,
including covenants that restrict the Company's ability to incur additional
indebtedness and to pay dividends on its capital stock. For a description of
such credit agreements at December 31, 1993, see Note 7 of the Notes to the
Company's Consolidated Financial Statements included elsewhere in this
Prospectus. For a description of the proposed terms of the Debentures, see
"Description of the Debentures."
Effective February 28, 1994, the Company entered into the Bank Facility
with a group of banks for which Texas Commerce Bank National Association ("Texas
Commerce") and NationsBank of Texas act as co-agents. The Bank Facility consists
of a five year secured reducing revolving credit facility maturing December 31,
1998 ("Facility A") and a three year unsecured reducing revolving credit
facility maturing December 31, 1996 ("Facility B"). Assuming completion of this
Offering and the Concurrent DECS Offering and the application of the net
proceeds therefrom as described in "Use of Proceeds," the initial aggregate
borrowing limits under the Bank Facility would be $175.0 million (up to $90.0
million under Facility A and up to $85.0 million under Facility B), none of
which would be outstanding. Interest rates under the Bank Facility are tied to
LIBOR or Texas Commerce's prime rate, with the actual interest rate reflecting
certain ratios based upon the Company's ability to repay its outstanding debt
and the value and projected timing of production of the Company's oil and gas
reserves. These and other similar ratios will also affect the Company's ability
to borrow under the Bank Facility and the timing and amount of any required
repayments and corresponding commitment reductions. Marc J. Shapiro, a director
of the Company, is the Chairman and Chief Executive Officer of Texas Commerce.
EFFECTS OF INFLATION
Inflation during the three years ended December 31, 1993 has had little
effect on the Company's capital costs and results of operations.
24
<PAGE> 27
ENVIRONMENTAL MATTERS
Almost all phases of the Company's oil and gas operations are subject to
stringent environmental regulation by governmental authorities. Such regulation
has increased the costs of planning, designing, drilling, installing, operating
and abandoning oil and gas wells and other facilities. The Company has expended
significant financial and managerial resources to comply with such regulations.
Although the Company believes its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations. It is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies or claims for damages to property, employees, other
persons and the environment resulting from the Company's operations, could
result in significant costs and liabilities in the future. As it has done in the
past, the Company intends to fund its cost of environmental compliance from
operating cash flows. See also, "Business--Other Business Matters--Environmental
Regulation" and Note 12 of the Notes to the Company's Consolidated Financial
Statements included elsewhere in this Prospectus.
DIVIDENDS
Dividends on the Company's Convertible Preferred Stock, Series 7%, are
cumulative at an annual rate of $1.40 per share. No dividends may be declared or
paid with respect to the Common Stock if any dividends with respect to the
Convertible Preferred Stock, Series 7%, or, assuming consummation of the
Concurrent DECS Offering, the DECS are in arrears. As described elsewhere in
this Prospectus, the Company has eliminated the payment of its $0.04 per share
quarterly dividend on its Common Stock. The determination of the amount of
future cash dividends, if any, to be declared and paid on the Company's Common
Stock is in the sole discretion of the Company's Board of Directors and will
depend on dividend requirements with respect to the Convertible Preferred Stock,
Series 7%, and, assuming consummation of the Concurrent DECS Offering, the DECS,
the Company's financial condition, earnings and funds from operations, the level
of capital and exploration expenditures, dividend restrictions in financing
agreements, future business prospects and other matters the Board of Directors
deems relevant.
25
<PAGE> 28
BUSINESS AND PROPERTIES
GENERAL
The Company is engaged in the exploration, development and production of
oil and natural gas in the continental United States and in certain foreign
areas. At December 31, 1993, the Company had worldwide proved reserves totaling
292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and approximately
263.0 Bcf of natural gas), of which approximately 93% were domestic reserves and
approximately 7% were foreign reserves. During 1993, the Company's worldwide
production aggregated approximately 94.3 MBOE per day, of which approximately
71% was crude oil and approximately 29% was natural gas. A substantial portion
of the Company's domestic oil production is in long-lived fields with
well-established production histories. Pursuant to the Company's corporate
restructuring program (see "--Corporate Restructuring Program" below), the
Company has focused its activities on its three domestic core areas--the Permian
Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin
Valley of California--as well as in Argentina and Indonesia.
For the five years ended December 31, 1993, the Company has replaced
approximately 172% of its production at an average finding cost of $4.80 per
BOE. Over the last four years, the Company has increased overall production by
increasing production from existing properties and through acquisitions. In
addition, the Company has reduced its overall cost structure. For example, over
the four-year period ended December 31, 1993, Santa Fe has increased its average
daily production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993
attributable to production from non-core assets sold pursuant to the corporate
restructuring program) and has reduced its average production costs (including
related production, severance and ad valorem taxes) from $6.22 per BOE in 1990
to $5.39 per BOE in 1993.
Most of the Company's domestic crude oil production is located in
California and Texas, while its domestic natural gas production comes primarily
from the Gulf of Mexico, New Mexico and Texas. During 1993, the Company's
domestic daily production averaged approximately 60.2 MBbls of crude oil and
165.0 MMcf of natural gas. Substantially all of the Company's oil and gas
production is sold at market responsive prices. Pursuant to the corporate
restructuring program, during 1993 the Company sold properties having 1993
combined production of 4.1 MBbls per day and 21.7 MMcf per day and estimated
proved reserves of approximately 16.7 MMBOE. The domestic crude oil marketing
activities of the Company are conducted through its Santa Fe Energy Products
Division ("Energy Products"), which is also engaged in crude oil trading.
Substantially all of the Company's domestic natural gas production is currently
marketed under the terms of a sales contract with Hadson. See "--Current Markets
for Oil and Gas."
A substantial portion of the Company's domestic oil production is in
long-lived fields with well-established production histories and where EOR
methods are employed. As of December 31, 1993, approximately 69% of the
Company's domestic proved crude oil and liquids reserves and 50% of its 1993
average daily domestic production of crude oil and liquids were attributable to
the Midway-Sunset field in the San Joaquin Valley of California, where the
Company first began production in 1905. Nearly all of the reserves in this field
are heavy oil, the production of which depends primarily on steam injection. As
of December 31, 1993, an additional 21% of the Company's domestic proved crude
oil and liquids reserves and approximately 25% of its 1993 average daily
domestic production of crude oil and liquids were attributable to five other oil
producing properties: the Wasson and Reeves fields in the Permian Basin of west
Texas and the South Belridge, Kern River and Coalinga fields in the San Joaquin
Valley.
The Company's foreign production is located in the El Tordillo field in
Argentina and in the Salawati Basin and Salawati Island area of Indonesia.
Production from the El Tordillo field averaged 2.4 MBbls of oil per day in 1993
and production from the Indonesian operations averaged 4.1 MBbls of oil per day
in 1993.
The Company maintains an active exploration and development program, a
significant portion of which consists of EOR projects on the producing fields
discussed above. During 1993, Santa Fe spent a total of $128.6 million on
exploration and development programs and $32.6 million on proved property
acquisitions. In October 1993, the Company announced that its 1994 capital
expenditures could increase
26
<PAGE> 29
to up to $240 million. However, as a result of depressed oil prices that have
prevailed since November 1993, the Company, consistent with industry practice,
has determined to defer certain of its capital projects in order to prudently
manage cash flow in the near term. Based upon current market conditions, the
Company has authorized up to $130 million of capital expenditures during 1994, a
level which should allow the Company to replace its estimated 1994 production,
although no assurance can be given regarding such replacement. The Company
intends to continue to monitor its capital expenditure program throughout the
balance of 1994 and may, in response to industry conditions, including, without
limitation, prevailing oil and natural gas prices and the outlook therefor,
revise such program.
In the United States, at December 31, 1993, the Company held oil and gas
rights to approximately 0.8 million net undeveloped leasehold and fee acres in
14 states, excluding approximately 1.1 million net undeveloped acres sold to
Bridge in April 1994 and 0.1 million net undeveloped fee acres sold to another
company in January 1994. See "--Corporate Restructuring Program." Outside the
United States, at December 31, 1993, the Company held exploration rights with
respect to an aggregate of approximately 3.5 million net undeveloped acres in
Argentina, Bolivia, Canada, Gabon, Indonesia, Morocco, Myanmar and Papua New
Guinea.
CORPORATE RESTRUCTURING PROGRAM
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program designed to improve earnings and cash flow while
increasing production and replacing reserves in the long-term. The restructuring
program is the result of an intensive review of the Company's operations and
cash flows and focuses on the concentration of capital spending in the Company's
core operating areas and the disposition of non-core assets. To provide
additional funding for the capital program, the Company also announced the
elimination of the payment of its $0.04 per share quarterly dividend on the
Common Stock, which will make available approximately $14 million annually. The
dividend on the Company's Convertible Preferred Stock, Series 7%, will remain at
its current level and, assuming consummation of the Concurrent DECS Offering,
dividends on the DECS are expected to be approximately $ million per year.
As a part of the Company's restructuring program, the Company intends to
concentrate its capital spending on its three domestic core areas--the Permian
Basin in Texas and New Mexico, the offshore Gulf Coast and the San Joaquin
Valley of California--as well as its productive areas in Indonesia and
Argentina. The domestic program includes development activities in the Delaware
formation in southeast New Mexico, a development drilling program for the
offshore Gulf of Mexico natural gas properties and infill drilling in the San
Joaquin Valley of California. Internationally, the program includes development
of the Company's Sierra Chata discovery in Argentina with gas sales expected to
commence in early 1995.
The restructuring program includes an evaluation of the Company's capital
and cost structures to examine ways to increase flexibility and strengthen the
Company's financial performance. In this respect, in 1994 the Company determined
to proceed with the Refinancing, of which this Offering and the Concurrent DECS
Offering are a part, pursuant to which approximately $180 million of the
Company's long-term indebtedness will be refinanced, assuming consummation of
such offerings.
As a result of the dispositions described below, the Company has sold
undeveloped leasehold acreage and properties having combined production during
1993 of 4.1 MBbls per day and 21.7 MMcf per day and estimated proved reserves of
approximately 16.7 MMBOE for total proceeds of approximately $91.4 million, has
sold its natural gas gathering and processing assets for Hadson securities and
has realized approximately $11.3 million from the sale of its remaining
Depositary Units in the Trust. In addition, during the first quarter of 1994 the
Company sold its interest in certain oil and gas properties for $8.3 million. As
a result of these transactions, the Company has disposed of substantially all of
its inventory of non-core properties.
27
<PAGE> 30
Sale to Hadson. In December 1993, the Company completed a transaction with
Hadson under the terms of which the Company sold the common stock of Adobe Gas
Pipeline Company ("AGPC"), a wholly owned subsidiary, to Hadson in exchange for
Hadson 11.25% preferred stock with a face value of $52.0 million and 40% of
Hadson's common stock. In addition, the Company signed a seven-year gas sales
contract under the terms of which Hadson will market substantially all of the
Company's domestic natural gas production from specified existing wells and
certain domestic development and exploration wells. Pursuant to such contract,
Hadson will be required to pay the Company for all production delivered at a
price for such gas equal to stipulated published monthly index prices. See
"--Current Markets for Oil and Gas." The Company also designated one-half of the
members of the Hadson Board of Directors.
AGPC's assets include approximately 630 miles of gathering and
transportation lines in Oklahoma, Texas and New Mexico with three processing
plants in west Texas and New Mexico and an intrastate pipeline system supplying
gas to commercial customers in Lubbock, Texas. Hadson's natural gas assets are
predominantly located in southeastern New Mexico and include two gas processing
facilities, a 12 Bcf natural gas storage facility and the 650-mile Llano
intrastate pipeline which has six connections to various interstate pipelines
serving strategic markets in the Midwest, on the East Coast and in southern
California.
Sale to Vintage. In November 1993, the Company completed the sale to
Vintage of certain southern California and Gulf Coast producing properties for
net proceeds totaling $41.3 million in cash. The transaction included most of
the Company's California interests outside its core area in the San Joaquin
Valley as well as certain onshore Gulf Coast properties in Texas, Louisiana and
Mississippi. Production from the properties sold to Vintage averaged
approximately 2.8 MBbls of oil per day and 6.5 MMcf of natural gas per day
during 1993. During 1993 such properties contributed $2.7 million to the
Company's income from operations.
Sale to Bridge. On April 8, 1994, the Company completed the sale to Bridge
of certain Mid-Continent and Rocky Mountain producing and nonproducing oil and
gas properties. The purchase agreement was originally signed in December 1993.
Bridge paid the Company approximately $48 million in cash, reflecting the net
effect of estimated closing adjustments to the original $51 million sales price.
The transaction included substantially all of the Company's assets in the
Anadarko Basin of Oklahoma and Texas as well as its interests in the Rocky
Mountain states, excluding its interests in the Canyon Creek natural gas field
in Wyoming. The undeveloped acreage includes approximately 1.7 million mineral
and leasehold acres and exploratory options on an additional 8.1 million acres.
Production from the properties sold to Bridge averaged approximately 1.3 MBbls
of oil per day and 15.2 MMcf of natural gas per day during 1993. During 1993,
such properties contributed $5.8 million to the Company's income from
operations.
28
<PAGE> 31
RESERVES
The following tables set forth information regarding changes in the
Company's estimates of proved net reserves from January 1, 1991 to December 31,
1993 and the balance of the Company's estimated proved developed reserves at
December 31 of each of the years 1990 through 1993.
<TABLE>
<CAPTION>
INCREASES (DECREASES)
-------------------------------------------------------------------------
NET
BALANCE REVISION EXTENSIONS, PURCHASES CHANGES IN BALANCE
AT OF DISCOVERIES (SALES) OF OWNERSHIP- AT END
BEGINNING PREVIOUS IMPROVED AND MINERALS PARTNER- OF
OF PERIOD ESTIMATES RECOVERY ADDITIONS IN PLACE PRODUCTION SHIP(A) PERIOD
--------- --------- -------- ----------- ---------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved Reserves at December 31,
1991:
Oil and Condensate (MMBbls)..... 222.3 (1.9) 15.9 1.8 10.9 (20.2) 0.4 229.2
Gas (Bcf)....................... 185.9 0.4 0.5 19.6 (3.0) (34.8) 2.2 170.8
Oil Equivalent (MMBOE).......... 253.3 (1.8) 16.0 5.1 10.4 (26.0) 0.7 257.7
Proved Reserves at December 31,
1992:
Oil and Condensate (MMBbls)..... 229.2 14.1 17.0 2.6 15.0 (23.0) 0.2 255.1
Gas (Bcf)....................... 170.8 7.3 1.3 5.6 137.1 (46.2) 1.6 277.5
Oil Equivalent (MMBOE).......... 257.7 15.3 17.2 3.6 37.9 (30.6) 0.4 301.5
Proved Reserves at December 31,
1993:
Oil and Condensate (MMBbls)..... 255.1 (10.8) 26.7 6.2 (4.8) (24.3) 0.1 248.2
Gas (Bcf)....................... 277.5 26.7 -- 55.9 (37.5) (60.4) 0.8 263.0
Oil Equivalent (MMBOE).......... 301.5 (6.3) 26.7 15.4 (11.1) (34.4) 0.2 292.0 (b)
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------------
1993 1992 1991 1990
------ ------ ------ ------
<S> <C> <C> <C> <C>
Proved Developed Reserves (MMBOE)...................................... 225.5 248.4 210.3 205.0
</TABLE>
- ---------------
(a) The information set forth under the column headed "Changes in
Ownership--Partnership" reflects reserve additions attributable to the
Company's increased ownership interest in Santa Fe Energy Partners, L.P.
(the "Partnership") caused by the reinvestment of distributions received by
the Company in respect of its interest in the Partnership. At December 31,
1993, the Company (through its subsidiaries) owned an aggregate 100%
interest in the Partnership.
(b) At December 31, 1993, 5.2 MMBOE were subject to a 90% net profits interest
held by the Trust. See "--Santa Fe Energy Trust."
Historically, the Company has utilized active development and exploration
programs as well as selected acquisitions to replace its reserves depleted by
production. The Company has increased its proved reserves (net of production) by
approximately 35% over the five years ended December 31, 1993. Most of such
increases are attributable to proved reserve additions from the Company's
producing oil properties in the San Joaquin Valley of California and the Permian
Basin in west Texas, proved reserves acquired in the Adobe Merger and other
purchases of oil and gas reserves. At December 31, 1993, the Company's reserves
were 9.5 MMBOE lower than at December 31, 1992, primarily reflecting the sale
during 1993 of properties with reserves totaling 16.7 MMBOE partially offset by
additions.
29
<PAGE> 32
The following table sets forth as of December 31, 1993 the Company's
estimated proved reserves and the discounted net present value thereof in each
of the Company's principal operating areas.
<TABLE>
<CAPTION>
NATURAL OIL PRE-TAX
OIL GAS EQUIVALENT PV1O(A)
OPERATING REGION (MMBBLS) (MMCF) (MMBOE) (IN MILLIONS)
- ---------------- -------- ------- ---------- -------------
<S> <C> <C> <C> <C>
Permian Basin.............................. 41.6 45.8 49.2 $ 128.1
Offshore Gulf of Mexico.................... 3.8 103.8 21.1 169.8
San Joaquin Valley......................... 183.6 11.8 185.6 167.1
Other Domestic............................. 1.9 74.5 14.3 78.2
International.............................. 17.3 27.1 21.8 24.6
----- ----- ------ -------
Total.................................... 248.2 263.0 292.0 $ 567.8
----- ----- ----- -------
----- ----- ----- -------
</TABLE>
- ---------------
(a) Represents the net present value (discounted at 10%) of the pre-tax future
net cash flows estimated to result from production of the Company's
estimated proved reserves using estimated sales prices and estimates of
production costs, ad valorem and production taxes and future development
costs necessary to produce such reserves. The sales prices used in the
determination of proved reserves and of estimated future net cash flows are
based on the prices in effect at year end, and for 1993 averaged $9.27 per
barrel for oil and $2.17 per Mcf for natural gas. The average sales price
(unhedged) realized by the Company for its production during 1993 was
$12.93 per barrel for oil and $2.03 per Mcf for natural gas.
Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum
engineers, prepared the above estimates of the Company's total proved reserves
as of December 31, 1990 through 1993.
During 1993 the Company filed Energy Information Administration Form 23
which reported natural gas and oil reserves for the year 1992. On an equivalent
barrel basis, the reserve estimates for the year 1992 contained in such report
and those reported herein for the year 1992 do not differ by more than five
percent.
DOMESTIC DEVELOPMENT ACTIVITIES
The Company is engaged in development activities primarily through the
application of thermal enhanced recovery techniques to its heavy oil properties
in the San Joaquin Valley, the use of secondary waterfloods and tertiary CO2
floods on its properties in other mature fields and the development of producing
properties acquired by the Company through its exploration successes and its
acquisition program. Thermal EOR operations involve the injection of steam into
a reservoir to raise the temperature and reduce the viscosity of the heavy oil,
facilitating the flow of the oil into producing wellbores. The Company has
operated thermal EOR projects in the San Joaquin Valley since the mid-1960s.
Similarly, the Company has extensive experience in the use of waterfloods, which
involve the injection of water into a reservoir to drive hydrocarbons into
producing wellbores. The Company has an interest in more than 50 waterflood
projects, and additional projects are planned for the future. Following the
waterflood phase, certain fields may continue to produce in response to tertiary
EOR projects, such as the injection of CO2 which mixes miscibly with the oil and
improves the displacement efficiency of the water injection. The Company's
principal CO2 floods are in the Wasson field and are operated by affiliates of
Shell Oil Company, ARCO and Amoco.
Set forth below is a discussion of some of the Company's principal
development projects. The Company has operated in the Midway-Sunset and Wasson
fields since 1905 and 1939, respectively. The Company acquired interests in the
South Belridge field from Petro-Lewis in 1987 and in January 1991 expanded its
holdings in the field with the purchase of certain properties from Mission
Operating Partnership, L.P. The Company's interests in the Kern River and
Coalinga fields were acquired in 1905 and 1977, respectively. The Gulf of Mexico
fields were discovered on leases held by the Company or
30
<PAGE> 33
acquired in the Adobe Merger, while the Delaware and Cisco-Canyon properties
were acquired as undeveloped properties.
SAN JOAQUIN VALLEY
Midway-Sunset. The Company owns a 100% working interest (92% average net
revenue interest) in over 10,000 gross acres and 2,200 active wells in the
Midway-Sunset field. Substantially all the oil produced from the Midway-Sunset
field is heavy crude oil produced principally by cyclic steam and steamflood
operations from Pleistocene and Miocene reservoirs at depths less than 2,000
feet. These steam stimulation operations were initiated in the field in the
mid-1960s. During 1993 the Midway-Sunset field accounted for approximately 50%
of the Company's domestic crude oil and liquids production.
At December 31, 1993 the Midway-Sunset field accounted for approximately
69% of the Company's domestic proved crude oil and liquid reserves. Reservoir
engineering studies prepared on behalf of the Company indicate significant
additions to its proved reserves in this field can continue to be made through
additional EOR and development projects. The Company has identified a
substantial number of locations that could be drilled in the field, depending in
part on future prices and economic conditions. The Company is pursuing
electrical cogeneration opportunities which could lower Midway-Sunset operating
costs.
South Belridge. The South Belridge field is located approximately 15 miles
north of the Midway-Sunset field. The Company operates three leases in the field
which produce heavy oil from the shallow Tulare sands and lighter low viscosity
oil from the deeper Diatomite reservoirs. Steamflood operations in the lower
Tulare sands are in progress on one of these leases and plans call for flooding
the remaining Tulare sands on this lease and all Tulare sands on another lease
in the coming years. Waterflood operations in the Diatomite reservoir have been
initiated on two leases and the Company expects to expand these operations to
include the rest of the developed area.
Coalinga. The Coalinga field is located 55 miles southwest of Fresno,
California. Successful steamfloods and a pilot steamflood project have been
conducted in the Lower Temblor Sands on three of the six leases in which the
Company owns interests in the field. During the next several years, the Company
plans to expand the pilot steamflood project in the lower sands to cover the
remaining producing area and expand steam floods on the Upper Temblor Sands on
all leases after depletion of the lower zones. Most of the facilities required
for these projects are already in place as a result of the prior steamfloods.
Kern River. The Kern River field is located near Bakersfield, California.
The Lower Kern River Series sands have been successfully steamflooded on three
of the leases in which the Company owns an interest. Over the next several years
steamflood operations will be sequentially redeployed in the upper sands of the
Kern River Series. Eventually the Company plans to flood all sands on its
remaining leases in several stages. The Company has installed and operates a
large steam generation plant on these properties.
PERMIAN BASIN
Wasson. The Company's interests in the Wasson field principally consist of
royalty and working interests in three units which are presently under CO2
flood. Most of the expenditures for plant, facilities, wells and equipment
necessary for such tertiary recovery projects have been made. In addition, while
expenditures relating to the purchase of CO2 for the Wasson field are expected
to continue, CO2 can be recycled and, therefore, such expenditures should
decline in the future.
During 1993, the Wasson field accounted for approximately 9% of the
Company's domestic crude oil and liquids production and at December 31, 1993 the
field accounted for approximately 8% of the Company's domestic proved crude oil
and liquids reserves. Since initiation of CO2 flooding operations in 1984, the
field's previous production decline has been reversed. Reservoir engineering
studies prepared
31
<PAGE> 34
on behalf of the Company indicate significant additions to proved reserves can
be made through additional EOR and development projects.
Reeves. The Company owns a 72% net interest in the Reeves field, seven
miles east of the large Wasson field in west Texas. The field has been under
waterflood since 1965. During 1993, six wells were drilled and 16 wells were
worked over as part of a program to delineate the extended productive limits of
the field, to evaluate the potential for infill drilling and to enhance current
waterflood operations. Based on the successes of the prior year's program, the
Company plans to initiate an infill drilling and workover program in this field
in the near future.
New Mexico. During 1993, the Company increased its activity in the
light-oil Delaware prospect in Lea and Eddy Counties of southeast New Mexico. A
total of 51 gross (18.1 net) development wells were completed in 1993 with a
100% success rate and during December 1993 such wells produced approximately 1.4
MBbls of oil per day and 3.1 MMcf of natural gas per day. Net production from
this area during December 1993 totaled approximately 1.5 MBbls of oil per day
and 4.0 MMcf of natural gas per day. The Company plans to drill additional
development wells in 1994.
Also in southeastern New Mexico, the Company participated in five gross
(2.8 net) wells in 1993 in the light oil and gas Cisco-Canyon project. Four
wells were completed as producers from the Cisco-Canyon zone by year-end and a
fifth continued production testing. The Company plans to continue delineation of
this play which contains some 75 identified potential development locations.
OFFSHORE GULF OF MEXICO
At December 31, 1993, offshore Gulf of Mexico properties accounted for 39%
of the Company's proved natural gas reserves and during 1993 these properties
accounted for approximately 56% of the Company's natural gas production.
In the Gulf Division, several new fields or field additions were placed on
production during 1993. Net production from these fields at year-end averaged
approximately 29.0 MMcf of gas per day. Further development in these fields is
either planned or under study for 1994 and 1995. The Company's activities in the
offshore Gulf of Mexico are conducted in shallow water (less than 300 feet),
where the costs of drilling, completion and production are not as uncertain as
are the costs in the Flextrend and Deepwater areas of the Gulf of Mexico. During
1993, the Company participated in the drilling of four gross (1.3 net)
exploratory wells and one gross (0.3 net) well was drilling at year-end (which
well resulted in a discovery and a multi-well development program is expected to
commence in 1994). For a description of the Company's leasehold position in the
offshore Gulf of Mexico, see "--Domestic Exploration Activities."
DOMESTIC EXPLORATION ACTIVITIES
The Company's domestic exploration focus continues to be in the Permian
Basin and the offshore Gulf of Mexico. Overall the Company participated in 22
gross (9.0 net) exploratory wells in 1993. A total of ten gross (3.6 net) were
completed as producers for a 40% net well success. At year end there were nine
gross (4.3 net) wells in some stage of drilling or completion.
As of December 31, 1993, the Company held approximately 0.3 million net
undeveloped leasehold acres in 14 states and offshore areas, excluding
approximately 0.5 million net undeveloped leasehold acres sold to Bridge in
April 1994. The primary terms of lease expire with respect to 24% of such
acreage in 1994, 25% in 1995, 15% in 1996, 10% in 1997 and the remainder
thereafter. In addition, the Company owns approximately 0.5 million net acres of
undeveloped fee minerals in Louisiana, Texas and California.
The Company also controls the oil and gas rights on approximately 8.1
million net undeveloped acres in the western United States through direct
ownership and pursuant to lease option agreements from Santa Fe Pacific Railroad
Company and other former affiliates. These lands are located in high risk
exploration areas. Due to this risk, the Company has historically negotiated
with third parties to explore this acreage with the Company to receive a royalty
or carried interest in the exploration phase. An
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<PAGE> 35
agreement relating to substantially all of these oil and gas rights has been
entered into with Bridge. This agreement is intended to provide incentive to
Bridge to accelerate exploration activities on lands subject to these rights.
The Company will receive a small revenue interest in the event such activities
are successful.
Set forth below is a brief discussion of some of the Company's principal
exploration programs.
Permian Basin. This area continues to be one of the Company's most active
and successful exploration areas. During 1993, the Company participated in 18
gross (7.7 net) exploratory wells. Eight gross (3.3 net) of these were completed
in 1993 as oil or gas discoveries. Additionally, eight gross (4.0 net) were in
some phase of drilling or completing at year-end.
Drilling objectives for the Company's exploratory program target oil and
gas zones at depths of between 2,500 to 15,000 feet. The shallower targets such
as the Delaware and Cisco-Canyon formations are providing successful results.
The Delaware program in southeast New Mexico was the subject of seven gross (3.7
net) exploratory and 51 gross (18.1 net) development wells completed in 1993. A
success rate of 58% of the net exploratory wells and 100% of the net development
wells was achieved in this increasingly active light oil play. Currently, the
Company has identified in excess of 150 development well locations and has 20
exploratory prospects in inventory to be drilled over the next several years.
In the west Texas Permian Basin, the Company completed the shooting of 3-D
seismic over its 250-square mile block near Midland last fall. The joint venture
block contains over 100,000 net acres of lands owned or controlled by the
Company and its partners. Almost all of the Company's 25% interest in the 3-D
seismic was paid by a promoted partner. Drilling began in December 1993 on two
prospects identified in this program. Additional drilling is planned on a
variety of other prospects in 1994 at depths of 10,000 to 12,000 feet.
Offshore Gulf of Mexico. The Company participated in four gross (1.3 net)
exploratory wells in the offshore Gulf of Mexico in 1993 and one gross (0.3 net)
was drilling at year-end. One gross (0.3 net) well resulted in a discovery on
which a multi-well development program will commence in the first quarter of
1994.
The Company acquired 3-D seismic coverage over 12 blocks during 1993 adding
to its extensive Gulf of Mexico seismic database which includes 3-D coverage on
57 blocks. Currently, the Company has 35 exploratory prospects in inventory and
some 30 development locations identified, a portion of which are exploratory and
planned to be drilled in 1994.
At year-end, the Company owned 179 blocks of acreage in the offshore Gulf
of Mexico consisting of approximately 299,800 gross (147,400 net) undeveloped
acres and 257,900 gross (79,000 net) developed acres.
INTERNATIONAL DEVELOPMENT ACTIVITIES
Indonesia. The Company, through a wholly owned subsidiary, is engaged in
the production of crude oil in Indonesia through a joint venture (the "Salawati
Basin Joint Venture") formed in 1970 to explore for and develop hydrocarbon
reserves in the Salawati Basin area of Irian Jaya. At December 31, 1993, the
Company held a 33 1/3% participation interest in, and acts as operator for, the
Salawati Basin Joint Venture. The Salawati Basin Joint Venture operates under a
production sharing contract (the "PSC") with the Indonesia state oil agency
("Pertamina"), which had an initial term of 30 years and expires in the year
2000. The Company is currently negotiating with such state oil agency to extend
the contract for an additional 20 years. As of December 31, 1993, the contract
covered an area of approximately 235,000 acres. Production occurs from seven oil
and three gas condensate fields.
The PSC entitles the Salawati Basin Joint Venture to recover all of its
expenditures related to the operation (the "cost recovery amount") before any
additional production is shared with the Indonesian state oil agency, which
recovery is effected by allocating to the Salawati Basin Joint Venture a portion
of the crude oil production sufficient, at the Indonesian government official
crude oil price ("ICP"), to offset
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<PAGE> 36
the cost recovery amount. The balance of production after the cost recovery
amount is divided between the parties, with approximately 66% allocated to
Pertamina and 34% allocated to the Salawati Basin Joint Venture. However, 25% of
the 34% pre-tax portion (8.5% of total production) must be sold into the
Indonesian domestic market for $0.20 per barrel. The entire entitlement of the
Salawati Basin Joint Venture under the PSC, including the domestic market
obligation, averaged approximately 10.1 MBbls per day (approximately 3.4 MBbls
per day net to the Company) for the year ended December 31, 1993. The Salawati
Basin Joint Venture is required to pay Indonesian income taxes at the rate of
56%.
The Company, through another subsidiary, has also entered into a joint
venture with Pertamina to explore the Salawati Island Block of Irian Jaya. The
effective date of this joint venture is April 23, 1990 with a term of 30 years.
At December 31, 1993, the Company held a 16 2/3% participation interest in the
block which covers 1.09 million acres. The Company and Pertamina (with its 50%
interest) jointly operate the contract area. In 1991, a successful exploratory
well tested at a combined rate of 3.6 MBbls of oil per day and was followed by
two successful delineation wells. Pertamina declared the field commercial in
January 1993 and designated it as the Matoa field. Sales of production began in
January 1993. Development activities through 1993 have the Matoa field producing
approximately 5.6 MBbls of oil per day from eight wells as of December 31, 1993.
Under the terms of the PSC, the joint venture participants are allowed to
recover the cost recovery amount, after an initial 20% portion (2.9% to the
joint venture participants and 17.1% to Pertamina) has been deducted, by
allocating to the joint venture participants a portion of the crude oil
production ("cost oil") sufficient to offset the cost recovery amount. All
unrecovered costs in any calendar year can be carried forward to future years.
The balance of production after allocation of cost oil is allocated
approximately 85.5% to Pertamina and 14.5% to the other Salawati Island Venture
participants. However, 7.25% of the gross production allocated to the joint
venture participants must be sold into the Indonesian domestic market for 10% of
ICP.
Argentina. In 1991, the Company, through a wholly owned subsidiary,
acquired an 18% non-operated working interest (15.84% net interest) in the El
Tordillo field in Chubut Province, Argentina. At that time, the field was
producing approximately 10,500 barrels of oil per day. The Company has agreed to
spend approximately $16.7 million net during the period from July 1, 1992 to
July 1, 1996 on development and maintenance of the field which began with an
extensive workover and recompletion program. As of December 31, 1993 the El
Tordillo owners have completed 163 such workovers and drilled three new wells.
During that time, production increased to approximately 16.0 MBbls of oil per
day. The Company expects this program to continue through 1994 and anticipates
an expansion of the existing waterflood facilities.
Under the terms of the contract with the Argentine national oil company,
the joint venture group is allowed to sell crude oil produced from this field
into the open market. There is a 12% royalty on gross production and the joint
venture is taxed at a 30% rate after deductions for capitalized costs and
expenses.
In April 1993, the Company's subsidiary completed the Sierra Chata X-1 as a
successful exploratory test in Chihuidos Block, Neuquen Province, Argentina. The
well produced at a combined rate of 22.2 MMcf per day and 109 barrels of
condensate per day. Carbon dioxide content of the natural gas was 6%. Five
successful delineation wells were drilled in 1993. Producing rates on these
wells varied from 3.2 MMcf to 27.6 MMcf per day. Engineering and geological
studies are presently being undertaken to develop the field through additional
drilling, with 4.0 gross (1.0 net) additional wells currently planned for 1994.
In addition, the Company and its partners intend to build a gas processing
facility and a 40-mile gathering pipeline during 1994 that will transport
production from the field and interconnect with a main transmission line owned
by a third party that transports gas to Buenos Aires and other major markets.
Construction of the gas processing facility and the pipeline and the drilling of
the development wells are estimated to cost an aggregate of $76.0 million gross
($17.2 million net to the Company's interest). The Company expects that sales of
production from the Sierra Chata discovery will commence in 1995.
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<PAGE> 37
INTERNATIONAL EXPLORATION ACTIVITIES
In 1993, the Company had its most active year ever in the international
arena. The Company participated in six gross (1.8 net) exploratory wells of
which two gross (0.5 net) were completed as natural gas wells. Additionally,
four gross (1.2 net) wells were either drilling or completing at year-end.
The Company made one exploration discovery in 1993. The Sierra Chata
natural gas discovery in the Neuquen Basin of Argentina is being developed from
sandstone reservoirs at 6,000 feet. The Company has a 22.5% working interest
(20% net revenue interest) and is operator of this field. To date a total of six
gross (1.3 net) wells have been drilled with no dry holes. Combined gross flow
rates from these six wells are in excess of 100 MMcf of gas and 500 barrels of
condensate per day. Additional development drilling will continue during 1994 to
increase production capacity and further define the limits of the field. See
"--International Development Activities."
The Company plans to drill eight gross (2.8 net) wells in 1994 in addition
to the four gross (1.2 net) wells which carried over from 1993 in either a
drilling or completing status. The 1994 drilling and exploratory activity will
be centered principally in Indonesia and South America. Of the total wells to be
completed in 1994, four gross (1.2 net) are in Indonesia, four gross (1.3 net)
are in Argentina and Bolivia, one gross (0.2 net) is in Papua New Guinea, two
gross (1.0 net) are in Canada and one gross (0.3 net) is in Gabon (West Africa).
The Company holds exploration contracts totaling 3.5 million net acres in
eight foreign countries. The majority of acreage is in Indonesia (1.1 million
net acres) and South America (1.2 net million acres) with the balance in Canada,
Morocco, Myanmar, Papua New Guinea and Gabon.
DRILLING ACTIVITIES
The table below sets forth, for the periods indicated, the number of wells
drilled in which the Company had an economic interest. As of December 31, 1993,
the Company was in the process of drilling or completing 9 gross (4.3 net)
domestic exploratory wells and 13 gross (5.3 net) domestic development wells, 4
gross (1.2 net) foreign exploratory wells and 3 gross (1.0 net) foreign
development wells.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1993 1992 1991
---------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ----- ------- ---- ----- ------
<S> <C> <C> <C> <C> <C> <C>
Development Wells
Domestic
Completed as natural gas wells......... 21 6.0 6 1.5 25 7.5
Completed as oil wells................. 237 180.0 62 39.0 220 167.3
Dry holes.............................. 10 3.6 5 0.4 6 1.6
Foreign
Completed as natural gas wells......... 4 1.0 -- -- -- --
Completed as oil wells................. 3 0.9 -- -- -- --
--- ----- -- ---- --- -----
275 191.5 73 40.9 251 176.4
--- ----- -- ---- --- -----
Exploratory Wells
Domestic
Completed as natural gas wells......... 3 0.9 1 0.3 6 2.0
Completed as oil wells................. 7 2.7 4 1.2 6 1.9
Dry holes.............................. 12 5.4 2 0.6 19 7.2
Foreign
Completed as natural gas wells......... 2 0.4 -- -- -- --
Completed as oil wells................. -- -- 1 0.3 -- --
Dry holes.............................. 4 1.3 4 1.3 3 0.4
--- ----- -- ---- --- -----
28 10.7 12 3.7 34 11.5
--- ----- -- ---- --- -----
303 202.2 85 44.6 285 187.9
--- ----- -- ---- --- -----
--- ----- -- ---- --- -----
</TABLE>
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<PAGE> 38
DOMESTIC ACREAGE
The following table summarizes the Company's developed and undeveloped fee
and leasehold acreage in the United States at December 31, 1993. Excluded from
such information is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
<TABLE>
<CAPTION>
UNDEVELOPED DEVELOPED
--------------------- ---------------------
GROSS NET GROSS NET
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Alabama--Offshore................................ -- -- 23,040 12,480
Alabama--Onshore................................. 3,089 108 6,063 382
Arkansas......................................... 633 493 4,177 3,173
California--Offshore............................. -- -- 17,280 2,074
California--Onshore.............................. 249,207 248,990 7,391 7,011
Colorado......................................... -- -- 6,368 5,657
Illinois......................................... 202 50 43 13
Kansas........................................... 19,433 19,373 4,591 1,002
Louisiana--Offshore.............................. 222,376 116,843 190,675 57,721
Louisiana--Onshore............................... 17,575 16,620 14,635 2,941
Michigan......................................... -- -- 71 11
Mississippi...................................... 114 30 3,724 810
Montana.......................................... -- -- 3,196 142
Nevada........................................... 3,491 764 9,455 9,455
New Mexico....................................... 195,750 155,594 41,427 18,852
New York......................................... -- -- 189 47
North Dakota..................................... 1,509 544 4,337 1,377
Oklahoma......................................... 1,917 1,917 29,589 9,940
Texas--Offshore.................................. 77,397 30,545 67,194 21,243
Texas--Onshore................................... 180,828 174,912 246,287 168,421
Utah............................................. 1,348 575 8,389 3,494
Wyoming.......................................... 13,785 10,804 25,888 11,312
------- ------- ------- -------
988,654 778,162 714,009 337,558
------- ------- ------- -------
------- ------- ------- -------
</TABLE>
The foregoing table excludes approximately 2,033,400 gross (1,682,000 net)
undeveloped fee and leasehold acres and 80,200 gross (45,900 net) developed
acres sold to Bridge in April 1994 pursuant to a purchase agreement signed in
December 1993 and 123,000 gross (123,000 net) undeveloped acres sold in January
1994.
FOREIGN ACREAGE
The following table summarizes the Company's foreign acreage at December
31, 1993:
<TABLE>
<CAPTION>
UNDEVELOPED DEVELOPED
------------------------- -------------------
GROSS NET GROSS NET
----------- --------- ------- -------
<S> <C> <C> <C> <C>
Argentina...................................... 2,103,010 550,457 53,988 10,858
Bolivia........................................ 1,442,446 649,100 -- --
Canada (Alberta)............................... 150,703 68,071 -- --
Gabon.......................................... 701,000 175,250 -- --
Indonesia...................................... 4,439,569 1,059,193 9,360 2,870
Morocco........................................ 1,300,000 422,500 -- --
Myanmar........................................ 394,000 315,200 -- --
Papua New Guinea............................... 1,970,000 295,500 -- --
---------- --------- ------ ------
12,500,728 3,535,271 63,348 13,728
---------- --------- ------ ------
---------- --------- ------ ------
</TABLE>
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<PAGE> 39
CURRENT MARKETS FOR OIL AND GAS
The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and gas. For the last several years,
prices of these products have reflected a worldwide surplus of supply over
demand. The price received by the Company for its crude oil and natural gas
depends upon numerous factors beyond the Company's control, including economic
conditions in the United States and elsewhere and the world political situation
as it affects OPEC, the Middle East (including the current embargo of Iraqi
crude oil from worldwide markets) and other producing countries, the actions of
OPEC and governmental regulation. The fluctuation in world oil prices continues
to reflect market uncertainty regarding OPEC's ability to control member country
production and underlying concern about the balance of world demand for and
supply of oil and natural gas. Decreases in the prices of oil and gas have had,
and could have in the future, an adverse effect on the Company's development and
exploration programs, proved reserves, revenues, profitability, cash flow and
dividend levels. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--General."
The Company believes the market for heavy crude oil produced in California
differs substantially from the remainder of the domestic crude oil market. It is
necessary to heat or dilute heavy oil to make it flow, which increases
transportation and handling costs, and it is also more costly to refine. As a
result, the price paid for heavy crude oil is generally lower than the price
paid for light crudes. In addition, there is currently an oversupply of crude
oil in the California market that has had an adverse effect on the prices for
crude oil in that market. Although no assurance can be given, the Company
believes that such oversupply will not continue for the long term due to the
availability of crude oil pipelines to transport excess crude oils, including
blended oils, to markets in the Midwest and west Texas, and due to the decline
of crude oil produced from the North Slope of Alaska.
From time to time the Company has hedged a portion of its oil and natural
gas production to manage its exposure to volatility in prices of oil and natural
gas. The Company used several instruments whereby monthly settlements were based
on the difference between the price, or a range of prices, specified in the
instruments and the monthly average of the daily settlement prices of certain
WTI crude oil futures contracts or of certain natural gas futures contracts
quoted on the New York Mercantile Exchange. In instances where the actual
average of the daily settlement price was less than the price specified in the
contract, the Company received a settlement based on the difference; in
instances where the actual average of the daily settlement price was higher than
the specified price, the Company paid an amount based on the difference. The
instruments utilized by the Company differed from futures contracts in that
there was no contractual obligation which required or allowed for the future
delivery of the product. Settlements were included in revenues in the period in
which the oil and natural gas were sold.
In 1990, oil hedges resulted in a $10.7 million reduction in oil revenues
and in 1991 and 1992 oil hedges resulted in an increase in oil revenues of $41.7
million and $9.7 million, respectively. The Company has had no oil hedging
contracts subsequent to 1992. In 1992 and 1993, natural gas hedges resulted in a
reduction in natural gas revenues of $0.5 million and $8.2 million,
respectively. The Company currently has six open natural gas hedging contracts
covering an aggregate of approximately 24.6 MMcf of natural gas per day with
terms beginning in March and April 1994 and ending in August and September 1994.
The "approximate break-even price" (the average of the monthly settlement prices
of the applicable futures contracts which would result in no settlement being
due to or from the Company) with respect to such contracts is approximately
$1.88 per Mcf. In addition, a certain party holds an option to exercise an
additional hedging contract for a five-month period beginning May 1994 covering
approximately 4.7 MMcf of natural gas per day at an approximate break-even price
of $1.92 per Mcf. The Company has no other outstanding natural gas hedging
instruments.
During 1993, affiliates of Shell Oil Company and Celeron Corporation
accounted for approximately 23% and 15%, respectively, of the Company's domestic
crude oil and liquids and natural gas revenues. No other individual customer
accounted for more than 10% of such revenues during 1993. Substantially all of
the Company's oil and natural gas production is currently sold at
market-responsive prices that approximate spot prices. Availability of a ready
market for the Company's oil and gas production depends
37
<PAGE> 40
on numerous factors, including the level of consumer demand, the extent of
worldwide oil production, the cost and availability of alternative fuels, the
cost of and proximity of pipelines and other transportation facilities,
regulation by state and federal authorities and the cost of complying with
applicable environmental regulations.
In December 1993, the Company signed a seven-year gas sales contract with
Hadson pursuant to the terms of which Hadson will market substantially all of
the Company's domestic natural gas production. Pursuant to such gas contract,
Santa Fe dedicated to Hadson all of its domestic natural gas production from
specified existing wells, which consist of essentially all of the Company's
domestic natural gas production, except to the extent such production was
dedicated under pre-existing contracts. Upon the expiration of any such
pre-existing contracts, that production shall also be dedicated to Hadson.
In addition to production from existing wells, such gas contract provides
for the dedication by the Company of gas production from certain domestic
development wells and exploration wells to the extent that the Company accepts
proposals from Hadson to gather and market production from such exploration
wells. Production from gas wells acquired by the Company pursuant to an
acquisition of producing oil and gas properties will not be dedicated under the
gas contract but may be dedicated by the mutual agreement of the Company and
Hadson.
Pursuant to the gas contract, Hadson will be required to pay the Company
for all production delivered at a price for such gas equal to stipulated
published monthly index prices. Hadson is obligated to use its best efforts to
receive gas from the Company at delivery points so as to maximize the net price
received by the Company for such production. Payment for purchases by Hadson are
to be made in immediately available funds no later than the last working day of
the month following the month of production.
SANTA FE ENERGY TRUST
In November 1992, 5,725,000 Depositary Units, each consisting of beneficial
ownership of one unit of undivided interest in the Trust and a $20 face amount
beneficial ownership interest in a $1,000 face amount zero-coupon United States
Treasury obligation maturing on February 15, 2008, were sold in a public
offering. The assets of the Trust consist of certain oil and gas properties
conveyed by the Company. 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. The
Company received the remaining $70.1 million of proceeds and retained 575,000
Depositary Units. A portion of the proceeds received by the Company was used to
retire $30.0 million of the debt incurred in connection with the Adobe Merger
and the remainder was used for general corporate purposes. In the first quarter
of 1994, the Company sold the remaining 575,000 Depositary Units it held for
$11.3 million.
The properties conveyed to the Trust consisted of two term royalty
interests in two production units in the Wasson field in west Texas and a net
profits royalty interest in certain royalty and working interests in a
diversified portfolio of properties located in 12 states. At December 31, 1993,
5.2 MMBOE of the Company's estimated proved reserves were subject to such net
profits interest. The reserve estimates included herein reflect the conveyance
of the Wasson term royalties to the Trust.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments to the extent that such payments are
required to provide distributions of $0.40 per Depositary Unit per quarter. Such
additional royalty payments, if needed, will come from the Company's remaining
royalty interest in one of the production units in the Wasson field described
above, and are non-recourse to the Company. If such additional payments are
made, certain proceeds otherwise payable to the Trust in subsequent quarters may
be reduced to recoup the amount of such additional payments. The aggregate
amount of the additional royalty payments (net of any amounts recouped) are
limited to $20.0 million on a revolving basis. The Company was required to make
an additional royalty payment of $362,000 with respect to the distribution made
by the Trust for operations during the quarter ended
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<PAGE> 41
December 31, 1993. On April 21, 1994, the Trust announced that a distribution of
$0.40 per Depositary Unit would be paid for the calendar quarter ended March 31,
1994 to Unitholders of record on May 16, 1994, which distribution will include
an additional royalty payment by the Company of $505,700.
OTHER BUSINESS MATTERS
Competition
The Company faces competition in all aspects of its business, including,
but not limited to, acquiring reserves, leases, licenses and concessions;
obtaining goods, services and labor needed to conduct its operations and manage
the Company; and marketing its oil and gas. The Company's competitors include
multinational energy companies, government-owned oil and gas companies, other
independent producers and individual producers and operators. The Company
believes that its competitive position is affected by price, its geological and
geophysical capabilities and ready access to markets for production. Many
competitors have greater financial and other resources than the Company, more
favorable exploration prospects and ready access to more favorable markets for
their production. The Company believes that the well-defined nature of the
reservoirs in its long-lived oil fields, its expertise in EOR methods in these
fields, its active development and exploration position and its experienced
management may give it a competitive advantage over some other producers.
Regulation of Crude Oil and Natural Gas
The petroleum industry is subject to various types of regulation throughout
the world, including regulation in the United States by state and federal
agencies. Domestic legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue and have issued rules and regulations binding on
the oil and gas industry and its individual members, compliance with which is
often difficult and costly and which may carry substantial penalties for
non-compliance. Although the regulatory burden on the oil and gas industry
increases the cost of doing business and, consequently, affects profitability,
generally these burdens do not appear to affect the Company any differently or
to any greater or lesser extent than other companies in the industry with
similar types and quantities of production. While the Company is a party to
several regulatory proceedings before governmental agencies arising in the
ordinary course of business, management does not believe that the outcome of
such proceedings will have a material adverse affect on the operations or
financial condition of the Company. Set forth below is a general description of
certain state and federal regulations which have an effect on the Company's
operations.
State Regulation. State statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning operations. Most
states in which the Company operates also have statutes and regulations
governing the conservation of oil and gas and the prevention of waste, including
the unitization or pooling of oil and gas properties and rates of production
from oil and gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.
Federal Regulation. A portion of the Company's oil and gas leases are
granted by the federal government and administered by the Bureau of Land
Management ("BLM") and the Minerals Management Service ("MMS"), both of which
are federal agencies. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed BLM
and MMS regulations and orders (which are subject to change by the BLM and the
MMS). For offshore operations, lessees must obtain MMS approval for exploration
plans and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, Army Corps of Engineers and Environmental Protection Agency),
lessees must obtain a permit from the BLM or the MMS prior to the commencement
of drilling.
The interstate transportation of natural gas is regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 and, to
a lesser extent, the Natural Gas Policy Act of
39
<PAGE> 42
1978 (collectively, the "Acts"). Numerous questions have been raised concerning
the interpretation and implementation of several significant provisions of the
Acts, as well as the regulations and policies promulgated by FERC thereunder. A
number of lawsuits and administrative proceedings have been instituted which
challenge the validity of regulations implementing the Acts. In addition, as
described below, FERC currently has under consideration various policies and
proposals which will affect the marketing of gas under new and existing
contracts.
Since 1991, FERC's regulatory efforts have centered largely around its
generic rulemaking proceedings, Order No. 636. Through Order No. 636 and
successor orders, FERC has undertaken to restructure the interstate pipeline
industry with the goal of providing enhanced access to, and competition among,
alternative gas suppliers. By requiring interstate pipelines to "unbundle" their
sales services and to provide its customers with direct access to any upstream
pipeline capacity held by pipelines, Order No. 636 has enabled pipeline
customers to choose the levels of transportation and storage service they
require, as well as to purchase gas directly from third-party merchants other
than the pipelines.
Although the implementation of Order No. 636 on individual interstate
pipelines is nearing completion, this process is not yet final. Moreover, nearly
all of these individual restructuring proceedings, as well as Order No. 636
itself and the regulations promulgated thereunder, are subject to pending
appellate review and could possibly be substantially modified by the courts.
Thus, while Order No. 636, if ultimately implemented without substantial change,
should generally facilitate the transportation of gas and the direct access to
end-user markets, the precise impact of these regulations on marketing
production cannot be predicted at this time.
Beyond Order No. 636, FERC is now considering a number of other important
policies, all of which could significantly affect the marketing of gas. Some of
the more notable of these regulatory initiatives include FERC's rulemakings on
gathering and production-area rate design, regulation of pipeline marketing
affiliates under Order No. 497, and standards for pipeline electronic bulletin
boards and electronic data exchange.
The U.S. Congress has historically been active in the area of oil and
natural gas regulation. Although no prediction can be made concerning future
regulation or legislation which may affect the competitive status of the
Company, or affect the prices at which it may sell its oil and gas, any
regulation or legislation that, directly or indirectly, lowers price levels for
oil and gas sold or increases the costs of production could have an adverse
effect on the Company's operations.
Environmental Regulation
Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs. In
particular, the Company's oil and gas exploration, development, production and
EOR operations, its activities in connection with storage and transportation of
liquid hydrocarbons and its use of facilities for treating, processing,
recovering or otherwise handling hydrocarbons and wastes therefrom are subject
to stringent environmental regulation by governmental authorities. Such
regulation has increased the cost of planning, designing, drilling, installing,
operating and abandoning the Company's oil and gas wells and other facilities.
The Company has expended significant resources, both financial and managerial,
to comply with environmental regulations and permitting requirements and
anticipates that it will continue to do so in the future in order to comply with
stricter industry and regulatory safety standards such as those described below.
Although the Company believes that its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations and there can be no
assurance that significant costs and liabilities will not be incurred in the
future. Moreover, it is possible that other developments, such as increasingly
strict environmental laws, regulations and enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in substantial costs and
liabilities in the future. Although the resulting costs cannot be accurately
estimated at this time, these requirements and risks typically apply
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<PAGE> 43
to companies with types and quantities of production similar to those of the
Company and to the oil and gas industry in general.
Offshore Production. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior, the Department of
Transportation, the United States Environmental Protection Agency ("EPA") and
certain state agencies. In particular, the Federal Water Pollution Control Act
of 1972, as amended ("FWPCA"), imposes strict controls on the discharge of oil
and its derivatives into navigable waters. The FWPCA provides for civil and
criminal penalties for any discharges of petroleum in reportable quantities and,
along with the Oil Pollution Act of 1990 and similar state laws, imposes
substantial liability for the costs of oil removal, remediation and damages.
Solid and Hazardous Waste. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other solid wastes may have been disposed or released on or
under the properties owned or leased by the Company. State and federal laws
applicable to oil and gas wastes and properties have gradually become more
strict. Under these new laws, the Company has been, and in the future 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 Company generates hazardous and nonhazardous wastes that are subject to
the federal Resource Conservation and Recovery Act and comparable state
statutes. The EPA has limited the disposal options for certain hazardous wastes
and has recently issued stricter disposal standards for nonhazardous wastes.
Furthermore, it is possible that additional wastes (which could include certain
wastes generated by the Company's oil and gas operations) could in the future be
designated as "hazardous wastes," which are subject to more rigorous and costly
disposal requirements. In response to the changing regulatory environment, the
Company has made certain changes in its operations and disposal practices. For
example, the Company has commenced remediation of sites or replacement of
facilities in some locations where its wastes have previously been disposed.
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 or 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 responses to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. In the course of its operations, the Company has generated and
will generate wastes that may fall within CERCLA's definition of "hazardous
substances." The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been disposed.
The Company has been identified as one of over 250 potentially responsible
parties ("PRPs") at a superfund site in Los Angeles County, California. The site
was operated by a third party as a waste disposal facility from 1948 until 1983.
The EPA is requiring the PRPs to undertake remediation of the site in several
phases, which include site monitoring and leachate control, gas control and
final remediation. In 1989 the EPA and a group of the PRPs entered into a
consent decree covering the site monitoring and leachate control phase of
remediation. The Company is a member of the group that is responsible for
carrying out this first phase of work, which is expected to be completed in five
to eight years. The maximum liability of the group, which is joint and several
for each member of the group, for the first phase is $37.0 million, of which the
Company's share is expected to be approximately $2.4 million ($1.3 million after
recoveries from working interest participants in the unit at which the wastes
were generated) payable over the period that the phase one work is performed.
The EPA and a group of PRPs of which the Company is a member have also entered
into a subsequent consent decree with respect to the second phase of work (gas
control). The liability of this group has not been capped, but is estimated to
be
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<PAGE> 44
$130 million. The Company's share of costs for this phase, however, is expected
to be approximately of the same magnitude as that of the first phase because
more parties are involved in the settlement. The Company has provided for costs
with respect to the first two phases, but it cannot currently estimate the cost
of any subsequent phases of work which may be required by the EPA.
In 1989, Adobe received requests from the EPA for information pursuant to
Section 104(e) of CERCLA with respect to the Gulf Coast Vacuum Services and D.
L. Mud superfund sites located in Abbeville, Louisiana. The EPA has issued its
record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued
to all PRPs at the site a settlement order pursuant to Section 122 of CERCLA. On
December 15, 1993 the Company entered into a cost-sharing agreement with other
PRPs to participate in the final remediation of the Gulf Coast site, which is
presently estimated to cost $15.0 million. The Company's share of the
remediation is approximately $600,000 and reflects its proportionate share of
the "orphans' share" for this site. With respect to the D. L. Mud site, a former
property owner has already conducted remedial activities at the site under a
state agency agreement. To date, the Company has not been requested to share in
the remediation costs. The extent, if any, of any further necessary remedial
activity at, and the prospective PRPs and the Company's financial obligations
for, the D. L. Mud site has not been finally determined.
The Company has received a request for information from the EPA regarding
the Lee Acres Landfill CERCLA site in New Mexico. The Company advised the EPA
that it was not able to locate any information indicating that it had used that
facility. The Company is investigating its potential connection, if any, to this
facility and is not able to estimate its share of costs, if any, for the site at
this time.
On April 4, 1994, the Company received a request from the EPA for
information pursuant to Section 104(a) of CERCLA and a letter ordering the
Company and seven other PRPs to negotiate with the EPA regarding implementation
of a remedial plan for a site located in Sante Fe Springs, California. The
Company owned the property on which the site is located from 1921 to 1932. After
the Company sold the property, hazardous wastes were allegedly disposed there by
a third party who operated a disposal site. The EPA estimates that the total
past and future costs for remediation will approximate $9 million. The Company
believes that it has valid defenses to liability. While it is still
investigating its exposure, if any, for the remedial costs, the Company does not
believe that any such costs would be material.
Air Emissions. The operations of the Company, including its operations in
the San Joaquin Valley, are subject to local, state and federal regulations for
the control of emissions from sources of air pollution. Legal and regulatory
requirements in this area are increasing, and there can be no assurance that
significant costs and liabilities will not be incurred in the future as a result
of new regulatory developments. In particular, the 1990 Clean Air Act Amendments
will impose additional requirements that may affect the Company's operations,
including permitting of existing sources and control of hazardous air
pollutants. However, it is impossible to predict accurately the effects, if any,
of the Clean Air Act Amendments on the Company at this time. The Company has
been and may in the future be subject to administrative enforcement actions for
failure to comply strictly with air regulations or permits. These administrative
actions are generally resolved by payment of a monetary penalty and correction
of any identified deficiencies. Alternatively, regulatory agencies may require
the Company to forego construction or operation of certain air emission sources.
Other. The Company is 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 (such as California Proposition 65) require the Company
to organize information about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state and
local governmental authorities and local citizens. The Company's facilities in
California are also subject to California Proposition 65, which was adopted in
1986 to address discharges and releases of, or exposures to, toxic chemicals in
the environment. Proposition 65 makes it illegal to knowingly discharge a listed
chemical if the chemical will pass (or probably will pass) into any source of
drinking water. It also prohibits companies from knowingly and intentionally
exposing any
42
<PAGE> 45
individual to such chemicals through ingestion, inhalation or other exposure
pathways without first giving a clear and reasonable warning.
Although generally less stringent, the Company's foreign operations are
subject to similar foreign laws respecting environmental and worker safety
matters.
Insurance Coverage Maintained with Respect to Operations
The Company maintains insurance policies covering its operations in amounts
and areas of coverage normal for a company of its size in the oil and gas
exploration and production industry. These coverages include, but are not
limited to, workers' compensation, employers' liability, automotive liability
and general liability. In addition, an umbrella liability and operator's extra
expense policies are maintained. All such insurance is subject to normal
deductible levels. The Company does not insure against all risks associated with
its business either because insurance is not available or because it has elected
not to insure due to prohibitive premium costs.
Employees
As of December 31, 1993, the Company had approximately 777 employees, 210
of whom were covered by a collective bargaining agreement which expires on
January 31, 1996. The Company believes that its relations with its employees are
satisfactory.
Legal Proceedings
The Company, its subsidiaries and other related companies are named
defendants in several lawsuits and named parties in certain governmental
proceedings arising in the ordinary course of business. For a description of
certain proceedings in which the Company is involved, see
"--Environmental Regulation." While the outcome of lawsuits or other proceedings
against the Company cannot be predicted with certainty, management does not
expect these matters to have a material adverse effect on the financial position
or results of operations of the Company.
43
<PAGE> 46
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The current directors and executive officers of the Company and their ages
(as of January 1, 1994) and positions are listed below.
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- --- --------
<S> <C> <C>
James L. Payne................... 56 Chairman of the Board, President and Chief
Executive Officer
Hugh L. Boyt..................... 48 Senior Vice President--Production
Jerry L. Bridwell................ 50 Senior Vice President--Exploration and Land
Keith P. Hensler................. 62 Senior Vice President--Marketing
Richard B. Bonneville............ 51 Vice President--Planning and Administration
E. Everett Deschner.............. 53 Vice President--Reservoir Engineering and
Evaluation
C. Ed Hall....................... 51 Vice President--Public Affairs
Charles G. Hain, Jr.............. 47 Vice President--Employee Relations
David L. Hicks................... 44 Vice President--Law and General Counsel
Michael J. Rosinski.............. 48 Vice President and Chief Financial Officer
John R. Womack................... 55 Vice President--Business Development
Rod F. Dammeyer.................. 53 Director
Marc J. Shapiro.................. 47 Director
William E. Greehey............... 57 Director
Robert F. Vagt................... 47 Director
Melvyn N. Klein.................. 52 Director
Robert D. Krebs.................. 51 Director
David M. Schulte................. 47 Director
Allan V. Martini................. 66 Director
Michael A. Morphy................ 61 Director
Kathryn D. Wriston............... 55 Director
Reuben F. Richards............... 64 Director
</TABLE>
The business experience of the above officers and directors for the past
five years is described below. Unless otherwise stated, all offices were held
with Santa Fe Energy Company prior to its merger with the Company. Each
executive officer holds office until his successor is elected or appointed or
until his earlier death, resignation or removal.
James L. Payne has served as a Director since 1986 and has been Chairman of
the Board, President and Chief Executive Officer of the Company since June 1990.
Mr. Payne was President of Santa Fe Energy Company from January 1986 to January
1990 when he became President of the Company. From 1982 to January 1986 Mr.
Payne was Senior Vice President--Exploration and Land of Santa Fe Energy
Company. Mr. Payne is also a director of Pool Energy Services Co. (oilfield
services) and Hadson (natural gas transportation and marketing).
Hugh L. Boyt has been Senior Vice President--Production since March 1,
1990. From 1989 until March 1990, Mr. Boyt served as Corporate Production
Manager. From 1983, when Mr. Boyt joined the Company, until 1989 he served as
District Production Manager--Permian Basin.
Jerry L. Bridwell has been Senior Vice President--Exploration and Land
since 1986. Mr. Bridwell served in various other capacities, including Vice
President--Exploration, Central Division, since joining the Company in 1974.
Keith P. Hensler has been Senior Vice President--Marketing since January
1990. From 1980, when Mr. Hensler joined the Company, until January 1990, he
served as Vice President--Marketing. Mr. Hensler is also Senior Vice President
of Energy Products.
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<PAGE> 47
Richard B. Bonneville has been Vice President--Planning and Administration
since 1988. Prior to such time Mr. Bonneville served as Secretary of Santa Fe
Pacific Corporation ("SFP").
E. Everett Deschner has been Vice President--Reservoir Engineering and
Evaluation since April 1990. From 1982, when Mr. Deschner joined the Company,
until 1990, he served as Manager-- Engineering and Evaluation.
C. Ed Hall has been Vice President--Public Affairs since March 1991. Prior
to such time Mr. Hall served as Director--Public Affairs since joining the
Company in 1984.
Charles G. Hain, Jr. has been Vice President--Employee Relations since
1988. From 1981, when Mr. Hain joined the Company, until 1988, Mr. Hain served
as Director--Employee Relations.
David L. Hicks has been Vice President--Law and General Counsel since March
1991. From 1988 until March 1991, Mr. Hicks was General Counsel and prior to
that time was General Attorney for SFP.
Michael J. Rosinski has been Vice President and Chief Financial Officer
since September 1992. Prior to joining the Company, Mr. Rosinski was with
Tenneco Inc. and its subsidiaries for 24 years. From 1988 until 1990, Mr.
Rosinski served as Deputy Project Executive for the Colombian Crude Oil Pipeline
Project and from 1990 until August 1992 he was Executive Director of Investor
Relations. Mr. Rosinski is also a director of Hadson (natural gas transportation
and marketing).
John R. Womack has been Vice President--Business Development since 1987.
From 1982, when Mr. Womack joined the Company, until 1987, Mr. Womack served as
Vice President--Land.
Rod F. Dammeyer has served as a Director since 1990. Mr. Dammeyer has been
President and a director since 1985 and Chief Executive Officer since 1993 of
Itel Corporation (holding company involved primarily in distribution of wiring
systems products). Mr. Dammeyer is also a director of Q-Tel S.A., Servicios
Financieros Quadrum, S.A., Lomas Financial Corporation, Jacor Communications,
Inc., Revco D.S., Inc., Capsure Holdings Corp. and the Vigoro Corporation and a
trustee of Van Kampen Merritt Closed-End Mutual Funds. In addition, Mr. Dammeyer
is President, Chief Executive Officer and a director of Great American
Management and Investment, Inc.
Marc J. Shapiro has served as a Director since 1990. Mr. Shapiro has been
Chairman, President and Chief Executive Officer of Texas Commerce Bancshares,
Inc. (banking) since January 1994. He has been President and Chief Executive
Officer of Texas Commerce Bancshares, Inc. since December 1989, Chairman and
Chief Executive Officer of Texas Commerce Bank National Association since 1987
and a member of the Management Committee of Chemical Banking Corporation since
December 1991. Mr. Shapiro was a member of the Office of the Chairman of
Chemical Banking Corporation from August 1990 to December 1991 , Vice Chairman
of Texas Commerce Bancshares, Inc. from 1982 to 1989, and Vice Chairman of Texas
Commerce Bank National Association from 1982 to 1987. Mr. Shapiro is also a
director of Browning-Ferris Industries and a trustee of Weingarten Realty
Investors.
William F. Greehey has served as a Director since 1991. Mr. Greehey has
been Chairman of the Board, Chief Executive Officer and director of Valero
Energy Corporation (refining and marketing, gas transmission and processing)
since 1983. Mr. Greehey is also a director of Weatherford International.
Robert F. Vagt has served as a Director since 1992. Mr. Vagt has been
President, Chief Executive Officer and director of Global Natural Resources Inc.
(oil and gas exploration and production) since May 1992; President and Chief
Operating Officer of Adobe (oil and gas exploration and production) from
November 1990 to May 1992; Executive Vice President of Adobe from August 1987 to
October 1990; and Senior Vice President of Adobe from October 1985 to August
1987. Mr. Vagt is also a director of First Albany Corporation (brokerage firm).
Melvyn N. Klein has served as a Director since February 1993, when he was
elected to fill the vacancy created by the resignation of L.G. Dodd. Mr. Klein
is an Attorney and Counselor at Law, private investor and the sole stockholder
of a general partner in GKH Partners, L.P. Mr. Klein is also a director of Itel
Corporation, American Medical Holdings, Inc. (hospital ownership and
management), Bayou Steel
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<PAGE> 48
Corporation (specialty steel manufacturer) and Savoy Pictures Entertainment,
Inc. (distributor of motion pictures).
Robert D. Krebs has served as a Director since 1985. Mr. Krebs has been
Chairman, President and Chief Executive Officer of SFP since 1988. Prior to such
time, Mr. Krebs was President and Chief Operating Officer of SFP. Mr. Krebs is
also a director of SFP, Catellus Development Corporation, the Atchison, Topeka
and Santa Fe Railway Company, Santa Fe Pacific Pipelines, Inc., Phelps Dodge
Corporation and Northern Trust Corporation.
David M. Schulte has served as a Director since February 1994. Mr. Schulte
has been, for the past five years, Managing Partner of Chilmark Partners, L.P.
(investments) and since July 1990, General Partner of ZC Limited Partnership,
the General Partner of Zell/Chilmark Fund, L.P. (investments). Mr. Schulte is
also a director of Carter Hawley Hale Stores, Inc., Revco D.S., Inc., Sealy
Corporation and Jacor Communications, Inc.
Allan V. Martini has served as a Director since 1990. Mr. Martini retired
as Vice President Exploration/Production and director of Chevron Corporation
(petroleum operations) in August 1988. Mr. Martini served in that position from
July 1986 until his retirement.
Michael A. Morphy has served as a Director since 1990. Mr. Morphy has been,
for the past five years, retired Chairman and Chief Executive Officer of
California Portland Cement Company. Mr. Morphy is also a director of Cyprus Amax
Minerals Co. and SFP.
Kathryn D. Wriston has served as a Director since 1990. Ms. Wriston has
been, for the past five years, director of various corporations and
organizations, including Northwestern Mutual Life Insurance Company and a
Trustee of the Financial Accounting Foundation.
Reuben F. Richards has served as a Director since 1992. Mr. Richards has
been Chairman of the Board of Terra Industries Inc. (agribusiness) since
December 1982; Chief Executive Officer of Terra Industries Inc. from December
1982 to May 1991 and President of Terra Industries Inc. from July 1983 to May
1991; Chairman of the Board of Engelhard Corporation (specialty chemicals and
engineered materials) since May 1985; Chairman of the Board of Minorco (U.S.A.)
Inc. ("Minorco (USA)") since May 1990 and Chief Executive Officer and President
of Minorco (USA) since February 1994. Mr. Richards is also a director of Ecolab,
Inc. (cleaning and sanitizing products), Potlatch Corporation (forest products),
and Minorco.
46
<PAGE> 49
DESCRIPTION OF THE DEBENTURES
The Debentures will be issued under an indenture to be dated as of
, 1994 (the "Indenture"), between the Company and The First National
Bank of Boston, as trustee (the "Trustee"). A copy of the Indenture is filed as
an exhibit to the Registration Statement of which this Prospectus is a part. The
Indenture is subject to and is governed by the Trust Indenture Act of 1939, as
amended (the "TIA"). The following summary of certain provisions of the
Debentures and the Indenture does not purport to be complete and is subject to
and qualified in its entirety by reference to the TIA and all the provisions of
the Debentures and the Indenture, including the definitions therein of certain
terms that are not otherwise defined in this Prospectus. Wherever particular
provisions of the Indenture or terms defined therein are referred to herein,
such provisions or definitions are incorporated herein by reference. References
herein are to articles and sections in the Indenture. All references to the
"Company" in this Section of the Prospectus are to Santa Fe Energy Resources,
Inc., and do not include its subsidiaries.
GENERAL
The Debentures will mature on , 2004, and will be limited to an
aggregate principal amount of $100,000,000. The Debentures will bear interest at
the rate set forth on the cover page of this Prospectus from , 1994
(the "Issue Date"), or from the most recent interest payment date to which
interest has been paid, payable semi-annually on and of each
year, beginning on , 1994, to the person in whose name the Debenture
(or any predecessor Debenture) is registered at the close of business on the
preceding or , as the case may be.
Principal of, premium, if any, and interest on the Debentures will be
payable, and the Debentures will be exchangeable and transferable, at an office
or agency of the Company, one of which will be maintained for such purpose in
The City of New York (which initially will be the Corporate Trust Office of the
Trustee, at ) or such other office or agency permitted under the
Indenture; provided, however, that payment of interest may be made at the option
of the Company by check mailed to the person entitled thereto as shown on the
Security Register. The Debentures will be issued only in fully registered form
without coupons, in denominations of $1,000 or any integral multiple thereof. No
service charge will be made for any registration of transfer or exchange of
Debentures, except for any tax or other governmental charge that may be imposed
in connection therewith.
All moneys paid by the Company to a Paying Agent for the payment of the
principal of or any premium or interest on any Debentures that remain unclaimed
at the end of two years after such principal, premium or interest has become due
and payable may be repaid to the Company, and the Holder of such Debenture
thereafter may look only to the Company for payment thereof. (Section 8.04)
SUBORDINATION
The Debentures will be general unsecured senior subordinated obligations of
the Company. The payment of the principal of, premium, if any, and interest on,
the Debentures will be subordinated in right of payment, as set forth in the
Indenture, to the payment when due in cash of all Senior Indebtedness of the
Company. However, payment from the money or the proceeds of U.S. Government
Obligations held in any defeasance trust will not be subordinate to any Senior
Indebtedness or subject to the restrictions described herein. The Debentures
will rank subordinate in right of payment to all existing and future Senior
Indebtedness (as defined), pari passu with any future senior subordinated
indebtedness and senior to any future junior subordinated indebtedness of the
Company. At December 31, 1993, after giving effect to the application of the
proceeds of the Offerings, the pro forma amount of Senior Indebtedness
outstanding would have been $289.4 million. The Debentures will be structurally
subordinated to all liabilities of the Company's subsidiaries, which would have
totaled $58.8 million at December 31, 1993, after giving effect to the
application of the proceeds of the Offerings. The amounts referred to above
include only liabilities included on the Company's consolidated balance sheet
under GAAP; the Company and its subsidiaries have other liabilities, including
contingent liabilities, which may be significant. Although the Indenture
contains limitations on the amount of additional Indebtedness that
47
<PAGE> 50
the Company and its subsidiaries may incur, the amounts of such Indebtedness
could be substantial and, in any case, such Indebtedness may be Senior
Indebtedness or Indebtedness of subsidiaries (to which the Debentures will be
structurally subordinated). See "--Certain Covenants-Limitation on Indebtedness"
below.
The Company may not pay principal of, premium, if any, or interest on, the
Debentures or make any deposit pursuant to the provisions described under
"--Defeasance and Covenant Defeasance" below and may not repurchase, redeem or
otherwise retire any Debentures, including pursuant to the obligation described
below under "--Mandatory Repurchase upon Change of Control and Subsequent Rating
Decline" (collectively, "pay the Debentures"), if (a) any principal, premium or
interest (including interest (if any) occurring on or after the commencement of
a proceeding in bankruptcy) in respect of any Senior Indebtedness is due and
payable and is not paid within any applicable grace period (including at
maturity) or (b) any other default on Senior Indebtedness occurs and the
maturity of such Senior Indebtedness is accelerated in accordance with its terms
unless, in either case, the default has been cured or waived and any such
acceleration has been rescinded or such Senior Indebtedness has been paid in
full; provided, however, that the Company may pay the Debentures without regard
to the foregoing if the Company and the Trustee receive written notice approving
such payment from the Representative of each issue of Designated Senior
Indebtedness. During the continuance of any default (other than a default
described in clause (a) or (b) of the preceding sentence) with respect to any
Senior Indebtedness pursuant to which the maturity thereof may be accelerated
immediately without further notice (except such notice as may be required to
effect such acceleration), the Company may not pay the Debentures for a period
(a "Payment Blockage Period") commencing upon the receipt by the Company and the
Trustee of written notice of such default from the Representative to the holders
of any Designated Senior Indebtedness specifying an election to effect a Payment
Blockage Period (a "Payment Blockage Notice") and ending 179 days thereafter
(unless earlier terminated (i) by written notice to the Trustee and the Company
from the Representative that submitted such Payment Blockage Notice, (ii)
because such default is no longer continuing or (iii) because the Senior
Indebtedness in respect of which such Blockage Notice was given has been repaid
in full). Notwithstanding the provisions described in the immediately preceding
sentence, unless the holders of such Senior Indebtedness or the Representative
of such holders have accelerated the maturity of such Senior Indebtedness and
not rescinded such acceleration, the Company may (unless otherwise prohibited as
described in the first sentence of this paragraph) resume payments on the
Debentures after the end of such Payment Blockage Period. Not more than one
Payment Blockage Notice may be given in any consecutive 360-day period,
irrespective of the number of defaults with respect to any number of issues of
Senior Indebtedness during such period. (Section 10.03)
Upon any payment or distribution of the assets of the Company upon a total
or partial liquidation, dissolution or winding up of the Company or in a
bankruptcy, reorganization, insolvency, receivership or similar proceeding
relating to the Company or its property, the holders of Senior Indebtedness will
be entitled to receive payment in full in cash of the Senior Indebtedness before
the Holders of the Debentures are entitled to receive any payment of principal
of, or premium, if any, or interest on, the Debentures. In addition, until the
Senior Indebtedness is paid in full, any distribution to which Holders of
Debentures would be entitled but for the subordination provisions of the
Indenture will be made to holders of the Senior Indebtedness, except that
Holders of Debentures may receive and retain shares of stock and any debt
securities that are subordinated to Senior Indebtedness to at least the same
extent as the Debentures. (Section 10.02)
By reason of such subordination provisions contained in the Indenture, in
the event of bankruptcy, insolvency or winding up, creditors of the Company who
are holders of Senior Indebtedness may recover more, ratably, than the Holders
of the Debentures, and creditors of the Company who are not holders of Senior
Indebtedness or the Debentures may recover less, ratably, than holders of Senior
Indebtedness and may recover more, ratably, than the Holders of the Debentures.
Claims of creditors of the Company's subsidiaries, including trade
creditors, and holders of Preferred Stock of the Company's subsidiaries (if
any), will generally have a priority as to the assets of such subsidiaries over
the claims of the Company and the holders of the Company's Indebtedness. Under
the
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<PAGE> 51
Indenture, and subject to certain limitations, Indebtedness may be incurred by
subsidiaries of the Company.
OPTIONAL REDEMPTION
Except as provided below, the Debentures are not redeemable prior to
, 1999. At any time on or after , 1999, the Debentures are
redeemable at the option of the Company, in whole or from time to time in part,
on not less than 30 nor more than 60 days' notice, at the following redemption
prices (expressed as percentages of principal amount), plus accrued and unpaid
interest (if any) to the date of redemption.
If redeemed during the 12-month period commencing :
<TABLE>
<CAPTION>
YEAR REDEMPTION PRICE
---- ----------------
<S> <C>
1999................................................ %
2000................................................ %
2001................................................ %
</TABLE>
and thereafter, beginning , 2002, at 100% of the principal amount of
the Debentures plus accrued and unpaid interest (if any) to the date of
redemption.
SINKING FUND
There will be no mandatory sinking fund payments for the Debentures.
MANDATORY REPURCHASE UPON CHANGE OF CONTROL AND SUBSEQUENT RATING DECLINE
Upon the occurrence of a Change of Control and a subsequent Rating Decline,
the Company will, within 30 days after the occurrence of such Rating Decline,
notify each Holder of the Debentures, with a copy of such notice to the Trustee,
in writing of the occurrence of the Change of Control and along with such notice
will make an offer to purchase (the "Change of Control Offer") the Debentures at
a purchase price equal to 101% of the principal amount thereof, plus any accrued
and unpaid interest due thereon to the Change of Control Purchase Date (as
defined below) (such price, together with such interest, the "Change of Control
Purchase Price") on or before the date specified in such notice, which date
shall be no earlier than 30 days nor later than 60 days from the date such
notice is mailed (the "Change of Control Purchase Date"). The Change of Control
Offer will remain open from the time such offer is made until the Change of
Control Purchase Date. The Company will purchase all Debentures properly
tendered in the Change of Control Offer and not withdrawn in accordance with the
procedures set forth in such notice. The Change of Control Offer will state,
among other things, the procedures that holders of the Debentures must follow to
accept the Change of Control Offer.
The occurrence of certain of the events which would constitute a Change of
Control could constitute a default under the Company's existing and future
indebtedness. In addition, the exercise by the holders of the Debentures of
their right to require the Company to repurchase the Debentures could cause a
default under existing or future indebtedness, even if the Change of Control
itself does not, due to the financial effect of such repurchase on the Company.
Finally, if a Change of Control Offer is made, there can be no assurance that
the Company will have sufficient funds or other resources to pay the Change of
Control Purchase Price for all the Debentures that might be delivered by Holders
thereof seeking to accept the Change of Control Offer.
The Change of Control provisions described above may deter certain mergers,
tender offers and other takeover attempts involving the Company and, thus, the
removal of incumbent management. The Change of Control provisions will not
prevent a change in a majority of the members of the Board of Directors of the
Company which is approved by a majority of the then-present Board of Directors
of the Company. One of the events that constitutes a Change of Control under the
Indenture is a sale,
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conveyance, transfer or lease of all or substantially all the property of the
Company and its Subsidiaries, taken as a whole. The phrase "all or substantially
all" is subject to judicial interpretation depending on the facts and
circumstances of the subject transaction. The Indenture will be governed by New
York law, and there is no established quantitative definition under New York law
of "substantially all" the assets of a corporation. Accordingly, in certain
circumstances it may be unclear whether a Change of Control has occurred and
whether the Company may therefore be required to make a Change of Control Offer.
The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Debentures pursuant to any Change of
Control Offer. To the extent that the provisions of any securities laws or
regulations conflict with provisions relating to the Change of Control Offer,
the Company will comply with the applicable securities laws and regulations and
will not be deemed to have breached its obligations under the Change of Control
covenant by virtue thereof. (Section 4.08)
CERTAIN COVENANTS
Limitation on Indebtedness. The Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly, Incur any
Indebtedness unless (i) no Default or Event of Default shall have occurred and
be continuing at the time of such Incurrence or would occur as a consequence of
such incurrence and (ii) such Indebtedness is Permitted Indebtedness.
Permitted Indebtedness means any and all of the following: (a) Indebtedness
Incurred if, after giving pro forma effect to the Incurrence of such
Indebtedness and the receipt and application of the proceeds thereof, the
Consolidated Interest Coverage Ratio exceeds 3.0 to 1.0; (b) Indebtedness
evidenced by the Debentures; (c) Indebtedness under Bank Credit Facilities but
only to the extent that the aggregate principal amount of all such Indebtedness
under Bank Credit Facilities equals or is less than $175 million; (d)
Indebtedness under Interest Rate Protection Agreements, provided that the
obligations under such agreements are related to payment obligations on
Indebtedness otherwise permitted by the terms of this covenant; (e) Indebtedness
to the Company or any Restricted Subsidiary by any of its Restricted
Subsidiaries or Indebtedness of the Company to any of its Restricted
Subsidiaries, provided, however, that any subsequent issuance or transfer of any
Capital Stock which results in any such Restricted Subsidiary ceasing to be a
wholly owned Subsidiary or any subsequent transfer of any such Indebtedness
(except to the Company or any Restricted Subsidiary) will be deemed, in each
case, to constitute the incurrence of such Indebtedness by the issuer thereof;
(f) Capital Expenditure Indebtedness (provided that the principal amount of such
Indebtedness does not exceed the fair market value of the property or asset with
respect to which such expenditure is made, such fair market value to be
determined after giving effect to such expenditure) but only to the extent the
aggregate principal amount of all Capital Expenditure Indebtedness Incurred
under this clause (f) during any calendar year equals or is less than $160
million; (g) Indebtedness under Oil and Gas Purchase and Sale Contracts,
provided that such contracts were entered into for the purpose of limiting risks
that arise in connection with the sale of oil and gas produced by the Company
and its Subsidiaries in the ordinary course of business; (h) Indebtedness of any
Person which shall merge into or consolidate with the Company in accordance with
the "Merger, Consolidation and Sale of Assets" covenant, which Indebtedness was
not Incurred in anticipation of such merger or consolidation and was outstanding
prior to such merger or consolidation; (i) Indebtedness in connection with one
or more standby letters of credit, Guarantees or performance bonds issued in the
ordinary course of business and not in connection with the borrowing of money or
the obtaining of advances or credit (other than advances or credit on open
account, includable in current liabilities, for goods and services in the
ordinary course of business and on terms and conditions which are customary in
the Oil and Gas Business and other than the extension of credit represented by
such letter of credit, Guarantee or performance bond itself); (j) Indebtedness
not otherwise permitted to be Incurred pursuant to this paragraph, provided that
the aggregate principal amount of all Indebtedness Incurred pursuant to this
clause (j) does not exceed $50 million; (k) Indebtedness outstanding on the date
of the Indenture; (l) Indebtedness Incurred in exchange for, or the proceeds of
which are used to refinance, Indebtedness referred to in clauses (a) through (k)
of this paragraph or Indebtedness previously
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incurred pursuant to this clause (l), provided that (i) such Indebtedness is in
an aggregate principal amount not in excess of the aggregate principal amount
then outstanding of the Indebtedness being exchanged or refinanced, (ii) such
Indebtedness has a Stated Maturity no earlier than the Stated Maturity of the
Indebtedness being exchanged or refinanced, (iii) such Indebtedness has an
Average Life at the time such Indebtedness is Incurred that is equal to or
greater than the Average Life of the Indebtedness being exchanged or refinanced
and (iv) such Indebtedness is subordinated in right of payment to Senior
Indebtedness or the Debentures to at least the same extent, if any, as the
Indebtedness being exchanged or refinanced; and (m) accounts payable or other
obligations of the Company or any Restricted Subsidiary to trade creditors
created or assumed by the Company or such Restricted Subsidiary in the ordinary
course of business in connection with the obtaining of goods or services. The
Company and its Restricted Subsidiaries may Incur Indebtedness under a single
debt facility or instrument in reliance on two or more of the aforementioned
clauses of the definition of Permitted Indebtedness. (Section 4.03)
Limitation on Liens. The Company will not, directly or indirectly, Incur
any Lien on or with respect to any Property of the Company or any interest
therein or any income or profits therefrom, unless the Debentures are secured
equally and ratably with (or prior to) any and all other obligations secured by
such Lien, except that the Company may without restriction Incur Liens securing
Senior Indebtedness and except for: (a) any Lien existing on any Property of a
Person at the time such Person is merged or consolidated with or into the
Company (and not Incurred in anticipation of such transaction), provided that
such Liens are not extended to other Property of the Company; (b) any Lien
existing on any Property at the time of the acquisition thereof (and not
Incurred in anticipation of such transaction); (c) any Lien incidental to the
normal conduct of the business of the Company or the ownership of its property
or the conduct in the ordinary course of its business (including without
limitation (i) easements, rights of way and similar encumbrances, (ii) rights of
lessees or lessors under leases, (iii) rights of collecting banks having rights
of setoff, revocation, refund or chargeback with respect to money or instruments
of the Company on deposit with or in the possession of such banks, (iv) Liens
imposed by law, including without limitation mechanics', carriers',
warehousemen's, materialmen's, suppliers' and vendors' Liens, (v) Oil and Gas
Liens, and (vi) Liens incurred to secure performance of bids, tenders, contracts
(other than contracts for the payment or repayment of money), statutory or
regulatory requirements, performance or return-of-money bonds, surety bonds or
other obligations of a like nature and incurred in a manner consistent with
industry practice) in each case which are not Incurred in connection with the
borrowing of money, the obtaining of advances or credit (other than the
extension of credit represented by such bond or other instrument) or the payment
of the deferred purchase price of Property and which do not in the aggregate
impair in any material respect the use of Property in the operation of the
business of the Company and its Restricted Subsidiaries taken as a whole; (d)
Liens for taxes not yet due or which are being contested in good faith by
appropriate proceedings, so long as reserves have been established to the extent
required by GAAP; (e) Liens existing as of the date of the Indenture; and (f)
Liens to secure any permitted extension, renewal, refinancing, refunding or
exchange (or successive extensions, renewals, refinancings, refundings or
exchanges), in whole or in part, of or for any Indebtedness secured by Liens
referred to in the foregoing clauses (a) through (e), provided that such Liens
do not extend to any other Property and the principal amount of the Indebtedness
secured by such Liens is not increased. (Section 4.11)
Limitation on Restricted Payments. The Company will not, and will not
permit any Restricted Subsidiary to, directly or indirectly, (i) declare or pay
any dividend on, or make any distribution on or in respect of, its Capital Stock
or Redeemable Stock (including any such payment (other than payments solely in
its Capital Stock or in options, warrants or other rights to purchase its
Capital Stock) in connection with any merger or consolidation involving the
Company), except dividends or distributions payable solely in its Capital Stock
or in options, warrants or other rights to purchase such Capital Stock and
except dividends or distributions payable solely to the Company or any
Restricted Subsidiary, (ii) purchase, redeem or otherwise acquire for value any
Capital Stock or Redeemable Stock of the Company or any Restricted Subsidiary
held by Persons other than the Company or any Restricted Subsidiary, (iii) make
any principal payment on, or redeem, purchase, repurchase, defease or otherwise
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acquire or retire for value prior to any scheduled repayment, scheduled sinking
fund payment or other scheduled maturity, any Indebtedness that is subordinated
in right of payment to the Debentures or (iv) make any Investment in any Person
(any such dividend, distribution, purchase, redemption, repurchase, defeasance,
other acquisition, retirement or Investment being herein referred to as a
"Restricted Payment"), unless at the time of and after giving effect to the
proposed Restricted Payment (a) no Default or Event of Default shall have
occurred and be continuing under the Indenture, (b) the Company could incur at
least $1.00 of additional Indebtedness under clause (a) of the definition of
"Permitted Indebtedness" and (c) the aggregate amount of such Restricted Payment
and all other Restricted Payments (the amount so expended, if other than in
cash, to be determined in good faith by the Board of Directors of the Company,
whose determination shall be evidenced by a resolution of such Board) declared
or made since the date of the Indenture, would not exceed, without duplication,
the sum of (1) 50% of the Consolidated Adjusted Net Income accrued during the
period (treated as one accounting period) from the quarter end on or before the
date of the Indenture, to the end of the Company's most recent fiscal quarter
immediately preceding such proposed Restricted Payment (or, if such Consolidated
Adjusted Net Income shall be a deficit, minus 50% of such deficit), (2) the
aggregate net proceeds, including cash and the Fair Market Value of Property
other than cash, received by the Company from the issue or sale of its Capital
Stock (including pursuant to the exercise of options or warrants or the making
of any equity contribution by stockholders of the Company subsequent to the date
of the Indenture (other than an issuance or sale to a Subsidiary of the Company
or any employee stock ownership plan or other trust established by the Company
or any of its Subsidiaries), (3) the amount by which the Indebtedness of the
Company or any Restricted Subsidiary is reduced on the Company's balance sheet
upon the conversion or exchange (other than by a Subsidiary of the Company),
subsequent to the date of the Indenture, of any Indebtedness or Redeemable Stock
of the Company or any Restricted Subsidiary into or for Capital Stock of the
Company (less the amount of any cash or other property distributed by the
Company or any Restricted Subsidiary upon such conversion or exchange) and (4)
$50 million.
Any payments made pursuant to clauses (a) through (f) of the definition of
"Permitted Investment" shall be excluded for purposes of any calculation of the
aggregate amount of Restricted Payments. Any payments made pursuant to clauses
(g), (h) and (i) of the definition of "Permitted Investment" shall be included
for purposes of any calculation of the aggregate amount of Restricted Payments.
The foregoing limitations will not prevent the Company or any Restricted
Subsidiary from (a) paying a dividend on its Capital Stock within 60 days after
declaration thereof if, on the declaration date, such dividend could have been
paid in compliance with the Indenture or (b) making Permitted Investments, so
long as no Default or Event of Default shall have occurred and be continuing.
Notwithstanding the provisions of the preceding three paragraphs, during
any period of time that (i) the ratings assigned to the Debentures by both
Rating Agencies are equal to or higher than BBB -- and Baa3, respectively (the
"Investment Grade Ratings"), and (ii) no Event of Default or Default has
occurred and is continuing, the Company and its Restricted Subsidiaries will not
be subject to the provisions of the Limitation on Restricted Payments covenant
(the "Suspended Covenant"). In the event that the Company is not subject to the
Suspended Covenant for any period of time as a result of the preceding sentence
and, subsequently, one or both Rating Agencies withdraws its rating or
downgrades the rating below the required Investment Grade Ratings, then the
Company and its Restricted Subsidiaries will again be subject to the Suspended
Covenant and compliance with the Suspended Covenant with respect to Restricted
Payments made after the time of such withdrawal or downgrade will be calculated
in accordance with the terms of the Suspended Covenant as if such covenant had
been in effect during the entire period of time from the date of the Indenture.
(Section 4.04)
Limitation on Issuance and Sale of Capital Stock of Restricted
Subsidiaries. The Company will not (a) permit any Restricted Subsidiary to
issue any Capital Stock or Redeemable Stock other than to the Company or one of
its Restricted Subsidiaries; provided, however, that any subsequent issuance or
transfer of any Capital Stock that results in any such Restricted Subsidiary
ceasing to be a Restricted
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Subsidiary or any subsequent transfer of any such Capital Stock (except to the
Company or any Restricted Subsidiary) will be deemed, in each case, to
constitute the issuance of such Capital Stock by the issuer thereof or (b)
permit any Person (other than the Company or a Restricted Subsidiary) to own any
Capital Stock of a Restricted Subsidiary (other than directors' qualifying
shares); provided, however, that clauses (a) and (b) will not prohibit a sale of
100% of the Capital Stock of a Restricted Subsidiary owned by the Company or a
Restricted Subsidiary effected in accordance with the "Limitation on Asset
Sales" covenant. (Section 4.13)
Incurrence of Layered Indebtedness. The Company will not Incur any
Indebtedness which is subordinate or junior in right of payment to any Senior
Indebtedness unless such Indebtedness constitutes Indebtedness that is junior
to, or pari passu with, the Debentures in right of payment. (Section 4.14)
Transactions with Affiliates. The Company will not, and will not permit
any of its Restricted Subsidiaries to, directly or indirectly, conduct any
business or enter into any transaction or series of transactions (including, but
not limited to, the sale, transfer, disposition, purchase, exchange or lease of
Property, the making of any Investment, the giving of any Guarantee or the
rendering of any service) with or for the benefit of any Affiliate of the
Company, unless (i) an Officer will have determined, in his good faith judgment,
that such transaction or series of transactions is in the best interest of the
Company or such Restricted Subsidiary, and on terms no less favorable to the
Company or such Restricted Subsidiary than those that could be obtained in a
comparable arm's-length transaction with a Person that is not an Affiliate of
the Company, and the Company delivers an Officers' Certificate to the Trustee to
that effect, (ii) with respect to a transaction or series of transactions
involving aggregate payments by the Company or such Restricted Subsidiary having
a Fair Market Value equal to or in excess of $10 million, the Board of Directors
of the Company (including a majority of the disinterested Directors) approves
such transaction or series of transactions and determines, in its good faith
judgment, that such transaction or series of transactions complies with the
standards set forth in clause (i) of this paragraph, and the Company delivers a
certified resolution to the Trustee to that effect and (iii) with respect to a
transaction or series of transactions involving aggregate payments by the
Company or such Restricted Subsidiary having a Fair Market Value equal to or in
excess of $25 million, the Company receives the written opinion of a nationally
recognized investment banking firm or other nationally recognized expert having
sufficient expertise to the effect that such transaction (or series of
transactions) is fair to the Company from a financial point of view, which
opinion shall be delivered promptly to the Trustee. With respect to any capital
contribution to, or transaction with, a Subsidiary, the requirement that a
transaction be on "terms no less favorable to the Company or such Restricted
Subsidiary than those that could be obtained in a comparable arm's length
transaction with a Person that is not an Affiliate of the Company" shall be
satisfied if such transaction is fair, from a financial point of view, to the
Company.
The limitations of the preceding paragraph do not apply to (i) transactions
with Affiliates in accordance with the terms of agreements as in effect on the
date of the Indenture (and not otherwise in violation of the Indenture) provided
that any renewal or modification of the terms of any such agreement after the
date of the Indenture shall comply with the preceding paragraph, or (ii)
transactions with Restricted Subsidiaries. The requirements of clause (iii) of
the preceding paragraph shall not apply (i) to a transaction that constitutes a
Permitted Business Investment if none of the parties to such transaction (other
than the Company, the Restricted Subsidiary (if any) making such Permitted
Business Investment, other Restricted Subsidiaries of the Company and the entity
(if any) receiving such Permitted Business Investment) (x) are Affiliates of the
Company or (y) were during the preceding 12 months, or are expected during the
following 12 months to be, associated with more than 10% of the net oil and gas
production of the Company and its Subsidiaries (whether by reason of purchases
of oil and gas or any kind of shared or cooperative production arrangements) or
(ii) to additional sales of or commitments to sell to Hadson natural gas on
terms no less favorable to the Company than those obtained as of the date of the
Indenture pursuant to the Hadson Agreement (Section 4.07)
Limitation on Sales of Assets. The Company will not, and will not permit
any Restricted Subsidiary to, make any Asset Sale unless (i) the Company or such
Restricted Subsidiary, as the case may be,
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receives consideration at the time of such Asset Sale at least equal to the Fair
Market Value of the shares and assets subject to such Asset Sale, (ii) all of
the consideration paid to the Company or such Restricted Subsidiary in
connection with such Asset Sale is in the form of cash, cash equivalents, Liquid
Securities or the assumption by the purchaser of liabilities other than
Subordinated Indebtedness (provided, however, that (x) the Fair Market Value of
oil and gas properties with proved reserves received by the Company or a
Restricted Subsidiary in trade for other such properties (and, if the assets
traded by the Company or a Restricted Subsidiary consist of properties without
proved reserves, the Fair Market Value of properties with or without proved
reserves received in exchange for such traded properties) shall be treated as
cash for purposes of this clause (ii) and (y) the Company and its Restricted
Subsidiaries shall be permitted to receive securities other than cash
equivalents or Liquid Securities with an aggregate Fair Market Value (measured
as of the date of the then-proposed Asset Sale) not in excess of: (1) in
connection with any one or series of related Asset Sales, 10% of Consolidated
Net Tangible Assets and (2) when considered with all other such securities
received in connection with Asset Sales after the date of the Indenture and held
by the Company or a Restricted Subsidiary as of the date of the determination,
25% of Consolidated Net Tangible Assets) and (iii) the Company delivers an
Officers' Certificate to the Trustee certifying that such Asset Sale complies
with clauses (i) and (ii).
The Net Available Cash from Asset Sales may (but need not) be applied by
the Company or a Restricted Subsidiary (A) to the extent the Company or such
Restricted Subsidiary elects (or is required by the terms of any Senior
Indebtedness), to prepay, repay or purchase Senior Indebtedness or Indebtedness
(other than Redeemable Stock) of a Restricted Subsidiary (in each case excluding
Indebtedness owed to the Company or an Affiliate of the Company); (B) to the
extent the Company or such Restricted Subsidiary elects, to reinvest in
Additional Assets (including by means of an Investment in Additional Assets by a
Restricted Subsidiary with Net Available Cash received by the Company or another
Restricted Subsidiary); or (C) to the extent the Company or such Restricted
Subsidiary elects, to purchase Debentures (excluding Debentures owned by the
Company or an Affiliate of the Company).
Any Net Available Cash from an Asset Sale not applied in accordance with
the preceding paragraph within 360 days from the date of such Asset Sale shall
constitute "Excess Proceeds." When the aggregate amount of Excess Proceeds
exceeds $10 million, the Company will be required to purchase Debentures
tendered pursuant to an offer by the Company for Debentures (the "Prepayment
Offer") at a purchase price of at least 100% of their principal amount plus
accrued and unpaid interest thereon (if any) to the Purchase Date (as defined
below) in accordance with the procedures (including prorating in the event of
oversubscription) set forth in the Indenture. To the extent that any portion of
the amount of Net Available Cash remains after compliance with the preceding
sentence and provided that all Holders of Debentures have been given the
opportunity to tender their Debentures for repurchase as described in the
following paragraph in accordance with the Indenture, the Company or such
Restricted Subsidiary may use such remaining amount for general corporate
purposes and the amount of Excess Proceeds will be reset to zero.
Promptly, and in any event within 10 days after the Company becomes
obligated to make a Prepayment Offer, the Company will deliver to the Trustee
and send to each holder of the Debentures a written notice stating that such
holder may elect to have its Debentures purchased by the Company, either in
whole or in part (subject to prorationing in the event the Prepayment Offer is
oversubscribed) and in integral multiples of $1,000 of principal amount, at the
applicable purchase price. The notice will specify a purchase date not less than
30 days nor more than 60 days after the date of such notice (the "Purchase
Date") and will contain information concerning the business of the Company which
the Company in good faith believes will enable such holder to make an informed
decision and will contain all instructions and materials necessary to tender
Debentures pursuant to the Prepayment Offer and the procedures for withdrawing
such a tender (such procedures as set forth in the Indenture).
The Company will comply, to the extent applicable, with the requirements of
Section 14(e) of the Exchange Act and any other securities laws or regulations
in connection with the repurchase of Debentures as described above. To the
extent that the provisions of any securities laws or regulations
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conflict with provisions relating to the Prepayment Offer, the Company will
comply with the applicable securities laws and regulations and will not be
deemed to have breached its obligations described above by virtue thereof.
In connection with any prepayment, repayment or purchase of Indebtedness
pursuant to clause (A) or (C) or an offer to repurchase Debentures using Excess
Proceeds, the Company or such Restricted Subsidiary will permanently retire such
Indebtedness and, if the Indebtedness permanently retired constitutes
Indebtedness under a Bank Credit Facility, then the amount of Indebtedness
permitted under clause (c) of the definition of "Permitted Indebtedness" shall
thereafter be deemed to have been permanently reduced by the amount of such
retirement; provided, however, that notwithstanding any permanent retirement of
Indebtedness under a Bank Credit Facility in accordance with this provision, the
related loan commitment (if any) need not be reduced and the Company may
continue to Incur Indebtedness pursuant to such commitment to the extent
permitted under such clause (c) (as so reduced) and/or under any other clause of
the definition of "Permitted Indebtedness." Pending application of Net Available
Cash pursuant to this provision, such Net Available Cash will be invested in
Permitted Short Term Investments or will be applied temporarily to reduce
amounts outstanding under revolving credit facilities. (Section 4.06)
Limitation on Restrictions on Distributions from Restricted
Subsidiaries. The Company will not and will not permit any of its Restricted
Subsidiaries to, directly or indirectly, create or otherwise cause or suffer to
exist or become effective, or enter into any agreement with any person that
would cause to become effective, any consensual encumbrance or restriction on
the legal right of any Restricted Subsidiary to (a) pay dividends, in cash or
otherwise, or make any other distributions on or in respect of its Capital Stock
or Redeemable Stock or any other interest in, or measured by, its profits owned
by, or pay any Indebtedness or other obligation owed to, the Company or any
other Restricted Subsidiary of the Company, (b) make any loans or advances to
the Company or any other Restricted Subsidiary or (c) transfer any of its
property or assets to the Company or any other Restricted Subsidiary. Such
limitation will not apply (1) with respect to clauses (b) and (c) of the
preceding sentence only, to encumbrances and restrictions (i) in existence under
or by reason of any agreements in effect on the date of the Indenture, (ii)
existing at such Subsidiary at the time it became a Restricted Subsidiary of the
Company if (A) such encumbrance or restriction was not created in anticipation
of such Subsidiary becoming a Restricted Subsidiary of the Company and (B)
immediately following such Subsidiary becoming a Restricted Subsidiary of the
Company, on a pro forma basis, the Company could Incur at least $1.00 of
additional Indebtedness pursuant to clause (a) of the second paragraph of
"--Limitation on Indebtedness" or (iii) which result from the renewal,
refinancing, extension or amendment of an agreement referred to in the
immediately preceding clause (i) or (ii) provided such replacement or
encumbrance or restriction is no more restrictive to the Company or any
Restricted Subsidiary and is released or removed by its terms no later than that
which it replaced, (2) with respect to clause (c) of the preceding sentence
only, to restrictions in the form of Liens that are not prohibited as described
under "Limitation on Liens" and which contain customary limitations on the
transfer of collateral and (3) with respect to clauses (a), (b) and (c) of the
preceding sentence, to encumbrances and restrictions on a Restricted Subsidiary
so long as (x) such Restricted Subsidiary (together with all other Restricted
Subsidiaries subject to encumbrances or restrictions permitted under this clause
(3)) does not, during the four full fiscal quarters immediately prior to the
incurrence of such encumbrance or restriction, represent 10% or more of the
EBITDA of the Company during such period and (y) at the date of the incurrence
of such encumbrance or restriction (after giving pro forma effect to the
exclusion of such Restricted Subsidiary from the calculation of the Consolidated
Interest Coverage Ratio) the Company could Incur at least $1.00 of additional
Indebtedness pursuant to clause (a) of the definition of "Permitted
Indebtedness". (Section 4.05)
Restricted and Unrestricted Subsidiaries. The Board of Directors of the
Company may designate any Subsidiary of the Company or any Restricted Subsidiary
to be an Unrestricted Subsidiary if (i) the Subsidiary to be so designated does
not own any Capital Stock, Redeemable Stock or Indebtedness of, or own or hold
any Lien on any property of, the Company or any Restricted Subsidiary of the
Company,
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(ii) the Subsidiary to be so designated is not obligated by any Indebtedness or
Lien that, if in default, would result (with the passage of time or notice or
otherwise) in a default on any Indebtedness of the Company or any Restricted
Subsidiary, and (iii) either (A) the Subsidiary to be so designated has total
assets of $1,000 or less, or (B) such designation is effective immediately upon
such Person becoming a Subsidiary of the Company or of a Restricted Subsidiary.
Unless so designated as an Unrestricted Subsidiary, any Person that becomes a
Subsidiary of the Company or any Restricted Subsidiary will be classified as a
Restricted Subsidiary. Except as provided in the first sentence of this
paragraph, no Restricted Subsidiary may be redesignated as an Unrestricted
Subsidiary. An Unrestricted Subsidiary may not be redesignated as a Restricted
Subsidiary.
Any such designation by the Board of Directors of the Company will be
evidenced to the Trustee by promptly filing with the Trustee a copy of the
resolution of such Board giving effect to such designation and an Officers'
Certificate certifying that such designation complies with the foregoing
provisions. (Section 4.12)
MERGER, CONSOLIDATION AND SALE OF ASSETS
The Company will not merge or consolidate with or into any other entity
(other than a merger or consolidation of a Restricted Subsidiary into the
Company) or sell, transfer, assign, lease, convey or otherwise dispose of all or
substantially all of its Property to any Person, unless (a) the entity formed by
or surviving any such consolidation or merger (if the Company is a party to the
transaction and is not the surviving entity) or to which such sale, transfer or
conveyance is made (the "Surviving Entity") shall be an entity organized and
existing under the laws of the United States of America or a State thereof or
the District of Columbia and such Surviving Entity expressly assumes, by
supplemental indenture satisfactory to the Trustee, executed and delivered to
the Trustee by such Surviving Entity, the due and punctual payment of the
principal of, premium, if any, and interest on all the Debentures, according to
their tenor, and the due and punctual performance and observance of all of the
covenants and conditions of the Indenture to be performed by the Company; (b)
immediately before and after giving effect to such transaction or series of
transactions, no Default or Event of Default shall have occurred and be
continuing; (c) immediately after giving effect to such transaction or series of
transactions on a pro forma basis (including, without limitation, any
Indebtedness incurred or anticipated to be incurred in connection with such
transaction or series of transactions), the Company or the Surviving Entity, as
the case may be, would be able to incur at least $1.00 of additional
Indebtedness under clause (a) of the second paragraph of "--Limitation on
Indebtedness"; and (d) immediately after giving effect to such transaction or
series of transactions on a pro forma basis (including, without limitation, any
Indebtedness incurred or anticipated to be incurred in connection with such
transaction or series of transactions), the Company or the Surviving Entity
shall have a Consolidated Net Worth equal to or greater than the Consolidated
Net Worth of the Company immediately prior to the transaction or series of
transactions. (Section 5.01)
Upon any consolidation or merger, or any sale, assignment, transfer, lease,
conveyance or other disposition of the assets of the Company as an entirety or
virtually as an entirety in accordance with the preceding paragraph, the
successor entity formed by such consolidation or into which the Company is
merged or to which such sale, assignment, transfer, lease, conveyance or other
disposition is made will succeed to, and be substituted for, and may exercise
every right and power of, the Company under the Indenture with the same effect
as if such successor entity had been named as the Company therein. (Section
5.02)
CERTAIN DEFINITIONS
"Additional Assets" means (i) any Property (other than cash, cash
equivalents or securities) used in any business in which the Company or any
Restricted Subsidiary is engaged as of the date of the Indenture or any business
ancillary thereto, (ii) securities representing 100% of the equity of an issuer
engaged in any such business or (iii) Permitted Business Investments.
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"Affiliate" of any specified Person means any other Person (i) which
directly or indirectly through one or more intermediaries controls, or is
controlled by, or is under common control with, such specified Person, or (ii)
which beneficially owns or holds directly or indirectly 10% or more of any class
of the Voting Stock or Voting Redeemable Stock of such specified Person or of
any Subsidiary of such specified Person. For the purposes of this definition,
"control", when used with respect to any specified Person, means the power to
direct the management and policies of such Person directly or indirectly,
whether through the ownership of Voting Stock, by contract or otherwise; and the
terms "controlling" and "controlled" have meanings correlative to the foregoing.
"Asset Sale" means, with respect to any Person, any transfer, conveyance,
sale, lease or other disposition (including, without limitation, dispositions
pursuant to any consolidation or merger, but excluding any Sale and Leaseback
Transaction) by such Person or any of its Restricted Subsidiaries in any single
transaction or series of transactions of (a) shares of Capital Stock or other
ownership interests of another Person (including transfers of outstanding
Capital Stock of, and issuances of Capital Stock by, Restricted Subsidiaries and
Unrestricted Subsidiaries that are owned directly by the Company or a Restricted
Subsidiary) or (b) any other Property of such Person or any of its Restricted
Subsidiaries; provided, however, that the term "Asset Sale" shall not include
(i) the sale or transfer of Permitted Short-Term Investments, inventory or other
Property (or interests therein) in the ordinary course of business, or the sale
or transfer of oil and gas properties or direct or indirect interests in real
property, provided that such properties and interests do not have associated
with them any proved reserves (whether or not in the ordinary course of
business); (ii) a sale or transfer of hydrocarbons or other mineral products in
the ordinary course of business of the oil and gas production operations
conducted by the Company and its Restricted Subsidiaries; (iii) the liquidation
of Property received in settlement of debts owing to the Company or any
Restricted Subsidiary as a result of foreclosure, perfection or enforcement of
any Lien or debt, which debts were owing to the Company or any Restricted
Subsidiary in the ordinary course of business of the Company or such Restricted
Subsidiary; (iv) when used with respect to the Company, any asset disposition
permitted pursuant to the covenant described under "--Merger, Amalgamation,
Consolidation and Sale of Assets" which constitutes a disposition of all or
substantially all of the Company's assets; or (v) the sale or transfer of any
Property or Capital Stock by the Company to a Restricted Subsidiary or by a
Restricted Subsidiary to the Company or by a Restricted Subsidiary to a
Restricted Subsidiary.
"Average Life" means, as of the date of determination, with respect to any
Indebtedness or Preferred Stock, the quotient obtained by dividing (i) the sum
of the products of (x) the numbers of years from the date of determination to
the dates of each successive scheduled principal payment of such Indebtedness or
redemption or similar payment with respect to such Preferred Stock multiplied by
(y) the amount of such payment by (ii) the sum of all such payments.
"Bank Credit Facilities" means with respect to any Person, one or more debt
facilities or commercial paper facilities with banks or other institutional
lenders, whether or not in effect on the date of the Indenture, providing for
revolving credit loans, term loans, receivables financing (including through the
sale of receivables to such lenders or to special purpose entities formed to
borrow from such lenders against such receivables) or letters of credit.
Notwithstanding the foregoing, if the Company or any Restricted Subsidiary
chooses to Incur Indebtedness under any such facility after the Issue Date of
the Debentures in compliance with the "Limitation on Indebtedness" covenant but
not in reliance on the exception provided by clause (c) thereof or clause (l)
thereof (with respect to a refinancing of Indebtedness under Bank Credit
Facilities), such Indebtedness shall not constitute Indebtedness under Bank
Credit Facilities for purposes of the Indenture.
"Capital Expenditure Indebtedness" means Indebtedness Incurred by any
Person to finance a capital expenditure so long as (i) such capital expenditure
is or should be included as an "addition to oil and gas properties and
equipment, net" or "to property, plant or equipment" in accordance with GAAP,
and (ii) such Indebtedness is Incurred within 360 days of the date such capital
expenditure is made.
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"Capital Lease Obligation" of any Person means the obligation to pay rent
or other payment amounts under a lease of (or other arrangement conveying the
right to use) real or personal property of such Person which is required to be
classified and accounted for as a capitalized lease or a liability on the face
of a balance sheet of such Person in accordance with GAAP, to the extent
required pursuant to GAAP. For purposes of the "Limitation on Liens" covenant, a
Capital Lease Obligation shall be deemed to be secured by a Lien on the property
being leased.
"Capital Stock" in any Person means any and all shares, interests,
participations or other equivalents in the equity interest (however designated)
in such Person and any rights (other than debt securities convertible into an
equity interest), warrants or options to subscribe for or to acquire an equity
interest in such Person; provided, however, that "Capital Stock" shall not
include Redeemable Stock but shall, with respect to the Company, include the 7%
Preferred Stock.
"Change of Control" means the occurrence of any of the following events:
(i) any "person" (as such term is used in Sections 13(d) and 14(d) of the
Exchange Act), other than one or more Permitted Holders or an underwriter
engaged in a firm commitment underwriting in connection with a public offering
of the Voting Stock of the Company, is or becomes the "beneficial owner" (as
defined in Rules 13d-3 and 13d-5 under the Exchange Act, except that a person
shall be deemed to have "beneficial ownership" of all shares that any such
person has the right to acquire, whether such right is exercisable immediately
or only after the passage of time), directly or indirectly, of more than 35% of
the total voting power of the Voting Stock of the Company; (ii) during any
period of two consecutive years, individuals who at the beginning of such period
constitute the Board of Directors of the Company (together with any new
directors whose election by such Board of Directors or whose nomination for
election by the shareholders of the Company was approved by a vote of a majority
of the directors of the Company then still in office who were either directors
at the beginning of such period or whose election or nomination for election was
previously so approved) cease for any reason to constitute a majority of the
Board of Directors then in office; or (iii) the Company, either individually or
in conjunction with one or more of its Subsidiaries, sells, conveys, leases or
otherwise transfers or one or more such Subsidiaries sell, convey, lease or
otherwise transfer all or substantially all of the assets of the Company and the
Restricted Subsidiaries, taken as a whole, to any Person (other than a
Restricted Subsidiary).
"Consolidated Adjusted Net Income" of any Person means, for any period, the
aggregate net income (or net loss, as the case may be) of such Person and its
Restricted Subsidiaries for such period on a consolidated basis, determined in
accordance with GAAP, provided that there shall be excluded therefrom, without
duplication, (i) items classified as extraordinary (other than the tax benefit
of the utilization of net operating loss carryforwards and alternative minimum
tax credits), (ii) gains and losses from asset sales outside the ordinary course
of business, (iii) except to the extent of the amount of cash dividends or other
cash distributions actually paid to such specified Person or its Restricted
Subsidiaries by any other Person during such period, the net income (or loss) of
such other Person other than a Restricted Subsidiary of such specified Person,
(iv) the net income of any Person acquired by such specified Person or any of
its consolidated Restricted Subsidiaries in a pooling-of-interests transaction
for any period prior to the date of such acquisition, (v) any gain or loss, net
of taxes, realized on the termination of any employee pension benefit plan, and
(vi) the net income of any subsidiary of such specified Person to the extent
that the transfer to that Person of that income is restricted by contract or
otherwise, except for any dividends or distributions actually paid by such
subsidiary to such Person.
"Consolidated Interest Coverage Ratio" means as of the date of the
transaction giving rise to the need to calculate the Consolidated Interest
Coverage Ratio (the "Transaction Date"), the ratio of (i) the aggregate amount
of EBITDA of the Company and its consolidated Restricted Subsidiaries for the
four full fiscal quarters immediately prior to the Transaction Date to (ii) the
aggregate Consolidated Interest Expense of the Company and its Restricted
Subsidiaries that is anticipated to accrue during a period consisting of the
fiscal quarter in which the Transaction Date occurs and the three fiscal
quarters immediately subsequent thereto (based upon the pro forma amount and
maturity of, and interest payments in respect of, Indebtedness expected to be
outstanding on the Transaction Date), assuming the continuation of market
interest rates prevailing on the Transaction Date and base interest rates in
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respect of floating interest rate obligations equal to the base interest rates
in effect as of the Transaction Date; provided, however, that if the Company or
any of its Restricted Subsidiaries is a party to any Interest Rate Protection
Agreements which would have the effect of changing the interest rate on any
Indebtedness of the Company or any of its Restricted Subsidiaries for all (or
any portion of ) such four-quarter period, the resulting rate shall be used for
such four-quarter period (or corresponding portion thereof); provided, further,
that any Consolidated Interest Expense with respect to Indebtedness Incurred or
retired during the fiscal quarter in which the Transaction Date occurs shall be
calculated as if such Indebtedness was so Incurred or retired on the first day
of such fiscal quarter. In addition, if since the beginning of the four full
fiscal quarter period preceding the Transaction Date, (x) the Company or any of
its Restricted Subsidiaries shall have engaged in any asset sale out of the
ordinary course of business, EBITDA for such period shall be reduced by an
amount equal to the EBITDA (if positive), or increased by an amount equal to the
EBITDA (if negative), directly attributable to the assets which are the subject
of such asset sale for such period calculated on a pro forma basis as if such
sale and the receipt and application of the proceeds therefrom (including,
without limitation, any related retirement of Indebtedness) had occurred on the
first day of such period or (y) the Company or any of its Restricted
Subsidiaries shall have acquired any assets out of the ordinary course of
business, EBITDA shall be calculated on a pro forma basis as if such acquisition
had occurred on the first day of such four-quarter period.
"Consolidated Interest Expense" means, with respect to any Person for any
period, without duplication (A) the sum of (i) the aggregate amount of cash and
noncash interest expense (including capitalized interest) of such Person and its
Restricted Subsidiaries for such period as determined on a consolidated basis in
accordance with GAAP in respect of Indebtedness (including, without limitation,
(v) any amortization of debt discount, (w) net costs associated with any
Interest Rate Protection Agreement (including any amortization of discounts),
(x) the interest portion of any deferred payment obligation, (y) all accrued
interest, and (z) all commissions, discounts, commitment fees, origination fees
and other fees and charges owed with respect to Bank Credit Facilities and other
Indebtedness) paid, accrued or scheduled to be paid or accrued, during such
period; (ii) Redeemable Stock dividends of such Person (and of its Restricted
Subsidiaries if paid to a Person other than such Person or its Restricted
Subsidiaries) declared and payable; (iii) the portion of any rental obligation
of such Person or its Restricted Subsidiaries in respect of any Capital Lease
Obligation allocable to interest expense in accordance with GAAP; (iv) the
portion of any rental obligation of such Person or its Restricted Subsidiaries
in respect of any Sale and Leaseback Transaction allocable to interest expense
(determined as if such were treated as a Capital Lease Obligation); and (v) to
the extent any Indebtedness of any other Person is Guaranteed by such Person or
any of its Restricted Subsidiaries and on any determination date such
Indebtedness is in default or the Company should reasonably expect to make any
payments in respect of such Indebtedness during the four fiscal quarters
immediately following such date, the aggregate amount of interest paid, accrued
or scheduled to be paid or accrued, by such other Person during such period
attributable to any such Indebtedness, less (B) to the extent included in (A)
above, amortization or write-off of deferred financing costs (other than
discounts) of such Person and its Restricted Subsidiaries during such period and
any charge related to any premium or penalty paid in connection with redeeming
or retiring any Indebtedness of such Person and its Restricted Subsidiaries
prior to its Stated Maturity; in the case of both (A) and (B) above, after
elimination of intercompany accounts among such Person and its Restricted
Subsidiaries and as determined in accordance with GAAP.
"Consolidated Net Tangible Assets", as of any date of determination, means
the sum of the amounts that would appear on a consolidated balance sheet of the
Company and its consolidated Subsidiaries (other than Unrestricted Subsidiaries)
for the total assets (less accumulated depreciation or amortization, allowances
for doubtful receivables, other applicable reserves and other properly
deductible items) of the Company and its consolidated Subsidiaries (other than
Unrestricted Subsidiaries), determined on a consolidated basis in accordance
with GAAP, after giving effect to purchase accounting and after deducting
therefrom, to the extent otherwise included, the amounts of (without
duplication): (i) the aggregate amount of liabilities of the Company and its
consolidated Subsidiaries (other than Unrestricted
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Subsidiaries) which may properly be classified as current liabilities (including
taxes accrued as estimated), determined on a consolidated basis in accordance
with GAAP; (ii) minority interests in consolidated Subsidiaries held by Persons
other than the Company or a Restricted Subsidiary; (iii) the excess of cost over
Fair Market Value of assets or businesses acquired; (iv) any revaluation or
other write-up in book value of assets subsequent to the last day of the fiscal
quarter of the Company immediately preceding the Issue Date as a result of a
change in the method of valuation in accordance with GAAP; (v) unamortized debt
discount and expenses and other unamortized deferred charges, goodwill, patents,
trademarks, service marks, trade names, copyrights, licenses, organization or
developmental expenses and other intangible items (if included in total assets);
(vi) treasury stock (if included in total assets); and (vii) cash set apart and
held in a sinking or other analogous fund established for the purpose of
redemption or other retirement of Capital Stock or Indebtedness or restricted
cash (in accordance with GAAP).
"Consolidated Net Worth" of any Person means the stockholders' equity of
such Person and its Restricted Subsidiaries, as determined on a consolidated
basis in accordance with GAAP, less (to the extent included in stockholders'
equity) amounts attributable to Redeemable Stock of such Person or its
Restricted Subsidiaries.
"Default" means any event, act or condition the occurrence of which is, or
after notice or the passage of time or both would be, an Event of Default.
"Designated Senior Indebtedness" means any Senior Indebtedness which has,
at the time of determination, an aggregate principal amount outstanding of at
least $ million (including the amount of all undrawn commitments and
matured and contingent reimbursement obligations pursuant to letters of credit
thereunder) and is specifically designated in the instrument evidencing such
Senior Indebtedness or is designated in an irrevocable notice delivered by the
Company to the holders or a Representative of the holders of such Senior
Indebtedness and the Trustee as "Designated Senior Indebtedness" of the Company.
"Dollar-Denominated Production Payments" mean dollar-denominated production
payment obligations that are or, upon the occurrence of a contingent event,
would be recorded as liabilities in accordance with GAAP. Such obligations will
be deemed to constitute Indebtedness for borrowed money for purposes of the
Indenture.
"EBITDA" means with respect to any Person for any period, the Consolidated
Adjusted Net Income of such Person and its consolidated Restricted Subsidiaries
for such period, plus (a) the sum of, to the extent reflected in the
consolidated income statement of such Person and its Restricted Subsidiaries for
such period from which Consolidated Adjusted Net Income is determined and
deducted in the determination of such Consolidated Adjusted Net Income, without
duplication, (i) income tax expense, (ii) Consolidated Interest Expense, (iii)
depreciation and depletion expense, (iv) amortization expense, and (v) any other
non-cash charges including, without limitation, unrealized foreign exchange
losses, less (b) the sum of, to the extent reflected in the consolidated income
statement of such Person and its Restricted Subsidiaries for such period from
which Consolidated Adjusted Net Income is determined and added in the
determination of such Consolidated Adjusted Net Income, without duplication (i)
income tax recovery and (ii) unrealized foreign exchange gains.
"Fair Market Value" means, with respect to any assets to be transferred
pursuant to any Asset Sale or Sale and Leaseback Transaction or any noncash
consideration or Property transferred or received by any Person, the fair market
value of such consideration or property as determined in good faith by (i) any
Officer of the Company if such fair market value does not exceed $10 million and
(ii) the Board of Directors of the Company as evidenced by a certified
resolution delivered to the Trustee if such fair market value exceeds $10
million; provided that if such resolution indicates that such fair market value
exceeds $25 million and such Transaction involves any Affiliate of the Company
(other than a Restricted Subsidiary), such resolution shall be accompanied by
the written opinion delivered to the Trustee of a nationally recognized
investment banking firm or another nationally recognized expert having
sufficient
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expertise to the effect that such consideration or property is fair, from a
financial point of view, to such Person.
"GAAP" means United States generally accepted accounting principles as in
effect on the date of the Indenture.
"Guarantee" by any Person means any obligation, contingent or otherwise, of
such Person guaranteeing or having the economic effect of guaranteeing any
Indebtedness of any other Person (the "primary obligor") in any manner, whether
directly or indirectly, and including, without limitation, any Lien on the
assets of such Person securing obligations of the primary obligor and any
obligation of such Person (i) to purchase or pay (or advance or supply funds for
the purchase or payment of) such Indebtedness or to purchase (or to advance or
supply funds for the purchase or payment of) any security for the payment of
such Indebtedness, (ii) to purchase Property, securities or services for the
purpose of assuring the holder of such Indebtedness of the payment of such
Indebtedness, or (iii) to maintain working capital, equity capital or other
financial statement condition or liquidity of the primary obligor so as to
enable the primary obligor to pay such Indebtedness (and "Guaranteed",
"Guaranteeing" and "Guarantor" shall have meanings correlative to the
foregoing); provided, however, that a Guarantee by any Person shall not include
endorsements by such Person for collection or deposit, in either case, in the
ordinary course of business.
"Hedging Agreements" means Interest Rate Protection Agreements and Oil and
Gas Purchase and Sale Contracts.
"Incur" means, with respect to any Indebtedness or other obligation of any
Person, to create, issue, incur (by conversion, exchange or otherwise), extend,
assume, Guarantee or otherwise become liable in respect of such Indebtedness or
other obligation or the recording, as required pursuant to GAAP or otherwise, of
any such Indebtedness or obligation on the balance sheet of such Person (and
"Incurrence", "Incurred", "Incurrable" and "Incurring" shall have meanings
correlative to the foregoing); provided, however, that a change in GAAP that
results in an obligation of such Person that exists at such time becoming
Indebtedness shall not be deemed an Incurrence of such Indebtedness.
"Indebtedness" means at any time (without duplication), with respect to any
Person, whether recourse is to all or a portion of the assets of such Person,
and whether or not contingent, (i) any obligation of such Person for borrowed
money, (ii) any obligation of such Person evidenced by bonds, debentures, notes,
Guarantees or other similar instruments, including, without limitation, any such
obligations Incurred in connection with the acquisition of Property, assets or
businesses, (iii) any reimbursement obligation of such Person with respect to
letters of credit, bankers' acceptances or similar facilities issued for the
account of such Person, (iv) any obligation of such Person issued or assumed as
the deferred purchase price of Property or third party services, (v) any Capital
Lease Obligation of such Person, (vi) the maximum fixed redemption or repurchase
price of Redeemable Stock of such Person at the time of determination, (vii) any
payment obligation of such Person under Hedging Agreements at the time of
determination, (viii) any obligation to pay rent or other payment amounts of
such Person with respect to any Sale and Leaseback Transaction to which such
Person is a party, (ix) any obligation of the type referred to in clauses (i)
through (viii) of this paragraph of another Person and all dividends of another
Person the payment of which, in either case, such Person has Guaranteed or is
responsible or liable, directly or indirectly, as obligor, Guarantor or
otherwise and (x) any payment obligation of such Person in respect of any
Production Payment. For purposes of this definition, the maximum fixed
repurchase price of any Redeemable Stock that does not have a fixed repurchase
price shall be calculated in accordance with the terms of such Redeemable Stock
as if such Redeemable Stock were repurchased on any date on which Indebtedness
shall be required to be determined pursuant to the Indenture; provided, however,
that if such Redeemable Stock is not then permitted to be repurchased, the
repurchase price shall be the book value of such Redeemable Stock as reflected
in the most recent financial statements of such Person. The amount of
Indebtedness of any Person at any date shall be the outstanding balance at such
date of all unconditional obligations as described above and the maximum
liability of any contingent obligations in respect thereof at such date.
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"Interest Rate Protection Agreement" means, with respect to any Person, any
interest rate swap agreement, forward rate agreement, interest rate cap or
collar agreement or other financial agreement or arrangement designed to protect
such Person or its Restricted Subsidiaries against fluctuations in interest
rates, as in effect from time to time.
"Investment" means, with respect to any Person (i) any amount paid by such
Person, directly or indirectly, to any other Person for Capital Stock or other
Property of, or as a capital contribution to, any other Person (the amount of
any investment made other than in cash to be determined by the fair market value
of such non-cash investment at the time so made) or (ii) any direct or indirect
loan or advance to any other Person (other than accounts receivable of such
Person arising in the ordinary course of business), but excluding any increase
in equity ownership in a Person resulting from retained earnings of such Person.
"Lien" means, with respect to any Property, any mortgage or deed of trust,
pledge, hypothecation, assignment, deposit arrangement, security interest, lien
(statutory or other), charge, easement, encumbrance, preference, priority or
other security or similar agreement or preferential arrangement of any kind or
nature whatsoever on or with respect to such Property (including, without
limitation, any conditional sale or other title retention agreement having
substantially the same economic effect as any of the foregoing). For purposes of
the "Limitation on Liens" covenant, a Capital Lease Obligation shall be deemed
to be secured by a Lien on the property being leased.
"Liquid Securities" means securities (i) of an issuer that is not an
Affiliate of the Company, (ii) that are publicly traded on the New York Stock
Exchange, the American Stock Exchange or the Nasdaq National Market, (iii) as to
which the Company is not subject to any restrictions on sale or transfer
(including any volume restrictions under Rule 144 under the Securities Act or
any other restrictions imposed by the Securities Act) or as to which a
registration statement under the Securities Act covering the resale thereof is
in effect for as long as the securities are held and (iv) that are subsequently
sold or exchanged for cash or cash equivalents within 180 days of the receipt
thereof.
"Moody's" means Moody's Investors Service, Inc. and its successors.
"Net Available Cash" from an Asset Sale means cash proceeds received
(including any cash proceeds received by way of deferred payment of principal
pursuant to a note or installment receivable or otherwise, but only as and when
received, and excluding any other consideration received in the form of
assumption by the acquiring person of Indebtedness or other obligations relating
to such properties or assets) therefrom, in each case net of (i) all legal,
title and recording tax expenses, commissions and other fees and expenses
incurred, and all Federal, state, provincial, foreign and local taxes required
to be paid or accrued as a liability under GAAP as a consequence of such Asset
Sale, (ii) all payments made on any Indebtedness which is secured by any assets
subject to such Asset Sale, in accordance with the terms of any Lien upon such
assets, or which must by its terms, or in order to obtain a necessary consent to
such Asset Sale or by applicable law, be repaid out of the proceeds from such
Asset Sale, (iii) all distributions and other payments required to be made to
minority interest holders in Subsidiaries or joint ventures as a result of such
Asset Sale and (iv) the deduction of appropriate amounts to be provided by the
seller as a reserve, in accordance with GAAP, against any liabilities associated
with the assets disposed of in such Asset Sale and retained by the Company or
any Restricted Subsidiary after such Asset Sale; provided, however, that in the
event that any consideration for an Asset Sale (which would otherwise constitute
Net Available Cash) is required to be held in escrow pending determination of
whether a purchase price adjustment will be made, such consideration (or any
portion thereof) shall become Net Available Cash only at such time as it is
released to such Person or its Restricted Subsidiaries from escrow; and
provided, further, however, that any non-cash consideration received in
connection with an Asset Sale which is subsequently converted to cash shall be
deemed to be Net Available Cash at such time and shall thereafter be applied in
accordance with the "Limitation on Sales of Assets" covenant.
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"Oil and Gas Business" means the business of the exploration for, and
development, acquisition, production, processing, marketing, refining, storage
and transportation of, hydrocarbons and other related energy and natural
resource businesses.
"Oil and Gas Liens" means (i) Liens on any specific property or any
interest therein, construction thereon or improvement thereto to secure all or
any part of the costs incurred for surveying, exploration, drilling, extraction,
development, construction, alteration, repair or improvement of, in, under or on
such property (it being understood that, in the case of oil and gas producing
properties, or any interest therein, costs incurred for "development" shall
include costs incurred for all facilities relating to such properties or to
projects, ventures or other arrangements of which such properties form a part or
which relate to such properties or interests); (ii) Liens or the creation of
encumbrances on an oil and/or gas producing property to secure obligations
incurred or guarantees of obligations incurred in connection with or necessarily
incidental to commitments for the purchase or sale of, or the transportation or
distribution of, the products derived from such property; (iii) Liens reserved
in oil and gas mineral leases for bonus or rental payments and for compliance
with the terms of such leases provided that such Liens are limited to the oil
and gas subject to the relevant leases; (iv) Liens arising under partnership
agreements, oil and gas leases, farm-out agreements, division orders, contracts
for the sale, purchase, exchange, transportation, gathering or processing of
oil, gas or other hydrocarbons, unitization and pooling designations,
declarations, orders and agreements, development agreements, operating
agreements, area of mutual interest agreements, gas balancing or deferred
production agreements, injection, repressuring and recycling agreements, salt
water or other disposal agreements, seismic or geophysical permits or
agreements, and other agreements which are customary in the Oil and Gas
Business, provided in all instances that such Liens are limited to the assets
that are the subject of the relevant agreement and (v) Liens on pipelines or
pipeline facilities that arise by operation of law.
"Oil and Gas Purchase and Sale Contract" means, with respect to any Person,
any oil and gas agreements, and other agreements or arrangements, or any
combination thereof, designed to provide protection against oil and gas price
fluctuations.
"Permitted Business Investments" means Investments and expenditures made in
the ordinary course of, and of a nature customary for companies actively engaged
in, the Oil and Gas Business (including, without limitation, (i) ownership
interests in oil and gas properties and (ii) Investments and expenditures in the
form of or pursuant to operating agreements, processing agreements, farm-in
agreements, farm-out agreements, development agreements, area of mutual interest
agreements, unitization agreements, pooling arrangements, joint bidding
agreements, service contracts, partnership agreements (whether general or
limited), capital stock in corporations and subscription agreements, in, to or
with third parties (including Unrestricted Subsidiaries), pursuant to which the
Company or a Restricted Subsidiary actively engages in the Oil and Gas Business
through agreements, transactions, interests or arrangements which permit it to
share risks or costs, comply with regulatory requirements regarding local
ownership or satisfy other objectives customarily achieved through the conduct
of Oil and Gas Business jointly with third parties.
"Permitted Holders" means Itel Corporation, HC Associates, Minorco and
Minorco (U.S.A.) Inc.
"Permitted Investment" means any and all of the following: (a) Permitted
Short-Term Investments; (b) Investments in property, plant, equipment and other
assets used in the ordinary course of the Oil and Gas Business and Permitted
Business Investments; (c) Investments in a Restricted Subsidiary or in any other
Person as a result of which such other Person becomes a Restricted Subsidiary in
compliance with the "Restricted and Unrestricted Subsidiaries" covenant; (d)
negotiable instruments held for collection; outstanding travel, moving and other
like advances to officers, employees and consultants; lease, utility and other
similar deposits; or stock, obligations or securities received in settlement of
debts owing to the Company or any of its Restricted Subsidiaries as a result of
foreclosure, perfection or enforcement of any Lien or Indebtedness, in each of
the foregoing cases in the ordinary course of business of the Company or such
Restricted Subsidiary; (e) other advances and loans to officers and employees of
the Company or any Subsidiary, provided such loans and advances do not exceed $2
million at any one time outstanding;
63
<PAGE> 66
(f) Investments in the form of securities received from Asset Sales, provided,
that such Asset Sales are made in compliance with the "Limitation on Sales of
Asset" covenant; (g) payment of scheduled dividends on the 7% Preferred Stock
and the DECS in accordance with their terms (including scheduled payments, if
any, made in arrears) on the date of the Indenture; (h) Investments pursuant to
any agreement or obligation of the Company or any of its Restricted Subsidiaries
as in effect on the date of the Indenture (other than Investments described in
clauses (a) through (g) above) and (i) other Investments with an aggregate Fair
Market Value at any time not in excess of $5 million.
"Permitted Short-Term Investments" means any of the following: (i)
Investments in U.S. Government Obligations maturing within 180 days of the date
of acquisition thereof, (ii) Investments in time deposit accounts, certificates
of deposit and money market deposits maturing within 180 days of the date of
acquisition thereof issued by a bank or trust company which is organized under
the laws of the United States of America, any State thereof or any foreign
country recognized by the United States of America having capital, surplus and
undivided profits aggregating in excess of $500 million (or the Dollar
Equivalent thereof) and whose long-term Indebtedness is rated "A" or higher
according to Moody's (or such equivalent rating by at least one "nationally
recognized statistical rating organization" (as defined in Rule 436 under the
Securities Act)), (iii) repurchase and reverse repurchase obligations with a
term of not more than seven days for underlying securities of the types
described in clause (i) entered into with a bank meeting the qualification
described in clause (ii), (iv) Investments in commercial paper, maturing not
more than 180 days after the date of acquisition, issued by a corporation (other
than an Affiliate of the Company) organized and in existence under the laws of
the United States of America or any foreign country recognized by the United
States of America with a rating at the time as of which any Investment therein
is made of "P-1" (or higher) according to Moody's or "A-1" (or higher) according
to S&P and (v) pooled investments and Investments in mutual funds all the assets
of which consist of the Investments and other obligations of the types described
in clauses (i) through (iv) hereof.
"Person" means any individual, corporation, partnership, joint venture,
trust, unincorporated organization or government or any agency or political
subdivision thereof.
"Preferred Stock" of any Person means Capital Stock of such Person of any
class or classes (however designated) that ranks prior, as to the payment of
dividends and/or as to the distribution of assets upon any voluntary or
involuntary liquidation, dissolution or winding up of such Person, to shares of
Capital Stock of any other class of such Person; provided, however, that
"Preferred Stock" shall not include Redeemable Stock.
"Production Payments" means, collectively, Dollar-Denominated Production
Payments and Volumetric Production Payments.
"Property" means, with respect to any Person, any interest of such Person
in any kind of property or asset, whether real, personal or mixed, or tangible
or intangible, including, without limitation, Capital Stock in any other Person
(but excluding Capital Stock or other securities issued by such Person).
"Rating Agency" means S&P and Moody's or, if S&P or Moody's shall have
ceased to be a "nationally recognized statistical rating organization" (as
defined in Rule 436 under the Securities Act) or shall have ceased to make
publicly available a rating on any outstanding securities of any company engaged
primarily in the Oil and Gas Business, such other organization or organizations,
as the case may be, then making publicly available a rating on the Debentures as
is (or are) selected by the Company.
"Rating Date" means the date which is 90 days prior to the occurrence of a
Change of Control.
"Rating Decline" means the occurrence on any date within the 90-day period
following the occurrence of a Change of Control (which period shall be extended
so long as prior to the end of such 90-day period and continuing thereafter the
rating of the Debentures is under publicly announced consideration for possible
downgrade by either Rating Agency) of: (i) the rating of the Debentures by each
Rating Agency within such period shall be at least two Gradations below the
rating of the Debentures by such Rating Agency on the Rating Date or (ii) either
Rating Agency shall withdraw its rating of the Debentures. A Gradation shall
include changes within rating categories (e.g., with respect
64
<PAGE> 67
to S&P, a decline in a rating from BB+ to BB, or from BB- to B+, will constitute
a decrease of one Gradation).
"Redeemable Stock" of any Person means any equity security of such Person
that by its terms (or by the terms of any security into which it is convertible
or for which it is exchangeable), or otherwise (including on the happening of an
event), is or could be required to be redeemed for cash or other Property or is
redeemable for cash or other Property at the option of the holder thereof, in
whole or in part, on or prior to the Stated Maturity of the Debentures; or by
its terms is or could be exchangeable for Indebtedness at any time, in whole or
in part, on or prior to the Stated Maturity of the Debentures; provided,
however, that Redeemable Stock shall not include any security by virtue of the
fact that it may be exchanged or converted at the option of the holder or of the
Company for Capital Stock of the Company having no preference as to dividends or
liquidation over any other Capital Stock of the Company and provided, further,
that Redeemable Stock shall not include the 7% Preferred Stock or the DECS.
"Representative" means the trustee, agent or other representative expressly
authorized to act in such capacity, if any, for an issue of Senior Indebtedness.
"Restricted Subsidiary" means as of the date of determination any
Subsidiary of the Company all of the outstanding Capital Stock and outstanding
Voting Redeemable Stock of which is held directly or indirectly by the Company
and other Restricted Subsidiaries.
"Sale and Leaseback Transaction" means, with respect to any Person, any
direct or indirect arrangement (excluding, however, any such arrangement between
such Person and a Restricted Subsidiary of such Person or between one or more
Restricted Subsidiaries of such Person) pursuant to which Property is sold or
transferred by such Person or a Restricted Subsidiary of such Person and is
thereafter leased back from the purchaser or transferee thereof by such Person
or one of its Restricted Subsidiaries.
"S&P" means Standard & Poor's Corporation and its successors.
"Senior Indebtedness" means (i) all obligations of the Company consisting
of the principal of and premium, if any, and accrued and unpaid interest due in
respect of (A) Indebtedness of the Company for borrowed money and (B)
Indebtedness evidenced by notes, debentures, bonds or other similar instruments
permitted under the Indenture for the payment of which the Company is
responsible or liable; (ii) all Capital Lease Obligations of the Company; (iii)
all obligations of the Company (A) for the reimbursement of any obligor on any
letter of credit, bankers' acceptance or similar credit transaction or (B) under
Hedging Agreements; and (iv) all obligations of other persons of the type
referred to in clauses (i), (ii) and (iii) for the payment of which the Company
is responsible or liable as Guarantor; provided that Senior Indebtedness does
not include any obligations in respect of (i) Indebtedness of the Company that
is by its terms subordinate or pari passu in right of payment to the Debentures;
(ii) any Indebtedness Incurred or outstanding in violation of the provisions of
the Indenture; (iii) accounts payable or any other obligations of the Company to
trade creditors created, Incurred or assumed by the Company in the ordinary
course of business in connection with the obtaining of materials or services;
(iv) any liability for Federal, state, local or other taxes owed or owing by the
Company; or (v) any obligation of the Company to any Affiliate of the Company
other than an obligation or obligations constituting Permitted Business
Investments.
"7% Preferred Stock" means the Company's Convertible Preferred Stock,
Series 7%.
"Subsidiary" of a Person means another Person a majority of whose Voting
Stock is at the time, directly or indirectly, owned or controlled by (i) the
first Person, (ii) the first Person and one or more of its Subsidiaries or (iii)
one or more of the first Person's Subsidiaries.
"Unrestricted Subsidiary" means (i) each Subsidiary of the Company that the
Company has designated pursuant to the covenant described under "Certain
Covenants--Restricted and Unrestricted Subsidiaries" as an Unrestricted
Subsidiary and (ii) any Subsidiary of an Unrestricted Subsidiary.
65
<PAGE> 68
"U.S. Government Obligations" means direct obligations (or certificates
representing an ownership interest in such obligations) of the United States of
America (including any agency or instrumentality thereof) for the payment of
which the full faith and credit of the United States of America is pledged and
which are not callable or redeemable at the issuer's option.
"Volumetric Production Payments" mean volumetric production payment
obligations that are or, upon the occurrence of a contingent event, would be
recorded as liabilities in accordance with GAAP. Such obligations will be deemed
to constitute Indebtedness for borrowed money for purposes of the Indenture.
"Voting Redeemable Stock" of any Person means Redeemable Stock of such
Person which ordinarily has voting power for the election of directors (or
persons performing similar functions) of such Person whether at all times or
only so long as no senior class of securities has such voting power by reason of
any contingency.
"Voting Stock" of any Person means Capital Stock or Voting Redeemable Stock
of such Person which ordinarily has voting power for the election of directors
(or persons performing similar functions) of such Person whether at all times or
only so long as no senior class of securities has such voting power by reason of
any contingency.
DEFEASANCE
The Indenture provides that the Company, at its option, (a) will be
Discharged from any and all obligations in respect of the Debentures (except in
each case for certain obligations to register the transfer or exchange of
Debentures, replace stolen, lost or mutilated Debentures, maintain paying
agencies and hold moneys for payment in trust) on the 123rd day after
satisfaction of the conditions therein specified, including those set forth
below, or (b) will not thereafter be subject to certain provisions of the
Indenture (including the Events of Default described below other than defaults
on payments due on the Debentures), in each case if the Company irrevocably
deposits or causes to be deposited with the Trustee, in trust, money or U.S.
Government Obligations which through the payment of interest thereon and
principal thereof in accordance with their terms will provide money in an amount
sufficient to pay all the principal of, premium, if any, and interest on, the
Debentures not later than one day before the Stated Maturity or the applicable
redemption date, as the case may be, of such principal of, premium, if any, and
interest to the payment date. To exercise any such option, there shall not exist
any Default or Event of Default which shall have occurred and be continuing, and
the Company shall deliver to the Trustee an Opinion of Counsel to the effect
that, among other things, (1) the deposit and related defeasance would not cause
the Holders of the Debentures to recognize income, gain or loss for Federal
income tax purposes and, in the case of a Discharge pursuant to clause (a),
accompanied by a ruling to such effect received from or published by the United
States Internal Revenue Service, (2) the resulting trust will not be an
"Investment Company" within the meaning of the Investment Company Act of 1940 or
such trust is qualified thereunder or exempt from regulation thereunder, and (3)
if the Debentures are then listed on any national securities exchange, the
Debentures would not be delisted as a result of the exercise of such option.
(Sections 8.01 and 8.02)
EVENTS OF DEFAULT AND NOTICE
The following are summaries of Events of Default under the Indenture: (a)
failure to pay any interest on the Debentures when due, continued for 30 days;
(b) failure to pay principal of (or premium, if any, on) the Debentures when
due; (c) failure to perform any other covenant of the Company in the Indenture,
continued for 60 days after written notice as provided in the Indenture; (d) a
default under any Indebtedness for borrowed money by the Company or any
Restricted Subsidiary which results in acceleration of the maturity of such
indebtedness of the Company, or failure to pay any such Indebtedness at
maturity, in an amount greater than $25 million if such Indebtedness is not
discharged or such acceleration is not rescinded or annulled within 10 days
after written notice as provided in the Indenture; (e) one or more final
judgments or orders by a court of competent jurisdiction are entered
66
<PAGE> 69
against the Company or any Restricted Subsidiary in an uninsured or effectively
unindemnified aggregate amount in excess of $25 million and such judgments or
orders are not discharged, waived, stayed or satisfied for a period of 60
consecutive days; and (f) certain events of bankruptcy, insolvency or
reorganization. (Section 6.01)
The Indenture provides that if an Event of Default (other than an Event of
Default described in clause (f) above) with respect to the Debentures shall
occur and be continuing, either the Trustee or the Holders of at least 25% in
aggregate principal amount of the Outstanding Debentures by notice as provided
in the Indenture may declare the principal amount of the Debentures to be due
and payable on the fifth day after written notice of such declaration has been
delivered to the Representative for each issue of Designated Senior
Indebtedness. If an Event of Default described in clause (f) above with respect
to the Debentures shall occur, the principal amount of all the Debentures will
automatically, and without any action by the Trustee or any Holder, become
immediately due and payable. After any such acceleration, but before a judgment
or decree based on acceleration, the Holders of a majority in aggregate
principal amount of the Outstanding Debentures may, under certain circumstances,
rescind and annul such acceleration if all Events of Default, other than the non
payment of accelerated principal (or other specified amount), have been cured or
waived as provided in the Indenture. (Section 6.02)
Subject to the provisions of the Indenture relating to the duties of the
Trustee, in case an Event of Default shall occur and be continuing, the Trustee
will be under no obligation to exercise any of its rights or powers under the
Indenture at the request or direction of any of the Holders, unless such Holders
shall have offered to the Trustee reasonable indemnity. Subject to such
provisions for the indemnification of the Trustee, the Holders of a majority in
aggregate principal amount of the Outstanding Debentures will have the right to
direct the time, method and place of conducting any proceeding for any remedy
available to the Trustee or exercising any trust or power conferred on the
Trustee with respect to the Debentures. (Section 6.05)
No Holder of Debentures will have any right to institute any proceeding
with respect to the Indenture, or for the appointment of a receiver or a
trustee, or for any other remedy thereunder, unless (i) such Holder has
previously given to the Trustee written notice of a continuing Event of Default
with respect to the Debentures, (ii) the Holders of at least 25% in aggregate
principal amount of the Outstanding Debentures have made written request, and
such Holder or Holders have offered reasonable indemnity, to the Trustee to
institute such proceeding as trustee and (iii) the Trustee has failed to
institute such proceeding, and has not received from the Holders of a majority
in aggregate principal amount of the Outstanding Debentures a direction
inconsistent with such request, within 60 days after such notice, request and
offer. (Section 6.06) However, such limitations do not apply to a suit
instituted by a Holder of Debentures for the enforcement of payment of the
principal of or any premium or interest on such Debentures on or after the
applicable due date specified in the Debentures. (Section 6.07)
The Indenture includes a covenant that the Company will file annually with
the Trustee a certificate stating whether or not any Default exists. (Section
4.09)
MODIFICATION OF THE INDENTURE; WAIVER
The Indenture contains provisions permitting the Company and the Trustee,
with the written consent of the Holders of not less than a majority in aggregate
principal amount of the Outstanding Debentures, to execute supplemental
indentures adding any provisions to or changing or eliminating any of the
provisions of the Indenture or modifying the rights of the Holders of the
Debentures, except that no such supplemental indenture may, without the consent
of all the Holders of Debentures, among other things, (a) reduce the principal
amount of the Debentures; (b) reduce the rate of or change the time for payment
of interest on any Debentures; (c) change the currency in which any amount due
in respect of the Debentures is payable; (d) reduce the principal of or any
premium on or change the Stated Maturity of any Debentures or alter the
redemption or repurchase provisions with respect thereto; (e) reduce the
relative ranking of any Debentures; or (f) release any security that may have
been granted in respect of the Debentures. (Section 9.01)
67
<PAGE> 70
The Holders of a majority in principal amount of the Outstanding Debentures
may waive compliance by the Company with certain restrictive provisions of the
Indenture. (Section 9.02) The Holders of a majority in principal amount of the
Outstanding Debentures may waive any past default under the Indenture, except a
default in the payment of principal, premium or interest and certain covenants
and provisions of the Indenture which cannot be amended without the consent of
the Holder of all Outstanding Debentures. (Section 6.04)
NOTICES
Notices to Holders of Debentures will be given by mail to the addresses of
such Holders as they appear in the Security Register. (Section 11.01)
GOVERNING LAW
The Indenture and the Debentures are governed by and construed in
accordance with the internal laws of the State of New York without reference to
principles of conflicts of law. (Section 11.08)
THE TRUSTEE
The First National Bank of Boston is the Trustee under the Indenture. The
Trustee may perform certain services for and transact other business with the
Company and its subsidiaries from time to time in the ordinary course of
business.
UNDERWRITING
The Underwriters named below have severally agreed, subject to the terms
and conditions of the Underwriting Agreement with the Company, to purchase from
the Company the aggregate principal amount of Debentures set forth opposite
their respective names. The Underwriters are committed to purchase all of the
Debentures if any are purchased.
<TABLE>
<CAPTION>
PRINCIPAL
UNDERWRITERS AMOUNT
------------ -------------
<S> <C>
Salomon Brothers Inc................................ $
Dillon, Read & Co. Inc..............................
Lazard Freres & Co..................................
Chemical Securities Inc.............................
-------------
Total............................................. $ 100,000,000
-------------
-------------
</TABLE>
The Underwriters have advised the Company that they propose initially to
offer the Debentures to the public at the public offering price set forth on the
cover page of this Prospectus and to certain dealers at such price less a
concession not in excess of % of the principal amount of the Debentures. The
Underwriters may allow, and such dealers may reallow, a discount not in excess
of % of the principal amount of the Debentures on sales to certain other
dealers. After the initial public offering, the public offering price,
concession and discount may be changed.
The Company has agreed not to offer, sell, contract to sell or otherwise
dispose of any debt securities of the Company in an offering to the public (or
in a private offering where holders of the debt securities are granted rights to
have such debt securities registered under the Securities Act or to exchange
such debt securities for other debt securities that are so registered) for a
period of 120 days from the date of this Prospectus without the prior consent of
Salomon Brothers Inc, such consent not to be unreasonably withheld.
Chemical Securities Inc. is an affiliate of Texas Commerce Bank N.A. which
is an agent bank and a lender to the Company under the Bank Facility. Texas
Commerce Bank N.A. will receive its proportionate
68
<PAGE> 71
share of the repayment by the Company of borrowings outstanding under the Bank
Facility from the proceeds of the offering of the Debentures. In addition, Texas
Commerce Bank N.A., or its affiliates, participates on a regular basis in
various general financing and banking transactions for the Company. Mr. Marc J.
Shapiro, who is the Chairman and Chief Executive Officer of Texas Commerce Bank
N.A., is a director of the Company.
From time to time an affiliate of Salomon Brothers Inc conducts business
with the Company on customary terms and in the ordinary course of business.
The Company has agreed to indemnify the Underwriters against certain civil
liabilities, including certain liabilities under the Securities Act.
VALIDITY OF THE DEBENTURES
The validity of the Debentures will be passed upon for the Company by
Andrews & Kurth L.L.P., Houston, Texas, and for the Underwriters by Cravath,
Swaine & Moore, New York, New York.
EXPERTS
The financial statements as of December 31, 1993 and 1992 and for each of
the three years in the period ended December 31, 1993 included in this
Prospectus have been so included in reliance on the report of Price Waterhouse,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
Certain information appearing in this Prospectus regarding the estimated
quantities of reserves of the oil and natural gas properties owned by the
Company, the future net revenues from such reserves and the present value
thereof is based on estimates of such reserves and present values prepared by
Ryder Scott Company, independent petroleum engineers.
69
<PAGE> 72
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Audited Financial Statements
Report of Independent Accountants............................................ F-2
Consolidated Statement of Operations for the years ended December 31, 1993,
1992 and 1991.............................................................. F-3
Consolidated Balance Sheet -- December 31, 1993 and 1992..................... F-4
Consolidated Statement of Cash Flows for the years ended December 31, 1993,
1992 and 1991.............................................................. F-5
Consolidated Statement of Shareholders' Equity for the years ended December
31, 1993, 1992 and 1991.................................................... F-6
Notes to Consolidated Financial Statements................................... F-7
Unaudited Financial Information
Supplemental Information to the Consolidated Financial Statements............ F-26
</TABLE>
F-1
<PAGE> 73
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Santa Fe Energy Resources, Inc.
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of cash flows, and of shareholders'
equity present fairly, in all material respects, the financial position of Santa
Fe Energy Resources, Inc. and its subsidiaries at December 31, 1993 and 1992,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE
Houston, Texas
February 18, 1994
F-2
<PAGE> 74
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(IN MILLIONS OF DOLLARS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Revenues
Crude oil and liquids......................................................... $ 307.3 $ 333.6 $ 320.3
Natural gas................................................................... 107.8 74.8 47.9
Natural gas systems........................................................... 8.2 7.3 --
Crude oil marketing and trading............................................... 9.9 5.9 7.2
Other......................................................................... 3.7 5.9 4.4
--------- --------- ---------
436.9 427.5 379.8
--------- --------- ---------
Costs and Expenses
Production and operating...................................................... 163.8 153.4 134.6
Oil and gas systems and pipelines............................................. 4.2 3.2 --
Exploration, including dry hole costs......................................... 31.0 25.5 18.7
Depletion, depreciation and amortization...................................... 152.7 146.3 106.6
Impairment of oil and gas properties.......................................... 99.3 -- --
General and administrative.................................................... 32.3 30.9 27.8
Taxes (other than income)..................................................... 27.3 24.3 27.2
Restructuring charges......................................................... 38.6 -- --
Loss (gain) on disposition of oil and gas properties.......................... 0.7 (13.6) 0.5
--------- --------- ---------
549.9 370.0 315.4
--------- --------- ---------
Income (Loss) from Operations..................................................... (113.0) 57.5 64.4
Interest income............................................................... 9.1 2.3 2.3
Interest expense.............................................................. (45.8) (55.6) (47.3)
Interest capitalized.......................................................... 4.3 4.9 7.7
Other income (expense)........................................................ (4.8) (10.0) 5.6
--------- --------- ---------
Income (Loss) Before Income Taxes................................................. (150.2) (0.9) 32.7
Income taxes.................................................................. 73.1 (0.5) (14.2)
--------- --------- ---------
Net Income (Loss)................................................................. (77.1) (1.4) 18.5
Preferred dividend requirement.................................................... (7.0) (4.3) --
--------- --------- ---------
Earnings (Loss) Attributable to Common Shares..................................... $ (84.1) $ (5.7) $ 18.5
========= ========= =========
Earnings (Loss) Attributable to Common Shares Per Share........................... $ (0.94) $ (0.07) $ 0.29
========= ========= =========
Weighted Average Number of Shares Outstanding (in millions)....................... 89.7 79.0 63.8
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 75
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(IN MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1993 1992
----------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents......................................................... $ 4.8 $ 83.8
Accounts receivable............................................................... 87.4 90.0
Income tax refund receivable...................................................... -- 16.2
Inventories....................................................................... 8.7 4.8
Assets held for sale.............................................................. 59.5 --
Other current assets.............................................................. 12.2 10.6
------------ ------------
172.6 205.4
------------ ------------
Investment in Hadson Corporation...................................................... 56.2 --
------------ ------------
Properties and Equipment, at cost
Oil and gas (on the basis of successful efforts accounting)....................... 2,064.3 2,330.9
Other............................................................................. 27.3 26.8
------------ ------------
2,091.6 2,357.7
Accumulated depletion, depreciation, amortization and impairment.................. (1,258.9) (1,255.9)
------------ ------------
832.7 1,101.8
------------ ------------
Other Assets
Receivable under gas balancing arrangements....................................... 3.9 7.7
Other............................................................................. 11.5 22.3
------------ ------------
15.4 30.0
------------ ------------
$ 1,076.9 $ 1,337.2
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable.................................................................. $ 93.5 $ 90.9
Interest payable.................................................................. 10.2 11.0
Current portion of long-term debt................................................. 44.3 53.4
Other current liabilities......................................................... 18.1 17.1
------------ ------------
166.1 172.4
------------ ------------
Long-Term Debt........................................................................ 405.4 492.8
------------ ------------
Deferred Revenues..................................................................... 8.6 13.0
------------ ------------
Other Long-Term Obligations........................................................... 48.8 43.4
------------ ------------
Deferred Income Taxes................................................................. 44.4 119.0
------------ ------------
Commitments and Contingencies (Note 12)............................................... -- --
------------ ------------
Convertible Preferred Stock, $0.01 par value, 5.0 million shares authorized, issued
and outstanding..................................................................... 80.0 80.0
------------ ------------
Shareholders' Equity
Preferred stock, $0.01 par value, 45.0 million shares authorized, none issued..... -- --
Common stock, $0.01 par value, 200.0 million shares authorized.................... 0.9 0.9
Paid-in capital................................................................... 496.9 494.3
Unamortized restricted stock awards............................................... (0.1) (0.4)
Accumulated deficit............................................................... (173.8) (78.0)
Foreign currency translation adjustment........................................... (0.3) (0.2)
------------ ------------
323.6 416.6
------------ ------------
$ 1,076.9 $ 1,337.2
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 76
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
---------- ---------- ----------
<S> <C> <C> <C>
Operating Activities:
Net income (loss)......................................................... $ (77.1) $ (1.4) $ 18.5
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depletion, depreciation and amortization.............................. 152.7 146.3 106.6
Impairment of oil and gas properties.................................. 99.3 -- --
Restructuring charges................................................. 27.8 -- --
Deferred income taxes................................................. (71.9) (6.3) 1.5
Net loss (gain) on disposition of properties.......................... 0.7 (13.6) (5.5)
Exploratory dry hole costs............................................ 8.9 4.7 3.8
Expenses related to acquisition of Adobe Resources Corporation........ -- 10.9 --
Other................................................................. 4.2 2.0 0.3
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable............................ 12.4 (8.3) 23.6
Decrease (increase) in inventories.................................... (3.8) 0.3 5.6
Increase (decrease) in accounts payable............................... (2.6) 5.9 (24.9)
Increase (decrease) in interest payable............................... (0.8) 0.4 0.2
Decrease in income taxes payable...................................... (0.6) (0.4) (3.6)
Net change in other assets and liabilities............................ 11.0 1.0 2.3
---------- ---------- ----------
Net Cash Provided by Operating Activities..................................... 160.2 141.5 128.4
---------- ---------- ----------
Investing Activities:
Capital expenditures, including exploratory dry hole costs................ (127.0) (76.8) (108.1)
Acquisitions of producing properties, net of related debt................. (4.4) (14.2) (28.5)
Acquisition of Adobe Resources Corporation................................ -- (11.9) --
Acquisition of Santa Fe Energy Partners, L.P.............................. (28.3) -- --
Net proceeds from sales of properties..................................... 39.9 89.1 22.1
Increase in partnership interest due to reinvestment...................... (1.6) (2.1) (2.7)
---------- ---------- ----------
Net Cash Used in Investing Activities......................................... (121.4) (15.9) (117.2)
---------- ---------- ----------
Financing Activities:
Net change in short-term debt............................................. -- (4.6) (4.2)
Proceeds from long-term borrowings........................................ -- 5.0 --
Principal payments on long-term borrowings................................ (41.5) (55.5) (16.3)
Net change in revolving credit agreement.................................. (55.0) -- --
Cash dividends paid to others............................................. (21.3) (14.9) (10.2)
---------- ---------- ----------
Net Cash Used in Financing Activities......................................... (117.8) (70.0) (30.7)
---------- ---------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents.......................... (79.0) 55.6 (19.5)
Cash and Cash Equivalents at Beginning of Year................................ 83.8 28.2 47.7
---------- ---------- ----------
Cash and Cash Equivalents at End of Year...................................... $ 4.8 $ 83.8 $ 28.2
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 77
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(SHARES AND DOLLARS IN MILLIONS)
<TABLE>
<CAPTION>
FOREIGN
UNAMORTIZED CURRENCY
COMMON STOCK RESTRICTED TRANSLA- TOTAL
--------------- PAID-IN STOCK ACCUMULATED TION SHAREHOLDERS'
SHARES AMOUNT CAPITAL AWARDS DEFICIT ADJUSTMENT EQUITY
------ ------ ------- ------------ ----------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1990.................. 63.8 $0.6 $ 282.4 $ -- $ (67.2) $ -- $ 215.8
Net income.................................. -- -- -- -- 18.5 -- 18.5
Issuance of common stock.................... 0.3 -- 2.5 (1.4) -- -- 1.1
Dividends declared.......................... -- -- -- -- (10.3) -- (10.3)
---- ---- ------- ------- --------- ------ -------
Balance at December 31, 1991.................. 64.1 0.6 284.9 (1.4) (59.0) -- 225.1
Issuance of common stock
Acquisition of Adobe
Resources Corporation.................... 24.9 0.3 205.3 -- -- -- 205.6
Employee stock compensation and savings
plans.................................... 0.5 -- 4.1 (0.5) -- -- 3.6
Amortization of restricted stock awards..... -- -- -- 1.5 -- -- 1.5
Foreign currency translation adjustments.... -- -- -- -- -- (0.2) (0.2)
Net loss.................................... -- -- -- -- (1.4) -- (1.4)
Dividends declared.......................... -- -- -- -- (17.6) -- (17.6)
---- ---- ------- ------- --------- ------ -------
Balance at December 31, 1992.................. 89.5 0.9 494.3 (0.4) (78.0) (0.2) 416.6
Issuance of common stock
Employee stock compensation and savings
plans.................................... 0.3 -- 2.6 (0.1) -- -- 2.5
Amortization of restricted
stock awards............................... -- -- -- 0.4 -- -- 0.4
Pension liability adjustment................ -- -- -- -- (0.9) -- (0.9)
Foreign currency transaction adjustments.... -- -- -- -- -- (0.1) (0.1)
Net loss.................................... -- -- -- -- (77.1) -- (77.1)
Dividends declared.......................... -- -- -- -- (17.8) -- (17.8)
---- ---- ------- ------- --------- ------ -------
Balance December 31, 1993..................... 89.8 $0.9 $ 496.9 $ (0.1) $ (173.8) $ (0.3) $ 323.6
==== ==== ======= ======= ========= ====== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 78
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of Santa Fe Energy Resources, Inc.
("Santa Fe" or the "Company") and its subsidiaries include the accounts of all
wholly owned subsidiaries. The accounts of Santa Fe Energy Partners, L.P., (the
"Partnership") are included on a proportional basis until September 1993 when
Santa Fe purchased all the Partnership's outstanding Depositary Units and
undeposited LP Units other than those units held by Santa Fe and its affiliates.
On September 27, 1993 the Company exercised its right under the Agreement of
Limited Partnership to purchase all of the Partnership's outstanding Depositary
Units and undeposited LP Units, other than those units held by the Company and
its affiliates, at a redemption price of $4.9225 per unit. Consideration for the
5,749,500 outstanding units totalled $28.3 million. The acquisition of the units
has been accounted for as a purchase and the results of operations of the
Partnership attributable to the units acquired is included in the Company's
results of operations with effect from October 1, 1993. The purchase price has
been allocated primarily to oil and gas properties.
References herein to the "Company" or "Santa Fe" relate to Santa Fe Energy
Resources, Inc., individually or together with its consolidated subsidiaries;
references to the "Partnership" relate to Santa Fe Energy Partners, L.P.
All significant intercompany accounts and transactions have been eliminated.
Prior years' financial statements include certain reclassifications to conform
to current year's presentation.
Oil and Gas Operations
The Company follows the successful efforts method of accounting for its oil
and gas exploration and production activities. Costs (both tangible and
intangible) of productive wells and development dry holes, as well as the cost
of prospective acreage, are capitalized. The costs of drilling and equipping
exploratory wells which do not find proved reserves are expensed upon
determination that the well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs and delay rentals,
are charged to expense as incurred.
Depletion and depreciation of proved properties are computed on an
individual field basis using the unit-of-production method based upon proved oil
and gas reserves attributable to the field. Certain other oil and gas properties
are depreciated on a straight-line basis. Individual proved properties are
reviewed periodically to determine if the carrying value of the field exceeds
the estimated undiscounted future net revenues from proved oil and gas reserves
attributable to the field. Based on this review and the continuing evaluation of
development plans, economics and other factors, if appropriate, the Company
records impairments (additional depletion and depreciation) to the extent that
the carrying value exceeds the estimated undiscounted future net revenues. Such
impairments totaled $99.3 million in 1993 and there were none in 1992 and 1991.
The Company provides for future abandonment and site restoration costs with
respect to certain of its oil and gas properties. The Company estimates that
with respect to these properties such future costs total approximately $24.7
million and such amount is being accrued over the expected life of the
properties. At December 31, 1993 Accumulated Depletion, Depreciation,
Amortization and Impairment includes $14.6 million with respect to such costs.
The value of undeveloped acreage is aggregated and the portion of such costs
estimated to be nonproductive, based on historical experience, is amortized to
expense over the average holding period. Additional amortization may be
recognized based upon periodic assessment of prospect evaluation results. The
cost of properties determined to be productive is transferred to proved
F-7
<PAGE> 79
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
properties; the cost of properties determined to be nonproductive is charged to
accumulated amortization.
Maintenance and repairs are expensed as incurred; major renewals and
improvements are capitalized. Gains and losses arising from sales of properties
are included in income currently.
Revenue Recognition
Revenues from the sale of petroleum produced are generally recognized upon
the passage of title, net of royalties and net profits interests. Crude oil
revenues include the effect of hedging transactions; see Note 12 -- Commitments
and Contingencies -- Crude Oil Hedging Program. Crude oil revenues also include
the value of crude oil consumed in operations with an equal amount charged to
operating expenses. Such amounts totalled $15.4 million in 1991, $4.8 million in
1992 and $1.2 million in 1993.
Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests. Sales proceeds
in excess of the Company's entitlement are included in Deferred Revenues and the
Company's share of sales taken by others is included in Other Assets. At
December 31, 1993 the Company's deferred revenues for sales proceeds received in
excess of the Company's entitlement was $6.8 million with respect to 5.2 MMcf
and the asset related to the Company's share of sales taken by others was $3.9
million with respect to 2.7 MMcf. Natural gas revenues are net of the effect of
hedging transactions; see Note 12 -- Commitments and Contingencies -- Natural
Gas Hedging Program.
Revenues from crude oil marketing and trading represent the gross margin
resulting from such activities. Revenues from such activities are net of costs
of sales of $210.5 million in 1991, $247.3 million in 1992 and $225.9 million in
1993.
Revenues from natural gas systems are net of the cost of natural gas
purchased and resold. Such costs totalled $43.8 million in 1992 and $49.9
million in 1993.
Earnings Per Share
Earnings per share are based on the weighted average number of common shares
outstanding during the year.
Accounts Receivable
Accounts Receivable relates primarily to sales of oil and gas and amounts
due from joint interest partners for expenditures made by the Company on behalf
of such partners. The Company reviews the financial condition of potential
purchasers and partners prior to signing sales or joint interest agreements. At
December 31, 1993 and 1992 the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totaled $6.3 million and $5.0 million, respectively.
Accounts receivable totalling $0.2 million, $1.1 million and $0.1 million were
written off as uncollectible in 1991, 1992 and 1993, respectively.
Inventories
Inventories are valued at the lower of cost (average price or first.in,
first.out) or market. Crude oil inventories at December 31, 1993 and 1992 were
$1.1 million and $1.5 million, respectively, and materials and supplies
inventories at such dates were $7.6 million and $3.3 million, respectively.
Environmental Expenditures
Environmental expenditures relating to current operations are expensed or
capitalized, as appropriate, depending on whether such expenditures provide
future economic benefits. Liabilities
F-8
<PAGE> 80
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
are recognized when the expenditures are considered probable and can be
reasonably estimated. Measurement of liabilities is based on currently enacted
laws and regulations, existing technology and undiscounted site-specific costs.
Generally, such recognition coincides with the Company's commitment to a formal
plan of action.
Income Taxes
The Company follows the asset and liability approach to accounting for
income taxes. Deferred tax assets and liabilities are determined using the tax
rate for the period in which those amounts are expected to be received or paid,
based on a scheduling of temporary differences between the tax bases of assets
and liabilities and their reported amounts. Under this method of accounting for
income taxes, any future changes in income tax rates will affect deferred income
tax balances and financial results.
(2) CORPORATE RESTRUCTURING PROGRAM
In October 1993 the Company's Board of Directors endorsed a broad corporate
restructuring program that focuses on the disposition of non-core assets, the
concentration of capital spending in core areas, the refinancing of certain
long-term debt and the elimination of the payment of its $0.04 per share
quarterly dividend on common stock.
In implementing the restructuring program the Company recorded a
nonrecurring charge of $38.6 million in 1993 comprised of (1) losses on property
dispositions of $27.8 million: (2) long-term debt repayment penalties of $8.6
million; and (3) accruals for certain personnel benefits and related costs of
$2.2 million.
The Company's non-core asset disposition program includes the sale of its
natural gas gathering and processing assets to Hadson Corporation ("Hadson"),
the sale to Vintage Petroleum, Inc. of certain southern California and Gulf
Coast oil and gas producing properties and the sale to Bridge Oil (U.S.A.) Inc.
("Bridge") of certain Mid-Continent and Rocky Mountain oil and gas producing
properties and undeveloped acreage. The Company also plans to dispose of other
non-core oil and gas properties during 1994.
In 1994 the Company intends to refinance a portion of its existing
long-term debt and is currently evaluating a combination of debt and equity
financing arrangements with which to effect the refinancing.
Sale to Hadson. In December 1993 the Company completed a transaction with
Hadson under the terms of which the Company sold the common stock of Adobe Gas
Pipeline Company ("AGPC"), a wholly-owned subsidiary which held the Company's
natural gas gathering and processing assets, to Hadson in exchange for Hadson
11.25% preferred stock with a face value of $52.0 million and 40% of Hadson's
common stock. In addition, the Company signed a seven-year gas sales contract
under the terms of which Hadson will market substantially all of the Company's
domestic natural gas production at market prices as defined by published monthly
indices for relevant production locations.
The Company accounted for the sale as a non-monetary transaction and the
investment in Hadson has been valued at $56.2 million, the carrying value of the
Company's investment in AGPC. The Company's investment in Hadson is being
accounted for on the equity basis. At December 31, 1993 the Company's investment
in Hadson's common stock exceeded the net book value attributable to such common
shares by approximately $11.3 million. The Company's income from operations for
1993 includes $1.6 million attributable to the assets sold to Hadson.
Sale to Vintage. In November 1993 the Company completed the sale of certain
southern California and Gulf Coast producing properties for net proceeds
totalling $41.3 million in cash, $31.5
F-9
<PAGE> 81
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
million of which was collected in 1993. The Company's income from operations for
1993 includes $2.7 million attributable to the assets sold to Vintage.
Sale to Bridge. In December 1993 the Company signed a Purchase and Sales
Agreement with Bridge under the terms of which Bridge will purchase certain
Mid-Continent and Rocky Mountain producing and nonproducing oil and gas
properties. The sale price of $51.0 million, subject to certain adjustments,
will be received by the Company either in the form of cash plus 10% of the
outstanding shares of Bridge, following the contemplated public offering of that
stock in the first quarter of 1994, or entirely in cash. The transaction is
expected to close in the second quarter of 1994.
The net book value of these assets is included in Assets Held for Sale at
December 31, 1993. The Company's income from operations for 1993 includes $5.8
million attributable to the assets to be sold to Bridge.
Other Dispositions. The Company has identified certain other oil and gas
properties which it plans to dispose of in 1994. The estimated realizable value
of these properties, $1.0 million, is included in Assets Held for Sale at
December 31, 1993. In the first quarter of 1994 the Company sold its interest in
certain other oil and gas properties for $8.3 million.
(3) MERGER WITH ADOBE RESOURCES CORPORATION
On May 19, 1992 Adobe Resources Corporation ("Adobe"), an oil and gas
exploration and production company, was merged with and into Santa Fe (the
"Merger"). The acquisition has been accounted for as a purchase and the results
of operations of the properties acquired (the "Adobe Properties") are included
in Santa Fe's results of operations effective June 1, 1992.
To consummate the Merger, the Company issued 24.9 million shares of common
stock valued at $205.5 million, 5.0 million shares of convertible preferred
stock valued at $80.0 million, assumed long-term bank debt and other liabilities
of $140.0 million and $35.0 million, respectively, and incurred $13.8 million in
related costs. The Company also recorded a $19.7 million deferred tax liability
with respect to the difference between the book and tax basis in the assets
acquired. Certain merger.related costs incurred by Adobe and paid by Santa Fe
totaling $10.9 million were charged to income in the second quarter of 1992.
The Merger constituted a "change of control" as defined in certain of the
Company's employee benefit plans and employment agreements (see Notes 10 and
12).
In a separate transaction in January 1992, the Company purchased three
producing properties from Adobe for $14.2 million.
(4) SANTA FE ENERGY TRUST
In November 1992 5,725,000 Depository Units ("Trust Units"), each consisting
of beneficial ownership of one unit of undivided beneficial interest in the
Santa Fe Energy Trust (the "Trust") 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. The
Trust consists of certain oil and gas properties conveyed by Santa Fe. 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 Trust Units. A portion of the proceeds received by the
Company was used to retire $30.0 million of the debt incurred in connection with
the Merger and the remainder will be used for general corporate purposes
including possible acquisitions.
F-10
<PAGE> 82
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
For any calendar quarter ending on or prior to December 31, 2002, the
Trust will receive additional royalty payments to the extent that it needs such
payments to distribute $0.40 per Depository Unit per quarter. The source of such
additional royalty payments, if needed, will be limited to the Company's
remaining royalty interest in certain of the properties conveyed to the Trust.
If such additional payments are made, certain proceeds otherwise payable to the
Trust in subsequent quarters may be reduced to recoup the amount of such
additional payments. The aggregate amount of the additional royalty payments
(net of any amounts recouped) will be limited to $20.0 million on a revolving
basis.
At December 31, 1993 the Company held 575,000 Trust Units. At December 31,
1993 Accounts Receivable includes $0.2 million due from the Trust and Accounts
Payable includes $1.9 million due to the Trust. In the first quarter of 1994 the
Company sold the Trust Units for $11.3 million, the Company's investment in the
Trust Units, $10.4 million, is included in Assets Held for Sale at December 31,
1993.
(5) ACQUISITIONS OF OIL AND GAS PROPERTIES
In January 1991 the Company completed the purchase of Mission Operating
Partnership, L.P.'s ("Mission") interest in certain oil and gas properties,
effective from November 1, 1990, for approximately $55.0 million. The Company
formed a partnership, with an institutional investor as a limited partner, to
acquire and operate the properties. The investor contributed $27.5 million for a
50% interest in the partnership, which will be reduced to 15% upon the occurence
of payout. Payout will occur when the investor has received distributions from
the partnership totalling an amount equal to its original contribution plus a
12% rate of return on such contribution. Prior to payout, the Company will bear
100% of the capital expenditures of the partnership. Under the terms of the
partnership agreement a total of $36.8 million must be expended on development
of the property by the year 2000, $12.4 million of which had been expended
through the end of 1993.
The Company funded $16.8 million of its share of the purchase of the
properties with the assumption of a term loan and paid the remainder from
working capital. The Company has given the lender the equivalent of an
overriding royalty interest in certain production from the properties. The
royalty is payable only if such production occurs and is limited to a maximum of
$3.0 million.
In June 1991 the Company acquired a 10% interest in a producing field in
Argentina for approximately $18.3 million and in October 1991 purchased an
additional 8% interest in the field for approximately $15.7 million. The Company
financed $17.8 million of the total purchase price with loans from an Argentine
bank. The Company has agreed to spend approximately $16.7 million over a
five-year period on development and maintenance of the field.
(6) CASH FLOWS
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.
The Merger included certain non-cash investing and financing activities not
reflected in the Statement of Cash Flows as follows (in millions of dollars):
<TABLE>
<S> <C>
Common stock issued............................................. 205.5
Convertible preferred stock issued.............................. 80.0
Deferred tax liability.......................................... 19.7
Long-term debt.................................................. 140.0
Assets acquired, other than cash, net of liabilities assumed.... (457.1)
------
Cash paid....................................................... (11.9)
======
</TABLE>
F-11
<PAGE> 83
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1991, the Company sold a producing property for $0.9 million in cash
and a note receivable for $1.2 million. In 1991, the Partnership purchased
certain surface properties for $6.2 million, $5.5 million of which was funded
by the issuance of promissory notes and the Company also purchased producing
properties for $63.1 million, $34.6 million of which was funded with debt (see
Notes 5 and 7).
The Company made interest payments of $45.5 million, $49.0 million and $48.0
million in 1991, 1992 and 1993, respectively. In 1991, 1992 and 1993, the
Company made tax payments of $18.4 million, $4.4 million and $5.0 million,
respectively, and in 1993 received refunds of $4.1 million, primarily related to
the audit of prior years' returns.
(7) FINANCING AND DEBT
Long-term debt at December 31, 1993 and 1992 consisted of (in millions of
dollars):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------
1993 1992
-------------------- --------------------
CURRENT LONG-TERM CURRENT LONG-TERM
------- --------- ------- ----------
<S> <C> <C> <C> <C>
SFER
Senior Notes................................................... 30.0 310.0 25.0 340.0
Revolving and Term Credit Agreement............................ 1.3 48.7 12.8 92.2
Notes Payable to Bank.......................................... 3.8 11.3 2.5 15.1
Term.Loan...................................................... 1.2 11.4 1.2 12.6
Partnership
Credit Agreement............................................... 8.0 24.0 11.1 29.5
Promissory Notes............................................... -- -- 0.8 3.4
---- ----- ---- -----
44.3 405.4 53.4 492.8
==== ===== ==== =====
</TABLE>
Aggregate total maturities of long-term debt during the next five years are
as follows: 1994 -- $44.3 million; 1995 -- $78.9 million; 1996 -- $73.5 million;
1997 -- $43.0 million; and 1998 -- $35.0 million. These maturities will be
affected by the refinancing discussed in Note 2 -- Corporate Restructuring
Program.
On April 11, 1990 SFER issued $365.0 million of serial unsecured Senior
Notes with interest rates averaging 10.35%. The Note Agreement pursuant to which
the Senior Notes were issued includes certain covenants which, among other
things, restrict the Company's ability to incur additional indebtedness and to
pay dividends. Under the terms of the Note Agreement, at December 31, 1993 the
Company had the ability to incur at least $64.0 million in additional long-term
debt and pay $26.0 million in dividends and other restricted payments. At
December 31, 1993 $340.0 million in Senior Notes were outstanding and are to be
repaid, $30.0 million in 1994 and 1995, $35.0 million in 1996 through 1998 and
$25.0 million per year in 1999 through 2005.
In January 1991 the Company executed a $16.8 million term.loan agreement,
with interest at 9.0%, in connection with the purchase of certain producing
properties from Mission. At December 31, 1993 $12.6 million was outstanding
under the terms of the agreement and is to be repaid $1.2 million in 1994 and
$11.4 million in 1995. The Company made principal payments on the loan totalling
$1.8 million in 1991, $1.2 million in 1992 and $1.2 million in 1993.
In June 1991 the Company borrowed $10.4 million from an Argentine bank in
connection with the purchase of an interest in a producing oil field in
Argentina. The loan bore interest at the higher of 12% or the interbank offering
rate plus 2%. In October 1991 the Company borrowed an additional $7.8 million in
connection with the purchase of an additional interest in the field. The second
loan bore interest at the higher of rates ranging from 13.4% to 14.0% or the
London Interbank Offering
F-12
<PAGE> 84
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Rate ("LIBOR") plus 2%. During 1993 the two loans were combined in a new loan
which bears interest at the higher of 13.06% or LIBOR plus 2%.
In connection with the Merger the Company entered into a $195.0 million
Revolving and Term Credit Agreement (the "Credit Agreement") with a group of
banks. Upon consummation of the Merger the Company drew down the $145.0 million
available under the term loan feature of the Credit Agreement and repaid the
$140.0 million of long-term debt assumed in the Merger. The borrowings under the
term loan feature of the Credit Agreement are secured by properties acquired in
the Merger. Interest rates on borrowings are determined from time to time and at
December 31, 1993 amounts outstanding under the term loan feature bore interest
at an average of 5.5% per annum.
In April 1993 the term loan feature was amended to allow the Company to make
voluntary prepayments and reborrowings. At December 31, 1993 the balance
outstanding under the term loan feature was $50.0 million and the total amount
available under the term loan feature, including amounts then outstanding, was
$87.7 million. The amount available will be reduced, in semi.annual increments,
to $48.6 million in December 31, 1994 and $24.3 million at December 31, 1995.
The Credit Agreement expires December 31, 1996. In certain circumstances,
primarily related to the sale of properties securing the loans, the amount
available may be reduced or the Company may be required to make mandatory
repayments. The Company is currently negotiating an amendment to the Credit
Agreement which would extend the maturities and under certain circumstances
increase the amount available for borrowings.
Under the revolving credit feature of the Credit Agreement the Company may
borrow and issue letters of credit totalling up to $50.0 million. Borrowings
under the revolving credit feature are unsecured but are subject to compliance
with covenants identical to existing covenants under the Company's other
long-term debt agreeements including covenants related to debt incurrence,
dividends and other restricted payments, investments and limitations on liens,
mergers and sales of assets. In addition, the Company must comply annually with
certain borrowing base coverage ratios relating to projected cash flows from oil
and gas revenues. The amount available under the revolving credit feature will
be reduced to $10.0 million on February 28, 1994 and this feature expires on
February 28, 1995. At December 31, 1993, the Company had $8.7 million in letters
of credit outstanding under the revolving credit feature of the Credit
Agreement.
The Company has two uncommitted lines of credit totalling $35.0 million
which is used to meet short-term cash needs. Interest rates on borrowings under
this line of credit is typically lower than rates paid under the Credit
Agreement. At December 31, 1993 no amounts were outstanding under these lines of
credit.
In December 1991 the Partnership issued two promissory notes for a total of
$5.5 million in connection with the purchase of certain surface lands. The
notes, which bore interest at 10.0%, were retired in 1993. The Company's
proportionate share of such debt at December 31, 1992 was $4.2 million.
At December 31, 1993 and 1992 the Partnership had $32.0 million and $44.0
million, respectively, outstanding under the terms of long-term credit agreement
which expires in 1997. The Company's proportionate share of such debt totaled
$40.6 million at December 31, 1992. Interest on 65% of principal amount
outstanding is fixed at 10.13% with interest on the remaining amount outstanding
at floating rates which averaged 4.3% in 1993 and 5.46% in 1992. The credit
agreement imposes certain restrictions on future indebtedness and the transfer
or sale of principal properties and requires the maintenance of certain
financial ratios to avoid collateralization or default.
F-13
<PAGE> 85
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(8) SEGMENT INFORMATION
The principal business of the Company is oil and gas, which consists of the
acquisition, exploration and development of oil and gas properties and the
production and sale of crude oil and liquids and natural gas. Pertinent
information with respect to the Company's oil and gas business is presented in
the following table (in millions of dollars):
<TABLE>
<CAPTION> OIL AND GAS
---------------------------------------------
OTHER GENERAL
U.S. ARGENTINA INDONESIA FOREIGN CORPORATE TOTAL
-------- --------- --------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1993
Revenues..................................... 401.2 12.5 23.2 -- -- 436.9
Income (Loss) from Operations................ (33.6) 3.0 (13.4) (18.4) (50.6) (113.0)
Depletion, Depreciation, Amortization and
Impairment................................. 218.8 3.6 21.2 6.7 1.7 252.0
Additions to Property and Equipment.......... 116.1 7.3 16.8 6.1 4.4 150.7
Identifiable Assets at December 31........... 862.0 48.2 65.3 2.8 98.6 1,076.9
1992
Revenues..................................... 400.0 13.9 13.6 -- -- 427.5
Income (Loss) from Operations................ 100.6 2.5 2.3 (10.7 ) (37.2) 57.5
Depletion, Depreciation and Amortization..... 136.7 3.7 2.7 1.6 1.6 146.3
Additions to Property and Equipment.......... 452.6 4.0 71.6 5.7 2.4 536.3
Identifiable Assets at December 31........... 1,076.5 39.2 73.9 5.8 141.8 1,337.2
1991
Revenues..................................... 376.1 3.7 -- -- -- 379.8
Income (Loss) from Operations................ 103.7 (2.2) .2 (2.5 ) (34.8) 64.4
Depletion, Depreciation and Amortization..... 101.3 1.8 -- .7 2.8 106.6
Additions to Property and Equipment.......... 125.8 35.4 -- 3.7 8.8 173.7
Identifiable Assets at December 31........... 816.5 37.5 .2 3.9 53.8 911.9
</TABLE>
Crude oil and liquids and natural gas accounted for more than 95% of
revenues in 1991, 1992 and 1993. The following table reflects sales revenues
from crude oil purchasers who accounted for more than 10% of the Company's crude
oil and liquids revenues (in millions of dollars):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Texaco Trading and Transportation, Inc................................... -- 46.8 55.9
Celeron Corporation...................................................... 56.8 56.3 45.6
Shell Oil Company........................................................ 86.3 -- --
</TABLE>
None of the Company's purchasers of natural gas accounted for more than 10%
of revenues in 1991, 1992 or 1993. The Company does not believe the loss of any
purchaser would have a material adverse effect on its financial position since
the Company believes alternative sales arrangements could be made on relatively
comparable terms.
F-14
<PAGE> 86
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(9) CONVERTIBLE PREFERRED STOCK
The convertible preferred stock issued in connection with the Merger is
non-voting and entitled to receive cumulative cash dividends at an annual rate
equivalent to $1.40 per share. The holders of the convertible preferred shares
may, at their option, convert any or all such shares into 1.3913 shares of the
Company's common stock. The Company may, at any time after the fifth anniversary
of the effective date of the Merger and upon the occurrence of a "Special
Conversion Event", convert all outstanding shares of convertible preferred stock
into common stock at the initial conversion rate of 1.3913 shares of common
stock, subject to certain adjustments, plus additional shares in respect to
accrued and unpaid dividends. A Special Conversion Event is deemed to have
occurred when the average daily closing price for a share of the Company's
common stock for 20 of 30 consecutive trading days equals or exceeds 125% of the
quotient of $20.00 divided by the then applicable conversion rate (approximately
$18.00 per share at a conversion rate of 1.3913).
Upon the occurrence of the "First Ownership Change" of Santa Fe, each holder
of shares of convertible preferred stock shall have the right, at the holder's
option, to elect to have all of such holder's shares redeemed for $20.00 per
share plus accrued and unpaid interest and dividends. The First Ownership Change
shall be deemed to have occurred when any person or group, together with any
affiliates or associates, becomes the beneficial owner of 50% or more of the
outstanding common stock of Santa Fe.
(10) SHAREHOLDERS' EQUITY
Common Stock
In 1991, 1992 and 1993 the Company issued 1.1 million previously unissued
shares of common stock in connection with certain employee benefit and
compensation plans. Also in 1992, the Company issued 24.9 million previously
unissued shares of common stock in connection with the Merger.
The Company declared dividends to common shares of $0.16 per share in 1991
and 1992 and $0.12 per share in 1993.
Preferred Stock
The Board of Directors of the Company is empowered, without approval of the
shareholders, to cause shares of preferred stock to be issued in one or more
series, and to determine the number of shares in each series and the rights,
preferences and limitations of each series. Among the specific matters which may
be determined by the Board of Directors are: the annual rate of dividends; the
redemption price, if any; the terms of a sinking or purchase fund, if any; the
amount payable in the event of any voluntary liquidation, dissolution or winding
up of the affairs of the Company; conversion rights, if any; and voting powers,
if any.
Accumulated Deficit
At December 31, 1993 Accumulated Deficit included dividends in excess of
retained earnings of $89.8 million.
1990 Incentive Stock Compensation Plan
The Company has adopted the Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan (the "Plan") under the terms of which the Company may grant
options and awards with respect to no more than 5,000,000 shares of common stock
to officers and key employees.
Options granted in 1991 and prior are fully vested and expire in 2000.
Options granted in 1992 have a ten year term and vest as to 33.33 percent one
year after grant, as to a cumulative 66.67
F-15
<PAGE> 87
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
percent two years after grant and as to the entire amount three years after
grant. The options granted in 1993 have a ten year term and vest as to 50
percent 5 years after grant, as to a cumulative 75 percent 6 years after grant
and as to the entire amount 7 years after grant. The options are exercisable on
an accelerated basis beginning one year and ending three years after grant in
certain circumstances. If the market value per share of the Company's common
stock (sustained in all events for at least 60 days) exceeds $15, 25 percent of
the options shall become exercisable; in the event the market value per share
exceeds $20, 50 percent of the options shall become exercisable; and in the
event the market value exceeds $25, 100 percent shall become exercisable.
Unexercised options would be forfeited in the event of voluntary or involuntary
termination. Vested options are exercisable for a period of one year following
termination due to death, disability or retirement. In the event of termination
by the Company for any reason there is no prorata vesting of unvested options.
The following table reflects activity with respect to Non-Qualified Stock
Options during 1991 through 1993:
<TABLE>
<CAPTION>
OPTION
OPTIONS PRICE
OUTSTANDING PER SHARE
----------- ------------------
<S> <C> <C>
Outstanding at December 31, 1990................................ 1,803,923 $14.4375 to $24.24
Grants.......................................................... 4,500 $14.625
Cancellations................................................... (45,332) $14.4375 to $24.24
---------
Outstanding at December 31, 1991................................ 1,763,091 $14.4375 to $24.24
Grants.......................................................... 1,099,000 $ 9.5625
Cancellations................................................... (50,163) $14.4375 to $24.24
---------
Outstanding at December 31, 1992................................ 2,811,928 $ 9.5625 to $24.24
Grants.......................................................... 800,000 $ 9.5625
Cancellations................................................... (95,398) $ 9.5625 to $24.24
Exercises....................................................... (6,945) $ 9.5625
---------
Outstanding at December 31, 1993................................ 3,509,585 $ 9.5625 to $24.24
=========
</TABLE>
At December 31, 1993 options on 780,790 shares were available for future
grants.
A "Phantom Unit" is the right to receive a cash payment in an amount equal
to the average trading price of the shares of common stock at the time the award
becomes payable. Awards are made for a specified period and are dependent upon
continued employment and the achievement of performance objectives established
by the Company. In December 1990 the Company awarded 211,362 Phantom Units and
in December 1991 313,262 shares of restricted stock were issued in exchange for
such units. Compensation expense is recognized over the period the awards are
earned based on the market price of the restricted stock on the date it was
issued ($8.00 per share). During 1990 and 1991 $0.2 million and $0.8 million,
respectively, were charged to expense with respect to such awards. The
unamortized portion of the award at December 31, 1991 ($1.4 million) was
reflected in Shareholders' Equity. The consummation of the Merger resulted in a
"change of control" as defined in the Plan and resulted in the vesting of the
awards and $1.4 million in compensation expense was recognized in 1992.
In 1993 the Company issued 6,432 shares of restricted stock to certain
employees and 118,039 common shares in accordance with the terms of certain
other employee compensation plans.
F-16
<PAGE> 88
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(11) PENSION AND OTHER EMPLOYEE BENEFIT PLANS
Pension Plans
Prior to the Spin-Off the Company was included in certain non-contributory
pension plans of SFP. The Santa Fe Pacific Corporation Retirement Plan (the "SFP
Plan") covered substantially all of the Company's officers and salaried
employees who were not covered by collective bargaining agreements. The Santa Fe
Pacific Corporation Supplemental Retirement Plan was an unfunded plan which
provided supplementary benefits, primarily to senior management personnel.
The Company adopted, effective as of the date of the Spin-Off, a defined
benefit retirement plan (the "SFER Plan") covering substantially all salaried
employees not covered by collective bargaining agreements and a nonqualified
supplemental retirement plan (the "Supplemental Plan"). The Supplemental Plan
will pay benefits to participants in the SFER Plan in those instances where the
SFER Plan formula produces a benefit in excess of limits established by ERISA
and the Tax Reform Act of 1986. Benefits payable under the SFER Plan are based
on years of service and compensation during the five highest paid years of
service during the ten years immediately preceding retirement. Benefits accruing
to the Company's employees under the SFP Plan have been assumed by the SFER
Plan. The Company's funding policy is to contribute annually not less than the
minimum required by ERISA and not more than the maximum amount deductible for
income tax purposes. In the fourth quarter of 1993 the Company established a new
pension plan with respect to certain persons employed in foreign locations.
The following table sets forth the funded status of the SFER Plan and the
Supplemental Plan at December 31, 1993 and 1992 (in millions of dollars):
<TABLE>
<CAPTION>
SFER PLAN SUPPLEMENTAL PLAN
-------------------- --------------------
1993 1992 1993 1992
-------- --------- -------- ---------
<S> <C> <C> <C> <C>
Plan assets at fair value, primarily invested in common
stocks and U.S. and corporate bonds..................... 30.2 28.9 -- --
Actuarial present value of projected benefit obligations:
Accumulated benefit obligations
Vested............................................ (30.9) (24.5) (0.6) (0.5)
Nonvested......................................... (1.5) (1.4) -- --
Effect of projected future salary increases....... (8.3) (6.4) (0.3) (0.2)
----- ----- ---- ----
Excess of projected benefit obligation over plan
assets.................................................. (10.5) (3.4) (0.9) (0.7)
Unrecognized net loss from past experience different from
that assumed and effects of changes in assumptions...... 6.4 0.7 0.3 0.2
Unrecognized net (asset) obligation being recognized over
plan's average remaining service life................... (1.0) (1.1) 0.2 0.3
Additional minimum liability.............................. -- -- (0.3) (0.3)
----- ----- ---- ----
Accrued pension liability................................. (5.1) (3.8) (0.7) (0.5)
===== ===== ==== ====
Major assumptions at year-end
Discount rate......................................... 7.0% 8.25% 7.0% 8.25%
Long-term asset yield................................. 9.5% 9.5% 9.5% 9.5%
Rate of increase in future compensation............... 5.25% 5.25% 5.25% 5.25%
</TABLE>
F-17
<PAGE> 89
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the components of pension expense for the
SFER Plan and Supplemental Plan for 1993, 1992 and 1991 (in millions of
dollars):
<TABLE>
<CAPTION>
SFER PLAN SUPPLEMENTAL PLAN
------------------------------- -------------------------------
1993 1992 1991 1993 1992 1991
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Service cost..................... 1.4 1.2 1.1 -- -- --
Interest cost.................... 2.6 2.4 2.3 0.1 0.1 0.1
Return on plan assets............ (2.7) (2.5) (2.4) -- -- --
Net amortization and deferral.... -- -- (0.1) -- -- --
---- ---- ---- --- --- ---
1.3 1.1 0.9 0.1 0.1 0.1
==== ==== ==== === === ===
</TABLE>
The Company also sponsors a pension plan covering certain hourly-rated
employees in California (the "Hourly Plan"). The Hourly Plan provides benefits
that are based on a stated amount for each year of service. The Company annually
contributes amounts which are actuarially determined to provide the Hourly Plan
with sufficient assets to meet future benefit payment requirements.
The following table sets forth the components of pension expense for the
Hourly Plan for the years 1993, 1992 and 1991 (in millions of dollars):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Service cost............................................................. 0.2 0.2 0.2
Interest cost............................................................ 0.7 0.7 0.7
Return on plan assets.................................................... (0.8) (0.1) (0.5)
Net amortization and deferral............................................ 0.4 (0.4) 0.1
---- ---- ----
0.5 0.4 0.5
==== ==== ====
</TABLE>
The following table sets forth the funded status of the Hourly Plan at
December 31, 1993 and 1992 (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
---- ----
<S> <C> <C>
Plan assets at fair value, primarily invested in fixed-rate securities........... 7.7 7.2
Actual present value of projected benefit obligations
Accumulated benefit obligations
Vested................................................................... (11.2) (9.1)
Nonvested................................................................ (0.4) (0.3)
----- ----
Excess of projected benefit obligation over plan assets.......................... (3.9) (2.2)
Unrecognized net (gain) loss from past experience different from that
assumed and effects of changes in assumptions................................ 1.5 (0.3)
Unrecognized prior service cost.................................................. 0.5 0.6
Unrecognized net obligation...................................................... 1.5 1.6
Additional minimum liability..................................................... (3.5) (2.1)
----- ----
Accrued pension liability.................................................... (3.9) (2.4)
Major assumptions at year-end ===== ====
Discount rate................................................................ 7.0% 8.25%
Expected long-term rate of return on plan assets............................. 8.5% 8.5 %
</TABLE>
At December 31, 1993 the Company's additional minimum liability exceeded the
total of its unrecognized prior service cost and unrecognized net obligation by
$1.5 million. Accordingly, at
F-18
<PAGE> 90
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1993 the Company's retained earnings have been reduced by such
amount, net of related taxes of $0.6 million.
Postretirement Benefits Other Than Pensions
The Company provides health care and life insurance benefits for
substantially all employees who retire under the provisions of a
Company-sponsored retirement plan and their dependents. Participation in the
plans is voluntary and requires a monthly contribution by the employee.
Effective January 1, 1993 the Company adopted the provisions of SFAS No.
106 -- "Employers' Accounting for Postretirement Benefits Other Than Pensions".
The Statement requires the accrual, during the years the employee renders
service, of the expected cost of providing postretirement benefits to the
employee and the employee's beneficiaries and covered dependents. The following
table sets forth the plan's funded status at December 31, 1993 and January 1,
1993 (in millions of dollars):
<TABLE>
<CAPTION>
DECEMBER 31, JANUARY 1,
1993 1993
------------ ----------
<S> <C> <C>
Plan assets, at fair value............................................ -- --
Accumulated postretirement benefit obligation
Retirees............................................................ (3.6) (3.1)
Eligible active participants........................................ (1.2) (0.9)
Other active participants........................................... (1.4) (1.2)
----- ----
Accumulated postretirement benefit obligation in excess of plan
assets.............................................................. (6.2) (5.2)
Unrecognized transition obligation.................................... 5.0 5.2
Unrecognized net loss from past experience different from
that assumed and from changes in assumptions........................ 0.5 --
----- ----
Accrued postretirement benefit cost................................... (0.7) --
===== ====
Assumed discount rate................................................. 7.5% 8.25%
Assumed rate of compensation increase................................. 5.25% 5.25%
</TABLE>
The Company's net periodic postretirement benefit cost for 1993 includes the
following components (in millions of dollars):
<TABLE>
<S> <C>
Service costs........................................................ 0.3
Interest costs....................................................... 0.4
Amortization of unrecognized transition obligation................... 0.3
---
1.0
===
</TABLE>
In periods prior to 1993 the cost to the Company of providing health care
and life insurance benefits for qualified retired employees was recognized as
expenses when claims were paid. Such amounts totalled $0.4 million in 1991 and
$0.3 million in 1992.
Estimated costs and liabilities have been developed assuming trend rates for
growth in future health care costs beginning with 10% for 1993 graded to 6%
(5.5% for post age 65) by the year 2000 and remaining constant thereafter.
Increasing the assumed health care cost trend rate by one percent each year
would increase the accumulated postretirement benefit obligation as of December
31, 1993 by $0.9 million and the aggregate of the service cost and interest cost
components of the net periodic postretirement benefit cost for 1994 by $0.2
million.
Savings Plan
The Company has a savings plan, which became effective November 1, 1990,
available to substantially all salaried employees and intended to qualify as a
deferred compensation plan under
F-19
<PAGE> 91
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Section 401(k) of the Internal Revenue Code (the "401(k) Plan"). The
Company will match employee contributions for an amount up to 4% of each
employee's base salary. In addition, if at the end of each fiscal year the
Company's performance for such year has exceeded certain predetermined criteria,
each participant will receive an additional matching contribution equal to 50%
of the regular matching contribution. The Company's contributions to the 401(k)
Plan, which are charged to expense, totaled $1.2 million in 1991, $1.3 million
in 1992 and $1.5 million in 1993. In the fourth quarter of 1993 the Company
established a new savings plan with respect to certain personnel employed in
foreign locations.
Other Postemployment Benefits
In the fourth quarter of 1993 the Company adopted SFAS No.
112 -- "Employers' Accounting for Postemployment Benefits". The Statement
requires the accrual of the estimated costs of benefits provided by an employer
to former or inactive employees after employment but before retirement. Such
benefits include salary continuation, supplemental unemployment benefits,
severance benefits, disability-related benefits, job training and counseling and
continuation of benefits such as health care and life insurance coverage. The
adoption of SFAS No. 112 resulted in a charge to earnings of $1.8 million in
1993.
(12) COMMITMENTS AND CONTINGENCIES
Crude Oil Hedging Program
In the third quarter of 1990, the Company initiated a hedging program
designed to provide a certain minimum level of cash flow from its sales of crude
oil. Settlements were included in oil revenues in the period the oil is sold. In
the year ended December 31, 1990 hedges resulted in a reduction in oil revenues
of $10.7 million; in 1991 hedges resulted in an increase in oil revenues of
$41.7 million and in 1992 hedges resulted in an increase in oil revenues of $9.7
million. The Company had no open crude oil hedging contracts during 1993.
Natural Gas Hedging Program
In the third quarter of 1992 the Company initiated a hedging program with
respect to its sales of natural gas. The Company has used various instruments
whereby monthly settlements are based on the differences between the price or
range of prices specified in the instruments and the settlement price of certain
natural gas futures contracts quoted on the New York Mercantile Exchange. In
instances where the applicable settlement price is less than the price specified
in the contract, the Company receives a settlement based on the difference; in
instances where the applicable settlement price is higher than the specified
prices the Company pays an amount based on the difference. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product. In 1992 and 1993 hedges resulted in a reduction in natural gas revenues
of $0.5 million and $8.2 million, respectively.
At December 31, 1993 the Company had two open natural gas hedging contracts
covering approximately 1.2 Bcf during the six month period beginning March 1994.
The "approximate break-even price" (the average of the monthly settlement prices
of the applicable futures contracts which would result in no settlement being
due to or from the Company) with respect to such contracts is approximately
$1.82 per Mcf. In addition, certain parties hold options on contracts covering
approximately 4.8 Bcf during the seven month period beginning March 1994 at an
approximate break even price of $1.90 per Mcf. The Company has no other
outstanding natural gas hedging instruments.
Indemnity Agreement With SFP
At the time of the Spin-Off, the Company and SFP entered into an agreement
to protect SFP from federal and state income taxes, penalties and interest that
would be incurred by SFP if the
F-20
<PAGE> 92
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Spin-off were determined to be a taxable event resulting primarily from
actions taken by the Company during a one-year period that ended December 4,
1991. If the Company were required to make payments pursuant to the agreement,
such payments could have a material adverse effect on its financial condition;
however, the Company does not believe that it took any actions during such
one-year period that would have such an effect on the Spin-Off.
Environmental Regulation
Federal, state and local laws and regulations relating to environmental
quality control affect the Company in all of its oil and gas operations. The
Company has been identified as one of over 250 potentially responsible parties
("PRPs") at a superfund site in Los Angeles County, California. The site was
operated by a third party as a waste disposal facility from 1948 until 1983. The
Environmental Protection Agency ("EPA") is requiring the PRPs to undertake
remediation of the site in several phases, which include site monitoring and
leachate control, gas control and final remediation. In 1989, the EPA and a
group of the PRPs entered into a consent decree covering the site monitoring and
leachate control phases of remediation. The Company is a member of the group
that is responsible for carrying out this first phase of work, which is expected
to be completed in five to eight years. The maximum liability of the group,
which is joint and several for each member of the group, for the first phase is
$37.0 million, of which the Company's share is expected to be approximately $2.4
million ($1.3 million after recoveries from working interest participants in the
unit at which the wastes were generated) payable over the period that the phase
one work is performed. The EPA and a group of PRPs of which the Company is a
member have also entered into a subsequent consent decree (which has not been
finally entered by the court) with respect to the second phase of work (gas
control). The liability of this group has not been capped, but is estimated to
be $130.0 million. The Company's share of costs of this phase, however, is
expected to be approximately of the same magnitude as that of the first phase
because more parties are involved in the settlement. The Company has provided
for costs with respect to the first two phases, but it cannot currently estimate
the cost of any subsequent phases of work or final remediation which may be
required by the EPA.
In 1989, Adobe received requests from the EPA for information pursuant to
Section 104(e) of CERCLA with respect to the D.L. Mud and Gulf Coast Vacuum
Services superfund sites located in Abbeville, Louisiana. The EPA has issued its
record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued
to all PRP's at the site a settlement order pursuant to Section 122 of CERCLA.
Earlier, an emergency order pursuant to Section 106 of CERLA was issued on
December 11, 1992, for purposes of containment due to the Louisiana rainy
season. On December 15, 1993 the Company entered into a sharing agreement with
other PRP'S to participate in the final remediation of the Gulf Coast site. The
Company's share of the remediation is approximately $600,000 and includes its
proportionate share of those PRPs who do not have the financial resources to
provide their share of the work at the site. A former site owner has already
conducted remedial activities at the D.L. Mud Site under a state agency
agreement. The extent, if any, of any further necessary remedial activity at the
D.L. Mud Site has not been finally determined.
Employment Agreements
The Company has entered into employment agreements with certain key
employees. The initial term of each agreement expired on December 31, 1990 and,
on January 1, 1991 and beginning on each January 1 thereafter, is automatically
extended for one-year periods, unless by September 30 of any year the Company
gives notice that the agreement will not be extended. The term of the agreements
is automatically extended for 24 months following a change of control. The
consummation of the Merger constituted a change of control as defined in the
agreements.
F-21
<PAGE> 93
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In the event that following a change of control employment is terminated
for reasons specified in the agreements, the employee would receive: (i) a lump
sum payment equal to two years' base salary; (ii) the maximum possible bonus
under the terms of the Company's incentive compensation plan; (iii) a lapse of
restrictions on any outstanding restricted stock grants and full payout of any
outstanding Phantom Units; (iv) cash payment for each outstanding stock option
equal to the amount by which the fair market value of the common stock exceeds
the exercise price of the option; and, (v) life, disability and health benefits
for a period of up to two years. In addition, payments and benefits under
certain employment agreements are subject to further limitations based on
certain provisions of the Internal Revenue Code.
Interest Rate Swaps
Prior to the Merger, Adobe had entered into two interest rate swaps with a
bank with notional principal amounts of $15.0 mllion and $20.0 million. Under
the terms of the $20.0 million swap, which expires in April 1994, during any
quarterly period at the beginning of which a floating rate specified in the
agreement is less than 7.84%, the Company must pay the bank interest for such
period on the principal amount at the difference between the rates. Should the
floating rate be in excess of 7.84%, the bank must pay the Company interest for
such period on the principal amount at the difference between the rates. For the
period from the effective date of the Merger to December 31, 1992 the amount due
the bank in accordance with the terms of the $20.0 million swap totalled $0.6
million and the amount due the bank in 1993 totalled $0.9 million. For the
quarterly period which ends in April 1994, the amount due the bank is based on a
floating rate of 3.375%. The $15.0 million swap, which expired December 31,
1992, had terms similar to the $20.0 million swap and the amount due the bank
for the period subsequent to the Merger totaled $0.5 million.
Operating Leases
The Company has noncancellable agreements with terms ranging from one to ten
years to lease office space and equipment. Minimum rental payments due under the
terms of these agreements are: 1994 -- $6.1 million, 1995 -- $6.0 million,
1996 -- $5.5 million, 1997 -- $5.2 million, 1998 -- $4.4 million and $4.7
million thereafter. Rental payments made under the terms of noncancellable
agreements totaled $4.0 million in 1991,$4.5 million in 1992 and $5.5 million in
1993.
Other Matters
The Company has several long-term contracts ranging up to fifteen years for
the supply and transportation of approximately 30 million cubic feet per day of
natural gas. In the aggregate, these contracts involve a minimum commitment on
the part of the Company of approximately $10 million per year.
There are other claims and actions, including certain other environmental
matters, pending against the Company. In the opinion of management, the amounts,
if any, which may be awarded in connection with any of these claims and actions
could be significant to the results of operations of any period but would not
be material to the Company's consolidated financial position.
(13) INCOME TAXES
Effective January 1, 1993 the Company adopted the provisions of Statement of
Financial Accounting Standards No. 109 -- "Accounting for Income Taxes". The
adoption of SFAS No. 109 had no significant impact on the Company's provision
for income taxes.
Through the date of the Spin-Off the taxable income or loss of the Company
was included in the consolidated federal income tax return filed by SFP. The
Company has filed separate consolidated federal income tax returns for periods
subsequent to the Spin-Off. The consolidated federal income
F-22
<PAGE> 94
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tax returns of SFP have been examined through 1988 and all years prior
to 1981 are closed. Issues relating to the years 1981 through 1985 are being
contested through various stages of administrative appeal. The Company is
evaluating its position with respect to issues raised in a 1986 through 1988
audit. The Company believes adequate provision has been made for any adjustments
which might be assessed for all open years.
During 1989, the Company received a notice of deficiency for certain state
franchise tax returns filed for the years 1978 through 1983 as part of the
consolidated tax returns of SFP. The years subsequent to 1983 are still subject
to audit. At December 31, 1993 Other Long-Term Obligations includes $20.6
million with respect to this matter. The Company intends to contest this matter.
With the Merger of Adobe the Company succeeded to a net operating loss
carryforward that is subject to Internal Revenue Code Section 382 limitations
which annually limit taxable income that can be offset by such losses. Certain
changes in the Company's shareholders may impose additional limitations as well.
Losses carrying forward of $133.3 million expire beginning in 1998.
At date of the Merger, Adobe had ongoing tax litigation related to a refund
claim for carryback of certain net operating losses denied by the Internal
Revenue Service. During 1991 Adobe successfully defended its claim in Federal
District Court and prevailed again in 1992 in the United States Court of Appeals
for the Fifth Circuit. The Internal Revenue Service had no further recourse to
litigation and a $16.2 million refund was reflected as Income Tax Refund
Receivable at December 31, 1992 and collected in 1993.
Pretax income from continuing operations for the years ended December 31,
1993, 1992 and 1991 was taxed under the following jurisdictions:
<TABLE>
<CAPTION>
1993 1992 1991
------- ------ -----
<S> <C> <C> <C>
Domestic............................................................... (120.9) 2.7 34.8
Foreign................................................................ (29.3) (3.6) (2.1)
------ ---- ----
(150.2) (0.9) 32.7
====== ==== ====
</TABLE>
The Company's income tax expense (benefit) for the years ended December 31,
1993, 1992 and 1991 consisted of (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992 1991
------ ----- ----
<S> <C> <C> <C>
Current
U.S. federal........................................................... (1.3) 3.5 11.0
State.................................................................. (1.2) 1.4 1.7
Foreign................................................................ 1.3 1.9 --
---- ---- ----
(1.2) 6.8 12.7
----- ---- ----
Deferred
U.S. federal........................................................... (65.6) (3.5) 0.2
U.S. federal tax rate change........................................... 2.6 -- --
State.................................................................. (8.0) (2.5) 1.3
Foreign................................................................ (0.9) (0.3) --
----- ---- ----
(71.9) (6.3) 1.5
----- ---- ----
(73.1) 0.5 14.2
===== ==== ====
</TABLE>
F-23
<PAGE> 95
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's deferred income tax liabilities (assets) at December 31, 1993
and 1992 are composed of the following differences between financial and tax
reporting (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
----- -----
<S> <C> <C>
Capitalized costs and write-offs.............................................. 83.0 150.8
Differences in Partnership basis.............................................. 15.1 29.3
State deferred liability...................................................... 5.8 13.4
Foreign deferred liability.................................................... 13.7 15.5
----- -----
Gross deferred liabilities.................................................... 117.6 209.0
----- -----
Accruals not currently deductible for tax purposes............................ (17.7) (28.3)
Alternative minimum tax carryforwards......................................... (8.3) (5.3)
Net operating loss carryforwards.............................................. (46.7) (56.4)
Other......................................................................... (0.5) --
----- -----
Gross deferred assets......................................................... (73.2) (90.0)
----- -----
Deferred tax liability........................................................ 44.4 119.0
===== =====
</TABLE>
The Company had no deferred tax asset valuation allowance at December 31,
1993 or 1992.
A reconciliation of the Company's U.S. income tax expense (benefit) computed
by applying the statutory U.S. federal income tax rate to the Company's income
(loss) before income taxes for the years ended December 31, 1993, 1992 and 1991
is presented in the following table (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992 1991
------ ----- ----
<S> <C> <C> <C>
U.S. federal income taxes (benefit) at statutory rate................ (52.6) (0.3) 11.1
Increase (reduction) resulting from:
State income taxes, net of federal effect.......................... (1.0) 1.4 2.2
Foreign income taxes in excess of U.S. rate........................ (0.8) 0.3 --
Nondeductible amounts.............................................. (0.2) (2.4) --
Effect of increase in statutory rate on deferred taxes............. 2.6 -- --
Federal audit refund............................................... (3.2) -- --
Amendment to tax sharing agreement with SFP........................ (1.2) -- --
Benefit of tax losses.............................................. (11.2) -- --
Prior period adjustments........................................... (5.5) -- --
Other.............................................................. -- 1.5 0.9
----- ---- ----
(73.1) 0.5 14.2
===== ==== ====
</TABLE>
The Company increased its deferred tax liability in 1993 as a result of
legislation enacted during 1993 increasing the corporate tax rate from 34% to
35% commencing in 1993.
(14) FAIR VALUE OF FINANCIAL INSTRUMENTS
SFAS No. 107 "Disclosure About Fair Value of Financial Instruments" requires
the disclosure, to the extent practicable, of the fair value of financial
instruments which are recognized or unrecognized in the balance sheet. The fair
value of the financial instruments disclosed herein is not representative of the
amount that could be realized or settled, nor does the fair value amount
consider the tax consequences, if any, of realization or settlement. The
following table reflects the
F-24
<PAGE> 96
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
financial instruments for which the fair value differs from the carrying amount
of such financial instrument in the Company's December 31, 1993 and 1992 balance
sheets (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
<S> <C> <C> <C> <C>
Assets
Trust Units.................................... 10.4 11.3 10.4 10.5
Liabilities
Long-Term Debt (including current
portion)..................................... 449.7 482.2 546.2 572.2
Convertible Preferred Stock.................... 80.0 103.8 80.0 93.8
Interest rate swap............................. -- 0.4 -- 1.1
</TABLE>
The fair value of the Trust Units and convertible preferred stock is based
on market prices. The fair value of the Company's fixed-rate long-term debt is
based on current borrowing rates available for financings with similar terms and
maturities. With respect to the Company's floating-rate debt, the carrying
amount approximates fair value. The fair value of the interest rate swap
represents the estimated cost to the Company over the remaining life of the
contract.
At December 31, 1993 the Company had two open natural gas hedging contracts
and options outstanding on five additional contracts (see Note 12 -- Commitments
and Contingencies -- Natural Gas Hedging Contracts). Based on the settlement
prices of certain natural gas futures contracts as quoted on the New York
Mercantile Exchange on December 30, 1993, assuming all options are exercised,
the cost to the Company with respect to such contracts during 1994 would be
approximately $0.6 million.
F-25
<PAGE> 97
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
Information with respect to the Company's oil and gas producing activities
is presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants, Ryder Scott Company.
Oil and Gas Reserves
The following table sets forth the Company's net proved oil and gas reserves
at December 31, 1990, 1991, 1992 and 1993 and the changes in net proved oil and
gas reserves for the years ended December 31, 1991, 1992 and 1993.
<TABLE>
<CAPTION>
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
-------------------------------------- ------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- ----- ---- --------- --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved reserves at
December 31, 1990.............................. 222.3 -- -- 222.3 185.9 -- -- 185.9
Revisions of previous estimates............... (1.9) -- -- (1.9) 0.4 -- -- 0.4
Improved recovery techniques.................. 15.9 -- -- 15.9 0.5 -- -- 0.5
Extensions, discoveries and other
additions.................................... 1.8 -- -- 1.8 19.6 -- -- 19.6
Purchases of minerals-in-place................ 4.6 8.7 -- 13.3 2.5 -- -- 2.5
Sales of minerals-in-place.................... (2.4) -- -- (2.4) (5.5) -- -- (5.5)
Increase in ownership in Partnership.......... 0.4 -- -- 0.4 2.2 -- -- 2.2
Production.................................... (20.0) (0.2) -- (20.2) (34.8) -- -- (34.8)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1991.............................. 220.7 8.5 -- 229.2 170.8 -- -- 170.8
Revisions of previous estimates............... 14.4 (0.3) -- 14.1 7.3 -- -- 7.3
Improved recovery techniques.................. 17.0 -- -- 17.0 1.3 -- -- 1.3
Extensions, discoveries and other
additions.................................... 1.3 1.3 -- 2.6 5.6 -- -- 5.6
Purchases of minerals-in-place................ 13.5 -- 7.2 20.7 141.5 -- 0.6 142.1
Sales of minerals-in-place.................... (5.7) -- -- (5.7) (5.0) -- -- (5.0)
Increase in ownership in Partnership.......... 0.2 -- -- 0.2 1.6 -- -- 1.6
Production.................................... (21.4) (0.8) (0.8) (23.0) (46.2) -- -- (46.2)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1992.............................. 240.0 8.7 6.4 255.1 276.9 -- 0.6 277.5
Revisions to previous estimates............... (11.9) 0.5 0.6 (10.8) 26.6 -- 0.1 26.7
Improved recovery techniques.................. 26.7 -- -- 26.7 -- -- -- --
Extensions, discoveries and other
additions.................................... 3.4 0.5 2.3 6.2 29.5 26.4 -- 55.9
Purchases of minerals-in-place................ 3.2 -- 0.7 3.9 9.8 -- 0.1 9.9
Sales of minerals in place.................... (8.7) -- -- (8.7) (47.4) -- -- (47.4)
Increase in ownership in Partnership.......... 0.1 -- -- 0.1 0.8 -- -- 0.8
Production.................................... (21.9) (0.9) (1.5) (24.3) (60.3) -- (0.1) (60.4)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1993............................. 230.9 8.8 8.5 248.2 235.9 26.4 0.7 263.0
===== ==== ==== ===== ===== ==== ==== =====
</TABLE>
(Table continued on following page)
F-26
<PAGE> 98
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
-------------------------------------- ---------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- ------ ---- --------- --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved developed reserves
at December 31
1990........................ 176.8 -- -- 176.8 169.4 -- -- 169.4
1991........................ 179.2 5.4 -- 184.6 154.2 -- -- 154.2
1992........................ 194.6 5.6 6.4 206.6 250.2 -- 0.6 250.8
1993........................ 178.8 5.5 6.7 191.0 206.0 -- 0.7 206.7
</TABLE>
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.
Indonesian reserves represent an entitlement to gross reserves in accordance
with a production sharing contract. These reserves include estimated quantities
allocable to the Company for recovery of operating costs as well as quantities
related to the Company's net equity share after recovery of costs. Accordingly,
these quantities are subject to fluctuations with an inverse relationship to the
price of oil. If oil prices increase, the reserve quantities attributable to the
recovery of operating costs decline. Although this reduction would be offset
partially by an increase in the net equity share, the overall effect would be a
reduction of reserves attributable to the Company. At December 31, 1993, the
quantities include 0.6 million barrels which the Company is contractually
obligated to sell for $.20 per barrel.
At December 31, 1993 the Company's reserves were 6.9 million barrels of
crude oil and liquids and 14.5 Bcf of natural gas lower than at December 31,
1992, reflecting the sale in 1993 of properties with reserves totalling 8.7
million barrels of crude oil and liquids and 47.4 Bcf of natural gas.
At December 31, 1993, 1.9 million barrels of crude oil reserves and 19.7
billion cubic feet of natural gas reserves were subject to a 90% net profits
interest held by Santa Fe Energy Trust.
F-27
<PAGE> 99
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Estimated Present Value of Future Net Cash Flows
Estimated future net cash flows from the Company's proved oil and gas
reserves at December 31, 1991, 1992 and 1993 are presented in the following
table (in millions of dollars, except as noted):
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1993
Future cash inflows...................................... 2,654.9 117.9 115.6 2,888.4
Future production costs.................................. (1,547.2) (65.9) (78.7) (1,691.8)
Future development costs................................. (216.7) (32.4) (8.9) (258.0)
Future income tax expenses............................... (100.5) -- (6.9) (107.4)
-------- ----- ----- --------
Net future cash flows................................ 790.5 19.6 21.1 831.2
Discount at 10% for timing of cash flows................. (308.5) (12.1) (8.2) (328.8)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 482.0 7.5 12.9 502.4
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 9.10 9.74 13.50
Natural gas ($/Mcf).................................. 2.28 1.23 0.97
1992
Future cash inflows...................................... 3,709.8 132.9 105.8 3,948.5
Future production costs.................................. (1,982.6) (82.1) (79.5) (2,144.2)
Future development costs................................. (292.2) (13.5) -- (305.7)
Future income tax expenses............................... (286.9) (1.0) (9.5) (297.4)
-------- ----- ----- --------
Net future cash flows................................ 1,148.1 36.3 16.8 1,201.2
Discount at 10% for timing of cash flows................. (450.5) (14.0) (3.2) (467.7)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 697.6 22.3 13.6 733.5
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 13.30 15.28 16.46
Natural gas ($/Mcf).................................. 2.01 -- 0.97
1991
Future cash inflows...................................... 2,899.9 117.2 -- 3,017.1
Future production costs.................................. (1,655.3) (76.1) -- (1,731.4)
Future development costs................................. (242.2) (13.7) -- (255.9)
Future income tax expenses............................... (236.6) -- -- (236.6)
-------- ----- ----- --------
Net future cash flows................................ 765.8 27.4 -- 793.2
Discount at 10% for timing of cash flows................. (320.0) (9.6) -- (329.6)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 445.8 17.8 -- 463.6
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 11.80 13.72 --
Natural gas ($/Mcf).................................. 1.78 -- --
</TABLE>
F-28
<PAGE> 100
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
The following tables sets forth the changes in the present value of
estimated future net cash flows from proved reserves during 1991, 1992 and 1993
(in millions of dollars):
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1993
Balance at beginning of year.............................. 697.6 22.3 13.6 733.5
------ ----- ----- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $189.5 million..................................... (230.1) (7.3) (10.0) (247.4)
Net changes in prices and production costs.............. (325.1) (7.7) 1.7 (331.1)
Extensions, discoveries and improved recovery........... 94.8 14.8 7.0 116.6
Purchases of minerals-in-place.......................... 20.4 -- 2.1 22.5
Sales of minerals-in-place.............................. (84.7) -- -- (84.7)
Development costs incurred.............................. 50.0 5.1 -- 55.1
Changes in estimated volumes............................ 28.3 1.5 1.8 31.6
Changes in estimated development costs.................. 25.6 (24.1) (8.9) (7.4)
Interest factor -- accretion of discount................ 87.1 2.3 2.1 91.5
Income taxes............................................ 112.0 0.6 3.5 116.1
Increase in ownership in Partnership.................... 1.2 -- -- 1.2
Other................................................... 4.9 -- -- 4.9
------ ----- ----- ------
(215.6) (14.8) (0.7) (231.1)
------ ----- ----- ------
482.0 7.5 12.9 502.4
====== ===== ===== ======
</TABLE>
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1992
Balance at beginning of year.............................. 445.8 17.8 -- 463.6
------ ----- ----- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $176.2 million..................................... (236.6) (8.4) (6.3) (251.3)
Net changes in prices and production costs.............. 191.7 7.8 3.5 203.0
Extensions, discoveries and improved recovery........... 70.9 4.6 -- 75.5
Purchases of minerals-in-place.......................... 230.6 -- 24.1 254.7
Sales of minerals-in-place.............................. (77.7) -- -- (77.7)
Development costs incurred.............................. 26.5 3.1 -- 29.6
Changes in estimated volumes............................ 63.4 (1.0) -- 62.4
Changes in estimated development costs.................. (76.9) (2.8) -- (79.7)
Interest factor -- accretion of discount................ 58.7 1.8 -- 60.5
Income taxes............................................ (14.8) (0.6) (7.7) (23.1)
Increase in ownership in Partnership.................... 1.9 -- -- 1.9
Other................................................... 14.1 -- -- 14.1
------ ----- ----- ------
251.8 4.5 13.6 269.9
------ ----- ----- ------
697.6 22.3 13.6 733.5
====== ===== ===== ======
</TABLE>
F-29
<PAGE> 101
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1991
Balance at beginning of year.............................. 839.4 -- -- 839.4
------ ---- ---- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $157.6 million..................................... (221.0) (1.2) -- (222.2)
Net changes in prices and production costs.............. (617.6) 7.9 -- (609.7)
Extensions, discoveries and improved recovery........... 71.6 -- -- 71.6
Purchases of minerals-in-place.......................... 10.4 24.8 -- 35.2
Sales of minerals-in-place.............................. (30.7) -- -- (30.7)
Development costs incurred.............................. 54.0 0.7 -- 54.7
Changes in estimated volumes............................ 2.3 -- -- 2.3
Changes in estimated development costs.................. (117.5) (14.4) -- (131.9)
Interest factor -- accretion of discount................ 123.5 -- -- 123.5
Income taxes............................................ 233.5 -- -- 233.5
Increase in ownership in Partnership.................... 4.6 -- -- 4.6
Other................................................... 93.3 -- -- 93.3
------ ---- ---- ------
(393.6) 17.8 -- (375.8)
------ ---- ---- ------
445.8 17.8 -- 463.6
====== ==== ==== ======
</TABLE>
Estimated future cash flows represent an estimate of future net cash flows
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 general corporate
overhead or interest expense.
The sales prices used in the calculation of estimated future net cash flows
are based on the prices in effect at year end. Such prices have been held
constant except for known and determinable escalations.
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.
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved. While
applicable investment tax credits and other permanent differences are considered
in computing taxes, no recognition is given to tax benefits applicable to future
exploration costs or the activities of the Company that are unrelated to oil and
gas producing activities.
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 year-end 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.
F-30
<PAGE> 102
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Costs Incurred in Oil and Gas Producing Activities
The following table includes all costs incurred, whether capitalized or
charged to expense at the time incurred (in millions of dollars):
<TABLE>
<CAPTION>
OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------ --------- --------- ------- -----
<S> <C> <C> <C> <C> <C>
1993
Property acquisition costs
Unproved....................................... 6.4 -- 1.8 3.8 12.0
Proved......................................... 29.7 -- 2.9 -- 32.6
Other.......................................... 0.8 -- -- -- 0.8
Exploration costs................................ 20.9 0.7 5.2 11.7 38.5
Development costs................................ 85.3 7.3 7.6 -- 100.2
----- ---- ---- ---- -----
143.1 8.0 17.5 15.5 184.1
===== ==== ==== ==== =====
1992
Property acquisition costs
Unproved....................................... 29.3 0.2 8.8 3.5 41.8
Proved......................................... 294.1 -- 59.4 -- 353.5
Other.......................................... 65.6 -- -- -- 65.6
Exploration costs................................ 18.4 2.1 2.9 8.9 32.3
Development costs................................ 56.8 3.0 1.8 -- 61.6
----- ---- ---- ---- -----
464.2 5.3 72.9 12.4 554.8
===== ==== ==== ==== =====
1991
Property acquisition costs
Unproved....................................... 4.4 -- -- 3.2 7.6
Proved......................................... 29.0 -- -- 34.1 63.1
Other.......................................... -- -- -- -- --
Exploration costs................................ 20.7 -- -- 4.1 24.8
Development costs................................ 85.8 -- -- 0.7 86.5
----- ---- ---- ---- -----
139.9 -- -- 42.1 182.0
===== ==== ==== ==== =====
</TABLE>
F-31
<PAGE> 103
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Capitalized Costs Related to Oil and Gas Producing Activities
The following table sets forth information concerning capitalized costs at
December 31, 1993 and 1992 related to the Company's oil and gas operations (in
millions of dollars):
<TABLE>
<CAPTION>
1993 1992
------------------------------------------------- --------------------------------------------------
OTHER OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------ --------- --------- ------- -------- ----- --------- --------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and gas properties
Unproved............ 40.3 1.3 12.0 10.7 64.3 80.1 1.3 10.2 7.3 98.9
Proved.............. 1,869.9 48.9 68.0 -- 1,986.8 2,049.8 37.5 62.7 -- 2,150.0
Other............... 13.2 -- -- -- 13.2 82.0 -- -- 82.0
Accumulated amortization
of unproved
properties............ (14.6) (1.2) (2.8) (9.9) (28.5) (23.6) (1.0) (1.7) (2.6) (28.9)
Accumulated depletion,
depreciation and
impairment of proved
properties............ (1,181.9) (7.9) (22.4) -- (1,212.2) (1,200.0) (4.6) (2.3) -- (1,206.9)
Accumulated depreciation
of other oil and gas
properties (4.3) -- -- -- (4.3) (7.5) -- -- -- (7.5)
-------- ---- ----- ---- -------- -------- ---- ---- ---- --------
722.6 41.1 54.8 0.8 819.3 980.8 33.2 68.9 4.7 1,087.6
======== ==== ===== ==== ======== ======== ==== ==== ==== ========
</TABLE>
F-32
<PAGE> 104
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Results of Operations From Oil and Gas Producing Activities
The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1993, 1992 and
1991 (in millions of dollars):
<TABLE>
<CAPTION>
OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------- --------- --------- ------- ---------
<S> <C> <C> <C> <C> <C>
1993
Revenues.................................................. 401.2 12.5 23.2 -- 436.9
Production costs.......................................... (166.9) (5.2) (13.2) -- (185.3)
Oil and gas systems and pipelines......................... (4.2) -- -- -- (4.2)
Exploration, including dry hole costs..................... (16.4) (0.7) (2.2) (11.7) (31.0)
Depletion, depreciation, amortization and impairments..... (218.8) (3.6) (21.2) (6.7) (250.3)
Restructuring charges..................................... (27.8) -- -- -- (27.8)
Gain (loss) on disposition of properties.................. (0.7) -- -- -- (0.7)
------ ----- ----- ----- ------
(33.6) 3.0 (13.4) (18.4) (62.4)
Income taxes.............................................. 24.1 (0.9) 1.9 -- 25.1
------ ----- ----- ----- ------
(9.5) 2.1 (11.5) (18.4) (37.3)
====== ===== ===== ===== ======
1992
Revenues.................................................. 400.0 13.9 13.6 -- 427.5
Production costs.......................................... (160.2) (5.5) (7.3) -- (173.0)
Oil and gas systems and pipelines......................... (3.2) -- -- -- (3.2)
Exploration, including dry hole costs..................... (12.9) (2.2) (1.3) (9.1) (25.5)
Depletion, depreciation, amortization and impairments..... (136.7) (3.7) (2.7) (1.6) (144.7)
Gain (loss) on disposition of properties.................. 13.6 -- -- -- 13.6
------ ----- ----- ----- ------
100.6 2.5 2.3 (10.7) 94.7
Income taxes.............................................. (37.9) -- (1.6) -- (39.5)
------ ----- ----- ----- ------
62.7 2.5 0.7 (10.7) 55.2
====== ===== ===== ===== ======
1991
Revenues.................................................. 376.1 3.7 -- -- 379.8
Production costs.......................................... (155.1) (2.5) -- -- (157.6)
Exploration, including dry hole costs..................... (15.5) (1.5) -- (1.7) (18.7)
Depletion, depreciation, amortization and impairments..... (101.3) (1.8) -- (0.7) (103.8)
Gain (loss) on disposition of properties.................. (0.5) -- -- -- (0.5)
------ ----- ----- ----- ------
103.7 (2.1) -- (2.4) 99.2
Income Taxes.............................................. (42.3) -- -- -- (42.3)
------ ----- ----- ----- ------
61.4 (2.1) -- (2.4) 56.9
====== ===== ===== ===== ======
</TABLE>
Income taxes are computed by applying the appropriate statutory rate to the
results of operations before income taxes. Applicable tax credits and allowances
related to oil and gas producing activities have been taken into account in
computing income tax expenses. No deduction has been made for indirect cost such
as corporate overhead or interest expense.
F-33
<PAGE> 105
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
SUMMARIZED QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
1 QTR 2 QTR 3 QTR 4 QTR YEAR
----- ----- ----- ----- ----
(IN MILLIONS OF DOLLARS EXCEPT PER SHARE DATE)
<S> <C> <C> <C> <C> <C>
1993
Revenues........................................................... 115.3 116.3 102.7 102.6 436.9
Gross profit (a)................................................... 19.0 22.5 8.5 (130.7) (80.7)
Income (loss) from operations...................................... 12.0 15.4 1.2 (141.6)(b) (113.0)
Net income (loss).................................................. (0.4) 4.0 2.4 (83.1) (77.1)
Earnings (loss) attributable to common shares...................... (2.2) 2.3 0.6 (84.8) (84.1)
Earnings (loss) attributable to common shares per share............ (0.02) 0.02 0.01 (0.95) (0.94)
Average shares outstanding (millions).............................. 89.6 89.7 89.8 89.8 89.7
1992
Revenues........................................................... 78.5 97.7 127.9 123.4 427.5
Gross profit (a)................................................... 2.9 34.1 32.0 19.4 88.4
Income (loss) from operations...................................... (3.5) 25.1 24.4 11.5 57.5
Net income (loss).................................................. (8.8) 1.8 7.3 (1.7) (1.4)
Earnings (loss) attributable to common shares...................... (8.8) 1.0 5.5 (3.4) (5.7)
Earnings (loss) attributable to common shares per share............ (.14) .01 .06 (.04) (.07)
Average shares outstanding (millions).............................. 64.3 72.7 89.4 89.5 79.0
</TABLE>
__________
(a) Revenues less operating expenses other than general and administrative.
(b) Includes charges of $99.3 million for impairment of oil and gas properties
and $38.6 million for restructuring charges.
F-34
<PAGE> 106
NO DEALER, SALESPERSON OR ANY OTHER
PERSON HAS BEEN AUTHORIZED TO GIVE ANY $100,000,00
INFORMATION OR TO MAKE ANY REPRESENTATIONS
OTHER THAN THOSE CONTAINED IN OR
INCORPORATED BY REFERENCE IN THIS
PROSPECTUS IN CONNECTION WITH THE OFFER
MADE BY THIS PROSPECTUS AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATIONS
MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY OR ANY OF THE
UNDERWRITERS. NEITHER THE DELIVERY OF SANTA FE ENERGY
THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, RESOURCES, INC.
CREATE ANY IMPLICATION THAT THERE HAS
BEEN NO CHANGE IN THE AFFAIRS OF THE
COMPANY SINCE THE DATE HEREOF. THIS
PROSPECTUS DOES NOT CONSTITUTE AN OFFER
OR SOLICITATION BY ANYONE IN ANY
JURISDICTION IN WHICH SUCH OFFER OR
SOLICITATION IS NOT AUTHORIZED OR IN
WHICH THE PERSON MAKING SUCH OFFER IS
NOT QUALIFIED TO DO SO OR TO ANY PERSON % SENIOR SUBORDINATED
TO WHOM IT IS UNLAWFUL TO MAKE SUCH
SOLICITATION. DEBENTURES DUE 2004
-----------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information.................. 2
Documents Incorporated by Reference.... 2
Certain Definitions.................... 2
Prospectus Summary..................... 3 SALOMON BROTHERS INC
Investment Considerations.............. 11
Ratios of Earnings to Fixed Charges.... 15 DILLON, READ & CO. INC.
Use of Proceeds........................ 15
Capitalization......................... 16 LAZARD FRERES & CO.
Selected Financial and Operating
Data................................. 17 CHEMICAL SECURITIES INC.
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 19
Business and Properties................ 26
Management............................. 44
Description of the Debentures.......... 47
Underwriting........................... 68
Validity of the Debentures............. 69
Experts................................ 69 PROSPECTUS
Index to Financial Statements.......... F-1 DATED MAY , 1994
</TABLE>
[/R]
<PAGE> 107
***************************************************************************
* *
* Information contained herein is subject to completion or amendment. A *
* registration statement relating to these securities has been filed *
* with the Securities and Exchange Commission. These securities may not *
* be sold nor may offers to buy be accepted prior to the time the *
* registration statement becomes effective. This prospectus shall not *
* constitute an offer to sell or the solicitation of an offer to buy *
* nor shall there be any sale of these securities in any State in which *
* such offer, solicitation or sale would be unlawful prior to *
* registration or qualification under the securities laws of any such *
* State. *
* *
***************************************************************************
SUBJECT TO COMPLETION
APRIL 26, 1994
PROSPECTUS
10,700,000 DECSSM
(DIVIDEND ENHANCED CONVERTIBLE STOCKSM--DECSSM)
SANTA FE ENERGY RESOURCES, INC.
$ SERIES A CONVERTIBLE PREFERRED STOCK
(PAR VALUE $0.01 PER SHARE)
(SUBJECT TO CONVERSION INTO OR REDEMPTION FOR SHARES OF COMMON STOCK, PAR VALUE
$0.01 PER SHARE)
The DECS offered hereby (the "Offering") are 10,700,000 shares of
$ Series A Convertible Preferred Stock of Santa Fe Energy Resources,
Inc., a Delaware corporation (the "Company"), and are referred to herein as
Dividend Enhanced Convertible Stock (the "DECS").
On March 31, 1998 (the "Mandatory Conversion Date"), each of the outstanding
DECS will automatically convert into one share of the Company's common stock,
par value $0.01 per share (the "Common Stock"), subject to adjustment in certain
events, if not previously redeemed by the Company or converted at the option of
the holder. The DECS are redeemable, at the option of the Company, in whole or
in part, on or after March 31, 1997 (the "Initial Redemption Date"), at a call
price payable in shares of Common Stock, and are convertible at the option of
the holder at any time into shares of Common Stock, in each case as described
below. The number of shares of Common Stock a holder will receive upon
redemption, and the value of the shares received upon conversion, will vary
depending on the market price of the Common Stock at the time of redemption or
conversion, all as described herein.
Dividends on the DECS are cumulative at the annual rate of $ per share
and are payable quarterly in arrears on the first day of January, April, July
and October, commencing July 1, 1994. Each DECS has a liquidation preference
equal to the sum of (i) the per share price to public shown below and (ii) the
amount of accrued and unpaid dividends thereon to the date of liquidation,
dissolution or winding up.
The DECS are not redeemable by the Company prior to the Initial Redemption Date.
At any time and from time to time on or after the Initial Redemption Date and
prior to the Mandatory Conversion Date, the Company may redeem the outstanding
DECS, in whole or in part. Upon any such redemption, each holder of DECS will
receive, in exchange for each DECS so redeemed, shares of Common Stock having a
Current Market Price equal to the sum of (i) beginning on the Initial Redemption
Date, $ , and declining thereafter on the schedule set forth herein to
$ per share on January 1, 1998 and (ii) all accrued and unpaid dividends
thereon (the "Call Price"). See "Description of the DECS."
The DECS are convertible at the option of the holder, at any time prior to the
Mandatory Conversion Date, into shares of Common Stock for each DECS
(equivalent to a conversion price of $ per share of Common Stock (the
"Conversion Price")), subject to adjustment upon certain events.
The opportunity for equity appreciation afforded by an investment in the DECS is
less than the opportunity for equity appreciation afforded by an investment in
the Common Stock because the Company may, at its option, redeem the DECS at any
time on or after the Initial Redemption Date and prior to the Mandatory
Conversion Date, and may be expected to do so if, prior to the Mandatory
Conversion Date, the current market price of the Common Stock exceeds the
Conversion Price. In such event, holders of the DECS will receive less than one
share of Common Stock for each DECS. However, because holders of DECS called for
redemption will have the option to surrender DECS for conversion at the
Conversion Price up to the close of business on the redemption date (and may be
expected to do so if the market price of the Common Stock exceeds the Conversion
Price), a holder that elects to convert will receive shares of Common Stock
for each DECS. Because the price of Common Stock is subject to market
fluctuations, the value of the Common Stock received by an owner of DECS upon
mandatory conversion of the DECS may be more or less than the amount paid for
the DECS offered hereby.
The offering made hereby is part of a refinancing by the Company (the
"Refinancing"), consisting of this Offering and a concurrent offering (the
"Concurrent Debenture Offering") of $100 million of Senior Subordinated
Debentures Due 2004 (the "Debentures"). This Offering is not conditioned on the
Concurrent Debenture Offering, and the Concurrent Debenture Offering is not
conditioned on this Offering.
The Common Stock is listed on the New York Stock Exchange ("NYSE") under the
symbol SFR. On April 25, 1994, the last reported sale price of the Common Stock
on the NYSE was $8 7/8 per share. See "Price Range of Common Stock and
Dividends."
The DECS have been approved for listing on the NYSE under the symbol SFRPRA.
SEE "INVESTMENT CONSIDERATIONS" FOR A DISCUSSION OF CERTAIN FACTORS THAT SHOULD
BE CONSIDERED BY PROSPECTIVE INVESTORS BEFORE DECIDING TO INVEST IN THE DECS.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION PASSED UPON THE
ACCURACY OR ADEQUACY OF THIS PROSPECTUS. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
- --------------------------------------------------------------------------------
<TABLE>
<CAPTION>
PRICE TO UNDERWRITING PROCEEDS TO
PUBLIC(1) DISCOUNT COMPANY(1)(2)
<S> <C> <C> <C>
Per DECS............................................. $ $ $
Total(3)............................................. $ $ $
</TABLE>
- --------------------------------------------------------------------------------
(1) Plus accrued dividends, if any, from the date of original issuance.
(2) Before deducting expenses payable by the Company estimated to be $500,000.
(3) The Company has granted the Underwriters an option, exercisable within 30
days from the date hereof, to purchase up to an aggregate of 1,605,000
additional DECS at the Price to Public, less Underwriting Discount, for the
purpose of covering over-allotments, if any. If the Underwriters exercise
such option in full, the total Price to Public, Underwriting Discount, and
Proceeds to Company will be $ , $ , and $ ,
respectively. See "Underwriting."
The DECS are offered subject to receipt and acceptance by the Underwriters, to
prior sale and to the Underwriters' right to reject any order in whole or in
part and to withdraw, cancel or modify the offer without notice. It is expected
that delivery of the DECS will be made at the office of Salomon Brothers Inc,
Seven World Trade Center, New York, New York, or through the facilities of The
Depository Trust Company, on or about May , 1994.
SALOMON BROTHERS INC
LAZARD FRERES & CO.
PAINEWEBBER INCORPORATED
The date of this Prospectus is May , 1994.
<PAGE> 108
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS THAT STABILIZE OR MAINTAIN THE MARKET PRICE OF THE DECS AND THE
COMMON STOCK AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE OR
OTHERWISE. SUCH TRANSACTIONS, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended, and the rules and regulations promulgated
thereunder (the "Exchange Act") and, in accordance therewith, files reports,
proxy statements and other information with the Securities and Exchange
Commission (the "Commission"). Reports, proxy statements and other information
filed by the Company with the Commission may be inspected and copied at the
public reference facilities maintained by the Commission at Room 1024, 450 Fifth
Street, N.W., Judiciary Plaza, Washington, D.C. 20549-1004, and at the following
Regional Offices of the Commission: Chicago Regional Office, CitiCorp Center,
500 West Madison Street, Suite 1400, Chicago, Illinois 60621 2511; and New York
Regional Office, 7 World Trade Center, 13th Floor, New York, New York 10048.
Copies of such material may also be obtained at prescribed rates from the Public
Reference Section of the Commission at its principal office at 450 Fifth Street,
N.W., Judiciary Plaza, Washington, D.C. 20549-1004. The Company's Common Stock
and its Convertible Preferred Stock, Series 7%, are listed for trading on the
NYSE. The Company's registration statements, reports, proxy statements and other
information may also be inspected at the offices of the NYSE, 20 Broad Street,
New York, New York 10005.
DOCUMENTS INCORPORATED BY REFERENCE
The following documents heretofore filed by the Company with the Commission
pursuant to Section 13 of the Exchange Act are incorporated herein by reference:
(i) the Company's Annual Report on Form 10-K for the year ended December 31,
1993; (ii) the Company's Current Report on Form 8-K dated February 8, 1994; and
(iii) the description of the Common Stock contained in the Company's
Registration Statement on Form 8-A (File No. 1-7667) filed on February 21, 1990.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of the offering of the Debentures shall be deemed to be
incorporated by reference into this Prospectus and to be a part hereof from the
date of filing of such documents. Any statement contained in a document
incorporated or deemed to be incorporated by reference herein shall be deemed to
be modified or superseded for purposes of this Prospectus to the extent that a
statement contained herein or in any other subsequently filed document which
also is or is deemed to be incorporated by reference herein modifies or
supersedes such statement. Any such statement so modified or superseded shall
not be deemed, except as so modified or superseded, to constitute a part of this
Prospectus.
Any person receiving a copy of this Prospectus may obtain without charge,
upon written or oral request, a copy of any of the documents incorporated by
reference herein, except for the exhibits to such documents (unless such
exhibits are specifically incorporated by reference into such documents).
Requests should be addressed to Mark A. Older, Senior Counsel and Secretary,
Santa Fe Energy Resources, Inc., 1616 South Voss Road, Suite 1000, Houston,
Texas 77057 (telephone (713) 783 2401).
CERTAIN DEFINITIONS
As used herein, the following terms have the specific meanings set out:
"Bbl" means barrel, "MBbl" means thousand barrels, "MMBbl" means million
barrels, "Mcf" means thousand cubic feet, "MMcf" means million cubic feet, "Bcf"
means billion cubic feet, "BOE" means barrel of oil equivalent, "MBOE" means
thousand barrels of oil equivalent and "MMBOE" means million barrels of oil
equivalent. 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. Unless otherwise
indicated in this Prospectus, natural gas volumes are stated at the official
temperature and pressure bases of the area in which the reserves are located.
"Finding cost" refers to a fraction, of which the numerator is equal to the
costs incurred by the Company for property acquisition, exploration and
development and of which the denominator is equal to proved reserve additions
from extensions, discoveries, improved recovery, acquisitions and revisions of
previous estimates. "Improved recovery," "enhanced oil recovery" and "EOR"
include all methods of supplementing natural reservoir forces and energy, or
otherwise increasing ultimate recovery from a reservoir, such as waterfloods,
cyclic steam, steam drive and CO2 (carbon dioxide) injection and fireflood
projects. "Heavy oil" is low gravity, high viscosity crude oil.
2
<PAGE> 109
PROSPECTUS SUMMARY
The following information is a summary of the more detailed information and
financial statements appearing elsewhere or incorporated by reference in this
Prospectus and is qualified in its entirety by reference thereto. Unless
otherwise indicated or required by the context, references to "Santa Fe" and the
"Company" include its consolidated subsidiaries and the information set forth
herein assumes that the Underwriters' over-allotment option is not exercised.
THE COMPANY
GENERAL
Santa Fe Energy Resources, Inc. ("Santa Fe" or the "Company") is engaged in
the exploration, development and production of oil and natural gas in the
continental United States and in certain foreign areas. At December 31, 1993,
the Company had estimated worldwide proved reserves of oil and natural gas
totaling 292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and
approximately 263.0 Bcf of natural gas), of which approximately 93% were
domestic reserves and approximately 7% were foreign reserves. During 1993, the
Company's worldwide production aggregated approximately 94.3 MBOE per day, of
which approximately 71% was crude oil and approximately 29% was natural gas. A
substantial portion of the Company's domestic oil production is in long-lived
fields with well-established production histories. Pursuant to the Company's
corporate restructuring program, the Company has focused its activities on its
three domestic core areas--the Permian Basin in Texas and New Mexico, the
offshore Gulf of Mexico and the San Joaquin Valley of California--as well as in
Argentina and Indonesia.
For the five years ended December 31, 1993, the Company has replaced 172%
of its production at an average finding cost of $4.80 per BOE. Over the last
four years, the Company has increased overall production by increasing
production from existing properties and through acquisitions. In addition, the
Company has reduced its overall cost structure. For example, over the four-year
period ended December 31, 1993, Santa Fe has increased its average daily
production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993
attributable to production from non-core assets sold pursuant to the corporate
restructuring program) and has reduced its average production costs (including
related production, severance and ad valorem taxes) from $6.22 per BOE in 1990
to $5.39 per BOE in 1993.
CORPORATE RESTRUCTURING PROGRAM
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program designed to improve its earnings and cash flow while
increasing production and replacing reserves in the long-term. The restructuring
program is the result of an intensive review of the Company's operations and
cost structure and focuses on the concentration of capital spending in the
Company's core operating areas and the disposition of non-core assets. The
restructuring program also includes an evaluation of the Company's capital and
cost structures in an effort to identify and implement ways to increase
flexibility and strengthen the Company's financial performance.
The Company's capital program will be concentrated in its three domestic
core areas, as well as in its productive areas in Argentina and Indonesia. In
October 1993, Sante Fe announced that its 1994 capital expenditures could
increase to up to $240 million. However, as a result of the depressed crude oil
prices that have prevailed since November 1993, the Company, consistent with
industry practice, has determined to defer certain of its capital projects in
order to prudently manage available cash flow in the near term. Based on current
market conditions, the Company has authorized up to $130 million of capital
expenditures during 1994, a level which should allow the Company to replace its
estimated 1994 production, although no assurance can be given regarding such
replacement. The Company intends to continue to monitor its capital expenditure
program throughout the balance of 1994 and may, in response to industry
conditions, including, without limitation, prevailing oil and natural gas prices
and the outlook therefor, revise such program.
The non-core asset dispositions identified by the Company's restructuring
program included the sale of its natural gas gathering and processing assets for
securities as well as the sales of non-core oil and
3
<PAGE> 110
gas properties consisting of approximately 16.7 MMBOE of estimated proved
reserves and undeveloped leasehold acreage for approximately $91.4 million. In
addition, during the first quarter of 1994, the Company sold its remaining
interest in the Santa Fe Energy Trust for $11.3 million and its interest in
certain oil and gas properties for $8.3 million. As a result of these
transactions, the Company has disposed of substantially all of its inventory of
non-core assets.
Based on a review of its capital structure, the Company determined to
proceed with a refinancing of certain of the Company's indebtedness (the
"Refinancing") in the belief that it would increase the Company's financial
flexibility, strengthen the Company's financial position and permit the Company
to pursue aggressively its operating strategy. See "--Financial Strategy." The
evaluation of the Company's cost structure resulted in the announcement on April
25, 1994 of the implementation of a cost reduction program designed to reduce
the Company's expenses by approximately $30.0 million from the 1993 level (which
reduction includes approximately $5.0 million of non-recurring costs).
Substantially all of this cost reduction program is expected to be implemented
by year end 1994.
As part of its restructuring program the Company adopted the following
operating, financial and cost reduction strategies that should position it to
continue to efficiently replace its production and increase its reserves even in
a low oil price environment.
OPERATING STRATEGY
Santa Fe's operating strategy is designed to replace reserves and increase
its production in a cost effective manner by (i) exploiting its inventory of
lower risk, higher return projects in its domestic core areas, (ii) increasing
its light crude oil and natural gas reserves and production, and (iii)
increasing its international operations.
Develop Domestic Properties in Core Areas. A principal focus of the
Company's corporate restructuring program is the concentration of capital
spending in the Company's core domestic areas-- the Permian Basin of Texas and
New Mexico, the offshore Gulf of Mexico and the San Joaquin Valley of
California. In these areas, the Company has identified a significant number of
attractive development opportunities. Selection and timing of projects will
depend upon factors such as oil and natural gas prices and availability of
funds. In southeastern New Mexico, the Company has targeted for accelerated
development a light oil prospect in the Delaware formation and a light oil and
gas project in the Cisco-Canyon zone. The Company has conducted extensive
operations in these areas and has identified in excess of 150 development well
locations and 20 exploratory prospects to be drilled over the next several
years. During 1993, several new fields or field additions in the Offshore Gulf
of Mexico area were placed on production, and the Company expects to further
develop identified prospects in 1994. In the San Joaquin Valley, reservoir
engineering studies prepared on behalf of the Company indicate that significant
additions to proved reserves can be made through additional EOR and development
projects in several of the Company's long-lived fields with well-established
production histories.
Increase Light Crude Oil and Natural Gas. A substantial part of the
Company's domestic oil reserves consists of "heavy" oil, which is generally more
expensive to produce than, and sells at a significant discount to, lighter crude
oils such as the benchmark West Texas Intermediate. See "Investment
Considerations--Effects of Heavy Oil Production" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations--General." One of
the principal components of the Company's strategy is to reduce the proportion
of heavy oil in its reserves by increasing its lighter crude oil and natural gas
reserves, primarily through development drilling of its existing project
inventory (such as the Permian Basin and offshore Gulf of Mexico, as discussed
above) and selective acquisitions. The acquisition of Adobe Resources
Corporation ("Adobe")in May 1992 added significantly to the Company's lighter
crude oil and natural gas reserves.
Increase International Operations. The Company is actively engaged in
exploration and development activities in two foreign areas, Argentina and
Indonesia. The Company believes that it can continue to identify and pursue
other projects with the potential for increased reserves and production in these
and possibly other foreign areas. Revenues from sales of oil and gas production
in these areas have increased from approximately $3.7 million in 1991 to $35.6
million in 1993, with average daily production volumes
4
<PAGE> 111
from these areas increasing from 0.6 MBOE per day in 1991 to 6.5 MBOE per day in
1993. The Company made a significant exploration discovery in 1993--the Sierra
Chata natural gas discovery in Argentina. To date, six gross (1.3 net) wells
have been drilled with no dry holes. In 1994, the Company plans additional
development drilling to further define the limits of the field, and to construct
a gas processing plant and a 40-mile pipeline. First sales of production from
this discovery are expected in early 1995.
FINANCIAL STRATEGY
The Company's financial strategy is to provide additional flexibility in
the current low oil price environment thereby allowing the Company to further
implement its operating strategy. This Offering is part of the Refinancing,
consisting of this Offering and the Concurrent Debenture Offering. The net
proceeds from the Refinancing will be utilized to repay a portion of the
Company's senior indebtedness (on a pro forma basis at December 31, 1993, an
aggregate of approximately $180 million of senior indebtedness would be repaid
with such net proceeds). See "Use of Proceeds."
Completion of the Refinancing will extend the average life of the Company's
debt from approximately 4.5 years to approximately 7.5 years, reduce the
Company's overall leverage and reduce required debt amortization in 1994, 1995
and 1996 to $3.8 million, $5.2 million and $9.6 million, respectively (on a pro
forma basis at December 31, 1993). The Refinancing will also provide additional
liquidity by increasing the total amount available for borrowing under the
Company's existing bank credit facilities and by increasing cash flow in the
near term.
COST REDUCTION STRATEGY
On April 25, 1994, the Company announced the implementation of a major cost
reduction program aimed at reducing its expenses by approximately $30.0 million
from the 1993 level (which reduction includes approximately $5.0 million of
non-recurring costs). The Company intends to reduce its field expenses by
approximately $10.0 million, reduce its salaried work force by approximately
20%, significantly improve the efficiency of its information systems activities
and substantially reduce other general and administrative costs. Substantially
all of this cost reduction program is expected to be implemented by year end
1994. The Company recorded a $7.0 million charge during the quarter ended March
31, 1994 in connection with implementation of the cost reduction program. See
"--Recent Operating Results."
THE DECS OFFERING
<TABLE>
<S> <C>
Securities Offered............ 10,700,000 shares (12,305,000 shares if the Underwriters'
over-allotment option is exercised in full) of Series A
Convertible Preferred Stock, referred to as Dividend
Enhanced Convertible Stock (the "DECS").
Securities.................... The DECS are shares of convertible preferred stock and rank
prior to the Common Stock both as to payment of dividends
and distribution of assets upon liquidation. Each
outstanding DECS mandatorily converts into one share of
Common Stock on March 31, 1998 (the "Mandatory Conversion
Date"), and the Company has the option to redeem the shares
of DECS, in whole or in part, at any time and from time to
time on or after March 31, 1997 (the "Initial Redemption
Date") and prior to the Mandatory Conversion Date at the
Call Price (as defined herein), payable in shares of Common
Stock. In addition, each DECS is convertible into
shares of Common Stock at the option of the holder at any
time prior to the Mandatory Conversion Date as set forth
below.
Dividends..................... The holders of DECS are entitled to receive, when, as and if
dividends are declared by the Board of Directors of the
Company out of funds legally available therefor, cumulative
preferential dividends from the issue date of the DECS,
accruing at the rate per share of $ per annum
($ per quarter) for each DECS, payable quarterly in
arrears on the first day of each January, April, July and
October or, if any such date is not a business day, on the
next
</TABLE>
5
<PAGE> 112
<TABLE>
<S> <C>
succeeding business day. The first dividend payment will be
for the period from the issue date of the DECS to and
including June 30, 1994 and will be payable on July 1, 1994.
Dividends are payable in cash except in connection with
certain redemptions by the Company. Accumulated and unpaid
dividends will not bear interest. See "Description of the
DECS--Dividends."
Mandatory Conversion of
DECS.......................... On the Mandatory Conversion Date, each outstanding DECS will
convert (the "Mandatory Conversion") automatically into
shares of Common Stock at the Common Equivalent Rate and the
right to receive an amount of cash equal to all accrued and
unpaid dividends on such DECS (other than dividends payable
to a holder of record on a prior date). The "Common
Equivalent Rate" is initially one share of Common Stock for
each DECS, subject to adjustment in the event of certain
stock dividends or distributions, subdivisions, splits,
combinations, issuances of certain rights or warrants or
distributions of certain assets with respect to the Common
Stock. The Mandatory Conversion is, however, subject to the
Company's right to redeem all or a portion of the
outstanding DECS on or after the Initial Redemption Date and
prior to the Mandatory Conversion Date, and to the
conversion of the DECS at the option of the holder at any
time prior to the Mandatory Conversion Date. See
"--Description of the DECS--Right to Redeem DECS" and
"Description of the DECS-- Mandatory Conversion of DECS."
Because the price of the Common Stock is subject to market
fluctuations, the value of the Common Stock received upon
Mandatory Conversion of the DECS may be more or less than
the amount paid for the DECS offered hereby.
Right to Redeem DECS.......... The DECS are not redeemable by the Company prior to the
Initial Redemption Date. At any time or from time to time on
or after the Initial Redemption Date and prior to the
Mandatory Conversion Date, the Company may redeem the
outstanding DECS, in whole or in part. Upon any such
redemption, each holder of DECS will receive, in exchange
for each DECS so called, a number of shares of Common Stock
equal to the Call Price of the DECS in effect on the date of
redemption divided by the Current Market Price of the Common
Stock determined as of the date which is one trading day
prior to the public announcement of the call for redemption.
The "Call Price" of each DECS is the sum of (i) $ on
and after the Initial Redemption Date through June 30, 1997,
$ on and after July 1, 1997 through September 30,
1997, $ on and after October 1, 1997 through December
31, 1997, $ on and after January 1, 1998 until the
Mandatory Conversion Date, and (ii) all accrued and unpaid
dividends thereon to the date fixed for redemption (other
than dividends payable to a holder of record as of a prior
date). The number of shares of Common Stock to be delivered
in payment of the applicable Call Price will be based upon
the current market price of the Common Stock prior to the
announcement of the redemption, and the market price of the
Common Stock may vary between the date of such determination
and the subsequent delivery of such shares. See "Description
of the DECS--Right to Redeem DECS."
Conversion at Option of
Holder........................ The DECS are convertible, in whole or in part, at the option
of the holder at any time prior to the Mandatory Conversion
Date, unless previously redeemed, into shares of Common
Stock for each DECS (equivalent to a Conversion Price of
$ per share of Common Stock), subject to adjustment in
the event of certain stock dividends or distributions,
subdivisions, splits, combinations, issuances of certain
rights or warrants or distributions of certain assets with
respect to the Common Stock. The right of holders to convert
DECS called for redemption will terminate immediately prior
</TABLE>
6
<PAGE> 113
<TABLE>
<S> <C>
Enhanced Dividend Yield; Less
Equity Appreciation Than Com-
mon Stock..................... No dividends are currently paid on the Common Stock. The
opportunity for equity appreciation afforded by an
investment in the DECS is less than that afforded by an
investment in the Common Stock because the Conversion Price
is higher than the per share price to public of the DECS and
the Company may, at its option, redeem the DECS at any time
on or after the Initial Redemption Date, and prior to the
Mandatory Conversion Date, and may be expected to do so, if,
among other circumstances, the applicable Current Market
Price of the Common Stock exceeds the Call Price. In such
event, a holder of a DECS will receive less than one share
of Common Stock, but in no event less than shares of
Common Stock. A holder may also surrender for conversion any
DECS called for redemption up to the close of business on
the redemption date, and a holder that so elects to convert
will receive shares of Common Stock per DECS. The value
of Common Stock received by a holder of a DECS may be more
or less than the per share amount paid for the DECS offered
hereby, due to market fluctuations in the price of Common
Stock. See "Description of the DECS--Mandatory Conversion of
DECS" and "--Right to Redeem DECS."
Liquidation Preference........ The DECS rank senior to the Common Stock upon liquidation
and pari passu with the Company's outstanding shares of
Convertible Preferred Stock, Series 7% (of which 5,000,000
shares are outstanding with a liquidation preference of
$20.00 per share plus accrued and unpaid dividends thereon).
The liquidation preference of each of the DECS will be in an
amount equal to the sum of (i) the per share price to the
public shown on the cover page hereof and (ii) all accrued
and unpaid dividends thereon to the date of liquidation,
dissolution or winding up.
Voting Rights................. The holders of DECS shall have the right with the holders of
Common Stock to vote in the election of directors and upon
each other matter coming before any meeting of the
stockholders on the basis of 4/5 votes for each DECS held;
the holders of DECS and the holders of Common Stock will
vote together as one class. In addition, (i) whenever
dividends on the DECS shall be in arrears and unpaid in an
aggregate amount of dividends payable thereon for four quar-
terly dividend periods, the holders of the DECS (voting
separately as a class with holders of shares of Convertible
Preferred Stock, Series 7%, and shares of all other series
of Preferred Stock, if any, upon which like voting rights
have been conferred and are exercisable) will be entitled to
vote for the election of two directors of the Company, such
directors to be in addition to the number of directors
constituting the Board of Directors immediately prior to the
accrual of such right, and (ii) the holders of the DECS will
have voting rights with respect to certain alterations of
the Company's Restated Certificate of Incorporation. See
"Description of the DECS--Voting Rights."
Use of Proceeds............... The net proceeds to the Company from the sale of the DECS
offered hereby are estimated to be $91.6 million. Such net
proceeds will be used to repay certain of the Company's
senior indebtedness. See "Use of Proceeds."
Listing....................... The DECS have been approved for listing on the NYSE under
the symbol SFRPRA.
</TABLE>
7
<PAGE> 114
SUMMARY FINANCIAL INFORMATION
The following table presents summary historical financial information for
the periods presented and should be read in conjunction with the historical
consolidated financial statements, including the notes thereto, and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations." The following table also presents summary pro forma financial
information as of and for the year ended December 31, 1993 after giving effect
to the consummation of this Offering and the Concurrent Debenture Offering and
the application of the estimated net proceeds therefrom as described in "Use of
Proceeds." The summary pro forma financial information is unaudited.
<TABLE>
<CAPTION>
PRO YEAR ENDED DECEMBER 31,
FORMA ---------------------------------------------------------
1993(A) 1993 1992 1991 1990 1989
-------- -------- -------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues.................... $ 436.9 $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9
Production and operating
expenses................. 163.8 163.8 153.4 134.6 135.5 107.1
Exploration expenses........ 31.0 31.0 25.5 18.7 21.0 19.4
General and
administrative........... 32.3 32.3 30.9 27.8 25.6 28.6
Depreciation, depletion and
amortization............. 152.7 152.7 146.3 106.6 105.2 99.4
Impairment of oil and gas
properties............... 99.3(b) 99.3(b) -- -- 1.4 1.1
Restructuring charges....... 38.6(c) 38.6(c) -- -- -- --
Income (loss) from
operations............... (113.0) (113.0) 57.5 64.4 69.4 45.5
Interest expense(d)......... 40.7 45.8 55.6 47.3 57.1 30.5
Net income (loss)........... (73.9) (77.1) (1.4) 18.5 17.0 49.8
Earnings (Loss) to Common
Stock.................... (87.3) (84.1) (5.7) 18.5 17.0 49.8
Earnings (loss) per share of
Common Stock............. $ (0.97) $ (0.94) $ (0.07) $ 0.29 $ 0.28 --
CASH FLOW DATA:
Net cash provided by
operating activities..... $ 154.3 $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1
Capital expenditures........ 127.0 127.0 76.8 108.1 117.0 93.7
Preferred dividends......... 13.4 7.0 2.6 -- -- --
Common stock dividends(e)... 14.3 14.3 12.3 10.2 5.1 --
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA (AT END OF
PERIOD):
Properties and equipment,
net...................... $ 832.7 $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6
Total assets................ 1,079.0 1,076.9 1,337.2 911.9 911.1 881.8
Long-term debt.............. 365.9 405.4 492.8 440.8 417.2 124.7
Convertible Preferred Stock,
Series 7%................ 80.0 80.0 80.0 -- -- --
Shareholders' equity........ 414.8 323.6 416.6 225.1 215.8 228.1
</TABLE>
8
<PAGE> 115
<TABLE>
<CAPTION>
PRO YEAR ENDED DECEMBER 31,
FORMA -------------------------------------------------------
1993(A) 1993 1992 1991 1990 1989
------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
OTHER DATA:
EBITDA (in millions)(f).......... $ 174.9 $ 174.9 $ 183.6 $ 173.3 $ 186.1 $ 153.8
EBITDA/Interest expense.......... 4.3x 3.8x 3.3x 3.7x 3.3x 5.0x
EBITDA/Preferred dividends and
interest expense.............. 3.2x 3.3x 3.1x 3.7x 3.3x 5.0x
Ratio of earnings to combined
fixed charges and preferred
dividends(g).................. (h) (h) (h) 1.5x 1.3x 2.2x
</TABLE>
- ---------------
(a) Pro forma for the consummation of this Offering and the Concurrent
Debenture Offering and the application of the net proceeds therefrom as
described under "Use of Proceeds." Assumes 10,700,000 DECS are sold at a
price of $8 7/8 per share.
(b) Reflects a non-cash charge of $99.3 million for the impairment of oil and
gas properties recorded as of December 31, 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and Note 1 of the Notes to the Company's Consolidated Financial Statements
included elsewhere in this Prospectus.
(c) Reflects a non-cash, non-recurring charge of $38.6 million recorded in 1993
in conjunction with the implementation of the Company's restructuring
program, comprised of (i) losses on property dispositions of $27.8 million;
(ii) long-term debt prepayment penalties of $8.6 million; and (iii)
accruals for certain personnel benefits and related costs of $2.2 million.
See "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 2 of the Notes to the Company's
Consolidated Financial Statements included elsewhere in this Prospectus.
(d) Includes capitalized interest of $4.3 million, $4.9 million, $7.7 million,
$10.6 million and $13.8 million for 1993, 1992, 1991, 1990 and 1989,
respectively.
(e) Represents dividends paid subsequent to the Company's initial public
offering in March 1990. Prior to such time, the Company was a wholly owned
subsidiary of the Santa Fe Pacific Corporation, and dividends paid to its
parent are not considered relevant in the context of its dividend policy
subsequent to the initial public offering. As part of the Company's 1993
restructuring program, in October 1993, the Company eliminated its $0.04
per share quarterly dividend on Common Stock. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
(f) EBITDA is presented because it is a widely accepted financial indication of
a company's ability to service and incur debt and preferred stock
dividends. EBITDA is defined as income before taxes, interest expense
(including capitalized interest but excluding long-term debt prepayment
penalties), depletion, depreciation, amortization and other non-cash
charges. EBITDA should not be considered by an investor as an alternative
to earnings (loss) as an indicator of the Company's operating performance
or to cash flows as a measure of liquidity. EBITDA for the Company largely
results from sales of oil and gas produced from the Company's properties,
which production, if not replaced, will result in depletion of the
Company's assets and a reduction of the Company's ability to service and
incur debt at constant or reducing prices. The calculation of EBITDA for
1993 reflects an average sales price (unhedged) by the Company of $12.93
per barrel of oil. For the three months ended March 31, 1994, the average
sales price (unhedged) for the Company's 1994 oil production was $10.00 per
barrel. If such lower oil prices prevail throughout 1994, the Company's
EBITDA for 1994 will be significantly lower than that for 1993. See
"--Recent Operating Results."
(g) For the purpose of calculating such ratios, (i) earnings consist of income
(loss) before income taxes plus fixed charges and (ii) fixed charges
consist of interest expense (including amortization of deferred debt
issuance costs) and the amount of pre-tax earnings required to cover
preferred stock dividend requirements.
(h) Earnings for the years ended December 31, 1993 and 1992 were insufficient
to cover combined fixed charges and preferred dividends by $166.0 million
and $12.8 million, respectively. Pro forma earnings for the year ended
December 31, 1993, after giving effect to the consummation of this
Offering and the Concurrent DECS Offering and the application of the
estimated net proceeds therefrom as described in "Use of Proceeds," would
have been insufficient to cover fixed charges by $171.4 million.
9
<PAGE> 116
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------------
1993 1992 1991 1990 1989
------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Production of oil (MBbls per day)(a)........ 66.7(d) 62.5 55.5 52.0 50.7
Production of natural gas (MMcf per
day)(a)................................... 165.4(d) 126.3 95.2 102.5 81.6
Production of oil equivalent
(MBOE per day)(a)......................... 94.3(d) 83.6 71.4 69.1 64.3
Average sales price:
Oil (per Bbl).......................... $ 12.93 $ 14.54 $ 14.09 $ 17.90 $ 14.11
Natural gas (per Mcf).................. $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72
Production costs (including related
production, severance and ad valorem
taxes) per BOE............................ $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69
Five-year average finding cost per BOE(b)... $ 4.80 $ 4.05 $ 3.66 $ 3.73 $ 4.31
Annual reserve replacement ratio(c)......... 121% 262% 127% 108% 251%
Estimated reserve life(in years)............ 8.5(d) 9.9 9.9 10.0 10.7
</TABLE>
- ---------------
(a) Includes production attributable to certain net profits interests sold by
the Company to unaffiliated persons, which interests burden the Company's
working or royalty interests held in certain properties.
(b) Reflects the average finding cost per BOE during the five years ended
December 31 as of the year reflected in the column.
(c) The annual reserve replacement ratio is a fraction, of which the numerator
is the estimated number of reserves added during a year through additions
of estimated proved reserves from exploratory and development drilling,
acquisitions of proved properties and revisions of previous estimates,
excluding property sales, and of which the denominator is the oil and
natural gas produced during that year.
(d) Includes production attributable to the properties sold to Vintage
Petroleum, Inc. ("Vintage") (closed in November 1993) and Bridge Oil
(U.S.A.) Inc. ("Bridge") (closed in April 1994). Production attributable to
such properties during 1993 totaled approximately 4.1 MBbls of oil and 21.7
MMcf of natural gas per day (7.7 MBOE per day).
RECENT OPERATING RESULTS
For the three months ended March 31, 1994, the Company reported a net loss
to common shares of $4.3 million, or $0.05 per share, compared to a net loss to
common shares of $2.2 million, or $0.02 per share, in the same period in 1993.
Revenues for the first quarter of 1994 totaled $90.3 million compared to $115.3
million in the same period in 1993. The decline in revenues primarily reflects a
$3.73 per barrel decline in the Company's average sales price for its crude oil
and liquids as compared to its average sales price for the first quarter of
1993. Revenues from the properties sold to Vintage included in the 1993 period
totaled $5.4 million. The Company's costs and expenses totaled $90.3 million in
the first quarter of 1994 compared to $103.3 million in the first quarter of
1993. Lower production and operating costs (down $2.1 million, primarily
reflecting the effect of the Vintage sale), exploration expenses (down $2.1
million) and depreciation, depletion and amortization ("DD&A") expense (down
$5.6 million, primarily reflecting the effect of impairments taken in the fourth
quarter of 1993) and the recognition of a $9.4 million gain from the disposition
of oil and gas properties were the principal factors in the reduction in costs
and expenses. Costs and expenses for the first quarter of 1994 include $7.0
million in restructuring charges related to the Company's cost reduction
program. The restructuring charges, designed to reduce expenses by approximately
$30.0 million from the 1993 level (which reduction includes approximately $5.0
million of non-recurring costs), relate to severance, benefits and relocation
expenses associated with a cost reduction program that includes a 20% reduction
in the Company's work force, a reduction in other general and administrative
expenses and a $10.0 million reduction in field expenses. Substantially all of
this program is expected to be implemented by year end 1994. Net cash provided
by operating activities declined from $41.6 million in the first quarter of 1993
to $14.3 million in the first quarter of 1994, primarily reflecting the factors
described above.
The Company's production during the first quarter of 1994 totaled 5.9
MMBbls of crude oil and liquids and 14.0 Bcf of natural gas compared to 6.0
MMBbls of crude oil and liquids and 16.0 Bcf of
10
<PAGE> 117
natural gas in the first quarter of 1993. Natural gas production for the first
quarter of 1993 included a 1.5 Bcf positive adjustment attributable to prior
periods. Crude oil and liquids sales prices (unhedged) averaged $10.00 per
barrel in the first quarter of 1994 compared to $13.73 per barrel in the first
quarter of 1993. Natural gas sales prices (unhedged) averaged $2.10 per Mcf in
the first quarter of 1994 compared to $1.96 per Mcf in the first quarter of
1993.
SUMMARY OIL AND GAS RESERVE INFORMATION
The following table sets forth summary information with respect to the
Company's proved oil and gas reserves as of the dates indicated. For additional
information relating to reserves, see "Business and Properties--Reserves."
<TABLE>
<CAPTION>
NET PROVED RESERVES AS OF DECEMBER 31,(A)
------------------------------------------------------------
1993(B) 1992 1991 1990 1989
---------- ------- ------- -------- --------
<S> <C> <C> <C> <C> <C>
Crude oil, condensate and natural gas
liquids (MMBbls).................... 248.2 255.1 229.2 222.3 219.8
Natural gas (Bcf)..................... 263.0 277.5 170.8 185.9 188.0
Proved reserves (MMBOE)............... 292.0 301.5 257.7 253.3 251.1
Proved developed reserves (MMBOE)..... 225.5 248.4 210.3 205.0 204.0
Present value pre-tax future net cash
flows (in millions)(c).............. $ 567.8 $ 915.2 $ 602.6 $1,231.4 $1,090.1
</TABLE>
- ---------------
(a) Includes estimated proved reserves attributable to certain net profits
interests sold by the Company to unaffiliated persons, which interests
burden the Company's working or royalty interests held in certain
properties.
(b) The estimates set forth in this table for 1993 give effect to the sale by
the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which
sale closed in April 1994.
(c) Represents the present value (discounted at 10%) of the future net cash
flows estimated to result from production of the Company's estimated proved
reserves using estimated sales prices and estimates of production costs, ad
valorem and production taxes and future development costs necessary to
produce such reserves. The sales prices used in the determination of proved
reserves and of estimated future net cash flows are based on the prices in
effect at year end, and for 1993 averaged $9.27 per barrel for oil and
$2.17 per Mcf for natural gas. The average sales prices (unhedged) realized
by the Company for its production during 1993 was $12.93 per barrel for oil
and $2.03 per Mcf for natural gas. The average sales prices (unhedged)
realized by the Company for its production during the three months ended
March 31, 1994 were $10.00 per barrel of oil and $2.10 per Mcf of natural
gas. See "--Recent Operating Results."
11
<PAGE> 118
INVESTMENT CONSIDERATIONS
Before deciding to invest in the shares of DECS offered hereby, prospective
investors should carefully consider all of the information contained in this
Prospectus, and in particular the investment considerations described in the
following paragraphs.
EFFECTS OF CHANGING PRODUCT PRICES
The Company's profitability is determined in large part by the difference
between the prices received for the oil and natural gas that it produces and the
costs of finding and producing such resources. Prices for oil and gas have been
subject to wide fluctuations, which continue to reflect imbalances in supply and
demand as well as other market conditions and the world political situation as
it affects OPEC, the Middle East (including the current embargo of Iraqi crude
oil from worldwide markets) and other producing countries. Moreover, the price
of oil and natural gas may be affected by the price and availability of
alternative sources of energy, weather conditions and the general state of the
economy. Even relatively modest changes in oil and gas prices may significantly
change the Company's revenues, results of operations, cash flows and proved
reserves. Since the Company is primarily an oil producer, a change in the price
paid for its oil production more significantly affects its results of operations
than a change in natural gas prices. For example, the Company estimates that a
change of $1.00 per barrel in its average realized oil price would have resulted
in a change of $21.6 million in its 1993 operating income and $16.2 million in
its 1993 cash flow from operating activities, based on its 1993 operating
results. The foregoing estimates do not give effect to changes in any other
factors, such as the effect of the Company's hedging program or depreciation and
depletion, that would result from a change in oil prices. In recent months, spot
oil prices have reached their lowest levels in over five years, and no assurance
can be given that oil prices will not remain at these levels for the foreseeable
future or decline further.
The Company's cash flow from operating activities is a function of the
volumes of oil and gas produced from the Company's properties and the sales
prices realized therefor. Crude oil and natural gas are depleting assets.
Therefore, unless the Company replaces over the long term the oil and natural
gas produced from the Company's properties, the Company's assets will be
depleted over time and its ability to service and incur debt at constant or
declining prices will be reduced. The Company's cash flow from operations for
1993 reflects an average sales price (unhedged) for the Company's 1993 oil
production of $12.93 per barrel. For the three months ended March 31, 1994, the
average sales price (unhedged) for the Company's 1994 oil production was $10.00
per barrel. If such lower oil prices prevail throughout 1994, the Company's cash
flow from operating activities for 1994 will be significantly lower than that
for 1993.
EFFECTS OF HEAVY OIL PRODUCTION
A substantial portion of the Company's oil production consists of heavy oil
produced from the Midway-Sunset Field. The market for such heavy crude oil
production differs substantially from the remainder of the domestic crude oil
market, due principally to the higher transportation and refining costs
associated with heavy crude. As a result, the profit margin realized from the
sale of heavy oil is generally lower than that realized from the sale of light
oil, because the costs to produce heavy oil are generally higher, and the price
paid for heavy crude oil is generally lower, than the price paid for light
crudes. Furthermore, there is currently an oversupply of crude oil in the
California market that has had an adverse effect on the prices paid for crude
oil in that market. See "Business and Properties--Current Markets for Oil and
Gas."
DIVIDEND POLICY
Holders of the DECS will be entitled to receive cumulative preferential
dividends in the amount specified on the cover page of this Prospectus when, as
and if declared by the Board of Directors of the Company out of funds legally
available therefor. Certain of the Company's credit agreements, however,
restrict the payment of dividends to the holders of the Company's capital stock,
including the DECS. For
12
<PAGE> 119
a description of the aggregate amount that the Company could pay as a dividend
on its capital stock, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Liquidity and Capital Resources." In
addition, the terms of the Convertible Preferred Stock, Series 7%, restrict, and
the terms of the DECS will restrict, any dividend payment by the Company to
holders of Common Stock unless all dividends on the Convertible Preferred Stock,
Series 7%, and the DECS for all past quarterly dividend periods shall have been
paid, or declared and a sum sufficient for the payment thereof set apart. As
discussed in "Business and Properties--Corporate Restructuring Program," the
Company has eliminated the payment of its $0.04 per share quarterly dividend on
its Common Stock. The determination of the amount of future cash dividends, if
any, to be declared and paid is in the sole discretion of the Company's Board of
Directors and will depend on dividend requirements with respect to the Company's
Convertible Preferred Stock, Series 7%, and, assuming consummation of this
Offering, the DECS, the Company's financial condition, earnings and funds from
operations, the level of its capital and exploration expenditures, dividend
restrictions in its financing agreements, its future business prospects and
other matters as the Company's Board of Directors deems relevant. Pro forma for
this Offering and the Concurrent Debenture Offering, at December 31, 1993 the
Company would have had the capacity to pay dividends of up to $122.8 million in
the aggregate on capital stock, including its Convertible Preferred Stock,
Series 7%, and the DECS. However, pursuant to the terms of the Debentures, and
upon completion of this Offering and the Concurrent Debenture Offering, at
December 31, 1993 the Company would have had the ability to pay only up to $50.0
million on its Common Stock. The amount permitted under the Debentures to be
used to pay dividends will vary over time depending, among other things, on the
Company's earnings and any issuances of capital stock. The Debentures will not
restrict the Company from paying preferred dividends on the Convertible
Preferred Stock, Series 7%, or the DECS; however, payment of such preferred
dividends will reduce the Company's capacity under the Debentures to pay Common
Stock dividends.
POSSIBLE IMPAIRMENT OF OIL AND GAS PROPERTIES
The Company follows the successful efforts method of accounting for its oil
and gas exploration and production activities. Under this method, costs (both
tangible and intangible) of productive wells and development dry holes, as well
as the costs of prospective acreage, are capitalized. The costs of drilling and
equipping exploratory wells which do not result in proved reserves are expensed
upon the determination that the well does not justify commercial development.
Other exploratory costs, including geological and geophysical costs and delay
rentals, are charged to expense as incurred.
The Company periodically reviews individual proved properties to determine
if the carrying value of the field as reflected in its accounting records
exceeds the estimated undiscounted future net revenues from proved oil and gas
reserves attributable to the field. Based on this review and the continuing
evaluation of development plans, economics and other factors, if appropriate,
the Company records impairments (additional depletion and depreciation) to the
extent that the carrying value exceeds the estimated undiscounted future net
revenues. Such impairments constitute a charge to earnings which does not impact
the Company's cash flow from operating activities. However, such writedowns
impact the amount of the Company's stockholders' equity and, therefore, the
ratio of debt-to-equity. The risk that the Company will be required to write
down the carrying value of its oil and natural gas properties increases when oil
and natural gas prices are depressed. In 1993, the Company recorded impairments
of $99.3 million. No assurance can be given that the Company will not experience
additional impairments in the future.
SUBSTANTIAL LEVERAGE
The Company is, and after the Refinancing will continue to be, highly
leveraged. At December 31, 1993, the Company had total indebtedness of $449.7
million and shareholders' equity of $323.6 million. After giving effect to the
Offering, the Concurrent Debenture Offering and the application of the estimated
net proceeds therefrom as described in "Use of Proceeds," the Company would have
had, on a pro forma basis at December 31, 1993, total indebtedness of $369.7
million and shareholders' equity of
13
<PAGE> 120
$414.8 million. If this Offering is completed but the Concurrent Debenture
Offering is not consummated, the Company's pro forma total indebtedness and
shareholders' equity at December 31, 1993 would have been $360.6 million and
$415.1 million, respectively. The Company's high degree of leverage will have
important consequences to holders of the DECS, including the following: (i) the
ability of the Company to obtain additional financing in the future for working
capital, acquisitions, capital expenditures and other general corporate purposes
may be impaired; (ii) a substantial portion of the Company's cash flow from
operations will be required to be dedicated to the payment of the Company's
interest expense and principal repayment obligations; (iii) the Company is more
highly leveraged than many of its competitors, which may place it at a
competitive disadvantage; and (iv) the Company's degree of leverage may make it
more vulnerable to a downturn in its business or the economy generally. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Liquidity and Capital Resources."
GOVERNMENTAL AND ENVIRONMENTAL REGULATION
The Company's activities are subject to various federal, state and local
laws and regulations covering the discharge of material into the environment or
otherwise relating to protection of the environment. In particular, the
Company's oil and gas exploration, development, production and EOR operations,
its activities in connection with storage and transportation of liquid
hydrocarbons and its use of facilities for treating, processing, recovering or
otherwise handling hydrocarbons and waste therefrom are subject to stringent
environmental regulation by governmental authorities. Such regulations have
increased the costs of planning, designing, drilling, installing, operating and
abandoning the Company's oil and gas wells and other facilities.
The Company has expended significant resources, both financial and
managerial, to comply with environmental regulations and permitting requirements
and anticipates that it will continue to do so in the future. Although the
Company believes that its operations and facilities are in general compliance
with applicable environmental regulations, risks of substantial costs and
liabilities are inherent in oil and gas operations, and there can be no
assurance that significant costs and liabilities will not be incurred in the
future. Moreover, it is possible that other developments, such as increasingly
strict environmental laws, regulations and enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in substantial costs and
liabilities in the future. See "Business and Properties--Other Business
Matters--Environmental Regulation."
UNCERTAINTIES IN ESTIMATES OF PROVED RESERVES
Proved reserves of crude oil and natural gas are estimated quantities that
geological and engineering data demonstrate with reasonable certainty to be
economically producible under existing conditions. There are numerous
uncertainties inherent in estimating quantities of proved reserves and in
projecting future rates of production and timing of development expenditures.
All reserve estimates are to some degree speculative and various classifications
of reserves only constitute attempts to define the degree of speculation
involved. The accuracy of any reserve estimate is a function of the quality of
available data and engineering and geological interpretation and judgment and
the assumptions used regarding prices for crude oil, natural gas liquids and
natural gas. Results of drilling, testing and production and changes in crude
oil, natural gas liquids and natural gas prices after the date of the estimate
may require substantial upward or downward revisions. Although a substantial
portion of the Company's proved oil reserves is in long-lived fields with
well-established production histories where EOR and other development projects
are employed to produce such reserves, the external factors discussed above will
directly affect the Company's determination to proceed with any of such projects
and, therefore, the quantity of reserves in these fields classified as proved.
The reserve estimates included and incorporated by reference in this Prospectus
were prepared as of December 31, 1993 and could be materially different from the
quantities of crude oil, natural gas liquids and natural gas that ultimately
will be recovered from the Company's properties.
14
<PAGE> 121
In addition, actual future net cash flows from production of the Company's
reserves will be affected by factors such as actual production, supply and
demand for oil and natural gas, curtailments or increases in consumption by
natural gas purchasers, changes in governmental regulations or taxation and the
impact of inflation on costs. The timing of actual future net revenue from
proved reserves, and thus their actual present value, can be affected by the
timing of the incurrence of expenditures in connection with development of oil
and gas properties. The 10% discount factor, which is required by the Commission
to be used to calculate present value for reporting purposes, is not necessarily
the most appropriate discount factor based on interest rates in effect from time
to time and risks associated with the oil and gas industry. Discounted present
value, no matter what discount rate is used, is materially affected by
assumptions as to the amount and timing of future production, which may and
often do prove to be inaccurate.
INDUSTRY CONSIDERATIONS
The Company's business is the exploration for, and the development and
production of, oil and natural gas. Exploration for oil and natural gas involves
many risks, which even a combination of experience, knowledge and careful
evaluation may not be able to overcome. In addition, there is strong competition
relating to all aspects of the oil and gas industry, and in particular in the
exploration and development of new oil and gas reserves. The Company must
compete with a substantial number of other oil and natural gas companies, many
of which have significantly greater financial resources.
All of the Company's oil and gas activities are subject to the risks
normally incident to exploration for and production of oil and gas, including
blowouts, cratering, spillage and fires, each of which could result in damage to
life and property. Offshore operations are subject to usual marine perils,
including hurricanes and other adverse weather conditions, and governmental
regulations as well as interruption or termination by governmental authorities
based on environmental and other considerations. In accordance with customary
industry practices, the Company carries insurance against some, but not all, of
the risks associated with the Company's business. Losses and liabilities arising
from such events would reduce revenues and increase costs to the Company to the
extent not covered by insurance.
Another risk inherent in the oil and gas industry is the risk that a well
will be a dry hole or a marginal producer that will not, in either case, repay
the entire cost of drilling, testing, completing and equipping the well. There
can be no assurance, therefore, that the Company's future exploration and
development wells will be financially successful.
INTERNATIONAL OPERATIONS
Foreign properties, operations or investment may be adversely affected by
local political and economic developments, exchange controls, currency
fluctuations, royalty and tax increases, retroactive tax claims, expropriation,
import and export regulations and other foreign laws or policies as well as by
laws and policies of the United States affecting foreign trade, taxation and
investment. In addition, in the event of a dispute arising from foreign
operations, the Company may be subject to the exclusive jurisdiction of foreign
courts or may not be successful in subjecting foreign persons to the
jurisdiction of courts in the United States. The Company may also be hindered or
prevented from enforcing its rights with respect to a governmental
instrumentality because of the doctrine of sovereign immunity.
ABSENCE OF A PREVIOUS MARKET FOR THE DECS
The DECS are a new issue of securities with no established trading market.
The DECS have been approved for listing on the NYSE, but no assurance can be
given as to the development or liquidity of any trading market in the DECS. If
an active market does not develop, the market price and liquidity of the DECS
may be adversely affected.
15
<PAGE> 122
RATIOS OF EARNINGS TO FIXED CHARGES
The following table sets forth the historical ratios of earnings to fixed
charges and earnings to combined fixed charges and preferred stock dividends of
the Company for the periods indicated:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Earnings to Fixed Charges.......................... (a) (a) 1.5 x 1.3 x 2.2 x
Earnings to Combined Fixed Charges and Preferred
Dividends........................................ (b) (b) 1.5 x 1.3 x 2.2 x
</TABLE>
- ---------------
(a) Earnings during 1993 and 1992 were insufficient to cover fixed charges
(excluding dividends on preferred stock) by $154.5 million and $5.8
million, respectively.
(b) Earnings during 1993 and 1992 were insufficient to cover combined fixed
charges and preferred dividends by $166.0 million and $12.8 million,
respectively.
USE OF PROCEEDS
The net proceeds to the Company from the sale of the DECS offered hereby
are estimated to be approximately $91.6 million. Such net proceeds will be used
(i) to repay the floating rate debt borrowed under the Company's Amended and
Restated Revolving Credit Agreement ("Bank Facility"), the balance of which was
$30.0 million at April 25, 1994 and which currently bears interest at 5.5% per
year; (ii) to repay approximately $30.0 million principal amount of debt
previously incurred by Santa Fe Energy Operating Partners, L.P. (the "Operating
Partnership") (plus a prepayment penalty equal to approximately $2.5 million),
with a current interest rate of 8.3% per year, $6.0 million of which matures in
1994 and $8.0 million of which is scheduled to mature during each of the
succeeding three years; (iii) to repay approximately $12.3 million principal
amount of debt of Mission Resources, Inc. assumed by the Company in connection
with a property acquisition, with a current interest rate of 9.0% and a
scheduled maturity in 1995; and (iv) the balance, if any, will be used for
working capital purposes. If the Concurrent Debenture Offering is consummated,
the net proceeds (estimated to be approximately $97.0 million) from that
offering will be used (i) to prepay $65.0 million principal amount of the
Company's Senior Notes with scheduled maturities in 1995 (Series C, $30.0
million) and 1996 (Series D, $35.0 million), together with prepayment penalties
aggregating approximately $6.1 million; (ii) to repay any additional debt under
the Bank Facility; and (iii) the balance, if any, will be used for working
capital purposes. The Senior Notes (Series C) bear interest at 10.04% per year
and the Senior Notes (Series D) bear interest at 10.14% per year.
After the application of the net proceeds from this Offering and the
Concurrent Debenture Offering, the Company will have approximately $245.0
million principal amount of Senior Notes outstanding, none of which matures
before 1996.
16
<PAGE> 123
CAPITALIZATION
The following table sets forth the Company's consolidated capitalization at
December 31, 1993 on an historical basis and as adjusted as indicated below. See
"Use of Proceeds."
<TABLE>
<CAPTION>
DECEMBER 31, 1993
---------------------------------------------
AS ADJUSTED
-------------------------------
DECS AND
ACTUAL DECS ONLY(A) DEBENTURES(B)
-------- ------------ -------------
<S> <C> <C> <C>
(IN MILLIONS)
SHORT-TERM DEBT:
Current portion of long-term debt............. $ 44.3 $ 3.8 $ 3.8
-------- -------- ---------
-------- -------- ---------
LONG-TERM DEBT:
Senior notes.................................. 310.0 310.0 245.0
Revolving and term credit agreement........... 48.7 35.5 9.6
Notes payable to bank......................... 11.3 11.3 11.3
Term loan..................................... 11.4 -- --
Partnership credit agreement.................. 24.0 -- --
Senior subordinated debentures................ -- -- 100.0
-------- -------- ---------
Total long-term debt....................... 405.4 356.8 365.9
-------- -------- ---------
CONVERTIBLE PREFERRED STOCK, SERIES 7%:......... 80.0 80.0 80.0
-------- -------- ---------
SHAREHOLDERS' EQUITY:
DECS.......................................... -- 91.6 91.6
Common stock.................................. 0.9 0.9 0.9
Paid-in capital............................... 496.9 496.9 496.9
Accumulated deficit........................... (173.8) (173.9) (174.2)
Other......................................... (0.4) (0.4) (0.4)
-------- -------- ---------
Total shareholders' equity................. 323.6 415.1 414.8
-------- ------- ---------
Total capitalization..................... $ 809.0 $ 851.9 $ 860.7
-------- -------- ---------
-------- -------- ---------
</TABLE>
- ---------------
(a) Pro forma for the issuance of the DECS only. Assumes 10,700,000 DECS are
sold at a price of $8 7/8 per share. Net proceeds from the Offering will be
applied to prepay approximately $44.5 million of floating rate debt
borrowed under the Bank Facility, approximately $32.0 million of debt
incurred by the Operating Partnership and approximately $12.6 million of
debt assumed by the Company in connection with a property acquisition, in
each case on a pro forma basis at December 31, 1993.
(b) Pro forma for the issuance of both the DECS and the Debentures and the
application of the net proceeds therefrom (estimated to be $188.6 million)
as described in "Use of Proceeds." Assumes 10,700,000 DECS are sold at a
price of $8 7/8 per share.
17
<PAGE> 124
PRICE RANGE OF COMMON STOCK AND DIVIDENDS
The Company's Common Stock is listed on the NYSE and trades under the
symbol SFR. The following table sets forth information as to the high and low
closing prices per share of the Common Stock as reported by the NYSE and cash
dividends paid per share for each calendar quarter in 1992 and 1993 and the
first quarter and second quarter of 1994.
<TABLE>
<CAPTION>
CASH
LOW HIGH DIVIDENDS
---- ------ ---------
<S> <C> <C> <C>
1992
1st Quarter................................................. $7 $ 9 3/8 $0.04
2nd Quarter................................................. 7 7/8 9 3/4 0.04
3rd Quarter................................................. 7 7/8 9 7/8 0.04
4th Quarter................................................. 7 3/4 9 7/8 0.04
1993
1st Quarter................................................. $7 3/4 $11 $0.04
2nd Quarter................................................. 9 5/8 11 1/8 0.04
3rd Quarter................................................. 9 1/8 10 5/8 0.04
4th Quarter................................................. 8 3/8 10 7/8 (a)
1994
1st Quarter................................................. $8 1/2 $ 9 7/8 (a)
2nd Quarter (through April 25)(b)........................... 7 5/8 $ 8 7/8 (a)
</TABLE>
- ---------------
(a) As discussed in "Business and Properties--Corporate Restructuring Program,"
the Company has eliminated the payment of its $0.04 per share quarterly
dividend on its Common Stock. The determination of the amount of future
cash dividends, if any, to be declared and paid is in the sole discretion
of the Company's Board of Directors and will depend on dividend
requirements with respect to the Company's Convertible Preferred Stock,
Series 7%, and, assuming consummation of this Offering, the DECS, the
Company's financial condition, earnings and funds from operations, the
level of its capital and exploration expenditures, dividend restrictions in
its financing agreements, its future business prospects and other matters
as the Company's Board of Directors deems relevant. For a discussion of
certain restrictions on the Company's ability to pay dividends, see
"Description of Capital Stock--Common Stock."
(b) See the cover page of this Prospectus for a recent closing price of the
Common Stock on the NYSE.
At March 14, 1994, there were 89,936,650 shares of Common Stock issued and
outstanding held by approximately 57,755 shareholders of record.
18
<PAGE> 125
SELECTED FINANCIAL AND OPERATING DATA
The following data has been derived from the Company's consolidated
financial statements audited by Price Waterhouse, independent accountants. The
selected historical financial data should be read in conjunction with the
consolidated financial statements of the Company, including the notes thereto.
The Company's consolidated balance sheets at December 31, 1992 and 1993 and the
related consolidated statements of operations, of cash flows and of
shareholders' equity for the three years ended December 31, 1993 are included
elsewhere in this Prospectus.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1993 1992(A) 1991 1990 1989
-------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN MILLIONS, EXCEPT AS NOTED)
INCOME STATEMENT DATA:
Revenues............................... $ 436.9 $ 427.5 $ 379.8 $ 382.9 $ 322.9
Operating expenses
Production and operating............ 163.8 153.4 134.6 135.5 107.1
Oil and gas system and pipelines.... 4.2 3.2 -- -- --
Exploration, including dry hole
costs............................. 31.0 25.5 18.7 21.0 19.4
Depletion, depreciation and
amortization...................... 152.7 146.3 106.6 105.2 99.4
Impairment of oil and gas
properties(b)..................... 99.3 -- -- 1.4 1.1
General and administrative.......... 32.3 30.9 27.8 25.6 28.6
Taxes (other than income)........... 27.3 24.3 27.2 22.0 22.3
Restructuring charges (c)........... 38.6 -- -- -- --
Loss (gain) on disposition of oil
and gas properties................ 0.7 (13.6) 0.5 2.8 (0.5)
-------- -------- ------- ------- -------
Total operating expenses............... 549.9 370.0 315.4 313.5 277.4
-------- -------- ------- ------- -------
Operating income (loss)................ (113.0) 57.5 64.4 69.4 45.5
Other income (expense)................. (4.8) (10.0) 5.6 (0.3) 18.2
Interest income........................ 9.1 2.3 2.3 5.2 4.3
Interest expense....................... (45.8) (55.6) (47.3) (57.1) (30.5)
Interest capitalized................... 4.3 4.9 7.7 10.6 13.8
-------- -------- ------- ------- -------
Income (loss) before income taxes and
cumulative effect of accounting
charge.............................. (150.2) (0.9) 32.7 27.8 51.3
Income taxes benefit (expense)......... 73.1 (0.5) (14.2) (10.8) (26.0)
-------- -------- ------- ------- -------
Income (loss) before cumulative effect
of accounting change................ (77.1) (1.4) 18.5 17.0 25.3
Cumulative effect of accounting
change.............................. -- -- -- -- 24.5
-------- -------- ------- ------- -------
Net income (loss)...................... (77.1) (1.4) 18.5 17.0 49.8
Preferred dividend requirement......... (7.0) (4.3) -- -- --
-------- -------- ------- ------- -------
Earnings (loss) attributable to Common
Stock............................... $ (84.1) $ (5.7) $ 18.5 $ 17.0 $ 49.8
-------- -------- ------- ------- -------
-------- -------- ------- ------- -------
Per share data (in dollars):
Income (loss) before cumulative
effect of accounting change....... $ (0.94) $ (0.07) $ 0.29 $ 0.28 $ 0.48
Cumulative effect of change in
accounting for income taxes....... -- -- -- -- 0.47
Earnings (loss) to Common Stock..... (0.94) (0.07) 0.29 0.28 0.95
Weighted average number of shares
outstanding......................... 89.7 79.0 63.8 61.7 52.1
STATEMENT OF CASH FLOW DATA:
Net cash provided by operating
activities.......................... $ 160.2 $ 141.5 $ 128.4 $ 144.1 $ 173.1
Net cash used in investing
activities.......................... 121.4 15.9 117.2 108.2 86.8
</TABLE>
(Table continued on following page)
19
<PAGE> 126
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------
1993 1992(A) 1991 1990 1989
-------- -------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
(IN MILLIONS, EXCEPT AS NOTED)
BALANCE SHEET DATA (AT PERIOD END):
Properties and equipment, net.......... $ 832.7 $1,101.8 $ 797.4 $ 745.0 $ 747.6
Total assets........................... 1,076.9 1,337.2 911.9 911.1 881.8
Long-term debt......................... 405.4 492.8 440.8 417.2 124.7
Convertible Preferred Stock, Series
7%.................................. 80.0 80.0 -- -- --
Shareholders' equity................... 323.6 416.6 225.1 215.8 228.1
SELECTED OPERATING DATA:
Daily average production(d):
Crude oil and liquids (MBbls/day)
Domestic.......................... 60.2 58.3 54.9 52.0 50.7
Argentina......................... 2.4 2.4 0.6 -- --
Indonesia......................... 4.1 1.8 -- -- --
-------- -------- ------- ------- -------
66.7 62.5 55.5 52.0 50.7
-------- -------- ------- ------- -------
-------- -------- ------- ------- -------
Natural gas (MMcf/day).............. 165.4 126.3 95.2 102.5 81.6
Total production (MMBOE)............ 94.3 83.6 71.4 69.1 64.3
Average sales prices:
Crude oil and liquids ($/Bbl)
Unhedged
Domestic....................... $ 12.70 $ 14.38 $ 14.07 $ 17.90 $ 14.11
Argentina...................... 14.07 15.99 16.24 -- --
Indonesia...................... 15.50 17.51 -- -- --
Total.......................... 12.93 14.54 14.09 17.90 14.11
Hedged............................ 12.93 14.96 16.16 17.34 14.11
Natural Gas ($/Mcf)
Unhedged.......................... $ 2.03 $ 1.71 $ 1.49 $ 1.57 $ 1.72
Hedged............................ 1.89 1.70 1.49 1.57 1.72
Proved reserves at year end(e):
Crude oil, condensate and natural
gas liquids (MMBbls).............. 248.2 255.1 229.2 222.3 219.8
Natural gas (Bcf)................... 263.0 277.5 170.8 185.9 188.0
Proved reserves (MMBOE)............. 292.0 301.5 257.7 253.3 251.1
Proved developed reserves (MMBOE)... 225.5 248.4 210.3 205.0 204.0
Production costs (included related
production, severance and ad valorem
taxes) per BOE (in dollars)......... $ 5.39 $ 5.66 $ 6.06 $ 6.22 $ 5.69
</TABLE>
- ---------------
(a) On May 19, 1992, Adobe was merged with and into the Company.
(b) Reflects a non-cash charge of $99.3 million for the impairment of oil and
gas properties recorded as of December 31, 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations"
and Note 1 of the Notes to the Company's Consolidated Financial Statements
included elsewhere in this Prospectus.
(c) Includes losses on property dispositions of $27.8 million, long-term debt
repayment penalties of $8.6 million and accruals of certain personnel
benefits and related costs of $2.2 million.
(d) Includes production attributable to the properties sold to Vintage (closed
in November 1993) and Bridge (closed in April 1994). Production
attributable to such properties during 1993 totaled approximately 4.1 MBbls
of oil per day and 21.7 MMcf of natural gas per day (7.7 MBOE per day).
(e) The estimates set forth in this table for 1993 give effect to the sale by
the Company of approximately 8.0 MMBOE of proved reserves to Bridge, which
sale closed in April 1994.
20
<PAGE> 127
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
GENERAL
As an independent oil and gas producer, the Company's results of operations
are dependent upon the difference between the prices received for oil and gas
and the costs of finding and producing such resources. A substantial portion of
the Company's crude oil production is from long-lived fields where EOR methods
are being utilized. The market price of the heavy (i.e., low gravity, high
viscosity) and sour (i.e., high sulfur content) crude oils produced in these
fields is lower than sweeter, light (i.e., low sulfur and low viscosity) crude
oils, reflecting higher transportation and refining costs. The lower price
received for the Company's domestic heavy and sour crude oil is reflected in the
average sales price of the Company's domestic crude oil and liquids (excluding
the effect of hedging transactions) for 1993 of $12.70 per barrel, compared to
$16.94 per barrel for West Texas Intermediate ("WTI") crude oil (an industry
posted price generally indicative of spot prices for sweeter light crude oil).
In addition, the lifting costs of heavy crude oils are generally higher than the
lifting costs of light crude oils. As a result of these narrower margins, even
relatively modest changes in crude oil prices may significantly affect the
Company's revenues, results of operations, cash flows and proved reserves. In
addition, prolonged periods of high or low oil prices may have a material effect
on the Company's financial position.
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, the
Middle East and other producing countries. See "Business and Properties--Current
Markets for Oil and Gas." The period since mid-1990 has included some of the
largest fluctuations in oil prices in recent times, primarily due to the
political unrest in the Middle East. The actual average sales price (unhedged)
received by the Company ranged from a high of $23.92 per barrel in the fourth
quarter of 1990 to a low of $10.00 per barrel during the three months ended
March 31, 1994. The Company's average sales price for its 1993 oil production
was $12.93 per barrel. Based on operating results of 1993, the Company estimates
that a $1.00 per barrel increase or decrease in average oil sales prices would
have resulted in a corresponding $21.6 million change in 1993 income from
operations and a $16.2 million change in 1993 cash flow from operating
activities. The Company also estimates that a $0.10 per Mcf increase or decrease
in average natural gas sales prices would have resulted in a corresponding $5.8
million change in 1993 income from operations and a $4.4 million change in 1993
cash flow from operating activities. The foregoing estimates do not give effect
to changes in any other factors, such as the effect of the Company's hedging
program or depreciation and depletion, that would result from a change in oil
and natural gas prices.
During 1992 and 1993, certain significant events occurred which affect the
comparability of prior periods, including the merger of Adobe with and into the
Company in May 1992 the formation of the Santa Fe Energy Trust (the "Trust") in
November 1992 and implementation of the corporate restructuring program adopted
in October 1993. The corporate restructuring program includes (i) the
concentration of capital spending in the Company's core operating areas, (ii)
the disposition of non-core assets, (iii) the elimination of the $0.04 per share
quarterly Common Stock dividend and (iv) the recognition of $38.6 million of
restructuring charges. See Note 2 of the Notes to the Company's Consolidated
Financial Statements included elsewhere in this Prospectus and "Business and
Properties--Corporate Restructuring Program." In addition, the Company's results
of operations for 1993 include a charge of $99.3 million for the impairment of
oil and gas properties.
The Company's capital program will be concentrated in three domestic core
areas--the Permian Basin in Texas and New Mexico, the offshore Gulf of Mexico
and the San Joaquin Valley of California--as well as its productive areas in
Argentina and Indonesia. The domestic program includes development activities in
the Delaware and Cisco-Canyon formations in west Texas and southeast New Mexico,
a development drilling program for the offshore Gulf of Mexico natural gas
properties and relatively low risk infill drilling in the San Joaquin Valley of
California. Internationally, the program includes development of the Company's
Sierra Chata discovery in Argentina with gas sales expected to commence in early
1995
21
<PAGE> 128
and the Salawati Basin Joint Venture in Indonesia. See "Business and
Properties--Domestic Development Activities" and "--International Development
Activities."
The Company's non-core asset disposition program includes the sale of its
natural gas gathering and processing assets to Hadson Corporation ("Hadson")
(completed in December 1993), the sale to Vintage of certain southern California
and Gulf Coast oil and gas producing properties (completed in November 1993) and
the sale to Bridge of certain Mid-Continent and Rocky Mountain oil and gas
producing properties and undeveloped acreage (completed in April 1994). See
"Business and Properties--Corporate Restructuring Program" for a description of
the transactions with Hadson, Vintage and Bridge. In the first quarter of 1994,
the Company sold the remaining 575,000 Depositary Units which it held in the
Trust for $11.3 million and its interest in certain other oil and gas properties
for $8.3 million. As a result of the Vintage and Bridge dispositions described
above, the Company has sold properties having combined production during 1993 of
4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and estimated
proved reserves of approximately 16.7 MMBOE.
The restructuring program also includes an evaluation of the Company's
capital and cost structures to examine ways to increase flexibility and
strengthen the Company's financial performance. Based upon that evaluation, the
Company determined to proceed with the Refinancing to accomplish its financial
strategy. The evaluation of the Company's cost structure is designed to continue
the Company's efforts to reduce its operating costs and general administrative
expenses. During the quarter ended March 31, 1994, the Company recorded $7.0
million in restructuring charges reflecting the estimated costs of such cost
reduction program. See "--Recent Operating Results" and "--Liquidity and Capital
Resources."
In May 1992, Adobe, an oil and gas exploration and production company, was
merged with and into the Company (the "Adobe Merger"). The acquisition was
accounted for as a purchase and the results of operations of the properties
acquired (the "Adobe Properties") are included in the Company's results of
operations effective June 1, 1992. Pursuant to the Adobe Merger, the Company
issued 25,020,117 shares of Common Stock and 5,000,000 shares of its Convertible
Preferred Stock, Series 7%, and assumed approximately $175.0 million of
long-term debt and other liabilities. Pursuant to the Adobe Merger, the Company
also acquired Adobe's proved reserves and inventory of undeveloped acreage. As
of December 31, 1991, Adobe's estimated proved reserves totaled approximately
53.2 MMBOE (net of 6.9 MMBOE attributable to Adobe's ownership in certain gas
plants), of which approximately 58% was natural gas (approximately 66% of
Adobe's estimated domestic proved reserves were natural gas). Approximately 72%
of the discounted future net cash flow of Adobe's estimated domestic proved
reserves was concentrated in three areas of operation--offshore Gulf of Mexico,
onshore Louisiana and in the Spraberry Trend in west Texas. In addition, Adobe's
international operations consisted of certain production sharing arrangements in
Indonesia, in respect of which approximately 6.0 MMBOE of estimated proved
reserves had been attributed to Adobe's interest as of December 31, 1991. The
location of the Adobe Properties enhanced the Company's existing domestic
operations and added significant operations to the Company's international
program.
In November 1992, 5,725,000 Depositary Units ("Depositary Units")
consisting of interests in the Trust were sold in a public offering. After
payment of certain costs and expenses, the Company received net proceeds of
$70.1 million and 575,000 Depositary Units. For any calendar quarter ending on
or prior to December 31, 2002, the Trust will receive additional royalty
payments to the extent necessary to distribute $0.40 per Depositary Unit per
quarter. The source of such payments, if needed, will be limited to the
Company's remaining royalty interest in certain of the properties conveyed to
the Trust. The aggregate amount of such payments are limited to $20.0 million on
a revolving basis. The Company was required to make an additional royalty
payment of $362,000 with respect to the distribution made by the Trust for
operations during the quarter ended December 31, 1993. On April 21, 1994, the
Trust announced that a distribution of $0.40 per Depositary Unit would be paid
for the calendar quarter ended March 31, 1994 to Unitholders of record on May
16, 1994, which distribution will include an additional royalty payment by the
Company of $505,700. See "Business and Properties--Santa Fe Energy Trust."
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RECENT OPERATING RESULTS
For the three months ended March 31, 1994, the Company reported a net loss
to common shares of $4.3 million, or $0.05 per share, compared to a net loss to
common shares of $2.2 million, or $0.02 per share, in the same period in 1993.
Revenues for the first quarter of 1994 totaled $90.3 million compared to $115.3
million in the same period in 1993. The decline in revenues primarily reflects a
$3.73 per barrel decline in the Company's average sales price for its crude oil
and liquids as compared to its average sales price for the first quarter of
1993. Revenues from the properties sold to Vintage included in the 1993 period
totaled $5.4 million. The Company's costs and expenses totaled $90.3 million in
the first quarter of 1994 compared to $103.3 million in the first quarter of
1993. Lower production and operating costs (down $2.1 million, primarily
reflecting the effect of the Vintage sale), exploration expenses (down $2.1
million) and DD&A expense (down $5.6 million, primarily reflecting the effect of
impairments taken in the fourth quarter of 1993) and the recognition of a $9.4
million gain from the disposition of oil and gas properties were the principal
factors in the reduction in costs and expenses. Costs and expenses for the first
quarter of 1994 include $7.0 million in restructuring charges related to the
Company's cost reduction program. The restructuring charges, designed to reduce
expenses by approximately $30.0 million from the 1993 level (which reduction
includes approximately $5.0 million of non-recurring costs), relate to
severance, benefits and relocation expenses associated with a cost reduction
program that includes a 20% reduction in the Company's work force, a reduction
in other general and administrative expenses and a $10.0 million reduction in
field expenses. Substantially all of this program is expected to be implemented
by year end 1994. Net cash provided by operating activities declined from $41.6
million in the first quarter of 1993 to $14.3 million in the first quarter of
1994, primarily reflecting the factors described above.
The Company's production during the first quarter of 1994 totaled 5.9
MMBbls of crude oil and liquids and 14.0 Bcf of natural gas compared to 6.0
MMBbls of crude oil and liquids and 16.0 Bcf of natural gas in the first quarter
of 1993. Natural gas production for the first quarter of 1993 included a 1.5 Bcf
positive adjustment attributable to prior periods. Crude oil and liquids sales
prices (unhedged) averaged $10.00 per barrel in the first quarter of 1994
compared to $13.73 per barrel in the first quarter of 1993. Natural gas sales
prices (unhedged) averaged $2.10 per Mcf in the first quarter of 1994 compared
to $1.96 per Mcf in the first quarter of 1993.
RESULTS OF OPERATIONS
The following table sets forth, on the basis of the BOE produced by the
Company during the applicable annual period, certain of the Company's costs and
expenses for each of the years in the three-year period ended December 31, 1993.
<TABLE>
<CAPTION>
1993 1992 1991
------ ------ ------
<S> <C> <C> <C>
Production and operating costs per BOE (a)................... $ 4.76 $ 5.02 $ 5.17
Exploration, including dry hole costs per BOE................ 0.90 0.84 0.72
Depletion, depreciation and amortization per BOE............. 4.44 4.79 4.09
General and administrative costs per BOE..................... 0.94 1.01 1.07
Taxes other than income per BOE (b).......................... 0.79 0.80 1.05
Interest, net, per BOE (c)................................... 0.94 1.58 1.43
</TABLE>
- ---------------
(a) Excluding related production, severance and ad valorem taxes.
(b) Includes production, severance and ad valorem taxes.
(c) Reflects interest expense less amounts capitalized and interest income.
1993 Compared with 1992
Total revenues increased approximately 2% from $427.5 million in 1992 to
$436.9 million in 1993, principally due to an increase in oil and natural gas
production offset by a decline in average oil prices.
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<PAGE> 130
Average daily oil production increased 7% from 62.5 MBbls in 1992 to 66.7 MBbls
in 1993, principally due to increased domestic and Indonesian production. The
average price realized per barrel of oil during 1993 was $12.93, a decrease of
14% versus the average price of $14.96 in 1992. Natural gas production increased
31% from 126.3 MMcf per day in 1992 to 165.4 MMcf per day in 1993, primarily
reflecting the effect of a full year's production from the Adobe Properties.
Average natural gas prices realized increased approximately 11% from $1.70 per
Mcf in 1992 to $1.89 per Mcf in 1993.
Production and operating costs increased $10.4 million in 1993, primarily
reflecting the effect of a full year's costs for the Adobe Properties; however,
on a BOE basis such costs declined from $5.02 per barrel in 1992 to $4.76 per
barrel in 1993. Exploration costs were $5.5 million higher than in 1992
primarily reflecting higher geological and geophysical costs and higher dry hole
costs. DD&A increased $6.4 million in 1993 primarily reflecting a full year's
expense on Adobe Properties partially offset by reduced amortization rates with
respect to certain unproved properties. DD&A for 1993 includes $12.1 million
with respect to the properties sold to Vintage and Bridge. On a BOE basis, DD&A
decreased by $0.35 per barrel, from $4.79 to $4.44 per barrel. General and
administrative costs increased $1.4 million principally due to a $1.8 million
charge related to the adoption of Statement of Financial Standards No.
112--"Employer's Accounting for Postemployment Benefits." Taxes (other than
income) increased by $3.0 million in 1993 primarily reflecting the effect of the
Adobe Properties.
Costs and expenses for 1993 also include $99.3 million in impairments of
oil and gas properties and $38.6 million in restructuring charges. The Company
estimates that the impairments taken in 1993 will result in a $20.0 million
reduction in DD&A in 1994. The restructuring charges include losses on property
dispositions of $27.8 million, long-term debt repayment penalties of $8.6
million and accruals of certain personnel benefits and related costs of $2.2
million. In connection with the property dispositions effected during 1993 (see
"--Liquidity and Capital Resources"), the Company sold properties having
combined production during 1993 of 4.1 MBbls of oil per day and 21.7 MMcf of
natural gas per day and combined estimated proved reserves of approximately 16.7
MMBOE. The Company's income from operations for 1993 includes $8.5 million with
respect to such properties.
Interest income in 1993 includes $6.8 million related to a $10 million
refund received as a result of the completion of the audit of the Company's
federal income tax returns for 1971 through 1980. The decrease in interest
expenses during 1993 reflects a decrease in the Company's debt outstanding and a
$5.7 million credit related to a revision to a tax sharing agreement with the
Company's former parent. Other income and expenses of 1993 includes a $4.0
million charge related to the accrual of a contingent loss with respect to the
operations of a former affiliate of Adobe.
1992 Compared with 1991
Total revenues increased approximately 13% from $379.8 million in 1991 to
$427.5 million in 1992 principally due to an increase of approximately $53.2
million attributable to production from properties acquired in the Adobe Merger
and an increase of approximately $10.7 million and $10.2 million in revenues
from the Company's domestic and Argentine properties, respectively, offset in
part by a decline of $32.0 million in crude oil hedging revenues. Oil production
increased 13% from 55.5 MBbls per day in 1991 to 62.5 MBbls per day in 1992,
reflecting a 3.4 MBbl per day increase in domestic oil production and a 3.6 MBbl
per day increase in production in Argentina and Indonesia. The average price
realized per barrel of oil during 1992 decreased to $14.96, a decrease of 7%
versus the average price of $16.16 in 1991, primarily reflecting a $32.0 million
decrease in hedging revenues. Natural gas production increased 33% from 95.2
MMcf per day in 1991 to 126.3 MMcf per day in 1992 as a result of properties
acquired in the Adobe Merger. Average natural gas prices realized increased
approximately 14% from $1.49 per Mcf in 1991 to $1.70 per Mcf in 1992.
Total operating expenses of the Company increased $54.6 million from $315.4
million in 1991 to $370.0 million in 1992 primarily reflecting costs associated
with the Adobe Merger. Production and operating costs in 1992 were $18.8 million
higher than in 1991, primarily reflecting costs related to the Adobe Properties
and increased fuel costs associated with the Company's EOR projects. On a BOE
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<PAGE> 131
basis, production and operating costs declined from $5.17 per barrel in 1991 to
$5.02 per barrel in 1992, primarily reflecting the lower cost structure of the
Adobe Properties. Exploration costs were $6.8 million higher than in 1991
primarily reflecting higher geological and geophysical costs with respect to
foreign projects. Depletion, depreciation and amortization costs were $39.7
million higher in 1992 due to the acquisition of the Adobe Properties and, to a
lesser extent, adjustments to oil and gas reserves with respect to certain
producing properties. General and administrative costs increased $3.1 million
principally due to a $1.2 million charge related to certain stock awards which
fully vested upon consummation of the Adobe Merger and certain other
merger-related costs. Taxes (other than income) decreased by $2.9 million in
1992 as a result of lower accruals with respect to property taxes. The $13.6
million gain on the disposition of properties in 1992 primarily relates to the
sale of certain royalty interest properties, in which the Company had no
remaining financial basis.
The increase in interest expense during 1992 reflects the increase in debt
as a result of the Adobe Merger. Other income and expenses for 1992 includes a
$10.9 million charge for costs incurred by Adobe in connection with the Adobe
Merger and paid by Santa Fe.
LIQUIDITY AND CAPITAL RESOURCES
Historically, the Company has generally funded capital and exploration
expenditures and working capital requirements from cash provided by operating
activities. Depending upon the future levels of operating cash flows, which are
significantly affected by oil and gas prices, the restrictions on additional
borrowings included in certain of the Company's debt agreements, together with
debt service requirements and dividends, may limit the cash available for future
exploration, development and acquisition activities. Net cash provided by
operating activities totaled $160.2 million in 1993, $141.5 million in 1992 and
$128.4 million in 1991; net cash used in investing activities in such periods
totaled $121.4 million, $15.9 million and $117.2 million, respectively.
The Company's cash flow from operating activities is a function of the
volumes of oil and gas produced from the Company's properties and the sales
prices realized therefor. Crude oil and natural gas are depleting assets.
Therefore, unless the Company replaces over the long term the oil and natural
gas produced from the Company's properties, the Company's assets will be
depleted over time and its ability to service and incur debt at constant or
declining prices will be reduced. The Company's cash flow from operations for
1993 reflects an average sales price (unhedged) for the Company's 1993 oil
production of $12.93 per barrel. For the three months ended March 31, 1994, the
average sales price (unhedged) for the Company's 1994 oil production was $10.00
per barrel. If such lower oil prices prevail throughout 1994, the Company's cash
flow from operating activities for 1994 will be significantly lower than that
for 1993.
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program that focuses on the concentration of capital spending in
core areas and the disposition of non-core assets. The Company's asset
disposition program adopted in connection with the 1993 restructuring program
has been substantially completed by the asset sales to Hadson, Vintage and
Bridge, the sale of the 575,000 Depositary Units in the Trust and the sale of
its interest in certain other oil and gas properties. As a result of such sales,
the Company sold a total of 16.7 MMBOE of proved reserves and undeveloped
acreage for a total of approximately $111.0 million, and sold certain gas
gathering and processing facilities for Hadson securities.
In conjunction with the 1993 restructuring program, the Company also
determined to undertake a review of its capital and cost structures. Based upon
such review of its capital structure, the Company determined to proceed with the
Refinancing in the belief that it will increase the Company's financial
flexibility, strengthen the Company's financial condition and permit the Company
to pursue aggressively its operating strategy. The net proceeds from the
Refinancing will be used to repay existing indebtedness of the Company. See "Use
of Proceeds." The evaluation of the Company's cost structure is designed to
continue the Company's efforts to reduce its operating costs and general and
administrative expenses.
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<PAGE> 132
During the quarter ended March 31, 1994, the Company recorded $7.0 million in
restructuring charges reflecting the estimated costs of such cost reduction
program. See "--Recent Operating Results."
Under the most restrictive covenant in the Company's existing credit
agreements, as of December 31, 1993 the Company could incur up to $64.0 million
of additional indebtedness. After giving effect as of December 31, 1993 to the
consummation of this Offering and the Concurrent Debenture Offering and the
application of the net proceeds therefrom, as described in "Use of Proceeds,"
the Company would have been able to incur up to $149.6 million of additional
indebtedness under its most restrictive covenant. At December 31, 1993, under
the Company's most restrictive covenant, the Company had the ability to pay
$26.1 million in dividends on its capital stock. Pro forma for this Offering and
the Concurrent Debenture Offering, the Company would have had the capacity to
pay dividends of up to $117.7 million in the aggregate on its capital stock,
including its Convertible Preferred Stock, Series 7%, and the DECS. However,
pursuant to the terms of the Debentures, upon completion of this Offering and
Concurrent Debenture Offering, the Company would have the ability to pay only up
to $50.0 million on its Common Stock. The amount permitted under these covenants
to be used to pay dividends will vary over time depending, among other things,
on the Company's earnings and any issuances of capital stock. The Indenture
pursuant to which the Debentures will be issued does not restrict the Company
from paying preferred dividends on the Convertible Preferred Stock, Series 7%,
or the DECS; however, payment of such preferred dividends reduces the Company's
capacity under the Indenture to pay Common Stock dividends.
As a part of the 1993 restructuring program, the Company eliminated its
$0.04 per share quarterly dividend on its Common Stock and announced that it
might spend up to $240 million in 1994 on an accelerated capital program.
However, as a result of the depressed crude oil prices that have prevailed since
November 1993, the Company, consistent with industry practice, has determined to
defer certain of its capital projects in order to prudently manage cash flow in
the near term. Based on current market conditions, the Company has authorized up
to $130 million of capital expenditures during 1994, a level which should allow
the Company to replace its estimated 1994 production, although no assurance can
be given regarding such replacement. The Company intends to continue to monitor
its capital expenditure program throughout the balance of 1994 and may, in
response to industry conditions, including, without limitation, prevailing oil
and natural gas prices and the outlook therefor, revise such program.
The Company is a party to several long-term and short-term credit
agreements which restrict the Company's ability to take certain actions,
including covenants that restrict the Company's ability to incur additional
indebtedness and to pay dividends on its capital stock. For a description of
such credit agreements at December 31, 1993, see Note 7 of the Notes to the
Company's Consolidated Financial Statements included elsewhere in this
Prospectus.
Effective February 28, 1994, the Company entered into the Bank Facility
with a group of banks for which Texas Commerce Bank National Association ("Texas
Commerce") and NationsBank of Texas act as co-agents. The Bank Facility consists
of a five-year secured reducing revolving credit facility maturing December 31,
1998 ("Facility A") and a three-year unsecured reducing revolving credit
facility maturing December 31, 1996 ("Facility B"). Assuming completion of this
Offering and the Concurrent Debenture Offering and the application of the net
proceeds therefrom as described in "Use of Proceeds," the initial aggregate
borrowing limits under the Bank Facility would be $175.0 million (up to $90.0
million under Facility A and up to $85.0 million under Facility B) none of which
would be outstanding. Interest rates under the Bank Facility are tied to LIBOR
or Texas Commerce's prime rate, with the actual interest rate reflecting certain
ratios based upon the Company's ability to repay its outstanding debt and the
value and projected timing of production of the Company's oil and gas reserves.
These and other similar ratios will also affect the Company's ability to borrow
under the Bank Facility and the timing and amount of any required repayments and
corresponding commitment reductions. Marc J. Shapiro, a director of the Company,
is the Chairman and Chief Executive Officer of Texas Commerce.
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<PAGE> 133
EFFECTS OF INFLATION
Inflation during the three years ended December 31, 1993 has had little
effect on the Company's capital costs and results of operations.
ENVIRONMENTAL MATTERS
Almost all phases of the Company's oil and gas operations are subject to
stringent environmental regulation by governmental authorities. Such regulation
has increased the costs of planning, designing, drilling, installing, operating
and abandoning oil and gas wells and other facilities. The Company has expended
significant financial and managerial resources to comply with such regulations.
Although the Company believes its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations. It is possible that
other developments, such as increasingly strict environmental laws, regulations
and enforcement policies or claims for damages to property, employees, other
persons and the environment resulting from the Company's operations, could
result in significant costs and liabilities in the future. As it has done in the
past, the Company intends to fund its cost of environmental compliance from
operating cash flows. See also, "Business--Other Business Matters--Environmental
Regulation" and Note 12 of the Notes to the Company's Consolidated Financial
Statements included elsewhere in this Prospectus.
DIVIDENDS
Dividends on the Company's Convertible Preferred Stock, Series 7%, are
cumulative at an annual rate of $1.40 per share. No dividends may be declared or
paid with respect to the Common Stock if any dividends with respect to the
Convertible Preferred Stock, Series 7%, or the DECS are in arrears. As described
elsewhere in this Prospectus, the Company has eliminated the payment of its
$0.04 per share quarterly dividend on its Common Stock. The determination of the
amount of future cash dividends, if any, to be declared and paid on the
Company's Common Stock is in the sole discretion of the Company's Board of
Directors and will depend on dividend requirements with respect to the
Convertible Preferred Stock, Series 7%, and the DECS, the Company's financial
condition, earnings and funds from operations, the level of capital and
exploration expenditures, dividend restrictions in financing agreements, future
business prospects and other matters the Board of Directors deems relevant.
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<PAGE> 134
BUSINESS AND PROPERTIES
GENERAL
The Company is engaged in the exploration, development and production of
oil and natural gas in the continental United States and in certain foreign
areas. At December 31, 1993, the Company had worldwide proved reserves totaling
292.0 MMBOE (consisting of approximately 248.2 MMBbls of oil and approximately
263.0 Bcf of natural gas), of which approximately 93% were domestic reserves and
approximately 7% were foreign reserves. During 1993, the Company's worldwide
production aggregated approximately 94.3 MBOE per day, of which approximately
71% was crude oil and approximately 29% was natural gas. A substantial portion
of the Company's domestic oil production is in long-lived fields with
well-established production histories. Pursuant to the Company's corporate
restructuring program (see "--Corporate Restructuring Program" below), the
Company has focused its activities on its three domestic core areas--the Permian
Basin in Texas and New Mexico, the offshore Gulf of Mexico and the San Joaquin
Valley of California--as well as in Argentina and Indonesia.
For the five years ended December 31, 1993, the Company has replaced
approximately 172% of its production at an average finding cost of $4.80 per
BOE. Over the last four years, the Company has increased overall production by
increasing production from existing properties and through acquisitions. In
addition, the Company has reduced its overall cost structure. For example, over
the four-year period ended December 31, 1993, Santa Fe has increased its average
daily production from 69.1 MBOE to 94.3 MBOE (including 7.7 MBOE per day in 1993
attributable to production from non-core assets sold pursuant to the corporate
restructuring program) and has reduced its average production costs (including
related production, severance and ad valorem taxes) from $6.22 per BOE in 1990
to $5.39 per BOE in 1993.
Most of the Company's domestic crude oil production is located in
California and Texas, while its domestic natural gas production comes primarily
from the Gulf of Mexico, New Mexico and Texas. During 1993, the Company's
domestic daily production averaged approximately 60.2 MBbls of crude oil and
165.0 MMcf of natural gas. Substantially all of the Company's oil and gas
production is sold at market responsive prices. Pursuant to the corporate
restructuring program, during 1993 the Company sold properties having 1993
combined production of 4.1 MBbls per day and 21.7 MMcf per day and estimated
reserves of approximately 16.7 MMBOE. The domestic crude oil marketing
activities of the Company are conducted through its Santa Fe Energy Products
Division ("Energy Products"), which is also engaged in crude oil trading.
Substantially all of the Company's domestic natural gas production is currently
marketed under the terms of a sales contract with Hadson. See "--Current Markets
for Oil and Gas."
A substantial portion of the Company's domestic oil production is in
long-lived fields with well-established production histories and where EOR
methods are employed. As of December 31, 1993, approximately 69% of the
Company's domestic proved crude oil and liquids reserves and 50% of its 1993
average daily domestic production of crude oil and liquids were attributable to
the Midway-Sunset field in the San Joaquin Valley of California, where the
Company first began production in 1905. Nearly all of the reserves in this field
are heavy oil, the production of which depends primarily on steam injection. As
of December 31, 1993, an additional 21% of the Company's domestic proved crude
oil and liquids reserves and approximately 25% of its 1993 average daily
domestic production of crude oil and liquids were attributable to five other oil
producing properties: the Wasson and Reeves fields in the Permian Basin of west
Texas and the South Belridge, Kern River and Coalinga fields in the San Joaquin
Valley.
The Company's foreign production is located in the El Tordillo field in
Argentina and in the Salawati Basin and Salawati Island area of Indonesia.
Production from the El Tordillo field averaged 2.4 MBbls of oil per day in 1993
and production from the Indonesian operations averaged 4.1 MBbls of oil per day
in 1993.
The Company maintains an active exploration and development program, a
significant portion of which consists of EOR projects on the producing fields
discussed above. During 1993, Santa Fe spent a total of $128.6 million on
exploration and development programs and $32.6 million on proved property
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<PAGE> 135
acquisitions. In October 1993, the Company announced that its 1994 capital
expenditures could increase to up to $240 million. However, as a result of
depressed oil prices that have prevailed since November 1993, the Company,
consistent with industry practice, has determined to defer certain of its
capital projects in order to prudently manage cash flow in the near term. Based
upon current market conditions, the Company has authorized up to $130 million of
capital expenditures during 1994, a level which should allow the Company to
replace its estimated 1994 production, although no assurance can be given
regarding such replacement. The Company intends to continue to monitor its
capital expenditure program throughout the balance of 1994 and may, in response
to industry conditions, including, without limitation, prevailing oil and
natural gas prices and the outlook therefor, revise such program.
In the United States, at December 31, 1993, the Company held oil and gas
rights to approximately 0.8 million net undeveloped leasehold and fee acres in
14 states, excluding approximately 1.1 million net undeveloped acres sold to
Bridge in April 1994 and 0.1 million net undeveloped fee acres sold to another
company in January 1994. See "--Corporate Restructuring Program." Outside the
United States, at December 31, 1993, the Company held exploration rights with
respect to an aggregate of approximately 3.5 million net undeveloped acres in
Argentina, Bolivia, Canada, Gabon, Indonesia, Morocco, Myanmar and Papua New
Guinea.
CORPORATE RESTRUCTURING PROGRAM
In October 1993, the Company's Board of Directors adopted a broad corporate
restructuring program designed to improve earnings and cash flow while
increasing production and replacing reserves in the long-term. The restructuring
program is the result of an intensive review of the Company's operations and
cash flows and focuses on the concentration of capital spending in the Company's
core operating areas and the disposition of non-core assets. To provide
additional funding for the capital program, the Company also announced the
elimination of the payment of its $0.04 per share quarterly dividend on the
Common Stock, which will make available approximately $14 million annually. The
dividend on the Company's Convertible Preferred Stock, Series 7%, will remain at
its current level and dividends on the DECS are expected to be approximately
$ million per year.
As a part of the Company's restructuring program, the Company intends to
concentrate its capital spending on its three domestic core areas--the Permian
Basin in Texas and New Mexico, the offshore Gulf Coast and the San Joaquin
Valley of California--as well as its productive areas in Indonesia and
Argentina. The domestic program includes development activities in the Delaware
formation in southeast New Mexico, a development drilling program for the
offshore Gulf of Mexico natural gas properties and infill drilling in the San
Joaquin Valley of California. Internationally, the program includes development
of the Company's Sierra Chata discovery in Argentina with gas sales expected to
commence in early 1995.
The restructuring program includes an evaluation of the Company's capital
and cost structures to examine ways to increase flexibility and strengthen the
Company's financial performance. In this respect, in 1994 the Company determined
to proceed with the Refinancing, of which this Offering and the Concurrent
Debenture Offering are a part, pursuant to which approximately $180 million of
the Company's long-term indebtedness will be refinanced, assuming consummation
of such offerings.
As a result of the dispositions described below, the Company has sold
undeveloped leasehold acreage and properties having combined production during
1993 of 4.1 MBbls of oil per day and 21.7 MMcf of natural gas per day and
estimated proved reserves of approximately 16.7 MMBOE for total proceeds of
approximately $91.4 million, has sold its natural gas gathering and processing
assets for Hadson securities and has realized approximately $11.3 million from
the sale of its remaining Depositary Units in the Trust. In addition, during the
first quarter of 1994 the Company sold its interest in certain oil and gas
properties for $8.3 million. As a result of these transactions, the Company has
disposed of substantially all of its inventory of non-core properties.
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<PAGE> 136
Sale to Hadson. In December 1993, the Company completed a transaction with
Hadson under the terms of which the Company sold the common stock of Adobe Gas
Pipeline Company ("AGPC"), a wholly owned subsidiary, to Hadson in exchange for
Hadson 11.25% preferred stock with a face value of $52.0 million and 40% of
Hadson's common stock. In addition, the Company signed a seven-year gas sales
contract under the terms of which Hadson will market substantially all of the
Company's domestic natural gas production from specified existing wells and
certain domestic development and exploration wells. Pursuant to such contract,
Hadson will be required to pay the Company for all production delivered at a
price for such gas equal to stipulated monthly index prices. See "--Current
Markets for Oil and Gas." The Company also designated one-half of the members of
the Hadson Board of Directors.
AGPC's assets include approximately 630 miles of gathering and
transportation lines in Oklahoma, Texas and New Mexico with three processing
plants in west Texas and New Mexico and an intrastate pipeline system supplying
gas to commercial customers in Lubbock, Texas. Hadson's natural gas assets are
predominantly located in southeastern New Mexico and include two gas processing
facilities, a 12 Bcf natural gas storage facility and the 650-mile Llano
intrastate pipeline which has six connections to various interstate pipelines
serving strategic markets in the Midwest, on the East Coast and in southern
California.
Sale to Vintage. In November 1993, the Company completed the sale to
Vintage of certain southern California and Gulf Coast producing properties for
net proceeds totaling $41.3 million in cash. The transaction included most of
the Company's California interests outside its core area in the San Joaquin
Valley as well as certain offshore Gulf Coast properties in Texas, Louisiana and
Mississippi. Production from the properties sold to Vintage averaged
approximately 2.8 MBbls of oil per day and 6.5 MMcf of natural gas per day
during 1993. During 1993 such properties contributed $2.7 million to the
Company's income from operations.
Sale to Bridge. On April 8, 1994, the Company completed the sale to Bridge
of certain Mid-Continent and Rocky Mountain producing and nonproducing oil and
gas properties. The purchase agreement was originally signed in December 1993.
Bridge paid the Company approximately $48 million in cash, reflecting the net
effect of estimated closing adjustments to the original $51 million sales price.
The transaction included substantially all of the Company's assets in the
Anadarko Basin of Oklahoma and Texas as well as its interests in the Rocky
Mountain states, excluding its interests in the Canyon Creek natural gas field
in Wyoming. The undeveloped acreage includes approximately 1.7 million mineral
and leasehold acres and exploratory options on an additional 8.1 million acres.
Production from the properties sold to Bridge averaged approximately 1.3 MBbls
of oil per day and 15.2 MMcf of natural gas per day during 1993. During 1993,
such properties contributed $5.8 million to the Company's income from
operations.
30
<PAGE> 137
RESERVES
The following table sets forth information regarding changes in the
Company's estimates of proved net reserves from January 1, 1991 to December 31,
1993 and the balance of the Company's estimated proved developed reserves at
December 31 of each of the years 1990 through 1993.
<TABLE>
<CAPTION>
INCREASES (DECREASES)
------------------------------------------------------------------------------
BALANCE NET CHANGES
AT REVISION EXTENSIONS, PURCHASES IN BALANCE
BEGINNING OF DISCOVERIES (SALES) OF OWNERSHIP- AT END
OF PREVIOUS IMPROVED AND MINERALS PARTNER- OF
PERIOD ESTIMATES RECOVERY ADDITIONS IN PLACE PRODUCTION SHIP(A) PERIOD
--------- --------- -------- ----------- ---------- ---------- ---------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved Reserves at
December 31, 1991:
Oil and Condensate
(MMBbls)............ 222.3 (1.9) 15.9 1.8 10.9 (20.2) 0.4 229.2
Gas (Bcf)............. 185.9 0.4 0.5 19.6 (3.0) (34.8) 2.2 170.8
Oil Equivalent
(MMBOE)............. 253.3 (1.8) 16.0 5.1 10.4 (26.0) 0.7 257.7
Proved Reserves at
December 31, 1992:
Oil and Condensate
(MMBbls)............ 229.2 14.1 17.0 2.6 15.0 (23.0) 0.2 255.1
Gas (Bcf)............. 170.8 7.3 1.3 5.6 137.1 (46.2) 1.6 277.5
Oil Equivalent
(MMBOE)............. 257.7 15.3 17.2 3.6 37.9 (30.6) 0.4 301.5
Proved Reserves at
December 31, 1993:
Oil and Condensate
(MMBbls)............ 255.1 (10.8) 26.7 6.2 (4.8) (24.3) 0.1 248.2
Gas (Bcf)............. 277.5 26.7 -- 55.9 (37.5) (60.4) 0.8 263.0
Oil Equivalent
(MMBOE)............. 301.5 (6.3) 26.7 15.4 (11.1) (34.4) 0.2 292.0 (b)
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------------------
1993 1992 1991 1990
------ ------ ------ ------
<S> <C> <C> <C> <C>
Proved Developed Reserves (MMBOE)........................................... 225.5 248.4 210.3 205.0
</TABLE>
- ---------------
(a) The information set forth under the column headed "Changes in
Ownership--Partnership" reflects reserve additions attributable to the
Company's increased ownership interest in Santa Fe Energy Partners, L.P.
(the "Partnership") caused by the reinvestment of distributions received by
the Company in respect of its interest in the Partnership. At December 31,
1993, the Company (through its subsidiaries) owned an aggregate 100%
interest in the Partnership.
(b) At December 31, 1993, 5.2 MMBOE were subject to a 90% net profits interest
held by the Trust. See "--Santa Fe Energy Trust."
Historically, the Company has utilized active development and exploration
programs as well as selected acquisitions to replace its reserves depleted by
production. The Company has increased its proved reserves (net of production) by
approximately 35% over the five years ended December 31, 1993. Most of such
increases are attributable to proved reserve additions from the Company's
producing oil properties in the San Joaquin Valley of California and the Permian
Basin in west Texas, proved reserves acquired in the Adobe Merger and other
purchases of oil and gas reserves. At December 31, 1993, the Company's reserves
were 9.5 MMBOE lower than at December 31, 1992, primarily reflecting the sale
during 1993 of properties with reserves totaling 16.7 MMBOE partially offset by
additions.
31
<PAGE> 138
The following table sets forth as of December 31, 1993 the Company's
estimated proved reserves and the discounted net present value thereof in each
of the Company's principal operating areas.
<TABLE>
<CAPTION>
NATURAL OIL PRE-TAX
OIL GAS EQUIVALENT PV1O(A)
OPERATING REGION (MMBBLS) (MMCF) (MMBOE) (IN MILLIONS)
- ------------------------------------------- -------- ------- ---------- -------------
<S> <C> <C> <C> <C>
Permian Basin.............................. 41.6 45.8 49.2 $ 128.1
Offshore Gulf of Mexico.................... 3.8 103.8 21.1 169.8
San Joaquin Valley......................... 183.6 11.8 185.6 167.1
Other Domestic............................. 1.9 74.5 14.3 78.2
International.............................. 17.3 27.1 21.8 24.6
----- ----- ----- -------
Total.................................... 248.2 263.0 292.0 $ 567.8
----- ----- ----- -------
----- ----- ----- -------
</TABLE>
- ---------------
(a) Represents the net present value (discounted at 10%) of the pre-tax future
net cash flows estimated to result from production of the Company's
estimated proved reserves using estimated sales prices and estimates of
production costs, ad valorem and production taxes and future development
costs necessary to produce such reserves. The sales prices used in the
determination of proved reserves and of estimated future net cash flows are
based on the prices in effect at year end, and for 1993 averaged $9.27 per
barrel for oil and $2.17 per Mcf for natural gas. The average sales price
(unhedged) realized by the Company for its production during 1993 was
$12.93 per barrel for oil and $2.03 per Mcf for natural gas.
Ryder Scott Company ("Ryder Scott"), a firm of independent petroleum
engineers, prepared the above estimates of the Company's total proved reserves
as of December 31, 1990 through 1993.
During 1993 the Company filed Energy Information Administration Form 23
which reported natural gas and oil reserves for the year 1992. On an equivalent
barrel basis, the reserve estimates for the year 1992 contained in such report
and those reported herein for the year 1992 do not differ by more than five
percent.
DOMESTIC DEVELOPMENT ACTIVITIES
The Company is engaged in development activities primarily through the
application of thermal enhanced recovery techniques to its heavy oil properties
in the San Joaquin Valley, the use of secondary waterfloods and tertiary CO2
floods on its properties in other mature fields and the development of producing
properties acquired by the Company through its exploration successes and its
acquisition program. Thermal EOR operations involve the injection of steam into
a reservoir to raise the temperature and reduce the viscosity of the heavy oil,
facilitating the flow of the oil into producing wellbores. The Company has
operated thermal EOR projects in the San Joaquin Valley since the mid-1960s.
Similarly, the Company has extensive experience in the use of waterfloods, which
involve the injection of water into a reservoir to drive hydrocarbons into
producing wellbores. The Company has an interest in more than 50 waterflood
projects, and additional projects are planned for the future. Following the
waterflood phase, certain fields may continue to produce in response to tertiary
EOR projects, such as the injection of CO2 which mixes miscibly with the oil and
improves the displacement efficiency of the water injection. The Company's
principal CO2 floods are in the Wasson field and are operated by affiliates of
Shell Oil Company, ARCO and Amoco.
Set forth below is a discussion of some of the Company's principal
development projects. The Company has operated in the Midway-Sunset and Wasson
fields since 1905 and 1939, respectively. The Company acquired interests in the
South Belridge field from Petro-Lewis in 1987 and in January 1991 expanded its
holdings in the field with the purchase of certain properties from Mission
Operating Partnership, L.P. The Company's interests in the Kern River and
Coalinga fields were acquired in 1905 and 1977, respectively. The Gulf of Mexico
fields were discovered on leases held by the Company or
32
<PAGE> 139
acquired in the Adobe Merger, while the Delaware and Cisco-Canyon properties
were acquired as undeveloped properties.
SAN JOAQUIN VALLEY
Midway-Sunset. The Company owns a 100% working interest (92% average net
revenue interest) in over 10,000 gross acres and 2,200 active wells in the
Midway-Sunset field. Substantially all the oil produced from the Midway-Sunset
field is heavy crude oil produced principally by cyclic steam and steamflood
operations from Pleistocene and Miocene reservoirs at depths less than 2,000
feet. These steam stimulation operations were initiated in the field in the
mid-1960s. During 1993 the Midway-Sunset field accounted for approximately 50%
of the Company's domestic crude oil and liquids production.
At December 31, 1993 the Midway-Sunset field accounted for approximately
69% of the Company's domestic proved crude oil and liquid reserves. Reservoir
engineering studies prepared on behalf of the Company indicate significant
additions to its proved reserves in this field can continue to be made through
additional EOR and development projects. The Company has identified a
substantial number of locations that could be drilled in the field, depending in
part on future prices and economic conditions. The Company is pursuing
electrical cogeneration opportunities which could lower Midway-Sunset operating
costs.
South Belridge. The South Belridge field is located approximately 15 miles
north of the Midway-Sunset field. The Company operates three leases in the field
which produce heavy oil from the shallow Tulare sands and lighter low viscosity
oil from the deeper Diatomite reservoirs. Steamflood operations in the lower
Tulare sands are in progress on one of these leases and plans call for flooding
the remaining Tulare sands on this lease and all Tulare sands on another lease
in the coming years. Waterflood operations in the Diatomite reservoir have been
initiated on two leases and the Company expects to expand these operations to
include the rest of the developed area.
Coalinga. The Coalinga field is located 55 miles southwest of Fresno,
California. Successful steamfloods and a pilot steamflood project have been
conducted in the Lower Temblor Sands on three of the six leases in which the
Company owns interests in the field. During the next several years, the Company
plans to expand the pilot steamflood project in the lower sands to cover the
remaining producing area and expand steamfloods on the Upper Temblor Sands on
all leases after depletion of the lower zones. Most of the facilities required
for these projects are already in place as a result of the prior steamfloods.
Kern River. The Kern River field is located near Bakersfield, California.
The Lower Kern River Series sands have been successfully steamflooded on three
of the leases in which the Company owns an interest. Over the next several years
steamflood operations will be sequentially redeployed in the upper sands of the
Kern River Series. Eventually the Company plans to flood all sands on its
remaining leases in several stages. The Company has installed and operates a
large steam generation plant on these properties.
PERMIAN BASIN
Wasson. The Company's interests in the Wasson field principally consist of
royalty and working interests in three units which are presently under CO2
flood. Most of the expenditures for plant, facilities, wells and equipment
necessary for such tertiary recovery projects have been made. In addition, while
expenditures relating to the purchase of CO2 for the Wasson field are expected
to continue, CO2 can be recycled and, therefore, such expenditures should
decline in the future.
During 1993, the Wasson field accounted for approximately 9% of the
Company's domestic crude oil and liquids production and at December 31, 1993 the
field accounted for approximately 8% of the Company's domestic proved crude oil
and liquids reserves. Since initiation of CO2 flooding operations in 1984, the
field's previous production decline has been reversed. Reservoir engineering
studies prepared
33
<PAGE> 140
on behalf of the Company indicate significant additions to proved reserves can
be made through additional EOR and development projects.
Reeves. The Company owns a 72% net interest in the Reeves field, seven
miles east of the large Wasson field in west Texas. The field has been under
waterflood since 1965. During 1993, six wells were drilled and 16 wells were
worked over as part of a program to delineate the extended productive limits of
the field, to evaluate the potential for infill drilling and to enhance current
waterflood operations. Based on the successes of the prior year's program, the
Company plans to initiate an infill drilling and workover program in this field
in the near future.
New Mexico. During 1993, the Company increased its activity in the
light-oil Delaware prospect in Lea and Eddy Counties of southeast New Mexico. A
total of 51 gross (18.1 net) development wells were completed in 1993 with a
100% success rate and during December 1993 such wells produced approximately 1.4
MBbls of oil per day and 3.1 MMcf of natural gas per day. Net production from
this area during December 1993 totaled approximately 1.5 MBbls of oil per day
and 4.0 MMcf of natural gas per day. The Company has plans to drill additional
development wells in 1994.
Also in southeastern New Mexico, the Company participated in five gross
(2.8 net) wells in 1993 in the light oil and gas Cisco-Canyon project. Four
wells were completed as producers from the Cisco-Canyon zone by year-end and a
fifth continued production testing. The Company plans to continue delineation of
this play which contains some 75 identified potential development locations.
OFFSHORE GULF OF MEXICO
At December 31, 1993, offshore Gulf of Mexico properties accounted for 39%
of the Company's proved natural gas reserves and during 1993 these properties
accounted for approximately 56% of the Company's natural gas production.
In the Gulf Division, several new fields or field additions were placed on
production during 1993. Net production from these fields at year-end averaged
approximately 29.0 MMcf of gas per day. Further development in these fields is
either planned or under study for 1994 and 1995. The Company's activities in the
offshore Gulf of Mexico are conducted in shallow water (less than 300 feet),
where the costs of drilling, completion and production are not as uncertain as
are the costs in the Flextrend and Deepwater areas of the Gulf of Mexico. During
1993, the Company participated in the drilling of four gross (1.3 net)
exploratory wells and one gross (0.3 net) well was drilling at year-end (which
well resulted in a discovery and a multiwell development program is expected to
commence in 1994). For a description of the Company's leasehold position in the
offshore Gulf of Mexico, see "--Domestic Exploration Activities."
DOMESTIC EXPLORATION ACTIVITIES
The Company's domestic exploration focus continues to be in the Permian
Basin and the offshore Gulf of Mexico. Overall the Company participated in 22
gross (9.0 net) exploratory wells in 1993. A total of ten gross (3.6 net) were
completed as producers for a 40% net well success. At year end there were nine
gross (4.3 net) wells in some stage of drilling or completion.
As of December 31, 1993, the Company held approximately 0.3 million net
undeveloped leasehold acres in 14 states and offshore areas, excluding
approximately 0.5 million net undeveloped leasehold acres sold to Bridge in
April 1994. The primary terms of lease expire with respect to 24% of such
acreage in 1994, 25% in 1995, 15% in 1996, 10% in 1997 and the remainder
thereafter. In addition, the Company owns approximately 0.5 million net acres of
undeveloped fee minerals in Louisiana, Texas and California.
The Company also controls the oil and gas rights on approximately 8.1
million net undeveloped acres in the western United States through direct
ownership and pursuant to lease option agreements from Santa Fe Pacific Railroad
Company and other former affiliates. These lands are located in high risk
exploration areas. Due to this risk, the Company has historically negotiated
with third parties to explore this acreage with the Company to receive a royalty
or carried interest in the exploration phase. An
34
<PAGE> 141
agreement relating to substantially all of these oil and gas rights has been
entered into with Bridge. This agreement is intended to provide incentive to
Bridge to accelerate exploration activities on lands subject to these rights.
The Company will receive a small revenue interest in the event such activities
are successful.
Set forth below is a brief discussion of some of the Company's principal
exploration programs.
Permian Basin. This area continues to be one of the Company's most active
and successful exploration areas. During 1993, the Company participated in 18
gross (7.7 net) exploratory wells. Eight gross (3.3 net) of these were completed
in 1993 as oil or gas discoveries. Additionally, eight gross (4.0 net) were in
some phase of drilling or completing at year-end.
Drilling objectives for the Company's exploratory program target oil and
gas zones at depths of between 2,500 to 15,000 feet. The shallower targets such
as the Delaware and Cisco-Canyon formations are providing successful results.
The Delaware program in southeast New Mexico was the subject of seven gross (3.7
net) exploratory and 51 gross (18.1 net) development wells completed in 1993. A
success rate of 58% of the net exploratory wells and 100% of the net development
wells was achieved in this increasingly active light oil play. Currently, the
Company has identified in excess of 150 development well locations and has 20
exploratory prospects in inventory to be drilled over the next several years.
In the west Texas Permian Basin, the Company completed the shooting of 3-D
seismic over its 250-square mile block near Midland last fall. The joint venture
block contains over 100,000 net acres of lands owned or controlled by the
Company and its partners. Almost all of the Company's 25% interest in the 3-D
seismic was paid by a promoted partner. Drilling began in December 1993 on two
prospects identified in this program. Additional drilling is planned on a
variety of other prospects in 1994 at depths of 10,000 to 12,000 feet.
Offshore Gulf of Mexico. The Company participated in four gross (1.3 net)
exploratory wells in the offshore Gulf of Mexico in 1993 and one gross (0.3 net)
was drilling at year-end. One gross (0.3 net) well resulted in a discovery on
which a multi-well development program will commence in the first quarter of
1994.
The Company acquired 3-D seismic coverage over 12 blocks during 1993 adding
to its extensive Gulf of Mexico seismic database which includes 3-D coverage on
57 blocks. Currently, the Company has 35 exploratory prospects in inventory and
some 30 development locations identified, a portion of which are exploratory and
planned to be drilled in 1994.
At year-end, the Company owned 179 blocks of acreage in the offshore Gulf
of Mexico consisting of approximately 299,800 gross (147,400 net) undeveloped
acres and 257,900 gross (79,000 net) developed acres.
INTERNATIONAL DEVELOPMENT ACTIVITIES
Indonesia. The Company, through a wholly owned subsidiary, is engaged in
the production of crude oil in Indonesia through a joint venture (the "Salawati
Basin Joint Venture") formed in 1970 to explore for and develop hydrocarbon
reserves in the Salawati Basin area of Irian Jaya. At December 31, 1993, the
Company held a 33 1/3% participation interest in, and acts as operator for, the
Salawati Basin Joint Venture. The Salawati Basin Joint Venture operates under a
production sharing contract (the "PSC") with the Indonesia state oil agency
("Pertamina"), which had an initial term of 30 years and expires in the year
2000. The Company is currently negotiating with such state oil agency to extend
the contract for an additional 20 years. As of December 31, 1993, the contract
covered an area of approximately 235,000 acres. Production occurs from seven oil
and three gas condensate fields.
The PSC entitles the Salawati Basin Joint Venture to recover all of its
expenditures related to the operation (the "cost recovery amount") before any
additional production is shared with the Indonesian state oil agency, which
recovery is effected by allocating to the Salawati Basin Joint Venture a portion
of the crude oil production sufficient, at the Indonesian government official
crude oil price ("ICP"), to offset
35
<PAGE> 142
the cost recovery amount. The balance of production after the cost recovery
amount is divided between the parties, with approximately 66% allocated to
Pertamina and 34% allocated to the Salawati Basin Joint Venture. However, 25% of
the 34% pre-tax portion (8.5% of total production) must be sold into the
Indonesian domestic market for $0.20 per barrel. The entire entitlement of the
Salawati Basin Joint Venture under the PSC, including the domestic market
obligation, averaged approximately 10.1 MBbls per day (approximately 3.4 MBbls
per day net to the Company) for the year ended December 31, 1993. The Salawati
Basin Joint Venture is required to pay Indonesian income taxes at the rate of
56%.
The Company, through another subsidiary, has also entered into a joint
venture with Pertamina to explore the Salawati Island Block of Irian Jaya. The
effective date of this joint venture is April 23, 1990 with a term of 30 years.
At December 31, 1993, the Company held a 16 2/3% participation interest in the
block which covers 1.09 million acres. The Company and Pertamina (with its 50%
interest) jointly operate the contract area. In 1991, a successful exploratory
well tested at a combined rate of 3.6 MBbls of oil per day and was followed by
two successful delineation wells. Pertamina declared the field commercial in
January 1993 and designated it as the Matoa field. Sales of production began in
January 1993. Development activities through 1993 have the Matoa field producing
approximately 5.6 MBbls of oil per day from eight wells as of December 31, 1993.
Under the terms of the PSC, the joint venture participants are allowed to
recover the cost recovery amount, after an initial 20% portion (2.9% to the
joint venture participants and 17.1% to Pertamina) has been deducted, by
allocating to the joint venture participants a portion of the crude oil
production ("cost oil") sufficient to offset the cost recovery amount. All
unrecovered costs in any calendar year can be carried forward to future years.
The balance of production after allocation of cost oil is allocated
approximately 85.5% to Pertamina and 14.5% to the other Salawati Island Venture
participants. However, 7.25% of the gross production allocated to the joint
venture participants must be sold into the Indonesian domestic market for 10% of
ICP.
Argentina. In 1991, the Company, through a wholly owned subsidiary,
acquired an 18% non-operated working interest (15.84% net interest) in the El
Tordillo field in Chubut Province, Argentina. At that time, the field was
producing approximately 10,500 barrels of oil per day. The Company has agreed to
spend approximately $16.7 million net during the period from July 1, 1992 to
July 1, 1996 on development and maintenance of the field which began with an
extensive workover and recompletion program. As of December 31, 1993 the El
Tordillo owners have completed 163 such workovers and drilled three new wells.
During that time, production increased to approximately 16.0 MBbls of oil per
day. The Company expects this program to continue through 1994 and anticipates
an expansion of the existing waterflood facilities.
Under the terms of the contract with the Argentine national oil company,
the joint venture group is allowed to sell crude oil produced from this field
into the open market. There is a 12% royalty on gross production and the joint
venture is taxed at a 30% rate after deductions for capitalized costs and
expenses.
In April 1993, the Company's subsidiary completed the Sierra Chata X-1 as a
successful exploratory test in Chihuidos Block, Neuquen Province, Argentina. The
well produced at a combined rate of 22.2 MMcf per day and 109 barrels of
condensate per day. Carbon dioxide content of the natural gas was 6%. Five
successful delineation wells were drilled in 1993. Producing rates on these
wells varied from 3.2 MMcf to 27.6 MMcf per day. Engineering and geological
studies are presently being undertaken to develop the field through additional
drilling, with 4.0 gross (1.0 net) additional wells currently planned for 1994.
In addition, the Company and its partners intend to build a gas processing
facility and a 40-mile gathering pipeline during 1994 that will transport
production from the field and interconnect with a main transmission line owned
by a third party that transports gas to Buenos Aires and other major markets.
Construction of the gas processing facility and the pipeline and the drilling of
the development wells are estimated to cost an aggregate of $76.0 million gross
($17.2 million net to the Company's interest). The Company expects that sales of
production from the Sierra Chata discovery will commence in 1995.
36
<PAGE> 143
INTERNATIONAL EXPLORATION ACTIVITIES
In 1993, the Company had its most active year ever in the international
arena. The Company participated in six gross (1.8 net) exploratory wells of
which two gross (0.5 net) were completed as natural gas wells. Additionally,
four gross (1.2 net) wells were either drilling or completing at year-end.
The Company made one exploration discovery in 1993. The Sierra Chata
natural gas discovery in the Neuquen Basin of Argentina is being developed from
sandstone reservoirs at 6,000 feet. The Company has a 22.5% working interest
(20% net revenue interest) and is operator of this field. To date a total of six
gross (1.3 net) wells have been drilled with no dry holes. Combined gross flow
rates from these six wells are in excess of 100 MMcf of gas and 500 barrels of
condensate per day. Additional development drilling will continue during 1994 to
increase production capacity and further define the limits of the field. See
"--International Development Activities."
The Company plans to drill eight gross (2.8 net) wells in 1994 in addition
to the four gross (1.2 net) wells which carried over from 1993 in either a
drilling or completing status. The 1994 drilling and exploratory activity will
be centered principally in Indonesia and South America. Of the total wells to be
completed in 1994, four gross (1.2 net) are in Indonesia, four gross (1.3 net)
are in Argentina and Bolivia, one gross (0.2 net) is in Papua New Guinea, two
gross (1.0 net) are in Canada and one gross (0.3 net) is in Gabon (West Africa).
The Company holds exploration contracts totaling 3.5 million net acres in
eight foreign countries. The majority of acreage is in Indonesia (1.1 million
net acres) and South America (1.2 net million acres) with the balance in Canada,
Morocco, Myanmar, Papua New Guinea and Gabon.
DRILLING ACTIVITIES
The table below sets forth, for the periods indicated, the number of wells
drilled in which the Company had an economic interest. As of December 31, 1993,
the Company was in the process of drilling or completing 9 gross (4.3 net)
domestic exploratory wells and 13 gross (5.3 net) domestic development wells, 4
gross (1.2 net) foreign exploratory wells and 3 gross (1.0 net) foreign
development wells.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1993 1992 1991
---------------- -------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ---- ----- ------
<S> <C> <C> <C> <C> <C> <C>
Development Wells
Domestic
Completed as natural gas wells......... 21 6.0 6 1.5 25 7.5
Completed as oil wells................. 237 180.0 62 39.0 220 167.3
Dry holes.............................. 10 3.6 5 0.4 6 1.6
Foreign
Completed as natural gas wells......... 4 1.0 -- -- -- --
Completed as oil wells................. 3 0.9 -- -- -- --
----- ------ ----- ---- ----- ------
275 191.5 73 40.9 251 176.4
----- ------ ----- ---- ----- ------
Exploratory Wells
Domestic
Completed as natural gas wells......... 3 0.9 1 0.3 6 2.0
Completed as oil wells................. 7 2.7 4 1.2 6 1.9
Dry holes.............................. 12 5.4 2 0.6 19 7.2
Foreign
Completed as natural gas wells......... 2 0.4 -- -- -- --
Completed as oil wells................. -- -- 1 0.3 -- --
Dry holes.............................. 4 1.3 4 1.3 3 0.4
----- ------ ----- ---- ----- ------
28 10.7 12 3.7 34 11.5
----- ------ ----- ---- ----- ------
303 202.2 85 44.6 285 187.9
----- ------ ----- ---- ----- ------
----- ------ ----- ---- ----- ------
</TABLE>
37
<PAGE> 144
DOMESTIC ACREAGE
The following table summarizes the Company's developed and undeveloped fee
and leasehold acreage in the United States at December 31, 1993. Excluded from
such information is acreage in which the Company's interest is limited to
royalty, overriding royalty and other similar interests.
<TABLE>
<CAPTION>
UNDEVELOPED DEVELOPED
--------------------- ---------------------
GROSS NET GROSS NET
-------- -------- -------- --------
<S> <C> <C> <C> <C>
Alabama--Offshore................................ -- -- 23,040 12,480
Alabama--Onshore................................. 3,089 108 6,063 382
Arkansas......................................... 633 493 4,177 3,173
California--Offshore............................. -- -- 17,280 2,074
California--Onshore.............................. 249,207 248,990 7,391 7,011
Colorado......................................... -- -- 6,368 5,657
Illinois......................................... 202 50 43 13
Kansas........................................... 19,433 19,373 4,591 1,002
Louisiana--Offshore.............................. 222,376 116,843 190,675 57,721
Louisiana--Onshore............................... 17,575 16,620 14,635 2,941
Michigan......................................... -- - 71 11
Mississippi...................................... 114 30 3,724 810
Montana.......................................... -- -- 3,196 142
Nevada........................................... 3,491 764 9,455 9,455
New Mexico....................................... 195,750 155,594 41,427 18,852
New York......................................... -- -- 189 47
North Dakota..................................... 1,509 544 4,337 1,377
Oklahoma......................................... 1,917 1,917 29,589 9,940
Texas--Offshore.................................. 77,397 30,545 67,194 21,243
Texas--Onshore................................... 180,828 174,912 246,287 168,421
Utah............................................. 1,348 575 8,389 3,494
Wyoming.......................................... 13,785 10,804 25,888 11,312
-------- -------- -------- --------
988,654 778,162 714,009 337,558
-------- -------- -------- --------
-------- -------- -------- --------
</TABLE>
The foregoing table excludes approximately 2,033,400 gross (1,682,000 net)
undeveloped fee and leasehold acres and 80,200 gross (45,900 net) developed
acres sold to Bridge in April 1994 pursuant to a purchase agreement signed in
December 1993 and 123,000 gross (123,000 net) undeveloped acres sold in January
1994.
FOREIGN ACREAGE
The following table summarizes the Company's foreign acreage at December
31, 1993:
<TABLE>
<CAPTION>
UNDEVELOPED DEVELOPED
------------------------- -------------------
GROSS NET GROSS NET
----------- --------- ------- -------
<S> <C> <C> <C> <C>
Argentina...................................... 2,103,010 550,457 53,988 10,858
Bolivia........................................ 1,442,446 649,100 -- --
Canada (Alberta)............................... 150,703 68,071 -- --
Gabon.......................................... 701,000 175,250 -- --
Indonesia...................................... 4,439,569 1,059,193 9,360 2,870
Morocco........................................ 1,300,000 422,500 -- --
Myanmar........................................ 394,000 315,200 -- --
Papua New Guinea............................... 1,970,000 295,500 -- --
----------- --------- ------- -------
12,500,728 3,535,271 63,348 13,728
----------- --------- ------- -------
----------- --------- ------- -------
</TABLE>
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<PAGE> 145
CURRENT MARKETS FOR OIL AND GAS
The revenues generated by the Company's operations are highly dependent
upon the prices of, and demand for, oil and gas. For the last several years,
prices of these products have reflected a worldwide surplus of supply over
demand. The price received by the Company for its crude oil and natural gas
depends upon numerous factors beyond the Company's control, including economic
conditions in the United States and elsewhere and the world political situation
as it affects OPEC, the Middle East (including the current embargo of Iraqi
crude oil from worldwide markets) and other producing countries, the actions of
OPEC and governmental regulation. The fluctuation in world oil prices continues
to reflect market uncertainty regarding OPEC's ability to control member country
production and underlying concern about the balance of world demand for and
supply of oil and natural gas. Decreases in the prices of oil and gas have had,
and could have in the future, an adverse effect on the Company's development and
exploration programs, proved reserves, revenues, profitability, cash flow and
dividend levels. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations--General."
The Company believes the market for heavy crude oil produced in California
differs substantially from the remainder of the domestic crude oil market. It is
necessary to heat or dilute heavy oil to make it flow, which increases
transportation and handling costs, and it is also more costly to refine. As a
result, the price paid for heavy crude oil is generally lower than the price
paid for light crudes. In addition, there is currently an oversupply of crude
oil in the California market that has had an adverse effect on the prices for
crude oil in that market. Although no assurance can be given, the Company
believes that such oversupply will not continue for the long term due to the
availability of crude oil pipelines to transport excess crude oils, including
blended oils, to markets in the Midwest and west Texas, and due to the decline
of crude oil produced from the North Slope of Alaska.
From time to time the Company has hedged a portion of its oil and natural
gas production to manage its exposure to volatility in prices of oil and natural
gas. The Company used several instruments whereby monthly settlements were based
on the difference between the price, or a range of prices, specified in the
instruments and the monthly average of the daily settlement prices of certain
WTI crude oil futures contracts or of certain natural gas futures contracts
quoted on the New York Mercantile Exchange. In instances where the actual
average of the daily settlement price was less than the price specified in the
contract, the Company received a settlement based on the difference; in
instances where the actual average of the daily settlement price was higher than
the specified price, the Company paid an amount based on the difference. The
instruments utilized by the Company differed from futures contracts in that
there was no contractual obligation which required or allowed for the future
delivery of the product. Settlements were included in revenues in the period in
which the oil and natural gas were sold.
In 1990, oil hedges resulted in a $10.7 million reduction in oil revenues
and in 1991 and 1992 oil hedges resulted in an increase in oil revenues of $41.7
million and $9.7 million, respectively. The Company has had no oil hedging
contracts subsequent to 1992. In 1992 and 1993, natural gas hedges resulted in a
reduction in natural gas revenues of $0.5 million and $8.2 million,
respectively. The Company currently has six open natural gas hedging contracts
covering an aggregate of approximately 24.6 MMcf of natural gas per day with
terms beginning in March and April 1994 and ending in August and September 1994.
The "approximate break-even price" (the average of the monthly settlement prices
of the applicable futures contracts which would result in no settlement being
due to or from the Company) with respect to such contracts is approximately
$1.88 per Mcf. In addition, a certain party holds an option to exercise an
additional hedging contract for a five-month period beginning May 1994 covering
approximately 4.7 MMcf of natural gas per day at an approximate break-even price
of $1.92 per Mcf. The Company has no other outstanding natural gas hedging
instruments.
During 1993, affiliates of Shell Oil Company and Celeron Corporation
accounted for approximately 23% and 15%, respectively, of the Company's domestic
crude oil and liquids and natural gas revenues. No other individual customer
accounted for more than 10% of such revenues during 1993. Substantially all of
the Company's oil and natural gas production is currently sold at
market-responsive prices that approximate spot prices. Availability of a ready
market for the Company's oil and gas production depends
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<PAGE> 146
on numerous factors, including the level of consumer demand, the extent of
worldwide oil production, the cost and availability of alternative fuels, the
cost of and proximity of pipelines and other transportation facilities,
regulation by state and federal authorities and the cost of complying with
applicable environmental regulations.
In December 1993, the Company signed a seven-year gas sales contract with
Hadson pursuant to the terms of which Hadson will market substantially all of
the Company's domestic natural gas production. Pursuant to such gas contract,
Santa Fe dedicated to Hadson all of its domestic natural gas production from
specified existing wells, which consist of essentially all of the Company's
domestic natural gas production, except to the extent such production was
dedicated under pre-existing contracts. Upon the expiration of any such
pre-existing contracts, that production shall also be dedicated to Hadson.
In addition to production from existing wells, such gas contract provides
for the dedication by the Company of gas production from certain domestic
development wells and exploration wells to the extent that the Company accepts
proposals from Hadson to gather and market production from such exploration
wells. Production from gas wells acquired by the Company pursuant to an
acquisition of producing oil and gas properties will not be dedicated under the
gas contract but may be dedicated by the mutual agreement of the Company and
Hadson.
Pursuant to the gas contract, Hadson will be required to pay the Company
for all production delivered at a price for such gas equal to stipulated
published monthly index prices. Hadson is obligated to use its best efforts to
receive gas from the Company at delivery points so as to maximize the net price
received by the Company for such production. Payment for purchases by Hadson are
to be made in immediately available funds no later than the last working day of
the month following the month of production.
SANTA FE ENERGY TRUST
In November 1992, 5,725,000 Depositary Units, each consisting of beneficial
ownership of one unit of undivided interest in the Trust and a $20 face amount
beneficial ownership interest in a $1,000 face amount zero-coupon United States
Treasury obligation maturing on February 15, 2008, were sold in a public
offering. The assets of the Trust consist of certain oil and gas properties
conveyed by the Company. 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. The
Company received the remaining $70.1 million of proceeds and retained 575,000
Depositary Units. A portion of the proceeds received by the Company was used to
retire $30.0 million of the debt incurred in connection with the Adobe Merger
and the remainder was used for general corporate purposes. In the first quarter
of 1994, the Company sold the remaining 575,000 Depositary Units it held for
$11.3 million.
The properties conveyed to the Trust consisted of two term royalty
interests in two production units in the Wasson field in west Texas and a net
profits royalty interest in certain royalty and working interests in a
diversified portfolio of properties located in 12 states. At December 31, 1993,
5.2 MMBOE of the Company's estimated proved reserves were subject to such net
profits interest. The reserve estimates included herein reflect the conveyance
of the Wasson term royalties to the Trust.
For any calendar quarter ending on or prior to December 31, 2002, the Trust
will receive additional royalty payments to the extent that such payments are
required to provide distributions of $0.40 per Depositary Unit per quarter. Such
additional royalty payments, if needed, will come from the Company's remaining
royalty interest in one of the production units in the Wasson field described
above, and are non-recourse to the Company. If such additional payments are
made, certain proceeds otherwise payable to the Trust in subsequent quarters may
be reduced to recoup the amount of such additional payments. The aggregate
amount of the additional royalty payments (net of any amounts recouped) are
limited to $20.0 million on a revolving basis. The Company was required to make
an additional royalty payment of $362,000 with respect to the distribution made
by the Trust for operations during the quarter ended
40
<PAGE> 147
December 31, 1993. On April 21, 1994, the Trust announced that a distribution of
$0.40 per Depositary Unit would be paid for the calendar quarter ended March 31,
1994 to Unitholders of record on May 16, 1994, which distribution will include
an additional royalty payment by the Company of $505,700.
OTHER BUSINESS MATTERS
Competition
The Company faces competition in all aspects of its business, including,
but not limited to, acquiring reserves, leases, licenses and concessions;
obtaining goods, services and labor needed to conduct its operations and manage
the Company; and marketing its oil and gas. The Company's competitors include
multinational energy companies, government-owned oil and gas companies, other
independent producers and individual producers and operators. The Company
believes that its competitive position is affected by price, its geological and
geophysical capabilities and ready access to markets for production. Many
competitors have greater financial and other resources than the Company, more
favorable exploration prospects and ready access to more favorable markets for
their production. The Company believes that the well-defined nature of the
reservoirs in its long-lived oil fields, its expertise in EOR methods in these
fields, its active development and exploration position and its experienced
management may give it a competitive advantage over some other producers.
Regulation of Crude Oil and Natural Gas
The petroleum industry is subject to various types of regulation throughout
the world, including regulation in the United States by state and federal
agencies. Domestic legislation affecting the oil and gas industry is under
constant review for amendment or expansion, frequently increasing the regulatory
burden. Also, numerous departments and agencies, both federal and state, are
authorized by statute to issue and have issued rules and regulations binding on
the oil and gas industry and its individual members, compliance with which is
often difficult and costly and which may carry substantial penalties for
non-compliance. Although the regulatory burden on the oil and gas industry
increases the cost of doing business and, consequently, affects profitability,
generally these burdens do not appear to affect the Company any differently or
to any greater or lesser extent than other companies in the industry with
similar types and quantities of production. While the Company is a party to
several regulatory proceedings before governmental agencies arising in the
ordinary course of business, management does not believe that the outcome of
such proceedings will have a material adverse affect on the operations or
financial condition of the Company. Set forth below is a general description of
certain state and federal regulations which have an effect on the Company's
operations.
State Regulation. State statutes and regulations require permits for
drilling operations, drilling bonds and reports concerning operations. Most
states in which the Company operates also have statutes and regulations
governing the conservation of oil and gas and the prevention of waste, including
the unitization or pooling of oil and gas properties and rates of production
from oil and gas wells. Rates of production may be regulated through the
establishment of maximum daily production allowables on a market demand or
conservation basis or both.
Federal Regulation. A portion of the Company's oil and gas leases are
granted by the federal government and administered by the Bureau of Land
Management ("BLM") and the Minerals Management Service ("MMS"), both of which
are federal agencies. Such leases are issued through competitive bidding,
contain relatively standardized terms and require compliance with detailed BLM
and MMS regulations and orders (which are subject to change by the BLM and the
MMS). For offshore operations, lessees must obtain MMS approval for exploration
plans and development and production plans prior to the commencement of such
operations. In addition to permits required from other agencies (such as the
Coast Guard, Army Corps of Engineers and Environmental Protection Agency),
lessees must obtain a permit from the BLM or the MMS prior to the commencement
of drilling.
The interstate transportation of natural gas is regulated by the Federal
Energy Regulatory Commission ("FERC") under the Natural Gas Act of 1938 and, to
a lesser extent, the Natural Gas Policy Act of
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<PAGE> 148
1978 (collectively, the "Acts"). Numerous questions have been raised concerning
the interpretation and implementation of several significant provisions of the
Acts, as well as the regulations and policies promulgated by FERC thereunder. A
number of lawsuits and administrative proceedings have been instituted which
challenge the validity of regulations implementing the Acts. In addition, as
described below, FERC currently has under consideration various policies and
proposals which will affect the marketing of gas under new and existing
contracts.
Since 1991, FERC's regulatory efforts have centered largely around its
generic rulemaking proceedings, Order No. 636. Through Order No. 636 and
successor orders, FERC has undertaken to restructure the interstate pipeline
industry with the goal of providing enhanced access to, and competition among,
alternative gas suppliers. By requiring interstate pipelines to "unbundle" their
sales services and to provide its customers with direct access to any upstream
pipeline capacity held by pipelines, Order No. 636 has enabled pipeline
customers to choose the levels of transportation and storage service they
require, as well as to purchase gas directly from third-party merchants other
than the pipelines.
Although the implementation of Order No. 636 on individual interstate
pipelines is nearing completion, this process is not yet final. Moreover, nearly
all of these individual restructuring proceedings, as well as Order No. 636
itself and the regulations promulgated thereunder, are subject to pending
appellate review and could possibly be substantially modified by the courts.
Thus, while Order No. 636, if ultimately implemented without substantial change,
should generally facilitate the transportation of gas and the direct access to
end-user markets, the precise impact of these regulations on marketing
production cannot be predicted at this time.
Beyond Order No. 636, FERC is now considering a number of other important
policies, all of which could significantly affect the marketing of gas. Some of
the more notable of these regulatory initiatives include FERC's rulemakings on
gathering and production-area rate design, regulation of pipeline marketing
affiliates under Order No. 497, and standards for pipeline electronic bulletin
boards and electronic data exchange.
The U.S. Congress has historically been active in the area of oil and
natural gas regulation. Although no prediction can be made concerning future
regulation or legislation which may affect the competitive status of the
Company, or affect the prices at which it may sell its oil and gas, any
regulation or legislation that, directly or indirectly, lowers price levels for
oil and gas sold or increases the costs of production could have an adverse
effect on the Company's operations.
Environmental Regulation
Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs. In
particular, the Company's oil and gas exploration, development, production and
EOR operations, its activities in connection with storage and transportation of
liquid hydrocarbons and its use of facilities for treating, processing,
recovering or otherwise handling hydrocarbons and wastes therefrom are subject
to stringent environmental regulation by governmental authorities. Such
regulation has increased the cost of planning, designing, drilling, installing,
operating and abandoning the Company's oil and gas wells and other facilities.
The Company has expended significant resources, both financial and managerial,
to comply with environmental regulations and permitting requirements and
anticipates that it will continue to do so in the future in order to comply with
stricter industry and regulatory safety standards such as those described below.
Although the Company believes that its operations and facilities are in general
compliance with applicable environmental regulations, risks of substantial costs
and liabilities are inherent in oil and gas operations and there can be no
assurance that significant costs and liabilities will not be incurred in the
future. Moreover, it is possible that other developments, such as increasingly
strict environmental laws, regulations and enforcement policies thereunder, and
claims for damages to property, employees, other persons and the environment
resulting from the Company's operations, could result in substantial costs and
liabilities in the future. Although the resulting costs cannot be accurately
estimated at this time, these requirements and risks typically apply
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<PAGE> 149
to companies with types and quantities of production similar to those of the
Company and to the oil and gas industry in general.
Offshore Production. Offshore oil and gas operations are subject to
regulations of the United States Department of the Interior, the Department of
Transportation, the United States Environmental Protection Agency ("EPA") and
certain state agencies. In particular, the Federal Water Pollution Control Act
of 1972, as amended ("FWPCA"), imposes strict controls on the discharge of oil
and its derivatives into navigable waters. The FWPCA provides for civil and
criminal penalties for any discharges of petroleum in reportable quantities and,
along with the Oil Pollution Act of 1990 and similar state laws, imposes
substantial liability for the costs of oil removal, remediation and damages.
Solid and Hazardous Waste. The Company currently owns or leases, and has
in the past owned or leased, numerous properties that have been used for
production of oil and gas for many years. Although the Company has utilized
operating and disposal practices that were standard in the industry at the time,
hydrocarbons or other solid wastes may have been disposed or released on or
under the properties owned or leased by the Company. State and federal laws
applicable to oil and gas wastes and properties have gradually become more
strict. Under these new laws, the Company has been, and in the future 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 Company generates hazardous and nonhazardous wastes that are subject to
the federal Resource Conservation and Recovery Act and comparable state
statutes. The EPA has limited the disposal options for certain hazardous wastes
and has recently issued stricter disposal standards for nonhazardous wastes.
Furthermore, it is possible that additional wastes (which could include certain
wastes generated by the Company's oil and gas operations) could in the future be
designated as "hazardous wastes," which are subject to more rigorous and costly
disposal requirements. In response to the changing regulatory environment, the
Company has made certain changes in its operations and disposal practices. For
example, the Company has commenced remediation of sites or replacement of
facilities in some locations where its wastes have previously been disposed.
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 or 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 responses to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. In the course of its operations, the Company has generated and
will generate wastes that may fall within CERCLA's definition of "hazardous
substances." The Company may be responsible under CERCLA for all or part of the
costs to clean up sites at which such wastes have been disposed.
The Company has been identified as one of over 250 potentially responsible
parties ("PRPs") at a superfund site in Los Angeles County, California. The site
was operated by a third party as a waste disposal facility from 1948 until 1983.
The EPA is requiring the PRPs to undertake remediation of the site in several
phases, which include site monitoring and leachate control, gas control and
final remediation. In 1989 the EPA and a group of the PRPs entered into a
consent decree covering the site monitoring and leachate control phase of
remediation. The Company is a member of the group that is responsible for
carrying out this first phase of work, which is expected to be completed in five
to eight years. The maximum liability of the group, which is joint and several
for each member of the group, for the first phase is $37.0 million, of which the
Company's share is expected to be approximately $2.4 million ($1.3 million after
recoveries from working interest participants in the unit at which the wastes
were generated) payable over the period that the phase one work is performed.
The EPA and a group of PRPs of which the Company is a member have also entered
into a subsequent consent decree with respect to the second phase of work (gas
control). The liability of this group has not been capped, but is estimated to
be
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<PAGE> 150
$130 million. The Company's share of costs for this phase, however, is expected
to be approximately of the same magnitude as that of the first phase because
more parties are involved in the settlement. The Company has provided for costs
with respect to the first two phases, but it cannot currently estimate the cost
of any subsequent phases of work which may be required by the EPA.
In 1989, Adobe received requests from the EPA for information pursuant to
Section 104(e) of CERCLA with respect to the Gulf Coast Vacuum Services and D.
L. Mud superfund sites located in Abbeville, Louisiana. The EPA has issued its
record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued
to all PRPs at the site a settlement order pursuant to Section 122 of CERCLA. On
December 15, 1993 the Company entered into a cost-sharing agreement with other
PRPs to participate in the final remediation of the Gulf Coast site, which is
presently estimated to cost $15.0 million. The Company's share of the
remediation is approximately $600,000 and reflects its proportionate share of
the "orphans' share" for this site. With respect to the D.L. Mud site, a former
property owner has already conducted remedial activities at the site under a
state agency agreement. To date, the Company has not been requested to share in
the remediation costs. The extent, if any, of any further necessary remedial
activity at, and the prospective PRPs and the Company's financial obligations
for, the D. L. Mud site has not been finally determined.
The Company has received a request for information from the EPA regarding
the Lee Acres Landfill CERCLA site in New Mexico. The Company advised the EPA
that it was not able to locate any information indicating that it had used that
facility. The Company is investigating its potential connection, if any, to this
facility and is not able to estimate its share of costs, if any, for the site at
this time.
On April 4, 1994, the Company received a request from the EPA for
information pursuant to Section 104(a) of CERCLA and a letter ordering the
Company and seven other PRPs to negotiate with the EPA regarding implementation
of a remedial plan for a site located in Sante Fe Springs, California. The
Company owned the property on which the site is located from 1921 to 1932. After
the Company sold the property, hazardous wastes were allegedly disposed there by
a third party who operated a disposal site. The EPA estimates that the total
past and future costs for remediation will approximate $9 million. The Company
believes that it has valid defenses to liability. While it is still
investigating its exposure, if any, for the remedial costs, the Company does not
believe that any such costs would be material.
Air Emissions. The operations of the Company, including its operations in
the San Joaquin Valley, are subject to local, state and federal regulations for
the control of emissions from sources of air pollution. Legal and regulatory
requirements in this area are increasing, and there can be no assurance that
significant costs and liabilities will not be incurred in the future as a result
of new regulatory developments. In particular, the 1990 Clean Air Act Amendments
will impose additional requirements that may affect the Company's operations,
including permitting of existing sources and control of hazardous air
pollutants. However, it is impossible to predict accurately the effects, if any,
of the Clean Air Act Amendments on the Company at this time. The Company has
been and may in the future be subject to administrative enforcement actions for
failure to comply strictly with air regulations or permits. These administrative
actions are generally resolved by payment of a monetary penalty and correction
of any identified deficiencies. Alternatively, regulatory agencies may require
the Company to forego construction or operation of certain air emission sources.
Other. The Company is 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 (such as California Proposition 65) require the Company
to organize information about hazardous materials used or produced in its
operations. Certain of this information must be provided to employees, state and
local governmental authorities and local citizens. The Company's facilities in
California are also subject to California Proposition 65, which was adopted in
1986 to address discharges and releases of, or exposures to, toxic chemicals in
the environment. Proposition 65 makes it illegal to knowingly discharge a listed
chemical if the chemical will pass (or probably will pass) into any source of
drinking water. It also prohibits companies from knowingly and intentionally
exposing any
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<PAGE> 151
individual to such chemicals through ingestion, inhalation or other exposure
pathways without first giving a clear and reasonable warning.
Although generally less stringent, the Company's foreign operations are
subject to similar foreign laws respecting environmental and worker safety
matters.
Insurance Coverage Maintained with Respect to Operations
The Company maintains insurance policies covering its operations in amounts
and areas of coverage normal for a company of its size in the oil and gas
exploration and production industry. These coverages include, but are not
limited to, workers' compensation, employers' liability, automotive liability
and general liability. In addition, an umbrella liability and operator's extra
expense policies are maintained. All such insurance is subject to normal
deductible levels. The Company does not insure against all risks associated with
its business either because insurance is not available or because it has elected
not to insure due to prohibitive premium costs.
Employees
As of December 31, 1993, the Company had approximately 777 employees, 210
of whom were covered by a collective bargaining agreement which expires on
January 31, 1996. The Company believes that its relations with its employees are
satisfactory.
Legal Proceedings
The Company, its subsidiaries and other related companies are named
defendants in several lawsuits and named parties in certain governmental
proceedings arising in the ordinary course of business. For a description of
certain proceedings in which the Company is involved, see "--Environmental
Regulation." While the outcome of lawsuits or other proceedings against the
Company cannot be predicted with certainty, management does not expect these
matters to have a material adverse effect on the financial position or results
of operations of the Company.
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<PAGE> 152
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
The current directors and executive officers of the Company and their ages
(as of January 1, 1994) and positions are listed below.
<TABLE>
<CAPTION>
NAME AGE POSITION
---- --- --------
<S> <C> <C>
James L. Payne................... 56 Chairman of the Board,
President and Chief Executive Officer
Hugh L. Boyt..................... 48 Senior Vice President--Production
Jerry L. Bridwell................ 50 Senior Vice President--Exploration and Land
Keith P. Hensler................. 62 Senior Vice President--Marketing
Richard B. Bonneville............ 51 Vice President--Planning and Administration
E. Everett Deschner.............. 53 Vice President--Reservoir Engineering and
Evaluation
C. Ed Hall....................... 51 Vice President--Public Affairs
Charles G. Hain, Jr.............. 47 Vice President--Employee Relations
David L. Hicks................... 44 Vice President--Law and General Counsel
Michael J. Rosinski.............. 48 Vice President and Chief Financial Officer
John R. Womack................... 55 Vice President--Business Development
Rod F. Dammeyer.................. 53 Director
Marc J. Shapiro.................. 47 Director
William E. Greehey............... 57 Director
Robert F. Vagt................... 47 Director
Melvyn N. Klein.................. 52 Director
Robert D. Krebs.................. 51 Director
David M. Schulte................. 47 Director
Allan V. Martini................. 66 Director
Michael A. Morphy................ 61 Director
Kathryn D. Wriston............... 55 Director
Reuben F. Richards............... 64 Director
</TABLE>
The business experience of the above officers and directors for the past
five years is described below. Unless otherwise stated, all offices were held
with Santa Fe Energy Company prior to its merger with the Company. Each
executive officer holds office until his successor is elected or appointed or
until his earlier death, resignation or removal.
James L. Payne has served as a Director since 1986 and has been Chairman of
the Board, President and Chief Executive Officer of the Company since June 1990.
Mr. Payne was President of Santa Fe Energy Company from January 1986 to January
1990 when he became President of the Company. From 1982 to January 1986 Mr.
Payne was Senior Vice President--Exploration and Land of Santa Fe Energy
Company. Mr. Payne is also a director of Pool Energy Services Co. (oilfield
services) and Hadson (natural gas transportation and marketing).
Hugh L. Boyt has been Senior Vice President--Production since March 1,
1990. From 1989 until March 1990, Mr. Boyt served as Corporate Production
Manager. From 1983, when Mr. Boyt joined the Company, until 1989 he served as
District Production Manager--Permian Basin.
Jerry L. Bridwell has been Senior Vice President--Exploration and Land
since 1986. Mr. Bridwell served in various other capacities, including Vice
President--Exploration, Central Division, since joining the Company in 1974.
Keith P. Hensler has been Senior Vice President--Marketing since January
1990. From 1980, when Mr. Hensler joined the Company, until January 1990, he
served as Vice President--Marketing. Mr. Hensler is also Senior Vice President
of Energy Products.
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<PAGE> 153
Richard B. Bonneville has been Vice President--Planning and Administration
since 1988. Prior to such time Mr. Bonneville served as Secretary of Santa Fe
Pacific Corporation ("SFP").
E. Everett Deschner has been Vice President--Reservoir Engineering and
Evaluation since April 1990. From 1982, when Mr. Deschner joined the Company,
until 1990, he served as Manager-- Engineering and Evaluation.
C. Ed Hall has been Vice President--Public Affairs since March 1991. Prior
to such time Mr. Hall served as Director--Public Affairs since joining the
Company in 1984.
Charles G. Hain, Jr. has been Vice President--Employee Relations since
1988. From 1981, when Mr. Hain joined the Company, until 1988, Mr. Hain served
as Director--Employee Relations.
David L. Hicks has been Vice President--Law and General Counsel since March
1991. From 1988 until March 1991, Mr. Hicks was General Counsel and prior to
that time was General Attorney for SFP.
Michael J. Rosinski has been Vice President and Chief Financial Officer
since September 1992. Prior to joining the Company, Mr. Rosinski was with
Tenneco Inc. and its subsidiaries for 24 years. From 1988 until 1990, Mr.
Rosinski served as Deputy Project Executive for the Colombian Crude Oil Pipeline
Project and from 1990 until August 1992 he was Executive Director of Investor
Relations. Mr. Rosinski is also a director of Hadson (natural gas transportation
and marketing).
John R. Womack has been Vice President--Business Development since 1987.
From 1982, when Mr. Womack joined the Company, until 1987, Mr. Womack served as
Vice President--Land.
Rod F. Dammeyer has served as a Director since 1990. Mr. Dammeyer has been
President and a Director since 1985 and Chief Executive Officer since 1993 of
Itel Corporation (holding company involved primarily in distribution of wiring
systems products). Mr. Dammeyer is also a director of Q-Tel S.A., Servicios
Financieros Quadrum, S.A., Lomas Financial Corporation, Jacor Communications,
Inc., Revco D.S., Inc., Capsure Holdings Corp. and the Vigoro Corporation and a
trustee of Van Kampen Merritt Closed-End Mutual Funds. In addition, Mr. Dammeyer
is President, Chief Executive Officer and a director of Great American
Management and Investment, Inc.
Marc J. Shapiro has served as a Director since 1990. Mr. Shapiro has been
Chairman, President and Chief Executive Officer of Texas Commerce Bancshares,
Inc. (banking) since January 1994. He has been President and Chief Executive
Officer of Texas Commerce Bancshares, Inc. since December 1989, Chairman and
Chief Executive Officer of Texas Commerce Bank National Association since 1987
and a member of the Management Committee of Chemical Banking Corporation since
December 1991. Mr. Shapiro was a member of the Office of the Chairman of
Chemical Banking Corporation from August 1990 to December 1991, Vice Chairman of
Texas Commerce Bancshares, Inc. from 1982 to 1989, and Vice Chairman of Texas
Commerce Bank National Association from 1982 to 1987. Mr. Shapiro is also a
director of Browning-Ferris Industries and a trustee of Weingarten Realty
Investors.
William F. Greehey has served as a Director since 1991. Mr. Greehey has
been Chairman of the Board, Chief Executive Officer and director of Valero
Energy Corporation (refining and marketing, gas transmission and processing)
since 1983. Mr. Greehey is also a director of Weatherford International.
Robert F. Vagt has served as a Director since 1992. Mr. Vagt has been
President, Chief Executive Officer and director of Global Natural Resources Inc.
(oil and gas exploration and production) since May 1992; President and Chief
Operating Officer of Adobe (oil and gas exploration and production) from
November 1990 to May 1992; Executive Vice President of Adobe from August 1987 to
October 1990; and Senior Vice President of Adobe from October 1985 to August
1987. Mr. Vagt is also a director of First Albany Corporation (brokerage firm).
Melvyn N. Klein has served as a Director since February 1993, when he was
elected to fill the vacancy created by the resignation of L.G. Dodd. Mr. Klein
is an Attorney and Counselor at Law, private investor and the sole stockholder
of a general partner in GKH Partners, L.P. Mr. Klein is also a director of Itel
Corporation, American Medical Holdings, Inc. (hospital ownership and
management), Bayou Steel
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Corporation (specialty steel manufacturer) and Savoy Pictures Entertainment,
Inc. (distributor of motion pictures).
Robert D. Krebs has served as a Director since 1985. Mr. Krebs has been
Chairman, President and Chief Executive Officer of SFP since 1988. Prior to such
time, Mr. Krebs was President and Chief Operating Officer of SFP. Mr. Krebs is
also a director of SFP, Catellus Development Corporation, the Atchison, Topeka
and Santa Fe Railway Company, Santa Fe Pacific Pipelines, Inc., Phelps Dodge
Corporation and Northern Trust Corporation.
David M. Schulte has served as a Director since February 1994. Mr. Schulte
has been, for the past five years, Managing Partner of Chilmark Partners, L.P.
(investments) and since July 1990, General Partner of ZC Limited Partnership,
the General Partner of Zell/Chilmark Fund, L.P. (investments). Mr. Schulte is
also a director of Carter Hawley Hale Stores, Inc., Revco D.S., Inc., Sealy
Corporation and Jacor Communications, Inc.
Allan V. Martini has served as a Director since 1990. Mr. Martini retired
as Vice President Exploration/Production and director of Chevron Corporation
(petroleum operations) in August 1988. Mr. Martini served in that position from
July 1986 until his retirement.
Michael A. Morphy has served as a Director since 1990. Mr. Morphy has been,
for the past five years, retired Chairman and Chief Executive Officer of
California Portland Cement Company. Mr. Morphy is also a director of Cyprus Amax
Minerals Co. and SFP.
Kathryn D. Wriston has served as a Director since 1990. Ms. Wriston has
been, for the past five years, director of various corporations and
organizations, including Northwestern Mutual Life Insurance Company and a
Trustee of the Financial Accounting Foundation.
Reuben F. Richards has served as a Director since 1992. Mr. Richards has
been Chairman of the Board of Terra Industries Inc. (agribusiness) since
December 1982; Chief Executive Officer of Terra Industries Inc. from December
1982 to May 1991 and President of Terra Industries Inc. from July 1983 to May
1991; Chairman of the Board of Engelhard Corporation (specialty chemicals and
engineered materials) since May 1985; Chairman of the Board of Minorco (U.S.A.)
Inc. ("Minorco (USA)") since May 1990 and Chief Executive Officer and President
of Minorco (USA) since February 1994. Mr. Richards is also a director of Ecolab,
Inc. (cleaning and sanitizing products), Potlatch Corporation (forest products),
and Minorco.
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DESCRIPTION OF CAPITAL STOCK
AUTHORIZED AND OUTSTANDING CAPITAL STOCK
At the date hereof, the authorized capital stock of the Company is
250,000,000 shares, consisting of 200,000,000 shares of Common Stock, par value
$0.01 per share, and 50,000,000 shares of Preferred Stock, par value $0.01 per
share ("Preferred Stock"), of which 5,000,000 have been designated as
Convertible Preferred Stock, Series 7%, and of which up to 12,305,000 will be
designated as DECS to be issued pursuant to this Offering. The following summary
of the Company's Common Stock and Preferred Stock, including the Convertible
Preferred Stock, Series 7%, is qualified in its entirety by reference to the
Company's Restated Certificate of Incorporation, Bylaws and the Certificate of
Designations, Rights and Preferences for the Convertible Preferred Stock, Series
7%, copies of which are included as exhibits to the Registration Statement of
which this Prospectus is a part. For a description of the DECS, see "Description
of the DECS."
COMMON STOCK
Restrictions on Dividends
The holders of the Company's Common Stock are entitled to dividends in such
amounts and at such times as may be declared by the Company's Board of Directors
out of funds legally available therefor. Certain of the Company's existing
credit agreements restrict the payment of dividends to the holders of Common
Stock. The most restrictive of such agreements is the Senior Notes, which
contain a dividend restriction that limits aggregate dividends to $45 million
plus 100% (or minus 100% in the case of a deficit) of the cumulative
consolidated net income of Santa Fe and its subsidiaries from April 1, 1990,
subject to other financial conditions. For a description of the aggregate amount
that the Company could pay as a dividend on its capital stock, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Financing Activities." In addition, the terms of the Convertible
Preferred Stock, Series 7%, restrict and the terms of the DECS will restrict any
dividend payment by the Company to holders of Common Stock unless all dividends
on the Convertible Preferred Stock, Series 7%, and the DECS for all past
quarterly dividend periods shall have been paid, or declared and a sum
sufficient for the payment thereof set apart. At December 31, 1993, under its
most restrictive debt covenant the Company had the ability to pay up to $26.1
million in dividends on its outstanding capital stock. After giving effect as of
December 31, 1993 to consummation of this Offering and the Concurrent Debenture
Offering and the application of the net proceeds thereof as described in "Use of
Proceeds," under the Company's most restrictive covenant the Company would have
had the ability to pay up to only $50.0 million in dividends on its Common Stock
(pursuant to such covenant, dividends on the Convertible Preferred Stock, Series
7%, and the DECS are exempted from, but will reduce, the amount available for
the payment of dividends on Common Stock). The amount permitted under these
covenants to be used to pay dividends will vary over time depending, among other
things, on the Company's earnings and any issuances of capital stock.
Other
Holders of the Common Stock are entitled to one vote per share for the
election of directors and other corporate matters. There are no cumulative
voting rights, meaning that the holders of a majority of the shares voting for
the election of directors can elect all the directors if they choose to do so.
The Company's Board of Directors is divided into three classes, each of
which consists of approximately one-third of the total number of directors
constituting the Board. Directors are elected to three-year terms, and one class
of directors is elected each year. The Company's Bylaws include provisions that
establish procedures for director nominations by stockholders and for the
presentation by stockholders of matters to be considered at stockholder
meetings.
In addition, upon the failure to pay dividends on the Convertible Preferred
Stock, Series 7%, and, assuming consummation of the offering being made hereby,
the DECS for four quarterly dividend periods, the number of the Company
directors will be increased by two, and the holders of the Convertible Preferred
Stock, Series 7%, and the DECS at the time outstanding, voting together as a
class with all
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other holders of affected classes or series, if any, of Company parity capital
stock, upon which like voting rights have been conferred and are exercisable,
will be entitled to elect said two directors. See "-- Convertible Preferred
Stock--Voting Rights."
Upon liquidation or dissolution, holders of Common Stock are entitled to
share ratably in all net assets available for distribution to stockholders after
payment of any liquidation preferences to holders of Convertible Preferred
Stock, Series 7%, and, assuming consummation of the offering being made hereby,
holders of the DECS. The Common Stock carries no preemptive rights. All
outstanding shares of Common Stock are duly authorized, validly issued, fully
paid and nonassessable.
As of March 14, 1994, there were 89,936,650 shares of Common Stock issued
and outstanding held by approximately 57,755 shareholders of record.
PREFERRED STOCK
The Company's Board of Directors is authorized to issue from time to time,
without stockholder authorization, in one or more designated series, shares of
preferred stock with such dividend, redemption, conversion and exchange
provisions as are provided in the particular series. As of the date hereof,
5,000,000 shares of Preferred Stock were designated as the Convertible Preferred
Stock, Series 7%, all of which were outstanding as of March 1, 1994. The form of
the Certificate of Designations, Rights and Preferences for the Convertible
Preferred Stock, Series 7%, is included as an exhibit to the Registration
Statement of which this Prospectus is a part and the summary of the terms of
such shares contained herein is qualified in its entirety by reference thereto
and is incorporated herein.
In connection with this Offering, the Company's Board of Directors
authorized the creation of the DECS. The form of the Certificate of
Designations, Rights and Preferences for the DECS is included as an exhibit to
the Registration Statement of which this Prospectus is a part and the summary of
the terms of such shares contained herein is qualified in its entirety by
reference thereto and is incorporated herein. For a description of the terms of
the DECS, see "--Description of the DECS."
TAKEOVER PROVISIONS
Section 203 of the Delaware General Corporation Law
Section 203 of the Delaware Act ("Section 203") restricts certain
transactions between a corporation organized under Delaware law (or its
majority-owned subsidiaries) and any person holding 15% or more of the
corporation's outstanding voting stock, together with the affiliates or
associates of such person (an "Interested Stockholder"). Section 203 prevents,
for a period of three years following the date that a person becomes an
Interested Stockholder, the following types of transactions between the
corporation and the Interested Stockholder (unless certain conditions, described
below, are met): (a) mergers or consolidations, (b) sales, leases, exchanges or
other transfers of 10% or more of the aggregate assets of the corporation, (c)
issuances or transfers by the corporation of any stock of the corporation which
would have the effect of increasing the Interested Stockholder's proportionate
share of the stock of any class or series of the corporation, (d) any other
transaction which has the effect of increasing the proportionate share of the
stock of any class or series of the corporation which is owned by the Interested
Stockholder, and (e) receipt by the Interested Stockholder of the benefit
(except proportionately as a stockholder) of loans, advances, guarantees,
pledges or other financial benefits provided by the corporation.
The three-year ban does not apply if either the proposed transaction or the
transaction by which the Interested Stockholder became an Interested Stockholder
is approved by the board of directors of the corporation prior to the date such
stockholder becomes an Interested Stockholder. Additionally, an Interested
Stockholder may avoid the statutory restriction if, upon the consummation of the
transaction whereby such stockholder becomes an Interested Stockholder, the
stockholder owns at least 85% of the outstanding voting stock of the corporation
without regard to those shares owned by the corporation's officers and directors
or certain employee stock plans. Business combinations are also permitted within
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the three-year period if approved by the board of directors and authorized at an
annual or special meeting of stockholders, by the holders of at least 66 2/3% of
the outstanding voting stock not owned by the Interested Stockholder. In
addition, any transaction is exempt from the statutory ban if it is proposed at
a time when the corporation has proposed, and a majority of certain continuing
directors of the corporation have approved, a transaction with a party who is
not an Interested Stockholder of the corporation (or who becomes such with board
approval) if the proposed transaction involves (a) certain mergers or
consolidations involving the corporation, (b) a sale or other transfer of over
50% of the aggregate assets of the corporation, or (c) a tender or exchange
offer for 50% or more of the outstanding voting stock of the corporation.
Prior to the effective date of Section 203, a corporation, by action of its
board of directors, had the option of electing to exclude itself from the
coverage of Section 203. Since the effective date of such section, a corporation
may, at its option, exclude itself from the coverage of Section 203 by amending
its certificate of incorporation or bylaws by action of its shareholders to
exempt itself from coverage, provided that such bylaw or charter amendment shall
not become effective until 12 months after the date it is adopted. The Company
has not adopted such a charter or bylaw amendment.
No Action by Written Consent
The Restated Certificate of Incorporation of the Company (the "Charter")
prohibits the taking of any action by written stockholder consent in lieu of a
meeting and the amendment of the Charter to repeal or alter such provision
without the affirmative vote of the holders of at least 80% of the voting
capital stock of the Company.
Rights Plan
The Charter provides that the Company may, by action of its Board of
Directors, adopt a rights plan. The Company does not currently have a rights
plan in effect.
The foregoing provisions in the Charter, the existence of authorized but
unissued capital stock and the application of Section 203 to stockholders of the
Company may tend to deter unfriendly offers or other efforts to obtain control
of the Company that are not approved by the Company's Board of Directors and
thereby deprive the Company's stockholders of opportunities to sell their shares
of Common Stock at prices higher than prevailing market prices.
DESCRIPTION OF CONVERTIBLE PREFERRED STOCK, SERIES 7%
General
The Convertible Preferred Stock, Series 7%, has a liquidation preference of
$20 per share plus accrued and unpaid dividends and ranks prior to all shares of
the Common Stock as to payment of dividends and as to distributions of assets
upon liquidation, dissolution or winding up of the Company. Holders of the
Convertible Preferred Stock, Series 7%, have no preemptive rights.
The transfer agent for the Convertible Preferred Stock, Series 7%, is First
Chicago Trust Company of New York, which also acts as transfer agent and
registrar for the Common Stock, whose address is 30 West Broadway, New York, New
York 10007.
Dividends
Holders of Convertible Preferred Stock, Series 7%, are entitled to receive,
prior to the payment of dividends on shares of Common Stock, cumulative cash
dividends at an annual rate equivalent to $1.40 per share, when, as and if
declared by the Company's Board of Directors out of funds legally available
therefor, payable quarterly on March 1, June 1, September 1 and December 1.
If at any time any dividend on any outstanding shares of capital stock of
Santa Fe, which, by the terms of the Charter or of the instrument by which the
Company's Board of Directors shall fix, shall be
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senior to the Convertible Preferred Stock, Series 7%, in respect of the right to
receive dividends, then no dividend shall be paid or declared and set apart for
payment on the Convertible Preferred Stock, Series 7%, unless and until all
accrued and unpaid dividends with respect to such outstanding senior capital
stock shall have been paid or declared and a sum sufficient for the payment
thereof set apart for payment. No full dividend shall be paid or declared and
set apart for payment on the Convertible Preferred Stock, Series 7%, for any
dividend period unless full cumulative dividends have been or contemporaneously
are paid or declared and a sum sufficient for the payment thereof set apart for
such payment on all shares of outstanding Santa Fe capital stock which, by the
terms of the Charter or of the instrument by which the Company's Board of
Directors shall fix, shall be entitled to share ratably with the Convertible
Preferred Stock, Series 7%, in the payment of full dividends, for all dividend
periods terminating on or prior to the end of such dividend period. If this
Offering is consummated, the DECS will be entitled to share ratably with the
Convertible Preferred Stock, Series 7%, in the payment of dividends. When
dividends are not paid in full as aforesaid on all shares of such outstanding
parity capital stock and the Convertible Preferred Stock, Series 7%, any
dividend payments on the Convertible Preferred Stock, Series 7%, including
accumulated dividends, if any, will be paid to the holders of the shares of the
Convertible Preferred Stock, Series 7%, and any such outstanding parity capital
stock (including the DECS) ratably in proportion to the respective sums which
such holders would receive if all dividends accumulated thereon to the date of
payment were declared and paid in full. Accumulated dividends will not bear
interest.
So long as any shares of the Convertible Preferred Stock, Series 7%, are
outstanding, in no event will any dividends, other than dividends payable solely
in shares of junior stock, be paid or declared and set apart for payment, nor
will any distribution be made, on any class of stock ranking subordinate to the
Convertible Preferred Stock, Series 7%, unless all accrued and unpaid dividends
on the Convertible Preferred Stock, Series 7%, for all past quarterly dividend
periods shall have been paid, or declared and a sum sufficient for the payment
thereof set apart.
The amount of dividends payable per share of Convertible Preferred Stock,
Series 7%, for each full quarterly dividend period will be computed by dividing
the annual dividend rate by four.
Voting Rights
The holders of Convertible Preferred Stock, Series 7%, will have no voting
rights except as set forth below or as otherwise may be required by the Delaware
Act. On any matters on which the holders of the Convertible Preferred Stock,
Series 7%, will be entitled to vote, they will be entitled to one vote for each
share held.
If and when four quarterly dividends payable on the Convertible Preferred
Stock, Series 7%, or any capital stock of the Company ranking on a parity with
the Convertible Preferred Stock, Series 7%, in respect of dividend rights and
rights to share in the Company's liquidation upon dissolution or winding up of
the Company ("Parity Stock"), whether or not consecutive, shall be unpaid in
whole or in part, the number of directors will be increased by two, and the
holders of the Convertible Preferred Stock, Series 7%, at the time outstanding,
voting separately as a class with all holders of Parity Stock (which will
include the DECS) upon which like voting rights have been conferred and are
exercisable, will be entitled to elect said two directors. The right to elect
said two directors will begin at any meeting of stockholders of the Company at
which directors are to be elected held during the period such dividends remain
in arrears and will continue until said arrearages in dividends shall have been
paid or declared and a sum sufficient for the payment thereof set apart for
payment, at which time the right of the holders of shares of the Convertible
Preferred Stock, Series 7%, to elect said two directors will cease and the terms
of said two directors then in office will expire and terminate.
The affirmative vote of the holders of at least two-thirds of the shares of
Convertible Preferred Stock, Series 7%, at the time outstanding, voting
separately as a class, is necessary to amend, alter or repeal any of the
relative rights, preferences, qualifications, limitations or restrictions in the
Certificate of Designation for the Convertible Preferred Stock, Series 7%, so as
to affect adversely the relative rights,
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preferences, qualifications, limitations or restrictions of holders of the
Convertible Preferred Stock, Series 7%.
Conversion Rights
Voluntary Conversion. The holder of any shares of Convertible Preferred
Stock, Series 7%, has the right, at its option and at any time, to convert any
or all of such shares into Common Stock at the initial rate of 1.3913 shares of
Common Stock for each share of Convertible Preferred Stock, Series 7% (subject
to adjustments as described below) (a "Voluntary Conversion"). No payment or
adjustment shall be made upon any conversion of any share of Convertible
Preferred Stock, Series 7%, on account of any accrued and unpaid dividends on
the shares surrendered for conversion prior to the record date for the
determination of holders entitled to such dividends or on account of any
dividends on the Common Stock issued upon conversion subsequent to the record
date established by the Company for the determination of holders of Common Stock
entitled to such dividend.
Mandatory Conversion. The Company may, at its option and at any time on or
after May 19, 1997, during the 10-day period following a "Special Conversion
Event" (defined below), convert all outstanding shares of Convertible Preferred
Stock, Series 7%, together with all unpaid dividends thereon accrued on a pro
rata basis through the date of such conversion, into fully paid and
non-assessable shares of Common Stock (a "Mandatory Conversion"). A "Special
Conversion Event" shall be deemed to have occurred at, and shall be defined as,
such time(s) as the average of the daily closing prices for a share of Common
Stock for 20 of 30 consecutive trading days equals or exceeds 125% of the
quotient of (x) $20.00 divided by (y) the then applicable conversion rate. The
number of shares of Common Stock into which each outstanding share of
Convertible Preferred Stock, Series 7%, shall be converted shall equal the sum
of (i) the then current conversion rate, plus (ii) the number determined by
dividing the amount of such accrued and unpaid dividends by a fraction, the
numerator of which is $20.00 and the denominator of which is the average of such
daily closing prices.
No fractional shares of Common Stock will be issued upon conversion but, in
lieu thereof, an appropriate amount will be paid in cash by the Company in an
amount equal to the same fraction of the market price per share of the Common
Stock, as determined by the Company's Board of Directors, on the business day
prior to the date of the conversion.
The conversion rate of the Convertible Preferred Stock, Series 7%, is
subject to adjustment in certain events. No adjustment of the conversion rate
will be required to be made until cumulative adjustments amount to 1% or more of
the conversion rate as last adjusted; however, any adjustment not made will be
carried forward.
Special Redemption Right
Upon the occurrence of the first Ownership Change (as defined below) of the
Company, each holder of shares of Convertible Preferred Stock, Series 7%, will
have the right, at the holder's option, at any time within 45 days after notice
of such Ownership Change is mailed, to elect to have all of such holder's shares
of Convertible Preferred Stock, Series 7%, redeemed for an amount equal to the
sum of (x) $20.00 for each share plus (y) accrued and unpaid dividends thereon
up to the redemption date. An "Ownership Change" will be deemed to have occurred
at, and is defined as, such time as any person or group, together with any
affiliates or associates, becomes the beneficial owner of 50% or more of the
outstanding Common Stock.
Liquidation Preference
Subject to the prior rights of the Company's creditors, secured and
unsecured, and the prior rights of holders of the Company's capital stock
ranking senior to the Convertible Preferred Stock, Series 7%, if any, in the
event of any liquidation, dissolution or winding up of the Company, then, before
any distribution or payment may be made to the holders of shares of any of the
Company's capital stock ranking subordinate to the Convertible Preferred Stock,
Series 7%, the holders of shares of the
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Convertible Preferred Stock, Series 7%, will be entitled to be paid in full the
respective amount per share of Convertible Preferred Stock, Series 7%, equal to
the sum of (x) dividends accrued and unpaid thereon to the date of final
dissolution to such holders, whether or not declared, plus (y) $20.00; provided
that neither the consolidation, the merger or other business combination of the
Company with or into another corporation, nor sale or transfer of all or part of
the assets of the Company for cash, securities or other property will be deemed
a liquidation, dissolution or winding up of the Company for purposes of this
sentence. In any event, the right of holders of Convertible Preferred Stock,
Series 7%, to the foregoing liquidation preference will accrue to such holders
only if the Company's payments with respect to the liquidation preferences of
the holders of outstanding capital stock of the Company ranking senior to the
Convertible Preferred Stock, Series 7%, if any, are fully met. If the assets of
the Company available for distribution to the holders of the shares of the
Convertible Preferred Stock, Series 7%, shall not be sufficient to make the
payment thereon required to be made in full, such assets will be distributed to
the holders of the shares of the Convertible Preferred Stock, Series 7%, and any
Parity Stock (such as the DECS) ratably in proportion to the full amounts to
which they would otherwise be entitled. After payment is made in full to the
holders of the shares of the Convertible Preferred Stock, Series 7%, the
remaining assets and funds of the Company will be distributed among the holders
of all shares of stock ranking subordinate to the Convertible Preferred Stock,
Series 7%, according to their respective rights.
DESCRIPTION OF THE DECS
The following information concerning the DECS does not purport to be
complete and is subject to and qualified in its entirety by reference to all of
the provisions of the Company's Restated Certificate of Incorporation and the
terms of the Certificate of Designations with respect to the DECS, a copy of
which will be filed with the Securities and Exchange Commission.
Ranking. The DECS will rank prior to the Common Stock both as to payment
of dividends and distribution of assets upon liquidation and will rank pari
passu with the Company's outstanding Convertible Preferred Stock, Series 7%. In
addition, the DECS will rank on a parity with any Preferred Stock issued in the
future by the Company that by its terms ranks pari passu with the DECS.
Dividends. The holders of DECS are entitled to receive, when, as and if
dividends on the DECS are declared by the Board of Directors of the Company out
of funds legally available therefor, cumulative preferential dividends from the
issue date of the DECS, accruing at the rate per share of $ per annum
or $ per quarter for each DECS, payable quarterly in arrears on the
first day of each January, April, July and October, or, if any such date is not
a business day, on the next succeeding business day; provided, however, that
with respect to any dividend period during which a redemption occurs, the
Company may, at its option, declare accrued dividends to, and pay such dividends
on, the date fixed for redemption, in which case such dividends would be payable
in cash to the holders of DECS as of the record date for such dividend payment
and would not be included in the calculation of the related Call Price as set
forth below. The first dividend payment will be for the period from the issue
date of the DECS to and including June 30, 1994 and will be payable on July 1,
1994. Dividends (or amounts equal to accrued and unpaid dividends) payable on
the DECS for any period shorter than a quarterly dividend period will be
computed on the basis of a 360-day year of twelve 30-day months. Dividends will
be payable to holders of record of the DECS as they appear on the stock register
of the Company, on such record dates, not less than 15 nor more than 60 days
preceding the payment date thereof, as shall be fixed by the Board of Directors.
Dividends are payable in cash except in connection with certain redemptions by
the Company.
Dividends on the DECS will accrue whether or not the Company has earnings,
whether or not there are funds legally available for the payment of such
dividends and whether or not such dividends are declared. Dividends accumulate
to the extent they are not paid on the dividend payment date for the quarter for
which they accrue. Accumulated unpaid dividends will not bear interest.
Unless full cumulative dividends with respect to the DECS shall have been
paid or contemporaneously are declared and paid through the most recent dividend
payment date, then, whether or not the
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Mandatory Conversion Date has occurred, (a) no full cash dividend shall be
declared or paid or set aside for payment or other distribution declared or made
on any shares of the Company ranking on a parity as to dividends with the DECS,
(b) no dividend or other distribution (other than a dividend or distribution
paid in shares of, or warrants, rights or options exercisable for or convertible
into, shares of Common Stock or in any other stock of the Company ranking junior
to the DECS as to dividends and upon liquidation) shall be declared or paid or
set aside for payment or other distribution declared or made upon the Common
Stock or upon any other shares of the Company ranking junior to the DECS as to
dividends and (c) no Common Stock or any other shares of the Company ranking
junior to or on a parity with the DECS as to dividends or upon liquidation shall
be redeemed, purchased or otherwise acquired for any consideration (or any
moneys be paid to or made available for a sinking fund for the redemption of any
shares of any such series or class) by the Company, except by conversion into or
exchange for shares of the Company ranking junior to the DECS as to dividends
and upon liquidation. When dividends which are payable in cash have not been
paid or set aside in full with respect to the DECS and any other shares of the
Company ranking on a parity as to dividends with the DECS, all dividends
declared with respect to the DECS and any other shares of the Company ranking on
a parity as to dividends with the DECS shall be declared pro rata so that the
amount of dividends declared per share on the DECS and such other shares shall
in all cases bear to each other the same ratio that at the time of declaration
accrued and payable but unpaid dividends per share on the DECS and such other
shares bear to each other. Holders of the DECS shall not be entitled to any
dividends, whether payable in cash, property or stock, in excess of full
cumulative dividends, as herein described.
Mandatory Conversion of DECS. On the Mandatory Conversion Date, each
outstanding DECS will convert automatically into shares of Common Stock at the
Common Equivalent Rate in effect on such date and the right to receive an amount
in cash equal to all accrued and unpaid dividends on such DECS (other than
dividends payable to a holder of record on a prior date) to the Mandatory
Conversion Date, whether or not declared, out of funds legally available for the
payment of dividends, subject to the right of the Company to redeem the DECS on
or after the Initial Redemption Date and prior to the Mandatory Conversion Date,
as described below, and subject to the conversion of the DECS at the option of
the holder at any time prior to the Mandatory Conversion Date. The Common
Equivalent Rate is initially one share of Common Stock for each DECS, and is
subject to adjustment as described below.
Because the price of the Common Stock is subject to market fluctuations,
the value of the Common Stock received by a holder of DECS upon Mandatory
Conversion may be more or less than the amount paid for the DECS. Dividends will
cease to accrue on the Mandatory Conversion Date in respect of the DECS then
outstanding.
Right to Redeem DECS. The DECS are not redeemable by the Company prior to
the Initial Redemption Date. At any time and from time to time on or after the
Initial Redemption Date and prior to the Mandatory Conversion Date, the Company
may redeem the outstanding DECS, in whole or in part. Upon any such redemption,
each holder of DECS will receive, in exchange for each DECS so called, a number
of shares of Common Stock equal to the Call Price of the DECS in effect on the
date of redemption divided by the Current Market Price of the Common Stock
determined as of the date which is the trading day prior to the public
announcement of the call for redemption. The Call Price of each DECS is the sum
of (i) $ on and after the Initial Redemption Date through June 30, 1997,
$ on and after July 1, 1997 through September 30, 1997, $ on and
after October 1, 1997 through December 31, 1997, and $ on and after
January 1, 1998 until the Mandatory Conversion Date, and (ii) all accrued and
unpaid dividends thereon to the date fixed for redemption (other than dividends
payable to a holder of record as of a prior date). The public announcement of
any call for redemption shall be made prior to the mailing of the notice of such
call to holders of DECS as described below. Dividends will cease to accrue on
DECS on the date fixed for their redemption.
The term "Current Market Price" per share of the Common Stock on any date
of determination means the lesser of (x) the average of the closing sale prices
of the Common Stock as reported on the NYSE for the 15 consecutive trading days
ending on and including such date of determination and (y) the closing sale
price of the Common Stock as reported on the NYSE for such date of
determination;
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<PAGE> 162
provided, however, that, with respect to any redemption of the DECS, if any
event that results in an adjustment of the Common Equivalent Rate occurs during
the period beginning on the first day of such 15-day period and ending on the
applicable redemption date, the Current Market Price as determined pursuant to
the foregoing will be appropriately adjusted to reflect the occurrence of such
event.
The opportunity for equity appreciation afforded by an investment in the
DECS is less substantial than the opportunity for equity appreciation afforded
by an investment in the Common Stock because the Company may, at its option,
redeem the DECS at any time on or after the Initial Redemption Date and prior to
the Mandatory Conversion Date, and may be expected to do so prior to the
Mandatory Conversion Date if the market price of the Common Stock exceeds the
Call Price. In such event, holders of the DECS will receive less than one share
of Common Stock for each DECS. However, because holders of DECS called for
redemption will have the option to surrender DECS for conversion at the
Conversion Price up to the close of business on the redemption date (and may be
expected to do so if the market price of the Common Stock exceeds the Conversion
Price), a holder that elects to convert will receive of a share of Common
Stock for each DECS. Because the number of shares of Common Stock to be
delivered in payment of the Call Price will be determined on the basis of the
market price of the Common Stock prior to the announcement of the call, the
value per share of the shares of Common Stock to be delivered may be more or
less than the Call Price on the date of delivery.
As a result of these provisions, holders of DECS would be expected to
realize no equity appreciation if the market price of one share of Common Stock
is below the Conversion Price, and less than all of such appreciation if the
market price of one share of Common Stock is above the Conversion Price. Holders
of DECS will realize the entire decline in equity value if the market price of
the Common Stock is less than the price paid for a DECS.
Conversion at Option of Holder. The DECS are convertible, in whole or in
part, at the option of the holders thereof, at any time prior to the Mandatory
Conversion Date, unless previously redeemed, into shares of Common Stock at a
rate of of a share of Common Stock for each DECS (the "Optional Conversion
Rate") (equivalent to a Conversion Price of $ per share of Common
Stock), subject to adjustment as described below. The right to convert DECS
called for redemption will terminate at the close of business on the redemption
date.
Conversion of DECS may be effected by delivering certificates evidencing
such DECS, together with written notice of conversion and a proper assignment of
such certificates to the Company or in blank, to the office or agency to be
maintained by the Company for that purpose (and, if applicable, payment of an
amount equal to the dividend payable on such shares), and otherwise in
accordance with conversion procedures established by the Company. Each
conversion shall be deemed to have been effected immediately prior to the close
of business on the date on which the foregoing requirements shall have been
satisfied. The conversion shall be at the Optional Conversion Rate in effect at
such time and on such date.
Holders of DECS at the close of business on a record date for any payment
of dividends will be entitled to receive the dividend payable on such DECS on
the corresponding dividend payment date notwithstanding the conversion of such
DECS following such record date and prior to such dividend payment date.
However, DECS surrendered for conversion after the close of business on a record
date for any payment of dividends and before the opening of business on the next
succeeding dividend payment date (unless such DECS are subject to redemption on
a redemption date in that period) must be accompanied by payment of an amount
equal to the dividend thereon which is to be paid on such dividend payment date.
Except as provided above, the Company will make no payment of or allowance for
unpaid dividends, whether or not in arrears, on converted DECS or for dividends
or distributions on the shares of Common Stock issued upon such conversion.
Conversion Adjustment. The Common Equivalent Rate and the Optional
Conversion Rate are each subject to adjustment if the Company shall (i) pay a
dividend or make a distribution with respect to Common Stock in shares of such
stock, (ii) subdivide or split its outstanding shares of Common Stock, (iii)
combine its outstanding shares of Common Stock into a smaller number of shares,
(iv) issue by
56
<PAGE> 163
reclassification of its shares of Common Stock any shares of common stock of the
Company, (v) issue rights or warrants to all holders of its Common Stock
entitling them (for a period not exceeding 45 days from the date of such
issuance) to subscribe for or purchase shares of Common Stock at a price per
share less than the market price of the Common Stock or (vi) pay a dividend or
make a distribution to all holders of its Common Stock in the form of evidences
of its indebtedness, cash or other assets (including capital stock of the
Company other than Common Stock but excluding any dividends or distributions
referred to in clause (i) above or any cash dividends other than "Extraordinary
Cash Dividends" as defined below) or issue to all holders of its Common Stock
rights or warrants to subscribe for or purchase any of its securities (other
than those referred to in clause (v) above). The Company will also be entitled
(but shall not be required) to make upward adjustments in the Common Equivalent
Rate, the Optional Conversion Rate and the Call Price, as it in its discretion
shall determine to be advisable, in order that any stock dividends, subdivision
of shares, distribution of rights to purchase stock or securities, or
distribution of securities convertible into or exchangeable for stock (or any
transaction which could be treated as any of the foregoing transactions pursuant
to Section 305 of the Internal Revenue Code of 1986, as amended) hereafter made
by the Company to its stockholders will not be taxable. "Extraordinary Cash
Distribution" means the portion of any cash dividend or cash distribution on the
Common Stock that, when added to all other cash dividends and cash distributions
on the Common Stock made during the immediately preceding 12-month period (other
than cash dividends and cash distributions for which a prior adjustment to the
Common Equivalent Rate and the Optional Conversion Rate was previously made)
exceeds, on a per share of Common Stock basis, 10 percent of the average daily
closing sales price of the Common Stock over such 12-month period. All
adjustments to the Common Equivalent Rate and the Optional Conversion Rate will
be calculated to the nearest 1/100th of a share of Common Stock (or if there is
not a nearest 1/100th of a share to the next lower 1/100th of a share). No
adjustment in the Common Equivalent Rate and the Optional Conversion Rate shall
be required unless such adjustment would require an increase or decrease of at
least one percent therein; provided, however, that any adjustments which by
reason of the foregoing are not required to be made shall be carried forward and
taken into account in any subsequent adjustment.
Whenever the Common Equivalent Rate and the Optional Conversion Rate are
adjusted as provided in the preceding paragraph, the Company will file with each
transfer agent for the DECS a certificate with respect to such adjustment, make
a prompt public announcement thereof and mail a notice to holders of the DECS
providing specified information with respect to such adjustment. At least 10
business days prior to certain specified actions that could result in certain
adjustments in the Common Equivalent Rate and the Optional Conversion Rate, the
Company will notify each holder of DECS concerning such proposed action.
Adjustment for Consolidation or Merger. In case of any consolidation or
merger to which the Company is a party (other than a merger or consolidation in
which the Company is the continuing corporation and in which the Common Stock
outstanding immediately prior to the merger or consolidation is not exchanged
for cash, securities or other property of the Company or another corporation) or
in case of any statutory exchange of securities with another corporation (other
than in connection with a merger or acquisition), each DECS shall, after
consummation of such transaction, be subject to (i) conversion at the option of
the holder into the kind and amount of securities, cash or other property
receivable upon consummation of such transaction by a holder of the number of
shares of Common Stock into which such DECS might have been converted
immediately prior to consummation of such transaction, (ii) conversion on the
Mandatory Conversion Date into the kind and amount of securities, cash or other
property receivable upon consummation of such transaction by a holder of the
number of shares of Common Stock into which such DECS would have been converted
if the conversion on the Mandatory Conversion Date had occurred immediately
prior to the date of consummation of such transaction and (iii) redemption on
any redemption date in exchange for the kind and amount of securities, cash or
other property receivable upon consummation of such transaction by a holder of
the number of shares of Common Stock that would have been issuable at the Call
Price in effect on such redemption date upon a redemption of such DECS
immediately prior to consummation of such transaction, assuming that, if the
earlier of the public announcement of such redemption or the commencement of the
mailing of notice of such redemption to
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<PAGE> 164
holders of DECS (the "Notice Date") is not prior to such transaction, the Notice
Date had been the date of such transactions; and assuming in each case that such
holder of Common Stock failed to exercise rights of election, if any, as to the
kind or amount of securities, cash or other property receivable upon
consummation of such transaction (provided that if the kind or amount of
securities, cash or other property receivable upon consummation of such
transaction is not the same for each non-electing share of Common Stock, then
the kind and amount of securities, cash or other property receivable upon
consummation of such transaction for each non-electing share shall be deemed to
be the kind and amount so receivable per share by a plurality of the
non-electing shares). The kind and amount of securities into which the DECS
shall be convertible after consummation of such transaction shall be subject to
adjustment as described above under the caption "Conversion Adjustments"
following the date of consummation of such transaction. The Company may not
become a party to any such transaction unless the terms thereof are consistent
with the foregoing.
Fractional Shares. No fractional shares of Common Stock will be issued
upon redemption or conversion of the DECS. In lieu of any fractional share
otherwise issuable in respect of all DECS of any holder which are redeemed or
converted on any redemption date or upon Mandatory Conversion or any optional
conversion, such holder shall be entitled to receive an amount in cash equal to
the same fraction of the (i) Current Market Price in the case of redemption, or
(ii) Closing Price (as defined in the Certificate of Designations) of the Common
Stock determined (A) as of the fifth trading day immediately preceding the
Mandatory Conversion Date, in the case of Mandatory Conversion, or (B) as of the
second trading day immediately preceding the effective date of conversion, in
the case of an optional conversion by a holder.
Notice to Holders of DECS. The Company will provide notice of any call of
the DECS to holders of record of the DECS to be called not less than 15 nor more
than 60 days prior to the date fixed for redemption. Such notice shall be
provided by mailing notice of such redemption to the holders of record of the
DECS to be called. Each holder of DECS to be called shall surrender the
certificates evidencing such DECS to the Company at the place designated in such
notice and shall be entitled to receive certificates for shares of Common Stock
following such surrender and the date of such redemption. If fewer than all the
outstanding DECS are to be called, the DECS to be called shall be selected by
the Company from outstanding DECS by lot or pro rata (as nearly as may be) or by
any other method determined by the Board of Directors of the Company in its sole
discretion to be equitable.
Liquidation Rights. In the event of the liquidation, dissolution or
winding up of the business of the Company, whether voluntary or involuntary, the
holders of DECS, after payment or provision for payment of the debts and other
liabilities of the Company and before any distribution to the holders of the
Common Stock or any other stock ranking junior to the DECS with respect to
distributions upon liquidation, dissolution or winding up, will be entitled to
receive, for each DECS, an amount equal to the sum of (i) the per share price to
the public shown on the cover page of this Prospectus and (ii) all accrued and
unpaid dividends thereon to the date of liquidation, dissolution or winding up.
In the event the assets of the Company available for distribution to the holders
of the DECS upon any dissolution, liquidation or winding up of the Company shall
be insufficient to pay in full the liquidation payments payable to the holders
of outstanding DECS and any shares of the Company ranking on a parity with the
DECS upon liquidation, then the holders of all such DECS shall share ratably in
such distribution of assets in accordance with the amount which would be payable
on such distribution if the amounts to which the holders of outstanding DECS and
the holders of such shares of the Company ranking on a parity with the DECS upon
liquidation are entitled were paid in full.
Voting Rights. The holders of DECS shall have the right to vote with the
holders of Common Stock in the election of directors and upon each other matter
coming before any meeting of the stockholders on the basis of 4/5 of a vote for
each DECS held; the holders of DECS, and the holders of Common Stock will vote
together as one class except as otherwise provided by law or by the Restated
Certificate of Incorporation of the Company.
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<PAGE> 165
Whenever dividends on the DECS shall be in arrears and unpaid in an
aggregate amount of dividends payable thereon for four quarterly dividend
periods, or if any other series of Preferred Stock shall be entitled for any
reason to exercise voting rights, separate from the Common Stock, to elect any
Director of the Company ("Preferred Stock Directors") the holders of the DECS
(voting separately as a class with holders of all other series of Preferred
Stock upon which like voting rights have been conferred and are exercisable),
with each DECS entitled to one vote on this and other matters in which the
holders of Preferred Stock vote as a group, will be entitled to vote for the
election of two Preferred Stock Directors of the Company, such Directors to be
in addition to the number of directors constituting the Board of Directors
immediately prior to the accrual of such right. Such right shall, when vested,
continue until all dividends in default on the DECS shall have been paid in full
and the right of any other series of Preferred Stock to exercise voting rights,
separate from the Common Stock, to elect any Preferred Stock Directors shall
terminate or have terminated and, when so paid and such termination occurs or
has occurred, such right of the holders of the DECS shall cease. The term of
office of all Directors elected by the holders of the DECS and such other series
shall terminate on the earlier of (i) the next annual meeting of the
stockholders at which a successor shall have been elected and qualified or (ii)
the termination of the right of holders of the DECS and such other series to
vote for such Directors.
The Company will not, without the approval of the holders of at least
66 2/3 percent of all the DECS then outstanding: (i) amend, alter or repeal any
of the provisions of the Restated Certificate of Incorporation or the Bylaws of
the Company so as to affect adversely the powers, preferences or rights of the
holders of the DECS then outstanding or reduce the minimum time required for any
notice to which only the holders of the DECS then outstanding may be entitled
(an amendment of the Restated Certificate of Incorporation to authorize or
create, or to increase the authorized amount of any stock of any class ranking
junior to or on a parity with the DECS shall be deemed not to affect adversely
the powers, preferences, or rights of the holders of the DECS); (ii) create any
series of Preferred Stock ranking prior to the DECS as to payment of dividends
or upon liquidation; (iii) authorize or create, or increase the authorized
amount of, any capital stock, or any security convertible into capital stock, of
any class ranking prior to the DECS as to payment of dividends or upon
liquidation; or (iv) merge or consolidate with or into any other corporation,
unless each holder of the DECS immediately preceding such merger or
consolidation shall receive or continue to hold in the resulting corporation the
same number of shares, with substantially the same rights and preferences, as
correspond to the DECS so held.
As long as any DECS are outstanding, the Company will not, without the
approval of the holders of at least a majority of the DECS and shares of any
Preferred Stock ranking on a parity with the DECS then outstanding: (i) increase
the authorized amount of the Preferred Stock or (ii) create any class or classes
of capital stock ranking on a parity with the DECS, either as to payment of
dividends or upon liquidation, and not existing on the date of the Certificate
of Designations, or create any stock, or other security, convertible into or
exchangeable for or evidencing the right to purchase any stock of such other
class of capital stock ranking on a parity with the DECS, or increase the
authorized number of shares of any such other class of capital stock or amount
of such other stock or security.
Notwithstanding the provisions summarized in the preceding two paragraphs,
however, no such approval described therein of the holders of the DECS shall be
required if, at or prior to the time when such amendment, alteration, or repeal
is to take effect or when the authorization, creation or increase of any such
prior or parity stock or such other stock or security is to be made, or when
such consolidation or merger is to take effect, as the case may be, provision is
made for the redemption of all DECS at the time outstanding.
Reissuance. DECS redeemed for or converted into Common Stock or otherwise
acquired by the Company will assume the status of authorized but unissued
Preferred Stock and may thereafter be reissued in the same manner as other
authorized but unissued Preferred Stock.
Listing. The DECS have been approved for listing on the NYSE under the
symbol SFRPRA.
Registrar and Transfer Agent. will serve as registrar and
transfer agent for the DECS.
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<PAGE> 166
FEDERAL INCOME TAX CONSIDERATIONS
The following discussion sets forth the material United States federal
income tax consequences under existing law of the ownership and disposition of
the DECS. Changes to existing law, which could have retroactive effect, may
alter the consequences described below. This discussion relates only to DECS or
shares of Common Stock received upon conversion thereof or in exchange therefor
that are held as capital assets within the meaning of Section 1221 of the
Internal Revenue Code of 1986, as amended at the date hereof (the "Code"), and
does not deal with all tax consequences that may be relevant in the particular
circumstances of each holder (some of which, such as dealers in securities,
insurance companies, tax-exempt organizations and foreign persons, may be
subject to special rules). In addition, stock having terms closely resembling
those of the DECS has not been the subject of any regulation, ruling or judicial
decision currently in effect, and there can be no assurance that the Internal
Revenue Service will take the positions set forth below. Except as otherwise
indicated, statements of legal conclusions regarding federal income tax
consequences in this section reflect the opinion of Andrews & Kurth L.L.P.,
counsel to the Company. These conclusions are based on the Code, regulations
promulgated thereunder, and the current judicial and administrative
interpretations thereof. The Company has not and will not seek a ruling as to
any tax matters relating to the DECS. Persons considering the purchase of DECS
should consult their tax advisors with respect to the application of the United
States federal income tax laws to their particular situations as well as any tax
consequences arising under the laws of any state, local or foreign taxing
jurisdiction.
DIVIDENDS
Dividends paid on the DECs out of the Company's current or accumulated
earnings and profits will be taxable as ordinary income and will qualify for the
70 percent intercorporate dividends-received deduction subject to the minimum
holding period (generally at least 46 days) and other applicable requirements.
Under certain circumstances, a corporate holder may be subject to the
alternative minimum tax with respect to the amount of its dividends-received
deduction.
Under certain circumstances, a corporation that receives an "extraordinary
dividend," as defined in Section 1059(c) of the Code, is required to reduce its
stock basis by the non-taxed portion of such dividend. Generally, quarterly
dividends not in arrears paid to an original holder of the DECS will not
constitute extraordinary dividends under Section 1059(c). In addition, under
Section 1059(f), any dividend with respect to "disqualified preferred stock" is
treated as an "extraordinary dividend." However, while the issue is not free
from doubt due to the lack of authority directly on point, the DECs will not
constitute "disqualified preferred stock."
REDEMPTION PREMIUM
Under certain circumstances, Section 305(c) of the Code requires that any
excess of the redemption price of preferred stock over its issue price be
includable in income, prior to receipt, as a constructive dividend. While the
issue is not free from doubt due to a lack of authority addressing the issue,
Section 305(c) should not currently apply to stock with terms such as those of
the DECS.
REDEMPTION OR MANDATORY OR OPTIONAL CONVERSION INTO COMMON STOCK
Gain or loss generally will not be recognized by a holder upon the
redemption of the DECS for shares of Common Stock or the conversion of DECS into
shares of Common Stock if no cash is received. Income may be recognized,
however, to the extent cash or Common Stock is received in payment of accrued
and unpaid dividends in arrears. Such income would probably be characterized as
dividend income, although some uncertainty exists as to the appropriate
characterization of payments in satisfaction of undeclared accrued and unpaid
dividends. In addition, a holder who receives cash in lieu of a fractional share
will be treated as having received such fractional share and having exchanged it
for cash in a transaction subject to Section 302 of the Code and related
provisions. Such exchange should generally result in capital gain
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<PAGE> 167
or loss measured by the difference between the cash received for the fractional
share interest and the holder's basis in the fractional share interest.
Generally, a holder's basis in the Common Stock received upon the
redemption or conversion of the DECS (other than shares of Common Stock taxed
upon receipt) will equal the adjusted tax basis of the redeemed or converted
DECS plus the amount of gain recognized, minus the amount of cash received, and
the holding period of such Common Stock will include the holding period of the
redeemed or converted DECS.
ADJUSTMENT OF CONVERSION RATE
Certain adjustments (or failures to make adjustments) to the Common
Equivalent Rate to reflect the Company's issuance of certain rights, warrants,
evidences of indebtedness, securities or other assets to holders of Common Stock
may result in a constructive distribution taxable as dividends to the holders of
the DECS, which may constitute (and cause other dividends to constitute)
"extraordinary dividends" to corporate holders. See "--Dividends."
CONVERSION OF DECS AFTER DIVIDEND RECORD DATE
If a holder of DECS exercises such holder's right to convert DECS into
shares of Common Stock after a dividend record date but before payment of the
dividend, then such holder generally will be required to pay the Company an
amount equal to the portion of such dividend attributable to the current
quarterly dividend period upon conversion, which amount would increase the basis
of the Common Stock received. The holder would recognize the dividend payment as
income.
BACKUP WITHHOLDING
Certain non-corporate holders may be subject to backup withholding at a
rate of 31 percent on dividends and certain consideration received upon the
redemption or conversion of the DECS. Generally, backup withholding applies only
when the taxpayer fails to furnish or certify a proper Taxpayer Identification
Number or when the taxpayer is notified by the Internal Revenue Service that the
taxpayer has failed to report payments of interest and dividends properly.
Holders should consult their tax advisors regarding their qualification for
exemption from backup withholding and the procedure for obtaining any applicable
exemption.
UNDERWRITING
The Underwriters named below have severally agreed, subject to the terms
and conditions of the Underwriting Agreement with the Company, to purchase from
the Company the number of DECS set forth opposite their respective names. The
Underwriters are committed to purchase all of the DECS if any are purchased.
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITERS DECS
------------ ----------
<S> <C>
Salomon Brothers Inc..................................
Lazard Freres & Co....................................
PaineWebber Incorporated..............................
----------
Total............................................ 10,700,000
----------
</TABLE>
The Underwriters have advised the Company that they propose initially to
offer DECS to the public at the public offering price set forth on the cover
page of this Prospectus and to certain dealers at such price less a concession
not in excess of $ per share. The Underwriters may allow, and such
dealers may reallow, a discount not in excess of $ per share on sales
to certain other dealers. After the initial public offering, the public offering
price, concession and discount may be changed.
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<PAGE> 168
The Company and each of its executive officers and directors (other than
Mr. Dammeyer) and each of HC Associates, Minorco and Minorco USA, have agreed
not to offer, sell, contract to sell or otherwise dispose of any shares of
Common Stock, any securities convertible into or exercisable or exchangeable for
Common Stock, or any rights to acquire Common Stock for a period of 120 days
after the date of this Prospectus without the prior written consent of Salomon
Brothers Inc, such consent not to be unreasonably withheld; provided, however,
that such restriction shall not affect the ability of the Company or its
subsidiaries to take any such actions (i) as a consequence of obligations with
respect to securities outstanding prior to the date of this Prospectus, (ii) in
connection with any employee benefit or incentive plans of the Company or (iii)
in connection with the offering of the DECS made hereby or the conversion
hereof.
The Company has granted to the Underwriters an option, exercisable for 30
days from the date of this Prospectus, to purchase up to an additional 1,605,000
DECS, at the per share price to public less underwriting discounts and
commissions. The Underwriters may exercise such rights of purchase only for the
purpose of covering over-allotments, if any, incurred in connection with the
sale of DECS offered hereby. To the extent that the Underwriters exercise such
option, each Underwriter will become obligated, subject to certain conditions,
to purchase the same proportion of such additional DECS as the number of other
DECS to be purchased by that Underwriter shown in the foregoing table bears to
the total number of DECS initially offered hereby.
The Company has agreed to indemnify the Underwriters against certain civil
liabilities, including certain liabilities under the Securities Act of 1933, as
amended.
The DECS are a new issue of securities with no established trading market.
The DECS have been approved for trading on the NYSE, but no assurance can be
given as to the development or liquidity of any trading market in the DECS. If
an active market does not develop, the market price and liquidity of the DECS
may be adversely affected.
VALIDITY OF THE SECURITIES
The validity of the DECS will be passed upon for the Company by Andrews &
Kurth L.L.P., Houston, Texas, and for the Underwriters by Cravath, Swaine &
Moore, New York, New York.
EXPERTS
The financial statements as of December 31, 1993 and 1992 and for each of
the three years in the period ended December 31, 1993 included in this
Prospectus have been so included in reliance on the report of Price Waterhouse,
independent accountants, given on the authority of said firm as experts in
auditing and accounting.
Certain information appearing in this Prospectus regarding the estimated
quantities of reserves of the oil and natural gas properties owned by the
Company, the future net revenues from such reserves and the present value
thereof is based on estimates of such reserves and present values prepared by
Ryder Scott Company, independent petroleum engineers.
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<PAGE> 169
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
------
<S> <C>
Audited Financial Statements
Report of Independent Accountants............................................ F-2
Consolidated Statement of Operations for the years ended December 31, 1993,
1992 and 1991............................................................... F-3
Consolidated Balance Sheet -- December 31, 1993 and 1992..................... F-4
Consolidated Statement of Cash Flows for the years ended December 31, 1993,
1992 and 1991............................................................... F-5
Consolidated Statement of Shareholders' Equity for the years ended December
31, 1993, 1992 and 1991..................................................... F-6
Notes to Consolidated Financial Statements................................... F-7
Unaudited Financial Information
Supplemental Information to the Consolidated Financial Statements............ F-26
</TABLE>
F-1
<PAGE> 170
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders of
Santa Fe Energy Resources, Inc.
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, of cash flows, and of shareholders'
equity present fairly, in all material respects, the financial position of Santa
Fe Energy Resources, Inc. and its subsidiaries at December 31, 1993 and 1992,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1993, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE
Houston, Texas
February 18, 1994
F-2
<PAGE> 171
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF OPERATIONS
(IN MILLIONS OF DOLLARS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Revenues
Crude oil and liquids......................................................... $ 307.3 $ 333.6 $ 320.3
Natural gas................................................................... 107.8 74.8 47.9
Natural gas systems........................................................... 8.2 7.3 --
Crude oil marketing and trading............................................... 9.9 5.9 7.2
Other......................................................................... 3.7 5.9 4.4
--------- --------- ---------
436.9 427.5 379.8
--------- --------- ---------
Costs and Expenses
Production and operating...................................................... 163.8 153.4 134.6
Oil and gas systems and pipelines............................................. 4.2 3.2 --
Exploration, including dry hole costs......................................... 31.0 25.5 18.7
Depletion, depreciation and amortization...................................... 152.7 146.3 106.6
Impairment of oil and gas properties.......................................... 99.3 -- --
General and administrative.................................................... 32.3 30.9 27.8
Taxes (other than income)..................................................... 27.3 24.3 27.2
Restructuring charges......................................................... 38.6 -- --
Loss (gain) on disposition of oil and gas properties.......................... 0.7 (13.6) 0.5
--------- --------- ---------
549.9 370.0 315.4
--------- --------- ---------
Income (Loss) from Operations..................................................... (113.0) 57.5 64.4
Interest income............................................................... 9.1 2.3 2.3
Interest expense.............................................................. (45.8) (55.6) (47.3)
Interest capitalized.......................................................... 4.3 4.9 7.7
Other income (expense)........................................................ (4.8) (10.0) 5.6
--------- --------- ---------
Income (Loss) Before Income Taxes................................................. (150.2) (0.9) 32.7
Income taxes.................................................................. 73.1 (0.5) (14.2)
--------- --------- ---------
Net Income (Loss)................................................................. (77.1) (1.4) 18.5
Preferred dividend requirement.................................................... (7.0) (4.3) --
--------- --------- ---------
Earnings (Loss) Attributable to Common Shares..................................... $ (84.1) $ (5.7) $ 18.5
========= ========= =========
Earnings (Loss) Attributable to Common Shares Per Share........................... $ (0.94) $ (0.07) $ 0.29
========= ========= =========
Weighted Average Number of Shares Outstanding (in millions)....................... 89.7 79.0 63.8
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-3
<PAGE> 172
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED BALANCE SHEET
(IN MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1993 1992
----------- ------------
<S> <C> <C>
ASSETS
Current Assets
Cash and cash equivalents......................................................... $ 4.8 $ 83.8
Accounts receivable............................................................... 87.4 90.0
Income tax refund receivable...................................................... -- 16.2
Inventories....................................................................... 8.7 4.8
Assets held for sale.............................................................. 59.5 --
Other current assets.............................................................. 12.2 10.6
------------ ------------
172.6 205.4
------------ ------------
Investment in Hadson Corporation...................................................... 56.2 --
------------ ------------
Properties and Equipment, at cost
Oil and gas (on the basis of successful efforts accounting)....................... 2,064.3 2,330.9
Other............................................................................. 27.3 26.8
------------ ------------
2,091.6 2,357.7
Accumulated depletion, depreciation, amortization and impairment.................. (1,258.9) (1,255.9)
------------ ------------
832.7 1,101.8
------------ ------------
Other Assets
Receivable under gas balancing arrangements....................................... 3.9 7.7
Other............................................................................. 11.5 22.3
------------ ------------
15.4 30.0
------------ ------------
$ 1,076.9 $ 1,337.2
============ ============
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Accounts payable.................................................................. $ 93.5 $ 90.9
Interest payable.................................................................. 10.2 11.0
Current portion of long-term debt................................................. 44.3 53.4
Other current liabilities......................................................... 18.1 17.1
------------ ------------
166.1 172.4
------------ ------------
Long-Term Debt........................................................................ 405.4 492.8
------------ ------------
Deferred Revenues..................................................................... 8.6 13.0
------------ ------------
Other Long-Term Obligations........................................................... 48.8 43.4
------------ ------------
Deferred Income Taxes................................................................. 44.4 119.0
------------ ------------
Commitments and Contingencies (Note 12)............................................... -- --
------------ ------------
Convertible Preferred Stock, $0.01 par value, 5.0 million shares authorized, issued
and outstanding..................................................................... 80.0 80.0
------------ ------------
Shareholders' Equity
Preferred stock, $0.01 par value, 45.0 million shares authorized, none issued..... -- --
Common stock, $0.01 par value, 200.0 million shares authorized.................... 0.9 0.9
Paid-in capital................................................................... 496.9 494.3
Unamortized restricted stock awards............................................... (0.1) (0.4)
Accumulated deficit............................................................... (173.8) (78.0)
Foreign currency translation adjustment........................................... (0.3) (0.2)
------------ ------------
323.6 416.6
------------ ------------
$ 1,076.9 $ 1,337.2
============ ============
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 173
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF CASH FLOWS
(IN MILLIONS OF DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1993 1992 1991
---------- ---------- ----------
<S> <C> <C> <C>
Operating Activities:
Net income (loss)......................................................... $ (77.1) $ (1.4) $ 18.5
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depletion, depreciation and amortization.............................. 152.7 146.3 106.6
Impairment of oil and gas properties.................................. 99.3 -- --
Restructuring charges................................................. 27.8 -- --
Deferred income taxes................................................. (71.9) (6.3) 1.5
Net loss (gain) on disposition of properties.......................... 0.7 (13.6) (5.5)
Exploratory dry hole costs............................................ 8.9 4.7 3.8
Expenses related to acquisition of Adobe Resources Corporation........ -- 10.9 --
Other................................................................. 4.2 2.0 0.3
Changes in operating assets and liabilities:
Decrease (increase) in accounts receivable............................ 12.4 (8.3) 23.6
Decrease (increase) in inventories.................................... (3.8) 0.3 5.6
Increase (decrease) in accounts payable............................... (2.6) 5.9 (24.9)
Increase (decrease) in interest payable............................... (0.8) 0.4 0.2
Decrease in income taxes payable...................................... (0.6) (0.4) (3.6)
Net change in other assets and liabilities............................ 11.0 1.0 2.3
---------- ---------- ----------
Net Cash Provided by Operating Activities..................................... 160.2 141.5 128.4
---------- ---------- ----------
Investing Activities:
Capital expenditures, including exploratory dry hole costs................ (127.0) (76.8) (108.1)
Acquisitions of producing properties, net of related debt................. (4.4) (14.2) (28.5)
Acquisition of Adobe Resources Corporation................................ -- (11.9) --
Acquisition of Santa Fe Energy Partners, L.P.............................. (28.3) -- --
Net proceeds from sales of properties..................................... 39.9 89.1 22.1
Increase in partnership interest due to reinvestment...................... (1.6) (2.1) (2.7)
---------- ---------- ----------
Net Cash Used in Investing Activities......................................... (121.4) (15.9) (117.2)
---------- ---------- ----------
Financing Activities:
Net change in short-term debt............................................. -- (4.6) (4.2)
Proceeds from long-term borrowings........................................ -- 5.0 --
Principal payments on long-term borrowings................................ (41.5) (55.5) (16.3)
Net change in revolving credit agreement.................................. (55.0) -- --
Cash dividends paid to others............................................. (21.3) (14.9) (10.2)
---------- ---------- ----------
Net Cash Used in Financing Activities......................................... (117.8) (70.0) (30.7)
---------- ---------- ----------
Net Increase (Decrease) in Cash and Cash Equivalents.......................... (79.0) 55.6 (19.5)
Cash and Cash Equivalents at Beginning of Year................................ 83.8 28.2 47.7
---------- ---------- ----------
Cash and Cash Equivalents at End of Year...................................... $ 4.8 $ 83.8 $ 28.2
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-5
<PAGE> 174
SANTA FE ENERGY RESOURCES, INC.
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(SHARES AND DOLLARS IN MILLIONS)
<TABLE>
<CAPTION>
FOREIGN
UNAMORTIZED CURRENCY
COMMON STOCK RESTRICTED TRANSLA- TOTAL
--------------- PAID-IN STOCK ACCUMULATED TION SHAREHOLDERS'
SHARES AMOUNT CAPITAL AWARDS DEFICIT ADJUSTMENT EQUITY
------ ------ ------- ------------ ----------- ---------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1990.................. 63.8 $0.6 $ 282.4 $ -- $ (67.2) $ -- $ 215.8
Net income.................................. -- -- -- -- 18.5 -- 18.5
Issuance of common stock.................... 0.3 -- 2.5 (1.4) -- -- 1.1
Dividends declared.......................... -- -- -- -- (10.3) -- (10.3)
---- ---- ------- ------- --------- ------ -------
Balance at December 31, 1991.................. 64.1 0.6 284.9 (1.4) (59.0) -- 225.1
Issuance of common stock
Acquisition of Adobe
Resources Corporation.................... 24.9 0.3 205.3 -- -- -- 205.6
Employee stock compensation and savings
plans.................................... 0.5 -- 4.1 (0.5) -- -- 3.6
Amortization of restricted stock awards..... -- -- -- 1.5 -- -- 1.5
Foreign currency translation adjustments.... -- -- -- -- -- (0.2) (0.2)
Net loss.................................... -- -- -- -- (1.4) -- (1.4)
Dividends declared.......................... -- -- -- -- (17.6) -- (17.6)
---- ---- ------- ------- --------- ------ -------
Balance at December 31, 1992.................. 89.5 0.9 494.3 (0.4) (78.0) (0.2) 416.6
Issuance of common stock
Employee stock compensation and savings
plans.................................... 0.3 -- 2.6 (0.1) -- -- 2.5
Amortization of restricted
stock awards............................... -- -- -- 0.4 -- -- 0.4
Pension liability adjustment................ -- -- -- -- (0.9) -- (0.9)
Foreign currency transaction adjustments.... -- -- -- -- -- (0.1) (0.1)
Net loss.................................... -- -- -- -- (77.1) -- (77.1)
Dividends declared.......................... -- -- -- -- (17.8) -- (17.8)
---- ---- ------- ------- --------- ------ -------
Balance December 31, 1993..................... 89.8 $0.9 $ 496.9 $ (0.1) $ (173.8) $ (0.3) $ 323.6
==== ==== ======= ======= ========= ====== =======
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-6
<PAGE> 175
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The consolidated financial statements of Santa Fe Energy Resources, Inc.
("Santa Fe" or the "Company") and its subsidiaries include the accounts of all
wholly owned subsidiaries. The accounts of Santa Fe Energy Partners, L.P., (the
"Partnership") are included on a proportional basis until September 1993 when
Santa Fe purchased all the Partnership's outstanding Depositary Units and
undeposited LP Units other than those units held by Santa Fe and its affiliates.
On September 27, 1993 the Company exercised its right under the Agreement of
Limited Partnership to purchase all of the Partnership's outstanding Depositary
Units and undeposited LP Units, other than those units held by the Company and
its affiliates, at a redemption price of $4.9225 per unit. Consideration for the
5,749,500 outstanding units totalled $28.3 million. The acquisition of the units
has been accounted for as a purchase and the results of operations of the
Partnership attributable to the units acquired is included in the Company's
results of operations with effect from October 1, 1993. The purchase price has
been allocated primarily to oil and gas properties.
References herein to the "Company" or "Santa Fe" relate to Santa Fe Energy
Resources, Inc., individually or together with its consolidated subsidiaries;
references to the "Partnership" relate to Santa Fe Energy Partners, L.P.
All significant intercompany accounts and transactions have been eliminated.
Prior years' financial statements include certain reclassifications to conform
to current year's presentation.
Oil and Gas Operations
The Company follows the successful efforts method of accounting for its oil
and gas exploration and production activities. Costs (both tangible and
intangible) of productive wells and development dry holes, as well as the cost
of prospective acreage, are capitalized. The costs of drilling and equipping
exploratory wells which do not find proved reserves are expensed upon
determination that the well does not justify commercial development. Other
exploratory costs, including geological and geophysical costs and delay rentals,
are charged to expense as incurred.
Depletion and depreciation of proved properties are computed on an
individual field basis using the unit-of-production method based upon proved oil
and gas reserves attributable to the field. Certain other oil and gas properties
are depreciated on a straight-line basis. Individual proved properties are
reviewed periodically to determine if the carrying value of the field exceeds
the estimated undiscounted future net revenues from proved oil and gas reserves
attributable to the field. Based on this review and the continuing evaluation of
development plans, economics and other factors, if appropriate, the Company
records impairments (additional depletion and depreciation) to the extent that
the carrying value exceeds the estimated undiscounted future net revenues. Such
impairments totaled $99.3 million in 1993 and there were none in 1992 and 1991.
The Company provides for future abandonment and site restoration costs with
respect to certain of its oil and gas properties. The Company estimates that
with respect to these properties such future costs total approximately $24.7
million and such amount is being accrued over the expected life of the
properties. At December 31, 1993 Accumulated Depletion, Depreciation,
Amortization and Impairment includes $14.6 million with respect to such costs.
The value of undeveloped acreage is aggregated and the portion of such costs
estimated to be nonproductive, based on historical experience, is amortized to
expense over the average holding period. Additional amortization may be
recognized based upon periodic assessment of prospect evaluation results. The
cost of properties determined to be productive is transferred to proved
F-7
<PAGE> 176
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
properties; the cost of properties determined to be nonproductive is charged to
accumulated amortization.
Maintenance and repairs are expensed as incurred; major renewals and
improvements are capitalized. Gains and losses arising from sales of properties
are included in income currently.
Revenue Recognition
Revenues from the sale of petroleum produced are generally recognized upon
the passage of title, net of royalties and net profits interests. Crude oil
revenues include the effect of hedging transactions; see Note 12 -- Commitments
and Contingencies -- Crude Oil Hedging Program. Crude oil revenues also include
the value of crude oil consumed in operations with an equal amount charged to
operating expenses. Such amounts totalled $15.4 million in 1991, $4.8 million in
1992 and $1.2 million in 1993.
Revenues from natural gas production are generally recorded using the
entitlement method, net of royalties and net profits interests. Sales proceeds
in excess of the Company's entitlement are included in Deferred Revenues and the
Company's share of sales taken by others is included in Other Assets. At
December 31, 1993 the Company's deferred revenues for sales proceeds received in
excess of the Company's entitlement was $6.8 million with respect to 5.2 MMcf
and the asset related to the Company's share of sales taken by others was $3.9
million with respect to 2.7 MMcf. Natural gas revenues are net of the effect of
hedging transactions; see Note 12 -- Commitments and Contingencies -- Natural
Gas Hedging Program.
Revenues from crude oil marketing and trading represent the gross margin
resulting from such activities. Revenues from such activities are net of costs
of sales of $210.5 million in 1991, $247.3 million in 1992 and $225.9 million in
1993.
Revenues from natural gas systems are net of the cost of natural gas
purchased and resold. Such costs totalled $43.8 million in 1992 and $49.9
million in 1993.
Earnings Per Share
Earnings per share are based on the weighted average number of common shares
outstanding during the year.
Accounts Receivable
Accounts Receivable relates primarily to sales of oil and gas and amounts
due from joint interest partners for expenditures made by the Company on behalf
of such partners. The Company reviews the financial condition of potential
purchasers and partners prior to signing sales or joint interest agreements. At
December 31, 1993 and 1992 the Company's allowance for doubtful accounts
receivable, which is reflected in the consolidated balance sheet as a reduction
in accounts receivable, totaled $6.3 million and $5.0 million, respectively.
Accounts receivable totalling $0.2 million, $1.1 million and $0.1 million were
written off as uncollectible in 1991, 1992 and 1993, respectively.
Inventories
Inventories are valued at the lower of cost (average price or first.in,
first.out) or market. Crude oil inventories at December 31, 1993 and 1992 were
$1.1 million and $1.5 million, respectively, and materials and supplies
inventories at such dates were $7.6 million and $3.3 million, respectively.
Environmental Expenditures
Environmental expenditures relating to current operations are expensed or
capitalized, as appropriate, depending on whether such expenditures provide
future economic benefits. Liabilities
F-8
<PAGE> 177
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
are recognized when the expenditures are considered probable and can be
reasonably estimated. Measurement of liabilities is based on currently enacted
laws and regulations, existing technology and undiscounted site-specific costs.
Generally, such recognition coincides with the Company's commitment to a formal
plan of action.
Income Taxes
The Company follows the asset and liability approach to accounting for
income taxes. Deferred tax assets and liabilities are determined using the tax
rate for the period in which those amounts are expected to be received or paid,
based on a scheduling of temporary differences between the tax bases of assets
and liabilities and their reported amounts. Under this method of accounting for
income taxes, any future changes in income tax rates will affect deferred income
tax balances and financial results.
(2) CORPORATE RESTRUCTURING PROGRAM
In October 1993 the Company's Board of Directors endorsed a broad corporate
restructuring program that focuses on the disposition of non-core assets, the
concentration of capital spending in core areas, the refinancing of certain
long-term debt and the elimination of the payment of its $0.04 per share
quarterly dividend on common stock.
In implementing the restructuring program the Company recorded a
nonrecurring charge of $38.6 million in 1993 comprised of (1) losses on property
dispositions of $27.8 million: (2) long-term debt repayment penalties of $8.6
million; and (3) accruals for certain personnel benefits and related costs of
$2.2 million.
The Company's non-core asset disposition program includes the sale of its
natural gas gathering and processing assets to Hadson Corporation ("Hadson"),
the sale to Vintage Petroleum, Inc. of certain southern California and Gulf
Coast oil and gas producing properties and the sale to Bridge Oil (U.S.A.) Inc.
("Bridge") of certain Mid-Continent and Rocky Mountain oil and gas producing
properties and undeveloped acreage. The Company also plans to dispose of other
non-core oil and gas properties during 1994.
In 1994 the Company intends to refinance a portion of its existing
long-term debt and is currently evaluating a combination of debt and equity
financing arrangements with which to effect the refinancing.
Sale to Hadson. In December 1993 the Company completed a transaction with
Hadson under the terms of which the Company sold the common stock of Adobe Gas
Pipeline Company ("AGPC"), a wholly-owned subsidiary which held the Company's
natural gas gathering and processing assets, to Hadson in exchange for Hadson
11.25% preferred stock with a face value of $52.0 million and 40% of Hadson's
common stock. In addition, the Company signed a seven-year gas sales contract
under the terms of which Hadson will market substantially all of the Company's
domestic natural gas production at market prices as defined by published monthly
indices for relevant production locations.
The Company accounted for the sale as a non-monetary transaction and the
investment in Hadson has been valued at $56.2 million, the carrying value of the
Company's investment in AGPC. The Company's investment in Hadson is being
accounted for on the equity basis. At December 31, 1993 the Company's investment
in Hadson's common stock exceeded the net book value attributable to such common
shares by approximately $11.3 million. The Company's income from operations for
1993 includes $1.6 million attributable to the assets sold to Hadson.
Sale to Vintage. In November 1993 the Company completed the sale of certain
southern California and Gulf Coast producing properties for net proceeds
totalling $41.3 million in cash, $31.5
F-9
<PAGE> 178
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
million of which was collected in 1993. The Company's income from operations for
1993 includes $2.7 million attributable to the assets sold to Vintage.
Sale to Bridge. In December 1993 the Company signed a Purchase and Sales
Agreement with Bridge under the terms of which Bridge will purchase certain
Mid-Continent and Rocky Mountain producing and nonproducing oil and gas
properties. The sale price of $51.0 million, subject to certain adjustments,
will be received by the Company either in the form of cash plus 10% of the
outstanding shares of Bridge, following the contemplated public offering of that
stock in the first quarter of 1994, or entirely in cash. The transaction is
expected to close in the second quarter of 1994.
The net book value of these assets is included in Assets Held for Sale at
December 31, 1993. The Company's income from operations for 1993 includes $5.8
million attributable to the assets to be sold to Bridge.
Other Dispositions. The Company has identified certain other oil and gas
properties which it plans to dispose of in 1994. The estimated realizable value
of these properties, $1.0 million, is included in Assets Held for Sale at
December 31, 1993. In the first quarter of 1994 the Company sold its interest in
certain other oil and gas properties for $8.3 million.
(3) MERGER WITH ADOBE RESOURCES CORPORATION
On May 19, 1992 Adobe Resources Corporation ("Adobe"), an oil and gas
exploration and production company, was merged with and into Santa Fe (the
"Merger"). The acquisition has been accounted for as a purchase and the results
of operations of the properties acquired (the "Adobe Properties") are included
in Santa Fe's results of operations effective June 1, 1992.
To consummate the Merger, the Company issued 24.9 million shares of common
stock valued at $205.5 million, 5.0 million shares of convertible preferred
stock valued at $80.0 million, assumed long-term bank debt and other liabilities
of $140.0 million and $35.0 million, respectively, and incurred $13.8 million in
related costs. The Company also recorded a $19.7 million deferred tax liability
with respect to the difference between the book and tax basis in the assets
acquired. Certain merger.related costs incurred by Adobe and paid by Santa Fe
totaling $10.9 million were charged to income in the second quarter of 1992.
The Merger constituted a "change of control" as defined in certain of the
Company's employee benefit plans and employment agreements (see Notes 10 and
12).
In a separate transaction in January 1992, the Company purchased three
producing properties from Adobe for $14.2 million.
(4) SANTA FE ENERGY TRUST
In November 1992 5,725,000 Depository Units ("Trust Units"), each consisting
of beneficial ownership of one unit of undivided beneficial interest in the
Santa Fe Energy Trust (the "Trust") 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. The
Trust consists of certain oil and gas properties conveyed by Santa Fe. 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 Trust Units. A portion of the proceeds received by the
Company was used to retire $30.0 million of the debt incurred in connection with
the Merger and the remainder will be used for general corporate purposes
including possible acquisitions.
F-10
<PAGE> 179
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
For any calendar quarter ending on or prior to December 31, 2002, the
Trust will receive additional royalty payments to the extent that it needs such
payments to distribute $0.40 per Depository Unit per quarter. The source of such
additional royalty payments, if needed, will be limited to the Company's
remaining royalty interest in certain of the properties conveyed to the Trust.
If such additional payments are made, certain proceeds otherwise payable to the
Trust in subsequent quarters may be reduced to recoup the amount of such
additional payments. The aggregate amount of the additional royalty payments
(net of any amounts recouped) will be limited to $20.0 million on a revolving
basis.
At December 31, 1993 the Company held 575,000 Trust Units. At December 31,
1993 Accounts Receivable includes $0.2 million due from the Trust and Accounts
Payable includes $1.9 million due to the Trust. In the first quarter of 1994 the
Company sold the Trust Units for $11.3 million, the Company's investment in the
Trust Units, $10.4 million, is included in Assets Held for Sale at December 31,
1993.
(5) ACQUISITIONS OF OIL AND GAS PROPERTIES
In January 1991 the Company completed the purchase of Mission Operating
Partnership, L.P.'s ("Mission") interest in certain oil and gas properties,
effective from November 1, 1990, for approximately $55.0 million. The Company
formed a partnership, with an institutional investor as a limited partner, to
acquire and operate the properties. The investor contributed $27.5 million for a
50% interest in the partnership, which will be reduced to 15% upon the occurence
of payout. Payout will occur when the investor has received distributions from
the partnership totalling an amount equal to its original contribution plus a
12% rate of return on such contribution. Prior to payout, the Company will bear
100% of the capital expenditures of the partnership. Under the terms of the
partnership agreement a total of $36.8 million must be expended on development
of the property by the year 2000, $12.4 million of which had been expended
through the end of 1993.
The Company funded $16.8 million of its share of the purchase of the
properties with the assumption of a term loan and paid the remainder from
working capital. The Company has given the lender the equivalent of an
overriding royalty interest in certain production from the properties. The
royalty is payable only if such production occurs and is limited to a maximum of
$3.0 million.
In June 1991 the Company acquired a 10% interest in a producing field in
Argentina for approximately $18.3 million and in October 1991 purchased an
additional 8% interest in the field for approximately $15.7 million. The Company
financed $17.8 million of the total purchase price with loans from an Argentine
bank. The Company has agreed to spend approximately $16.7 million over a
five-year period on development and maintenance of the field.
(6) CASH FLOWS
The Company considers all highly liquid investments with a maturity of three
months or less when purchased to be cash equivalents.
The Merger included certain non-cash investing and financing activities not
reflected in the Statement of Cash Flows as follows (in millions of dollars):
<TABLE>
<S> <C>
Common stock issued............................................. 205.5
Convertible preferred stock issued.............................. 80.0
Deferred tax liability.......................................... 19.7
Long-term debt.................................................. 140.0
Assets acquired, other than cash, net of liabilities assumed.... (457.1)
------
Cash paid....................................................... (11.9)
======
</TABLE>
F-11
<PAGE> 180
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1991, the Company sold a producing property for $0.9 million in cash
and a note receivable for $1.2 million. In 1991, the Partnership purchased
certain surface properties for $6.2 million, $5.5 million of which was funded
by the issuance of promissory notes and the Company also purchased producing
properties for $63.1 million, $34.6 million of which was funded with debt (see
Notes 5 and 7).
The Company made interest payments of $45.5 million, $49.0 million and $48.0
million in 1991, 1992 and 1993, respectively. In 1991, 1992 and 1993, the
Company made tax payments of $18.4 million, $4.4 million and $5.0 million,
respectively, and in 1993 received refunds of $4.1 million, primarily related to
the audit of prior years' returns.
(7) FINANCING AND DEBT
Long-term debt at December 31, 1993 and 1992 consisted of (in millions of
dollars):
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------------------------
1993 1992
-------------------- --------------------
CURRENT LONG-TERM CURRENT LONG-TERM
------- --------- ------- ----------
<S> <C> <C> <C> <C>
SFER
Senior Notes................................................... 30.0 310.0 25.0 340.0
Revolving and Term Credit Agreement............................ 1.3 48.7 12.8 92.2
Notes Payable to Bank.......................................... 3.8 11.3 2.5 15.1
Term.Loan...................................................... 1.2 11.4 1.2 12.6
Partnership
Credit Agreement............................................... 8.0 24.0 11.1 29.5
Promissory Notes............................................... -- -- 0.8 3.4
---- ----- ---- -----
44.3 405.4 53.4 492.8
==== ===== ==== =====
</TABLE>
Aggregate total maturities of long-term debt during the next five years are
as follows: 1994 -- $44.3 million; 1995 -- $78.9 million; 1996 -- $73.5 million;
1997 -- $43.0 million; and 1998 -- $35.0 million. These maturities will be
affected by the refinancing discussed in Note 2 -- Corporate Restructuring
Program.
On April 11, 1990 SFER issued $365.0 million of serial unsecured Senior
Notes with interest rates averaging 10.35%. The Note Agreement pursuant to which
the Senior Notes were issued includes certain covenants which, among other
things, restrict the Company's ability to incur additional indebtedness and to
pay dividends. Under the terms of the Note Agreement, at December 31, 1993 the
Company had the ability to incur at least $64.0 million in additional long-term
debt and pay $26.0 million in dividends and other restricted payments. At
December 31, 1993 $340.0 million in Senior Notes were outstanding and are to be
repaid, $30.0 million in 1994 and 1995, $35.0 million in 1996 through 1998 and
$25.0 million per year in 1999 through 2005.
In January 1991 the Company executed a $16.8 million term.loan agreement,
with interest at 9.0%, in connection with the purchase of certain producing
properties from Mission. At December 31, 1993 $12.6 million was outstanding
under the terms of the agreement and is to be repaid $1.2 million in 1994 and
$11.4 million in 1995. The Company made principal payments on the loan totalling
$1.8 million in 1991, $1.2 million in 1992 and $1.2 million in 1993.
In June 1991 the Company borrowed $10.4 million from an Argentine bank in
connection with the purchase of an interest in a producing oil field in
Argentina. The loan bore interest at the higher of 12% or the interbank offering
rate plus 2%. In October 1991 the Company borrowed an additional $7.8 million in
connection with the purchase of an additional interest in the field. The second
loan bore interest at the higher of rates ranging from 13.4% to 14.0% or the
London Interbank Offering
F-12
<PAGE> 181
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Rate ("LIBOR") plus 2%. During 1993 the two loans were combined in a new loan
which bears interest at the higher of 13.06% or LIBOR plus 2%.
In connection with the Merger the Company entered into a $195.0 million
Revolving and Term Credit Agreement (the "Credit Agreement") with a group of
banks. Upon consummation of the Merger the Company drew down the $145.0 million
available under the term loan feature of the Credit Agreement and repaid the
$140.0 million of long-term debt assumed in the Merger. The borrowings under the
term loan feature of the Credit Agreement are secured by properties acquired in
the Merger. Interest rates on borrowings are determined from time to time and at
December 31, 1993 amounts outstanding under the term loan feature bore interest
at an average of 5.5% per annum.
In April 1993 the term loan feature was amended to allow the Company to make
voluntary prepayments and reborrowings. At December 31, 1993 the balance
outstanding under the term loan feature was $50.0 million and the total amount
available under the term loan feature, including amounts then outstanding, was
$87.7 million. The amount available will be reduced, in semi.annual increments,
to $48.6 million in December 31, 1994 and $24.3 million at December 31, 1995.
The Credit Agreement expires December 31, 1996. In certain circumstances,
primarily related to the sale of properties securing the loans, the amount
available may be reduced or the Company may be required to make mandatory
repayments. The Company is currently negotiating an amendment to the Credit
Agreement which would extend the maturities and under certain circumstances
increase the amount available for borrowings.
Under the revolving credit feature of the Credit Agreement the Company may
borrow and issue letters of credit totalling up to $50.0 million. Borrowings
under the revolving credit feature are unsecured but are subject to compliance
with covenants identical to existing covenants under the Company's other
long-term debt agreeements including covenants related to debt incurrence,
dividends and other restricted payments, investments and limitations on liens,
mergers and sales of assets. In addition, the Company must comply annually with
certain borrowing base coverage ratios relating to projected cash flows from oil
and gas revenues. The amount available under the revolving credit feature will
be reduced to $10.0 million on February 28, 1994 and this feature expires on
February 28, 1995. At December 31, 1993, the Company had $8.7 million in letters
of credit outstanding under the revolving credit feature of the Credit
Agreement.
The Company has two uncommitted lines of credit totalling $35.0 million
which is used to meet short-term cash needs. Interest rates on borrowings under
this line of credit is typically lower than rates paid under the Credit
Agreement. At December 31, 1993 no amounts were outstanding under these lines of
credit.
In December 1991 the Partnership issued two promissory notes for a total of
$5.5 million in connection with the purchase of certain surface lands. The
notes, which bore interest at 10.0%, were retired in 1993. The Company's
proportionate share of such debt at December 31, 1992 was $4.2 million.
At December 31, 1993 and 1992 the Partnership had $32.0 million and $44.0
million, respectively, outstanding under the terms of long-term credit agreement
which expires in 1997. The Company's proportionate share of such debt totaled
$40.6 million at December 31, 1992. Interest on 65% of principal amount
outstanding is fixed at 10.13% with interest on the remaining amount outstanding
at floating rates which averaged 4.3% in 1993 and 5.46% in 1992. The credit
agreement imposes certain restrictions on future indebtedness and the transfer
or sale of principal properties and requires the maintenance of certain
financial ratios to avoid collateralization or default.
F-13
<PAGE> 182
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(8) SEGMENT INFORMATION
The principal business of the Company is oil and gas, which consists of the
acquisition, exploration and development of oil and gas properties and the
production and sale of crude oil and liquids and natural gas. Pertinent
information with respect to the Company's oil and gas business is presented in
the following table (in millions of dollars):
<TABLE>
<CAPTION> OIL AND GAS
---------------------------------------------
OTHER GENERAL
U.S. ARGENTINA INDONESIA FOREIGN CORPORATE TOTAL
-------- --------- --------- ------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
1993
Revenues..................................... 401.2 12.5 23.2 -- -- 436.9
Income (Loss) from Operations................ (33.6) 3.0 (13.4) (18.4) (50.6) (113.0)
Depletion, Depreciation, Amortization and
Impairment................................. 218.8 3.6 21.2 6.7 1.7 252.0
Additions to Property and Equipment.......... 116.1 7.3 16.8 6.1 4.4 150.7
Identifiable Assets at December 31........... 862.0 48.2 65.3 2.8 98.6 1,076.9
1992
Revenues..................................... 400.0 13.9 13.6 -- -- 427.5
Income (Loss) from Operations................ 100.6 2.5 2.3 (10.7 ) (37.2) 57.5
Depletion, Depreciation and Amortization..... 136.7 3.7 2.7 1.6 1.6 146.3
Additions to Property and Equipment.......... 452.6 4.0 71.6 5.7 2.4 536.3
Identifiable Assets at December 31........... 1,076.5 39.2 73.9 5.8 141.8 1,337.2
1991
Revenues..................................... 376.1 3.7 -- -- -- 379.8
Income (Loss) from Operations................ 103.7 (2.2) .2 (2.5 ) (34.8) 64.4
Depletion, Depreciation and Amortization..... 101.3 1.8 -- .7 2.8 106.6
Additions to Property and Equipment.......... 125.8 35.4 -- 3.7 8.8 173.7
Identifiable Assets at December 31........... 816.5 37.5 .2 3.9 53.8 911.9
</TABLE>
Crude oil and liquids and natural gas accounted for more than 95% of
revenues in 1991, 1992 and 1993. The following table reflects sales revenues
from crude oil purchasers who accounted for more than 10% of the Company's crude
oil and liquids revenues (in millions of dollars):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1993 1992 1991
---- ---- ----
<S> <C> <C> <C>
Texaco Trading and Transportation, Inc................................... -- 46.8 55.9
Celeron Corporation...................................................... 56.8 56.3 45.6
Shell Oil Company........................................................ 86.3 -- --
</TABLE>
None of the Company's purchasers of natural gas accounted for more than 10%
of revenues in 1991, 1992 or 1993. The Company does not believe the loss of any
purchaser would have a material adverse effect on its financial position since
the Company believes alternative sales arrangements could be made on relatively
comparable terms.
F-14
<PAGE> 183
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(9) CONVERTIBLE PREFERRED STOCK
The convertible preferred stock issued in connection with the Merger is
non-voting and entitled to receive cumulative cash dividends at an annual rate
equivalent to $1.40 per share. The holders of the convertible preferred shares
may, at their option, convert any or all such shares into 1.3913 shares of the
Company's common stock. The Company may, at any time after the fifth anniversary
of the effective date of the Merger and upon the occurrence of a "Special
Conversion Event", convert all outstanding shares of convertible preferred stock
into common stock at the initial conversion rate of 1.3913 shares of common
stock, subject to certain adjustments, plus additional shares in respect to
accrued and unpaid dividends. A Special Conversion Event is deemed to have
occurred when the average daily closing price for a share of the Company's
common stock for 20 of 30 consecutive trading days equals or exceeds 125% of the
quotient of $20.00 divided by the then applicable conversion rate (approximately
$18.00 per share at a conversion rate of 1.3913).
Upon the occurrence of the "First Ownership Change" of Santa Fe, each holder
of shares of convertible preferred stock shall have the right, at the holder's
option, to elect to have all of such holder's shares redeemed for $20.00 per
share plus accrued and unpaid interest and dividends. The First Ownership Change
shall be deemed to have occurred when any person or group, together with any
affiliates or associates, becomes the beneficial owner of 50% or more of the
outstanding common stock of Santa Fe.
(10) SHAREHOLDERS' EQUITY
Common Stock
In 1991, 1992 and 1993 the Company issued 1.1 million previously unissued
shares of common stock in connection with certain employee benefit and
compensation plans. Also in 1992, the Company issued 24.9 million previously
unissued shares of common stock in connection with the Merger.
The Company declared dividends to common shares of $0.16 per share in 1991
and 1992 and $0.12 per share in 1993.
Preferred Stock
The Board of Directors of the Company is empowered, without approval of the
shareholders, to cause shares of preferred stock to be issued in one or more
series, and to determine the number of shares in each series and the rights,
preferences and limitations of each series. Among the specific matters which may
be determined by the Board of Directors are: the annual rate of dividends; the
redemption price, if any; the terms of a sinking or purchase fund, if any; the
amount payable in the event of any voluntary liquidation, dissolution or winding
up of the affairs of the Company; conversion rights, if any; and voting powers,
if any.
Accumulated Deficit
At December 31, 1993 Accumulated Deficit included dividends in excess of
retained earnings of $89.8 million.
1990 Incentive Stock Compensation Plan
The Company has adopted the Santa Fe Energy Resources 1990 Incentive Stock
Compensation Plan (the "Plan") under the terms of which the Company may grant
options and awards with respect to no more than 5,000,000 shares of common stock
to officers and key employees.
Options granted in 1991 and prior are fully vested and expire in 2000.
Options granted in 1992 have a ten year term and vest as to 33.33 percent one
year after grant, as to a cumulative 66.67
F-15
<PAGE> 184
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
percent two years after grant and as to the entire amount three years after
grant. The options granted in 1993 have a ten year term and vest as to 50
percent 5 years after grant, as to a cumulative 75 percent 6 years after grant
and as to the entire amount 7 years after grant. The options are exercisable on
an accelerated basis beginning one year and ending three years after grant in
certain circumstances. If the market value per share of the Company's common
stock (sustained in all events for at least 60 days) exceeds $15, 25 percent of
the options shall become exercisable; in the event the market value per share
exceeds $20, 50 percent of the options shall become exercisable; and in the
event the market value exceeds $25, 100 percent shall become exercisable.
Unexercised options would be forfeited in the event of voluntary or involuntary
termination. Vested options are exercisable for a period of one year following
termination due to death, disability or retirement. In the event of termination
by the Company for any reason there is no prorata vesting of unvested options.
The following table reflects activity with respect to Non-Qualified Stock
Options during 1991 through 1993:
<TABLE>
<CAPTION>
OPTION
OPTIONS PRICE
OUTSTANDING PER SHARE
----------- ------------------
<S> <C> <C>
Outstanding at December 31, 1990................................ 1,803,923 $14.4375 to $24.24
Grants.......................................................... 4,500 $14.625
Cancellations................................................... (45,332) $14.4375 to $24.24
---------
Outstanding at December 31, 1991................................ 1,763,091 $14.4375 to $24.24
Grants.......................................................... 1,099,000 $ 9.5625
Cancellations................................................... (50,163) $14.4375 to $24.24
---------
Outstanding at December 31, 1992................................ 2,811,928 $ 9.5625 to $24.24
Grants.......................................................... 800,000 $ 9.5625
Cancellations................................................... (95,398) $ 9.5625 to $24.24
Exercises....................................................... (6,945) $ 9.5625
---------
Outstanding at December 31, 1993................................ 3,509,585 $ 9.5625 to $24.24
=========
</TABLE>
At December 31, 1993 options on 780,790 shares were available for future
grants.
A "Phantom Unit" is the right to receive a cash payment in an amount equal
to the average trading price of the shares of common stock at the time the award
becomes payable. Awards are made for a specified period and are dependent upon
continued employment and the achievement of performance objectives established
by the Company. In December 1990 the Company awarded 211,362 Phantom Units and
in December 1991 313,262 shares of restricted stock were issued in exchange for
such units. Compensation expense is recognized over the period the awards are
earned based on the market price of the restricted stock on the date it was
issued ($8.00 per share). During 1990 and 1991 $0.2 million and $0.8 million,
respectively, were charged to expense with respect to such awards. The
unamortized portion of the award at December 31, 1991 ($1.4 million) was
reflected in Shareholders' Equity. The consummation of the Merger resulted in a
"change of control" as defined in the Plan and resulted in the vesting of the
awards and $1.4 million in compensation expense was recognized in 1992.
In 1993 the Company issued 6,432 shares of restricted stock to certain
employees and 118,039 common shares in accordance with the terms of certain
other employee compensation plans.
F-16
<PAGE> 185
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(11) PENSION AND OTHER EMPLOYEE BENEFIT PLANS
Pension Plans
Prior to the Spin-Off the Company was included in certain non-contributory
pension plans of SFP. The Santa Fe Pacific Corporation Retirement Plan (the "SFP
Plan") covered substantially all of the Company's officers and salaried
employees who were not covered by collective bargaining agreements. The Santa Fe
Pacific Corporation Supplemental Retirement Plan was an unfunded plan which
provided supplementary benefits, primarily to senior management personnel.
The Company adopted, effective as of the date of the Spin-Off, a defined
benefit retirement plan (the "SFER Plan") covering substantially all salaried
employees not covered by collective bargaining agreements and a nonqualified
supplemental retirement plan (the "Supplemental Plan"). The Supplemental Plan
will pay benefits to participants in the SFER Plan in those instances where the
SFER Plan formula produces a benefit in excess of limits established by ERISA
and the Tax Reform Act of 1986. Benefits payable under the SFER Plan are based
on years of service and compensation during the five highest paid years of
service during the ten years immediately preceding retirement. Benefits accruing
to the Company's employees under the SFP Plan have been assumed by the SFER
Plan. The Company's funding policy is to contribute annually not less than the
minimum required by ERISA and not more than the maximum amount deductible for
income tax purposes. In the fourth quarter of 1993 the Company established a new
pension plan with respect to certain persons employed in foreign locations.
The following table sets forth the funded status of the SFER Plan and the
Supplemental Plan at December 31, 1993 and 1992 (in millions of dollars):
<TABLE>
<CAPTION>
SFER PLAN SUPPLEMENTAL PLAN
-------------------- --------------------
1993 1992 1993 1992
-------- --------- -------- ---------
<S> <C> <C> <C> <C>
Plan assets at fair value, primarily invested in common
stocks and U.S. and corporate bonds..................... 30.2 28.9 -- --
Actuarial present value of projected benefit obligations:
Accumulated benefit obligations
Vested............................................ (30.9) (24.5) (0.6) (0.5)
Nonvested......................................... (1.5) (1.4) -- --
Effect of projected future salary increases....... (8.3) (6.4) (0.3) (0.2)
----- ----- ---- ----
Excess of projected benefit obligation over plan
assets.................................................. (10.5) (3.4) (0.9) (0.7)
Unrecognized net loss from past experience different from
that assumed and effects of changes in assumptions...... 6.4 0.7 0.3 0.2
Unrecognized net (asset) obligation being recognized over
plan's average remaining service life................... (1.0) (1.1) 0.2 0.3
Additional minimum liability.............................. -- -- (0.3) (0.3)
----- ----- ---- ----
Accrued pension liability................................. (5.1) (3.8) (0.7) (0.5)
===== ===== ==== ====
Major assumptions at year-end
Discount rate......................................... 7.0% 8.25% 7.0% 8.25%
Long-term asset yield................................. 9.5% 9.5% 9.5% 9.5%
Rate of increase in future compensation............... 5.25% 5.25% 5.25% 5.25%
</TABLE>
F-17
<PAGE> 186
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth the components of pension expense for the
SFER Plan and Supplemental Plan for 1993, 1992 and 1991 (in millions of
dollars):
<TABLE>
<CAPTION>
SFER PLAN SUPPLEMENTAL PLAN
------------------------------- -------------------------------
1993 1992 1991 1993 1992 1991
--------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Service cost..................... 1.4 1.2 1.1 -- -- --
Interest cost.................... 2.6 2.4 2.3 0.1 0.1 0.1
Return on plan assets............ (2.7) (2.5) (2.4) -- -- --
Net amortization and deferral.... -- -- (0.1) -- -- --
---- ---- ---- --- --- ---
1.3 1.1 0.9 0.1 0.1 0.1
==== ==== ==== === === ===
</TABLE>
The Company also sponsors a pension plan covering certain hourly-rated
employees in California (the "Hourly Plan"). The Hourly Plan provides benefits
that are based on a stated amount for each year of service. The Company annually
contributes amounts which are actuarially determined to provide the Hourly Plan
with sufficient assets to meet future benefit payment requirements.
The following table sets forth the components of pension expense for the
Hourly Plan for the years 1993, 1992 and 1991 (in millions of dollars):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------------
1993 1992 1991
--------- --------- ---------
<S> <C> <C> <C>
Service cost............................................................. 0.2 0.2 0.2
Interest cost............................................................ 0.7 0.7 0.7
Return on plan assets.................................................... (0.8) (0.1) (0.5)
Net amortization and deferral............................................ 0.4 (0.4) 0.1
---- ---- ----
0.5 0.4 0.5
==== ==== ====
</TABLE>
The following table sets forth the funded status of the Hourly Plan at
December 31, 1993 and 1992 (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
---- ----
<S> <C> <C>
Plan assets at fair value, primarily invested in fixed-rate securities........... 7.7 7.2
Actual present value of projected benefit obligations
Accumulated benefit obligations
Vested................................................................... (11.2) (9.1)
Nonvested................................................................ (0.4) (0.3)
----- ----
Excess of projected benefit obligation over plan assets.......................... (3.9) (2.2)
Unrecognized net (gain) loss from past experience different from that
assumed and effects of changes in assumptions................................ 1.5 (0.3)
Unrecognized prior service cost.................................................. 0.5 0.6
Unrecognized net obligation...................................................... 1.5 1.6
Additional minimum liability..................................................... (3.5) (2.1)
----- ----
Accrued pension liability.................................................... (3.9) (2.4)
Major assumptions at year-end ===== ====
Discount rate................................................................ 7.0% 8.25%
Expected long-term rate of return on plan assets............................. 8.5% 8.5 %
</TABLE>
At December 31, 1993 the Company's additional minimum liability exceeded the
total of its unrecognized prior service cost and unrecognized net obligation by
$1.5 million. Accordingly, at
F-18
<PAGE> 187
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1993 the Company's retained earnings have been reduced by such
amount, net of related taxes of $0.6 million.
Postretirement Benefits Other Than Pensions
The Company provides health care and life insurance benefits for
substantially all employees who retire under the provisions of a
Company-sponsored retirement plan and their dependents. Participation in the
plans is voluntary and requires a monthly contribution by the employee.
Effective January 1, 1993 the Company adopted the provisions of SFAS No.
106 -- "Employers' Accounting for Postretirement Benefits Other Than Pensions".
The Statement requires the accrual, during the years the employee renders
service, of the expected cost of providing postretirement benefits to the
employee and the employee's beneficiaries and covered dependents. The following
table sets forth the plan's funded status at December 31, 1993 and January 1,
1993 (in millions of dollars):
<TABLE>
<CAPTION>
DECEMBER 31, JANUARY 1,
1993 1993
------------ ----------
<S> <C> <C>
Plan assets, at fair value............................................ -- --
Accumulated postretirement benefit obligation
Retirees............................................................ (3.6) (3.1)
Eligible active participants........................................ (1.2) (0.9)
Other active participants........................................... (1.4) (1.2)
----- ----
Accumulated postretirement benefit obligation in excess of plan
assets.............................................................. (6.2) (5.2)
Unrecognized transition obligation.................................... 5.0 5.2
Unrecognized net loss from past experience different from
that assumed and from changes in assumptions........................ 0.5 --
----- ----
Accrued postretirement benefit cost................................... (0.7) --
===== ====
Assumed discount rate................................................. 7.5% 8.25%
Assumed rate of compensation increase................................. 5.25% 5.25%
</TABLE>
The Company's net periodic postretirement benefit cost for 1993 includes the
following components (in millions of dollars):
<TABLE>
<S> <C>
Service costs........................................................ 0.3
Interest costs....................................................... 0.4
Amortization of unrecognized transition obligation................... 0.3
---
1.0
===
</TABLE>
In periods prior to 1993 the cost to the Company of providing health care
and life insurance benefits for qualified retired employees was recognized as
expenses when claims were paid. Such amounts totalled $0.4 million in 1991 and
$0.3 million in 1992.
Estimated costs and liabilities have been developed assuming trend rates for
growth in future health care costs beginning with 10% for 1993 graded to 6%
(5.5% for post age 65) by the year 2000 and remaining constant thereafter.
Increasing the assumed health care cost trend rate by one percent each year
would increase the accumulated postretirement benefit obligation as of December
31, 1993 by $0.9 million and the aggregate of the service cost and interest cost
components of the net periodic postretirement benefit cost for 1994 by $0.2
million.
Savings Plan
The Company has a savings plan, which became effective November 1, 1990,
available to substantially all salaried employees and intended to qualify as a
deferred compensation plan under
F-19
<PAGE> 188
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Section 401(k) of the Internal Revenue Code (the "401(k) Plan"). The
Company will match employee contributions for an amount up to 4% of each
employee's base salary. In addition, if at the end of each fiscal year the
Company's performance for such year has exceeded certain predetermined criteria,
each participant will receive an additional matching contribution equal to 50%
of the regular matching contribution. The Company's contributions to the 401(k)
Plan, which are charged to expense, totaled $1.2 million in 1991, $1.3 million
in 1992 and $1.5 million in 1993. In the fourth quarter of 1993 the Company
established a new savings plan with respect to certain personnel employed in
foreign locations.
Other Postemployment Benefits
In the fourth quarter of 1993 the Company adopted SFAS No.
112 -- "Employers' Accounting for Postemployment Benefits". The Statement
requires the accrual of the estimated costs of benefits provided by an employer
to former or inactive employees after employment but before retirement. Such
benefits include salary continuation, supplemental unemployment benefits,
severance benefits, disability-related benefits, job training and counseling and
continuation of benefits such as health care and life insurance coverage. The
adoption of SFAS No. 112 resulted in a charge to earnings of $1.8 million in
1993.
(12) COMMITMENTS AND CONTINGENCIES
Crude Oil Hedging Program
In the third quarter of 1990, the Company initiated a hedging program
designed to provide a certain minimum level of cash flow from its sales of crude
oil. Settlements were included in oil revenues in the period the oil is sold. In
the year ended December 31, 1990 hedges resulted in a reduction in oil revenues
of $10.7 million; in 1991 hedges resulted in an increase in oil revenues of
$41.7 million and in 1992 hedges resulted in an increase in oil revenues of $9.7
million. The Company had no open crude oil hedging contracts during 1993.
Natural Gas Hedging Program
In the third quarter of 1992 the Company initiated a hedging program with
respect to its sales of natural gas. The Company has used various instruments
whereby monthly settlements are based on the differences between the price or
range of prices specified in the instruments and the settlement price of certain
natural gas futures contracts quoted on the New York Mercantile Exchange. In
instances where the applicable settlement price is less than the price specified
in the contract, the Company receives a settlement based on the difference; in
instances where the applicable settlement price is higher than the specified
prices the Company pays an amount based on the difference. The instruments
utilized by the Company differ from futures contracts in that there is no
contractual obligation which requires or allows for the future delivery of the
product. In 1992 and 1993 hedges resulted in a reduction in natural gas revenues
of $0.5 million and $8.2 million, respectively.
At December 31, 1993 the Company had two open natural gas hedging contracts
covering approximately 1.2 Bcf during the six month period beginning March 1994.
The "approximate break-even price" (the average of the monthly settlement prices
of the applicable futures contracts which would result in no settlement being
due to or from the Company) with respect to such contracts is approximately
$1.82 per Mcf. In addition, certain parties hold options on contracts covering
approximately 4.8 Bcf during the seven month period beginning March 1994 at an
approximate break even price of $1.90 per Mcf. The Company has no other
outstanding natural gas hedging instruments.
Indemnity Agreement With SFP
At the time of the Spin-Off, the Company and SFP entered into an agreement
to protect SFP from federal and state income taxes, penalties and interest that
would be incurred by SFP if the
F-20
<PAGE> 189
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Spin-off were determined to be a taxable event resulting primarily from
actions taken by the Company during a one-year period that ended December 4,
1991. If the Company were required to make payments pursuant to the agreement,
such payments could have a material adverse effect on its financial condition;
however, the Company does not believe that it took any actions during such
one-year period that would have such an effect on the Spin-Off.
Environmental Regulation
Federal, state and local laws and regulations relating to environmental
quality control affect the Company in all of its oil and gas operations. The
Company has been identified as one of over 250 potentially responsible parties
("PRPs") at a superfund site in Los Angeles County, California. The site was
operated by a third party as a waste disposal facility from 1948 until 1983. The
Environmental Protection Agency ("EPA") is requiring the PRPs to undertake
remediation of the site in several phases, which include site monitoring and
leachate control, gas control and final remediation. In 1989, the EPA and a
group of the PRPs entered into a consent decree covering the site monitoring and
leachate control phases of remediation. The Company is a member of the group
that is responsible for carrying out this first phase of work, which is expected
to be completed in five to eight years. The maximum liability of the group,
which is joint and several for each member of the group, for the first phase is
$37.0 million, of which the Company's share is expected to be approximately $2.4
million ($1.3 million after recoveries from working interest participants in the
unit at which the wastes were generated) payable over the period that the phase
one work is performed. The EPA and a group of PRPs of which the Company is a
member have also entered into a subsequent consent decree (which has not been
finally entered by the court) with respect to the second phase of work (gas
control). The liability of this group has not been capped, but is estimated to
be $130.0 million. The Company's share of costs of this phase, however, is
expected to be approximately of the same magnitude as that of the first phase
because more parties are involved in the settlement. The Company has provided
for costs with respect to the first two phases, but it cannot currently estimate
the cost of any subsequent phases of work or final remediation which may be
required by the EPA.
In 1989, Adobe received requests from the EPA for information pursuant to
Section 104(e) of CERCLA with respect to the D.L. Mud and Gulf Coast Vacuum
Services superfund sites located in Abbeville, Louisiana. The EPA has issued its
record of decision at the Gulf Coast Site and on February 9, 1993 the EPA issued
to all PRP's at the site a settlement order pursuant to Section 122 of CERCLA.
Earlier, an emergency order pursuant to Section 106 of CERLA was issued on
December 11, 1992, for purposes of containment due to the Louisiana rainy
season. On December 15, 1993 the Company entered into a sharing agreement with
other PRP'S to participate in the final remediation of the Gulf Coast site. The
Company's share of the remediation is approximately $600,000 and includes its
proportionate share of those PRPs who do not have the financial resources to
provide their share of the work at the site. A former site owner has already
conducted remedial activities at the D.L. Mud Site under a state agency
agreement. The extent, if any, of any further necessary remedial activity at the
D.L. Mud Site has not been finally determined.
Employment Agreements
The Company has entered into employment agreements with certain key
employees. The initial term of each agreement expired on December 31, 1990 and,
on January 1, 1991 and beginning on each January 1 thereafter, is automatically
extended for one-year periods, unless by September 30 of any year the Company
gives notice that the agreement will not be extended. The term of the agreements
is automatically extended for 24 months following a change of control. The
consummation of the Merger constituted a change of control as defined in the
agreements.
F-21
<PAGE> 190
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In the event that following a change of control employment is terminated
for reasons specified in the agreements, the employee would receive: (i) a lump
sum payment equal to two years' base salary; (ii) the maximum possible bonus
under the terms of the Company's incentive compensation plan; (iii) a lapse of
restrictions on any outstanding restricted stock grants and full payout of any
outstanding Phantom Units; (iv) cash payment for each outstanding stock option
equal to the amount by which the fair market value of the common stock exceeds
the exercise price of the option; and, (v) life, disability and health benefits
for a period of up to two years. In addition, payments and benefits under
certain employment agreements are subject to further limitations based on
certain provisions of the Internal Revenue Code.
Interest Rate Swaps
Prior to the Merger, Adobe had entered into two interest rate swaps with a
bank with notional principal amounts of $15.0 mllion and $20.0 million. Under
the terms of the $20.0 million swap, which expires in April 1994, during any
quarterly period at the beginning of which a floating rate specified in the
agreement is less than 7.84%, the Company must pay the bank interest for such
period on the principal amount at the difference between the rates. Should the
floating rate be in excess of 7.84%, the bank must pay the Company interest for
such period on the principal amount at the difference between the rates. For the
period from the effective date of the Merger to December 31, 1992 the amount due
the bank in accordance with the terms of the $20.0 million swap totalled $0.6
million and the amount due the bank in 1993 totalled $0.9 million. For the
quarterly period which ends in April 1994, the amount due the bank is based on a
floating rate of 3.375%. The $15.0 million swap, which expired December 31,
1992, had terms similar to the $20.0 million swap and the amount due the bank
for the period subsequent to the Merger totaled $0.5 million.
Operating Leases
The Company has noncancellable agreements with terms ranging from one to ten
years to lease office space and equipment. Minimum rental payments due under the
terms of these agreements are: 1994 -- $6.1 million, 1995 -- $6.0 million,
1996 -- $5.5 million, 1997 -- $5.2 million, 1998 -- $4.4 million and $4.7
million thereafter. Rental payments made under the terms of noncancellable
agreements totaled $4.0 million in 1991,$4.5 million in 1992 and $5.5 million in
1993.
Other Matters
The Company has several long-term contracts ranging up to fifteen years for
the supply and transportation of approximately 30 million cubic feet per day of
natural gas. In the aggregate, these contracts involve a minimum commitment on
the part of the Company of approximately $10 million per year.
There are other claims and actions, including certain other environmental
matters, pending against the Company. In the opinion of management, the amounts,
if any, which may be awarded in connection with any of these claims and actions
could be significant to the results of operations of any period but would not
be material to the Company's consolidated financial position.
(13) INCOME TAXES
Effective January 1, 1993 the Company adopted the provisions of Statement of
Financial Accounting Standards No. 109 -- "Accounting for Income Taxes". The
adoption of SFAS No. 109 had no significant impact on the Company's provision
for income taxes.
Through the date of the Spin-Off the taxable income or loss of the Company
was included in the consolidated federal income tax return filed by SFP. The
Company has filed separate consolidated federal income tax returns for periods
subsequent to the Spin-Off. The consolidated federal income
F-22
<PAGE> 191
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
tax returns of SFP have been examined through 1988 and all years prior
to 1981 are closed. Issues relating to the years 1981 through 1985 are being
contested through various stages of administrative appeal. The Company is
evaluating its position with respect to issues raised in a 1986 through 1988
audit. The Company believes adequate provision has been made for any adjustments
which might be assessed for all open years.
During 1989, the Company received a notice of deficiency for certain state
franchise tax returns filed for the years 1978 through 1983 as part of the
consolidated tax returns of SFP. The years subsequent to 1983 are still subject
to audit. At December 31, 1993 Other Long-Term Obligations includes $20.6
million with respect to this matter. The Company intends to contest this matter.
With the Merger of Adobe the Company succeeded to a net operating loss
carryforward that is subject to Internal Revenue Code Section 382 limitations
which annually limit taxable income that can be offset by such losses. Certain
changes in the Company's shareholders may impose additional limitations as well.
Losses carrying forward of $133.3 million expire beginning in 1998.
At date of the Merger, Adobe had ongoing tax litigation related to a refund
claim for carryback of certain net operating losses denied by the Internal
Revenue Service. During 1991 Adobe successfully defended its claim in Federal
District Court and prevailed again in 1992 in the United States Court of Appeals
for the Fifth Circuit. The Internal Revenue Service had no further recourse to
litigation and a $16.2 million refund was reflected as Income Tax Refund
Receivable at December 31, 1992 and collected in 1993.
Pretax income from continuing operations for the years ended December 31,
1993, 1992 and 1991 was taxed under the following jurisdictions:
<TABLE>
<CAPTION>
1993 1992 1991
------- ------ -----
<S> <C> <C> <C>
Domestic............................................................... (120.9) 2.7 34.8
Foreign................................................................ (29.3) (3.6) (2.1)
------ ---- ----
(150.2) (0.9) 32.7
====== ==== ====
</TABLE>
The Company's income tax expense (benefit) for the years ended December 31,
1993, 1992 and 1991 consisted of (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992 1991
------ ----- ----
<S> <C> <C> <C>
Current
U.S. federal........................................................... (1.3) 3.5 11.0
State.................................................................. (1.2) 1.4 1.7
Foreign................................................................ 1.3 1.9 --
---- ---- ----
(1.2) 6.8 12.7
----- ---- ----
Deferred
U.S. federal........................................................... (65.6) (3.5) 0.2
U.S. federal tax rate change........................................... 2.6 -- --
State.................................................................. (8.0) (2.5) 1.3
Foreign................................................................ (0.9) (0.3) --
----- ---- ----
(71.9) (6.3) 1.5
----- ---- ----
(73.1) 0.5 14.2
===== ==== ====
</TABLE>
F-23
<PAGE> 192
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's deferred income tax liabilities (assets) at December 31, 1993
and 1992 are composed of the following differences between financial and tax
reporting (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
----- -----
<S> <C> <C>
Capitalized costs and write-offs.............................................. 83.0 150.8
Differences in Partnership basis.............................................. 15.1 29.3
State deferred liability...................................................... 5.8 13.4
Foreign deferred liability.................................................... 13.7 15.5
----- -----
Gross deferred liabilities.................................................... 117.6 209.0
----- -----
Accruals not currently deductible for tax purposes............................ (17.7) (28.3)
Alternative minimum tax carryforwards......................................... (8.3) (5.3)
Net operating loss carryforwards.............................................. (46.7) (56.4)
Other......................................................................... (0.5) --
----- -----
Gross deferred assets......................................................... (73.2) (90.0)
----- -----
Deferred tax liability........................................................ 44.4 119.0
===== =====
</TABLE>
The Company had no deferred tax asset valuation allowance at December 31,
1993 or 1992.
A reconciliation of the Company's U.S. income tax expense (benefit) computed
by applying the statutory U.S. federal income tax rate to the Company's income
(loss) before income taxes for the years ended December 31, 1993, 1992 and 1991
is presented in the following table (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992 1991
------ ----- ----
<S> <C> <C> <C>
U.S. federal income taxes (benefit) at statutory rate................ (52.6) (0.3) 11.1
Increase (reduction) resulting from:
State income taxes, net of federal effect.......................... (1.0) 1.4 2.2
Foreign income taxes in excess of U.S. rate........................ (0.8) 0.3 --
Nondeductible amounts.............................................. (0.2) (2.4) --
Effect of increase in statutory rate on deferred taxes............. 2.6 -- --
Federal audit refund............................................... (3.2) -- --
Amendment to tax sharing agreement with SFP........................ (1.2) -- --
Benefit of tax losses.............................................. (11.2) -- --
Prior period adjustments........................................... (5.5) -- --
Other.............................................................. -- 1.5 0.9
----- ---- ----
(73.1) 0.5 14.2
===== ==== ====
</TABLE>
The Company increased its deferred tax liability in 1993 as a result of
legislation enacted during 1993 increasing the corporate tax rate from 34% to
35% commencing in 1993.
(14) FAIR VALUE OF FINANCIAL INSTRUMENTS
SFAS No. 107 "Disclosure About Fair Value of Financial Instruments" requires
the disclosure, to the extent practicable, of the fair value of financial
instruments which are recognized or unrecognized in the balance sheet. The fair
value of the financial instruments disclosed herein is not representative of the
amount that could be realized or settled, nor does the fair value amount
consider the tax consequences, if any, of realization or settlement. The
following table reflects the
F-24
<PAGE> 193
SANTA FE ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
financial instruments for which the fair value differs from the carrying amount
of such financial instrument in the Company's December 31, 1993 and 1992 balance
sheets (in millions of dollars):
<TABLE>
<CAPTION>
1993 1992
------------------- -------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ----- -------- -----
<S> <C> <C> <C> <C>
Assets
Trust Units.................................... 10.4 11.3 10.4 10.5
Liabilities
Long-Term Debt (including current
portion)..................................... 449.7 482.2 546.2 572.2
Convertible Preferred Stock.................... 80.0 103.8 80.0 93.8
Interest rate swap............................. -- 0.4 -- 1.1
</TABLE>
The fair value of the Trust Units and convertible preferred stock is based
on market prices. The fair value of the Company's fixed-rate long-term debt is
based on current borrowing rates available for financings with similar terms and
maturities. With respect to the Company's floating-rate debt, the carrying
amount approximates fair value. The fair value of the interest rate swap
represents the estimated cost to the Company over the remaining life of the
contract.
At December 31, 1993 the Company had two open natural gas hedging contracts
and options outstanding on five additional contracts (see Note 12 -- Commitments
and Contingencies -- Natural Gas Hedging Contracts). Based on the settlement
prices of certain natural gas futures contracts as quoted on the New York
Mercantile Exchange on December 30, 1993, assuming all options are exercised,
the cost to the Company with respect to such contracts during 1994 would be
approximately $0.6 million.
F-25
<PAGE> 194
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
OIL AND GAS RESERVES AND RELATED FINANCIAL DATA
Information with respect to the Company's oil and gas producing activities
is presented in the following tables. Reserve quantities as well as certain
information regarding future production and discounted cash flows were
determined by independent petroleum consultants, Ryder Scott Company.
Oil and Gas Reserves
The following table sets forth the Company's net proved oil and gas reserves
at December 31, 1990, 1991, 1992 and 1993 and the changes in net proved oil and
gas reserves for the years ended December 31, 1991, 1992 and 1993.
<TABLE>
<CAPTION>
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
-------------------------------------- ------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- ----- ---- --------- --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved reserves at
December 31, 1990.............................. 222.3 -- -- 222.3 185.9 -- -- 185.9
Revisions of previous estimates............... (1.9) -- -- (1.9) 0.4 -- -- 0.4
Improved recovery techniques.................. 15.9 -- -- 15.9 0.5 -- -- 0.5
Extensions, discoveries and other
additions.................................... 1.8 -- -- 1.8 19.6 -- -- 19.6
Purchases of minerals-in-place................ 4.6 8.7 -- 13.3 2.5 -- -- 2.5
Sales of minerals-in-place.................... (2.4) -- -- (2.4) (5.5) -- -- (5.5)
Increase in ownership in Partnership.......... 0.4 -- -- 0.4 2.2 -- -- 2.2
Production.................................... (20.0) (0.2) -- (20.2) (34.8) -- -- (34.8)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1991.............................. 220.7 8.5 -- 229.2 170.8 -- -- 170.8
Revisions of previous estimates............... 14.4 (0.3) -- 14.1 7.3 -- -- 7.3
Improved recovery techniques.................. 17.0 -- -- 17.0 1.3 -- -- 1.3
Extensions, discoveries and other
additions.................................... 1.3 1.3 -- 2.6 5.6 -- -- 5.6
Purchases of minerals-in-place................ 13.5 -- 7.2 20.7 141.5 -- 0.6 142.1
Sales of minerals-in-place.................... (5.7) -- -- (5.7) (5.0) -- -- (5.0)
Increase in ownership in Partnership.......... 0.2 -- -- 0.2 1.6 -- -- 1.6
Production.................................... (21.4) (0.8) (0.8) (23.0) (46.2) -- -- (46.2)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1992.............................. 240.0 8.7 6.4 255.1 276.9 -- 0.6 277.5
Revisions to previous estimates............... (11.9) 0.5 0.6 (10.8) 26.6 -- 0.1 26.7
Improved recovery techniques.................. 26.7 -- -- 26.7 -- -- -- --
Extensions, discoveries and other
additions.................................... 3.4 0.5 2.3 6.2 29.5 26.4 -- 55.9
Purchases of minerals-in-place................ 3.2 -- 0.7 3.9 9.8 -- 0.1 9.9
Sales of minerals in place.................... (8.7) -- -- (8.7) (47.4) -- -- (47.4)
Increase in ownership in Partnership.......... 0.1 -- -- 0.1 0.8 -- -- 0.8
Production.................................... (21.9) (0.9) (1.5) (24.3) (60.3) -- (0.1) (60.4)
----- ---- ---- ----- ----- ---- ---- -----
Proved reserves at
December 31, 1993............................. 230.9 8.8 8.5 248.2 235.9 26.4 0.7 263.0
===== ==== ==== ===== ===== ==== ==== =====
</TABLE>
(Table continued on following page)
F-26
<PAGE> 195
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
CRUDE OIL AND LIQUIDS (MMBBLS) NATURAL GAS (BCF)
-------------------------------------- ---------------------------------------
U.S. ARGENTINA INDONESIA TOTAL U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- ------ ---- --------- --------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Proved developed reserves
at December 31
1990........................ 176.8 -- -- 176.8 169.4 -- -- 169.4
1991........................ 179.2 5.4 -- 184.6 154.2 -- -- 154.2
1992........................ 194.6 5.6 6.4 206.6 250.2 -- 0.6 250.8
1993........................ 178.8 5.5 6.7 191.0 206.0 -- 0.7 206.7
</TABLE>
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.
Indonesian reserves represent an entitlement to gross reserves in accordance
with a production sharing contract. These reserves include estimated quantities
allocable to the Company for recovery of operating costs as well as quantities
related to the Company's net equity share after recovery of costs. Accordingly,
these quantities are subject to fluctuations with an inverse relationship to the
price of oil. If oil prices increase, the reserve quantities attributable to the
recovery of operating costs decline. Although this reduction would be offset
partially by an increase in the net equity share, the overall effect would be a
reduction of reserves attributable to the Company. At December 31, 1993, the
quantities include 0.6 million barrels which the Company is contractually
obligated to sell for $.20 per barrel.
At December 31, 1993 the Company's reserves were 6.9 million barrels of
crude oil and liquids and 14.5 Bcf of natural gas lower than at December 31,
1992, reflecting the sale in 1993 of properties with reserves totalling 8.7
million barrels of crude oil and liquids and 47.4 Bcf of natural gas.
At December 31, 1993, 1.9 million barrels of crude oil reserves and 19.7
billion cubic feet of natural gas reserves were subject to a 90% net profits
interest held by Santa Fe Energy Trust.
F-27
<PAGE> 196
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Estimated Present Value of Future Net Cash Flows
Estimated future net cash flows from the Company's proved oil and gas
reserves at December 31, 1991, 1992 and 1993 are presented in the following
table (in millions of dollars, except as noted):
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1993
Future cash inflows...................................... 2,654.9 117.9 115.6 2,888.4
Future production costs.................................. (1,547.2) (65.9) (78.7) (1,691.8)
Future development costs................................. (216.7) (32.4) (8.9) (258.0)
Future income tax expenses............................... (100.5) -- (6.9) (107.4)
-------- ----- ----- --------
Net future cash flows................................ 790.5 19.6 21.1 831.2
Discount at 10% for timing of cash flows................. (308.5) (12.1) (8.2) (328.8)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 482.0 7.5 12.9 502.4
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 9.10 9.74 13.50
Natural gas ($/Mcf).................................. 2.28 1.23 0.97
1992
Future cash inflows...................................... 3,709.8 132.9 105.8 3,948.5
Future production costs.................................. (1,982.6) (82.1) (79.5) (2,144.2)
Future development costs................................. (292.2) (13.5) -- (305.7)
Future income tax expenses............................... (286.9) (1.0) (9.5) (297.4)
-------- ----- ----- --------
Net future cash flows................................ 1,148.1 36.3 16.8 1,201.2
Discount at 10% for timing of cash flows................. (450.5) (14.0) (3.2) (467.7)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 697.6 22.3 13.6 733.5
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 13.30 15.28 16.46
Natural gas ($/Mcf).................................. 2.01 -- 0.97
1991
Future cash inflows...................................... 2,899.9 117.2 -- 3,017.1
Future production costs.................................. (1,655.3) (76.1) -- (1,731.4)
Future development costs................................. (242.2) (13.7) -- (255.9)
Future income tax expenses............................... (236.6) -- -- (236.6)
-------- ----- ----- --------
Net future cash flows................................ 765.8 27.4 -- 793.2
Discount at 10% for timing of cash flows................. (320.0) (9.6) -- (329.6)
-------- ----- ----- --------
Present value of future net cash flows from
proved reserves........................................ 445.8 17.8 -- 463.6
======== ===== ===== ========
Average sales prices
Oil ($/Barrel)....................................... 11.80 13.72 --
Natural gas ($/Mcf).................................. 1.78 -- --
</TABLE>
F-28
<PAGE> 197
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
The following tables sets forth the changes in the present value of
estimated future net cash flows from proved reserves during 1991, 1992 and 1993
(in millions of dollars):
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1993
Balance at beginning of year.............................. 697.6 22.3 13.6 733.5
------ ----- ----- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $189.5 million..................................... (230.1) (7.3) (10.0) (247.4)
Net changes in prices and production costs.............. (325.1) (7.7) 1.7 (331.1)
Extensions, discoveries and improved recovery........... 94.8 14.8 7.0 116.6
Purchases of minerals-in-place.......................... 20.4 -- 2.1 22.5
Sales of minerals-in-place.............................. (84.7) -- -- (84.7)
Development costs incurred.............................. 50.0 5.1 -- 55.1
Changes in estimated volumes............................ 28.3 1.5 1.8 31.6
Changes in estimated development costs.................. 25.6 (24.1) (8.9) (7.4)
Interest factor -- accretion of discount................ 87.1 2.3 2.1 91.5
Income taxes............................................ 112.0 0.6 3.5 116.1
Increase in ownership in Partnership.................... 1.2 -- -- 1.2
Other................................................... 4.9 -- -- 4.9
------ ----- ----- ------
(215.6) (14.8) (0.7) (231.1)
------ ----- ----- ------
482.0 7.5 12.9 502.4
====== ===== ===== ======
</TABLE>
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1992
Balance at beginning of year.............................. 445.8 17.8 -- 463.6
------ ----- ----- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $176.2 million..................................... (236.6) (8.4) (6.3) (251.3)
Net changes in prices and production costs.............. 191.7 7.8 3.5 203.0
Extensions, discoveries and improved recovery........... 70.9 4.6 -- 75.5
Purchases of minerals-in-place.......................... 230.6 -- 24.1 254.7
Sales of minerals-in-place.............................. (77.7) -- -- (77.7)
Development costs incurred.............................. 26.5 3.1 -- 29.6
Changes in estimated volumes............................ 63.4 (1.0) -- 62.4
Changes in estimated development costs.................. (76.9) (2.8) -- (79.7)
Interest factor -- accretion of discount................ 58.7 1.8 -- 60.5
Income taxes............................................ (14.8) (0.6) (7.7) (23.1)
Increase in ownership in Partnership.................... 1.9 -- -- 1.9
Other................................................... 14.1 -- -- 14.1
------ ----- ----- ------
251.8 4.5 13.6 269.9
------ ----- ----- ------
697.6 22.3 13.6 733.5
====== ===== ===== ======
</TABLE>
F-29
<PAGE> 198
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
<TABLE>
<CAPTION>
U.S. ARGENTINA INDONESIA TOTAL
---- --------- --------- -----
<S> <C> <C> <C> <C>
1991
Balance at beginning of year.............................. 839.4 -- -- 839.4
------ ---- ---- ------
Increase (decrease) due to:
Sales of oil and gas, net of production costs
of $157.6 million..................................... (221.0) (1.2) -- (222.2)
Net changes in prices and production costs.............. (617.6) 7.9 -- (609.7)
Extensions, discoveries and improved recovery........... 71.6 -- -- 71.6
Purchases of minerals-in-place.......................... 10.4 24.8 -- 35.2
Sales of minerals-in-place.............................. (30.7) -- -- (30.7)
Development costs incurred.............................. 54.0 0.7 -- 54.7
Changes in estimated volumes............................ 2.3 -- -- 2.3
Changes in estimated development costs.................. (117.5) (14.4) -- (131.9)
Interest factor -- accretion of discount................ 123.5 -- -- 123.5
Income taxes............................................ 233.5 -- -- 233.5
Increase in ownership in Partnership.................... 4.6 -- -- 4.6
Other................................................... 93.3 -- -- 93.3
------ ---- ---- ------
(393.6) 17.8 -- (375.8)
------ ---- ---- ------
445.8 17.8 -- 463.6
====== ==== ==== ======
</TABLE>
Estimated future cash flows represent an estimate of future net cash flows
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 general corporate
overhead or interest expense.
The sales prices used in the calculation of estimated future net cash flows
are based on the prices in effect at year end. Such prices have been held
constant except for known and determinable escalations.
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.
Income tax expense is computed based on applying the appropriate statutory
tax rate to the excess of future cash inflows less future production and
development costs over the current tax basis of the properties involved. While
applicable investment tax credits and other permanent differences are considered
in computing taxes, no recognition is given to tax benefits applicable to future
exploration costs or the activities of the Company that are unrelated to oil and
gas producing activities.
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 year-end 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.
F-30
<PAGE> 199
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Costs Incurred in Oil and Gas Producing Activities
The following table includes all costs incurred, whether capitalized or
charged to expense at the time incurred (in millions of dollars):
<TABLE>
<CAPTION>
OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------ --------- --------- ------- -----
<S> <C> <C> <C> <C> <C>
1993
Property acquisition costs
Unproved....................................... 6.4 -- 1.8 3.8 12.0
Proved......................................... 29.7 -- 2.9 -- 32.6
Other.......................................... 0.8 -- -- -- 0.8
Exploration costs................................ 20.9 0.7 5.2 11.7 38.5
Development costs................................ 85.3 7.3 7.6 -- 100.2
----- ---- ---- ---- -----
143.1 8.0 17.5 15.5 184.1
===== ==== ==== ==== =====
1992
Property acquisition costs
Unproved....................................... 29.3 0.2 8.8 3.5 41.8
Proved......................................... 294.1 -- 59.4 -- 353.5
Other.......................................... 65.6 -- -- -- 65.6
Exploration costs................................ 18.4 2.1 2.9 8.9 32.3
Development costs................................ 56.8 3.0 1.8 -- 61.6
----- ---- ---- ---- -----
464.2 5.3 72.9 12.4 554.8
===== ==== ==== ==== =====
1991
Property acquisition costs
Unproved....................................... 4.4 -- -- 3.2 7.6
Proved......................................... 29.0 -- -- 34.1 63.1
Other.......................................... -- -- -- -- --
Exploration costs................................ 20.7 -- -- 4.1 24.8
Development costs................................ 85.8 -- -- 0.7 86.5
----- ---- ---- ---- -----
139.9 -- -- 42.1 182.0
===== ==== ==== ==== =====
</TABLE>
F-31
<PAGE> 200
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Capitalized Costs Related to Oil and Gas Producing Activities
The following table sets forth information concerning capitalized costs at
December 31, 1993 and 1992 related to the Company's oil and gas operations (in
millions of dollars):
<TABLE>
<CAPTION>
1993 1992
------------------------------------------------- --------------------------------------------------
OTHER OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------ --------- --------- ------- -------- ----- --------- --------- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oil and gas properties
Unproved............ 40.3 1.3 12.0 10.7 64.3 80.1 1.3 10.2 7.3 98.9
Proved.............. 1,869.9 48.9 68.0 -- 1,986.8 2,049.8 37.5 62.7 -- 2,150.0
Other............... 13.2 -- -- -- 13.2 82.0 -- -- 82.0
Accumulated amortization
of unproved
properties............ (14.6) (1.2) (2.8) (9.9) (28.5) (23.6) (1.0) (1.7) (2.6) (28.9)
Accumulated depletion,
depreciation and
impairment of proved
properties............ (1,181.9) (7.9) (22.4) -- (1,212.2) (1,200.0) (4.6) (2.3) -- (1,206.9)
Accumulated depreciation
of other oil and gas
properties (4.3) -- -- -- (4.3) (7.5) -- -- -- (7.5)
-------- ---- ----- ---- -------- -------- ---- ---- ---- --------
722.6 41.1 54.8 0.8 819.3 980.8 33.2 68.9 4.7 1,087.6
======== ==== ===== ==== ======== ======== ==== ==== ==== ========
</TABLE>
F-32
<PAGE> 201
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
Results of Operations From Oil and Gas Producing Activities
The following table sets forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1993, 1992 and
1991 (in millions of dollars):
<TABLE>
<CAPTION>
OTHER
U.S. ARGENTINA INDONESIA FOREIGN TOTAL
------- --------- --------- ------- ---------
<S> <C> <C> <C> <C> <C>
1993
Revenues.................................................. 401.2 12.5 23.2 -- 436.9
Production costs.......................................... (166.9) (5.2) (13.2) -- (185.3)
Oil and gas systems and pipelines......................... (4.2) -- -- -- (4.2)
Exploration, including dry hole costs..................... (16.4) (0.7) (2.2) (11.7) (31.0)
Depletion, depreciation, amortization and impairments..... (218.8) (3.6) (21.2) (6.7) (250.3)
Restructuring charges..................................... (27.8) -- -- -- (27.8)
Gain (loss) on disposition of properties.................. (0.7) -- -- -- (0.7)
------ ----- ----- ----- ------
(33.6) 3.0 (13.4) (18.4) (62.4)
Income taxes.............................................. 24.1 (0.9) 1.9 -- 25.1
------ ----- ----- ----- ------
(9.5) 2.1 (11.5) (18.4) (37.3)
====== ===== ===== ===== ======
1992
Revenues.................................................. 400.0 13.9 13.6 -- 427.5
Production costs.......................................... (160.2) (5.5) (7.3) -- (173.0)
Oil and gas systems and pipelines......................... (3.2) -- -- -- (3.2)
Exploration, including dry hole costs..................... (12.9) (2.2) (1.3) (9.1) (25.5)
Depletion, depreciation, amortization and impairments..... (136.7) (3.7) (2.7) (1.6) (144.7)
Gain (loss) on disposition of properties.................. 13.6 -- -- -- 13.6
------ ----- ----- ----- ------
100.6 2.5 2.3 (10.7) 94.7
Income taxes.............................................. (37.9) -- (1.6) -- (39.5)
------ ----- ----- ----- ------
62.7 2.5 0.7 (10.7) 55.2
====== ===== ===== ===== ======
1991
Revenues.................................................. 376.1 3.7 -- -- 379.8
Production costs.......................................... (155.1) (2.5) -- -- (157.6)
Exploration, including dry hole costs..................... (15.5) (1.5) -- (1.7) (18.7)
Depletion, depreciation, amortization and impairments..... (101.3) (1.8) -- (0.7) (103.8)
Gain (loss) on disposition of properties.................. (0.5) -- -- -- (0.5)
------ ----- ----- ----- ------
103.7 (2.1) -- (2.4) 99.2
Income Taxes.............................................. (42.3) -- -- -- (42.3)
------ ----- ----- ----- ------
61.4 (2.1) -- (2.4) 56.9
====== ===== ===== ===== ======
</TABLE>
Income taxes are computed by applying the appropriate statutory rate to the
results of operations before income taxes. Applicable tax credits and allowances
related to oil and gas producing activities have been taken into account in
computing income tax expenses. No deduction has been made for indirect cost such
as corporate overhead or interest expense.
F-33
<PAGE> 202
SANTA FE ENERGY RESOURCES, INC.
SUPPLEMENTAL INFORMATION TO
CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) -- (CONTINUED)
SUMMARIZED QUARTERLY FINANCIAL DATA
<TABLE>
<CAPTION>
1 QTR 2 QTR 3 QTR 4 QTR YEAR
----- ----- ----- ----- ----
(IN MILLIONS OF DOLLARS EXCEPT PER SHARE DATE)
<S> <C> <C> <C> <C> <C>
1993
Revenues........................................................... 115.3 116.3 102.7 102.6 436.9
Gross profit (a)................................................... 19.0 22.5 8.5 (130.7) (80.7)
Income (loss) from operations...................................... 12.0 15.4 1.2 (141.6)(b) (113.0)
Net income (loss).................................................. (0.4) 4.0 2.4 (83.1) (77.1)
Earnings (loss) attributable to common shares...................... (2.2) 2.3 0.6 (84.8) (84.1)
Earnings (loss) attributable to common shares per share............ (0.02) 0.02 0.01 (0.95) (0.94)
Average shares outstanding (millions).............................. 89.6 89.7 89.8 89.8 89.7
1992
Revenues........................................................... 78.5 97.7 127.9 123.4 427.5
Gross profit (a)................................................... 2.9 34.1 32.0 19.4 88.4
Income (loss) from operations...................................... (3.5) 25.1 24.4 11.5 57.5
Net income (loss).................................................. (8.8) 1.8 7.3 (1.7) (1.4)
Earnings (loss) attributable to common shares...................... (8.8) 1.0 5.5 (3.4) (5.7)
Earnings (loss) attributable to common shares per share............ (.14) .01 .06 (.04) (.07)
Average shares outstanding (millions).............................. 64.3 72.7 89.4 89.5 79.0
</TABLE>
__________
(a) Revenues less operating expenses other than general and administrative.
(b) Includes charges of $99.3 million for impairment of oil and gas properties
and $38.6 million for restructuring charges.
F-34
<PAGE> 203
NO DEALER, SALESPERSON OR ANY OTHER
PERSON HAS BEEN AUTHORIZED TO GIVE ANY 10,700,000 SHARES
INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE
CONTAINED IN OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS IN
CONNECTION WITH THE OFFER MADE BY
THIS PROSPECTUS AND, IF GIVEN OR
MADE, SUCH INFORMATION OR SANTA FE ENERGY
REPRESENTATIONS MUST NOT BE RELIED
UPON AS HAVING BEEN AUTHORIZED BY RESOURCES, INC.
THE COMPANY OR ANY OF THE
UNDERWRITERS. NEITHER THE DELIVERY
OF THIS PROSPECTUS NOR ANY SALE
MADE HEREUNDER SHALL UNDER ANY
CIRCUMSTANCES CREATE ANY
IMPLICATION THAT THERE HAS BEEN NO
CHANGE IN THE AFFAIRS OF THE
COMPANY SINCE THE DATE HEREOF. THIS
PROSPECTUS DOES NOT CONSTITUTE AN
OFFER OR SOLICITATION BY ANYONE IN ANY $ SERIES A
JURISDICTION IN WHICH SUCH OFFER OR
SOLICITATION IS NOT AUTHORIZED OR IN CONVERTIBLE PREFERRED STOCK
WHICH THE PERSON MAKING SUCH OFFER
IS NOT QUALIFIED TO DO SO OR TO ANY (DIVIDEND ENHANCED
CONVERTIBLE
PERSON TO WHOM IT IS UNLAWFUL TO STOCK SM--DECS SM)
MAKE SUCH SOLICITATION.
-----------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Available Information.................. 2
Documents Incorporated by Reference.... 2
Certain Definitions.................... 2
Prospectus Summary..................... 3
Investment Considerations.............. 12
Ratios of Earnings to Fixed Charges.... 16 SALOMON BROTHERS INC
Use of Proceeds........................ 16
Capitalization......................... 17
Price Range of Common Stock and
Dividends............................ 18 LAZARD FRERES & CO.
Selected Financial and Operating
Data................................. 19
Management's Discussion and Analysis of PAINEWEBBER INCORPORATED
Financial Condition and Results of
Operations........................... 21
Business and Properties................ 28
Management............................. 46
Description of Capital Stock........... 49
Description of the DECS................ 54
Federal Income Tax Considerations...... 60
Underwriting........................... 61
Validity of the Securities............. 62 PROSPECTUS
Experts................................ 62
Index to Financial Statements.......... F-1
</TABLE>
DATED MAY , 1994
<PAGE> 204
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
All capitalized terms used and not defined in Part II of this Registration
Statement shall have the meanings assigned to them in the Prospectus which forms
a part of this Registration Statement.
ITEM 14. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The estimated expenses payable by the registrant in connection with this
offering, other than underwriting discounts and commissions, are as follows:
<TABLE>
<S> <C>
Securities Act registration fee...................................... $ 75,323
NASD filing fee...................................................... 22,844
Blue Sky qualification fees and expenses............................. 10,200
Legal fees and expenses.............................................. 250,000
Accounting fees and expenses......................................... 235,000
Trustee fees......................................................... 25,000
Transfer agent and registrar fees.................................... 30,000
Stock exchange listing fee........................................... 73,400
Printing and engraving costs......................................... 250,000
Miscellaneous expenses............................................... 28,233
-----------
Total.............................................................. $ 1,000,000
-----------
-----------
</TABLE>
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Subsection (a) of Section 145 of the General Corporation Law of the State
of Delaware empowers a corporation to indemnify any person who was or is a party
or is threatened to be made a party to any threatened, pending or completed
action, suit or proceeding, whether civil, criminal, administrative or
investigative (other than an action by or in the right of the corporation) by
reason of the fact that he is or was a director, officer, employee or agent of
the corporation, or is or was serving at the request of the corporation as a
director, officer, employee or agent of another corporation, partnership, joint
venture, trust or other enterprise, against expenses (including attorneys'
fees), judgments, fines and amounts paid in settlement actually and reasonably
incurred by him in connection with such action, suit or proceeding if he acted
in good faith and in a manner he reasonably believed to be in or not opposed to
the best interests of the corporation, and, with respect to any criminal action
or proceeding, had no reasonable cause to believe his conduct was unlawful.
Subsection (b) of Section 145 empowers a corporation to indemnify any
person who was or is a party or is threatened to be made a party to any
threatened, pending or completed action or suit by or in the right of the
corporation to procure a judgment in its favor by reason of the fact that such
person acted in any of the capacities set forth above, against expenses
(including attorneys' fees) actually and reasonably incurred by him in
connection with the defense or settlement of such action or suit if he acted in
good faith and in a manner he reasonably believed to be in or not opposed to the
best interests of the corporation, except that no indemnification may be made in
respect of any claim, issue or matter as to which such person shall have been
adjudged to be liable to the corporation unless and only to the extent that the
Court of Chancery or the court in which such action or suit was brought shall
determine upon application that, despite the adjudication of liability but in
view of all the circumstances of the case, such person is fairly and reasonably
entitled to indemnity for such expenses which the Court of Chancery or such
other court shall deem proper.
Section 145 further provides that to the extent a director or officer of a
corporation has been successful on the merits or otherwise in the defense of any
action, suit or proceeding referred to in
II-1
<PAGE> 205
subsections (a) and (b) of Section 145 or in the defense of any claim, issue or
matter therein, he shall be indemnified against expenses (including attorneys'
fees) actually and reasonably incurred by him in connection therewith; that
indemnification provided for by Section 145 shall not be deemed exclusive of any
other rights to which the indemnified party may be entitled; that
indemnification provided by Section 145 shall, unless otherwise provided when
authorized or ratified, continue as to a person who has ceased to be a director,
officer, employee or agent and shall inure to the benefit of such person's
heirs, executors and administrators; and empowers the corporation to purchase
and maintain insurance on behalf of a director or officer of the corporation
against any liability asserted against him and incurred by him in any such
capacity, or arising out of his status as such, whether or not the corporation
would have the power to indemnify him against such liabilities under Section
145.
Section 102(b)(7) of the General Corporation Law of the State of Delaware
provides that a certificate of incorporation may contain a provision eliminating
or limiting the personal liability of a director to the corporation or its
stockholders for monetary damages for breach of fiduciary duty as a director,
provided that such provision shall not eliminate or limit the liability of a
director (i) for any breach of the director's duty of loyalty to the corporation
or its stockholders, (ii) for acts or omissions not in good faith or which
involve intentional misconduct or a knowing violation of law, (iii) under
Section 174 of the Delaware General Corporation Law, or (iv) for any transaction
from which the director derived an improper personal benefit.
Article NINTH of the Company's Restated Certificate of Incorporation states
that:
"No director of the Corporation shall be personally liable to the
Corporation or its stockholders for monetary damages from breach of
fiduciary duty by such director as a director; provided, however, that
this Article NINTH shall not eliminate or limit the liability of a
director to the extent provided by applicable law (i) for any breach
of the director's duty of loyalty to the Corporation or its
stockholders, (ii) for acts or omissions not in good faith or which
involve intentional misconduct or a knowing violation of law, (iii)
under Section 174 of the General Corporation Law of the State of
Delaware, or (iv) for any transaction from which the director derived
an improper personal benefit. No amendment to or repeal of this
Article NINTH shall apply to, or have any effect on, the liability or
alleged liability of any director of the Corporation for or with
respect to any facts or omissions of such director occurring prior to
such amendment or repeal. If the General Corporation Law of the State
of Delaware is amended to authorize corporate action further
eliminating or limiting the personal liability of directors, then the
liability of a director of the Corporation shall be eliminated or
limited to the fullest extent permitted by the General Corporation Law
of the State of Delaware, as so amended."
Article VI of the Company's Bylaws further provides that the Company shall
indemnify its officers, directors and employees to the fullest extent permitted
by law. Pursuant to such provision, the Company has entered into agreements with
various of its officers, directors and employees which provide for
indemnification of such persons.
Pursuant to the Underwriting Agreements filed as Exhibit 1.1 and Exhibit
1.2 hereto, the Underwriters agree to indemnify, under certain conditions, the
Company, its officers and directors and persons who control the Company within
the meaning of the Securities Act against certain liabilities.
The Company maintains a $25,000,000 policy of officers and directors
liability insurance.
II-2
<PAGE> 206
ITEM 16. EXHIBITS
<TABLE>
<S> <C>
1.1 Form of Underwriting Agreement relating to the Debentures*
1.2 Form of Underwriting Agreement relating to the Series A Convertible Preferred
Stock*
4.1 Form of Indenture**
4.2 Form of Debenture (included in Exhibit 4.1)**
4.3 Form of Certificate of Designations of the Series A Convertible Preferred Stock*
4.4 Form of Stock Certificate representing shares of Series A Convertible Preferred
Stock (filed as Exhibit 2 to the Registrant's Registration Statement on Form 8-A
relating to the Series A Convertible Preferred Stock and incorporated herein by
reference)
4.5 Specimen Stock Certificate representing shares of Common Stock (filed as Exhibit
4.1 to the Registrant's Registration Statement on Form S-1 (Reg. No. 33-32831)
and incorporated herein by reference)
4.6 Form of Certificate of Designation, Rights and Preferences of the Convertible
Preferred Stock, Series 7% (filed as Exhibit 3(b) to the Registrant's
Registration Statement on Form S-4 (Reg. No. 33-45043) and incorporated herein
by reference)
5.1 Opinion of Andrews & Kurth L.L.P. re. Legality of Securities**
7.1 Opinion of Andrews & Kurth L.L.P. re. Liquidation Preference**
8.1 Opinion of Andrews & Kurth L.L.P. re. Tax Matters**
23.1 Consent of Price Waterhouse
23.2 Consent of Andrews & Kurth L.L.P. (included in their opinion filed as Exhibit
5.1)**
23.3 Consent of Ryder Scott Company, independent petroleum engineers
24.1 A power of attorney, pursuant to which amendments to this Registration Statement
may be filed, is included on the signature page contained in Part II of this
Registration Statement*
24.2 Power of attorney of David M. Schulte, pursuant to which amendments to this
Registration Statement may be filed
25.1 Statement of eligibility of Trustee**
</TABLE>
- ---------------
* Previously filed
** To be filed by amendment
ITEM 17. UNDERTAKINGS
The undersigned registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered herein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Securities and Exchange Commission
such indemnification is against public policy as expressed in the Act and is,
therefore, unenforceable. In the event that a claim for indemnification against
such liabilities (other than the payment by the registrant of expenses incurred
or paid by a director, officer or controlling person of the registrant in the
successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.
II-3
<PAGE> 207
The undersigned registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the forms of prospectuses filed as
part of this registration statement in reliance upon Rule 430A and
contained in a form of prospectus filed by the registrant pursuant to Rule
424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be
part of this registration statement as of the time it was declared
effective.
(2) For the purpose of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
II-4
<PAGE> 208
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Santa Fe Energy
Resources, Inc. certifies that it has reasonable grounds to believe that it
meets all of the requirements for filing on Form S-3 and has duly caused this
registration statement to be signed on its behalf by the undersigned, thereunto
duly authorized in the City of Houston, State of Texas, on April 26, 1994.
SANTA FE ENERGY RESOURCES, INC.
By: /S/ DAVID L. HICKS
____________________________
David L. Hicks
Vice President-Law
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed by the following persons in the
capacities and on the dates indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
JAMES L. PAYNE* Chairman of the Board, President April 26, 1994
- ------------------------------------- and Chief Executive Officer and
James L. Payne Director (Principal Executive
Officer)
MICHAEL J. ROSINSKI* Vice President and Chief Financial April 26, 1994
- ------------------------------------- Officer (Principal financial and
Michael J. Rosinski accounting officer)
ROD F. DAMMEYER* Director April 26, 1994
- -------------------------------------
Rod F. Dammeyer
WILLIAM E. GREEHEY* Director April 26, 1994
- -------------------------------------
William E. Greehey
ROBERT D. KREBS* Director April 26, 1994
- -------------------------------------
Robert D. Krebs
ALLAN V. MARTINI* Director April 26, 1994
- -------------------------------------
Allan V. Martini
MICHAEL A. MORPHY* Director April 26, 1994
- -------------------------------------
Michael A. Morphy
REUBEN F. RICHARDS* Director April 26, 1994
- -------------------------------------
Reuben F. Richards
MARC J. SHAPIRO* Director April 26, 1994
- -------------------------------------
Marc J. Shapiro
</TABLE>
II-5
<PAGE> 209
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
ROBERT F. VAGT* Director April 26, 1994
- -------------------------------------
Robert F. Vagt
KATHRYN D. WRISTON* Director April 26, 1994
- -------------------------------------
Kathryn D. Wriston
MELVYN N. KLEIN* Director April 26, 1994
- -------------------------------------
Melvyn N. Klein
DAVID M. SCHULTE* Director April 26, 1994
- -------------------------------------
David M. Schulte
*By: /s/ DAVID L. HICKS
- -------------------------------------
David L. Hicks,
Attorney-in-fact
</TABLE>
II-6
<PAGE> 1
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the use in the Prospectuses constituting part of this
Registration Statement on Form S-3 of our report dated February 18, 1994
relating to the financial statements of Santa Fe Energy Resources, Inc., which
appears in such Prospectuses. We also consent to the application of such report
to the Financial Statement Schedules for the three years ended December 31, 1993
listed under Item 14(a)(2) of the Santa Fe Energy Resources, Inc. Annual Report
on Form 10-K for the year ended December 31, 1993, which is incorporated by
reference in these Prospectuses, when such schedules are read in conjunction
with the financial statements referred to in our report. The audits referred to
in such report also included these Financial Statement Schedules. We also
consent to the references to us under the headings "Experts" and "Selected
Financial and Operating Data" in such Prospectuses. However, it should be noted
that Price Waterhouse has not prepared or certified such "Selected Financial and
Operating Data".
PRICE WATERHOUSE
Houston, Texas
April 26, 1994
<PAGE> 1
EXHIBIT 23.3
CONSENT OF RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
We hereby consent to the references to our firm included or incorporated by
reference in this Registration Statement on Form S-3.
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Houston, Texas
April 25, 1994
<PAGE> 1
EXHIBIT 24.2
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, Santa Fe Energy
Resources, Inc. certifies that it has reasonable grounds to believe that it
meets all of the requirements for filing on Form S-3 and has duly caused this
registration statement to be signed on its behalf by the undersigned, thereunto
duly authorized in the City of Houston, State of Texas, on March , 1994.
SANTA FE ENERGY RESOURCES, INC.
By:
James L. Payne
Chairman of the Board, President
and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1933, this
registration statement has been signed by the following persons in the
capacities and on the dates indicated.
Know all men by these presents, that each of the undersigned officers and
directors of Santa Fe Energy Resources, Inc. hereby constitutes and appoints
James L. Payne, Michael J. Rosinski and David L. Hicks, and each or any of them,
as his true and lawful attorneys-in-fact and agents, with full power of
substitution, for him or her in his name, place and stead, in any and all
capacities to sign any or all amendments or post-effective amendments to this
Registration Statement, and to file the same, and with all exhibits thereto and
other documents in connection therewith, with the Securities and Exchange
Commission, granting unto said attorneys-in-fact and agents full power and
authority to do and perform each and every act and thing requisite and necessary
to be done in and about the premises, as fully to all intents and purposes as he
or she might or could do in person, hereby ratifying and confirming all that
said attorneys-in-fact and agents, or any of them or their substitutes, may
lawfully do or cause to be done by virtue hereof.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
Chairman of the Board, President March , 1994
- ------------------------------------- and Chief Executive Officer and
James L. Payne Director (Principal Executive
Officer)
Vice President and Chief Financial March , 1994
- ------------------------------------- Officer (Principal financial and
Michael J. Rosinski accounting officer)
- ------------------------------------- Director March , 1994
Rod F. Dammeyer
Director March , 1994
- -------------------------------------
William E. Greehey
Director March , 1994
- -------------------------------------
Robert D. Krebs
Director March , 1994
- -------------------------------------
Allan V. Martini
</TABLE>
<PAGE> 2
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
--------- ----- ----
<S> <C> <C>
Director March , 1994
- -------------------------------------
Michael A. Morphy
Director March , 1994
- -------------------------------------
Reuben F. Richards
Director March , 1994
- -------------------------------------
Marc J. Shapiro
Director March , 1994
- -------------------------------------
Robert F. Vagt
Director March , 1994
- -------------------------------------
Kathryn D. Wriston
Director March , 1994
- -------------------------------------
Melvyn N. Klein
/S/ DAVID M. SCHULTE Director March 28, 1994
- -------------------------------------
David M. Schulte
</TABLE>
