1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON APRIL 1, 1994
REGISTRATION NO. 33-52807
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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AMENDMENT NO. 1
TO
FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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SNYDER OIL CORPORATION
(Exact name of Registrant as specified in its charter)
DELAWARE 75-2306158
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
777 MAIN STREET
FORT WORTH, TEXAS 76102
(817) 338-4043
(Address, including zip code, and telephone number, including area code, of
Registrant's principal executive offices)
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PETER E. LORENZEN
SNYDER OIL CORPORATION
777 MAIN STREET
FORT WORTH, TEXAS 76102
(817) 882-5905
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
Copies to:
THOMAS W. BRIGGS KERRY C. L. NORTH
KELLY, HART & HALLMAN, P.C. BAKER & BOTTS, L.L.P.
201 MAIN STREET 2001 ROSS AVENUE
FORT WORTH, TEXAS 76102 DALLAS, TEXAS 75201
(817) 332-2500 (214) 953-6500
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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 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: / /
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CALCULATION OF REGISTRATION FEE
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PROPOSED PROPOSED
MAXIMUM MAXIMUM
OFFERING AGGREGATE AMOUNT OF
TITLE OF EACH CLASS OF AMOUNT TO PRICE OFFERING REGISTRATION
SECURITIES TO BE REGISTERED BE REGISTERED PER UNIT(1) PRICE(1) FEE(2)
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% Step-up Convertible Subordinated
Notes Due 2001......................... $115,000,000(3) 100% $115,000,000 $39,656(5)
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Common Stock (par value $.01 per
share)................................. (4) -- -- --
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(1) Estimated solely for the purpose of calculating the registration fee.
(2) Pursuant to Rule 457, the registration fee has been calculated solely on the
basis of the proposed maximum aggregate offering price of the % Step-up
Convertible Subordinated Notes Due 2001 ("SIRENs").
(3) Includes $15,000,000 principal amount of SIRENs subject to the Underwriters'
over-allotment option.
(4) Such indeterminate number of shares as may be issuable on conversion of the
SIRENs, including such additional shares as may be issuable as a result of
adjustments to the conversion rate.
(5) Previously paid.
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 SECTION 8(A), MAY
DETERMINE.
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Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor
may offers to buy be accepted prior to the time the registration statement
becomes effective. This prospectus shall not constitute an offer to sell or
the solicitation of an offer to buy
nor shall there be any sale of these securities in any State in which such
offer, solicitation or sale would be unlawful prior to registration or
qualification under the securities laws of any such State.
SUBJECT TO COMPLETION, DATED APRIL 1, 1994
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PROSPECTUS
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(SOCO LOGO) $100,000,000
Snyder Oil Corporation
% Step-up Convertible Subordinated Notes Due 2001
(Step-up Income Redeemable Equity Notes(TM) -- SIRENs(TM))
Interest Payable March 31 and September 30 Due March 31, 2001
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The SIRENs are convertible into Common Stock of Snyder Oil Corporation (the
"Company") at any time on or prior to maturity, unless previously redeemed,
at a conversion price of $ per share, subject to adjustment in certain
events. On March 31, 1994, the last reported sale price for the Common
Stock on the New York Stock Exchange (Symbol: SNY) was $19 1/2 per
share. Interest on the SIRENs will accrue at the rate of % per
annum from the date of issuance through March 31, 1997 and
will accrue at the rate of % per annum from
April 1, 1997 to maturity or earlier redemption.
The SIRENs are redeemable, in whole or in part, at the option of the Company at
any time on or after March 31, 1997, at the redemption prices set forth herein
plus accrued interest to the date of redemption. Upon a Change of Control
(as defined) which constitutes a Repurchase Event (as defined), each
holder of SIRENs will have the right, subject to certain conditions
and restrictions, to require the Company to repurchase outstanding
SIRENs owned by such holder at their principal amount plus
accrued interest. The SIRENs are subordinated to all
Senior Indebtedness (as defined) of the Company.
The SIRENs will initially be issued in the form
of one or more Global Notes registered in the
name of Cede & Co., as nominee of The
Depository Trust Company. See
"Description of SIRENs."
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THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR
HAS THE SECURITIES AND EXCHANGE COMMISSION OR ANY STATE
SECURITIES COMMISSION PASSED UPON THE ACCURACY OR AD-
EQUACY OF THIS PROSPECTUS. ANY REPRESENTATION
TO THE CONTRARY IS A CRIMINAL OFFENSE.
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Price to Underwriting Proceeds to
Public(1) Discount Company(2)
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Per SIREN
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Total(3)
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(1) Plus accrued interest, if any, from , 1994.
(2) Before deduction of expenses payable by the Company, estimated at
$ .
(3) The Company has granted the Underwriters an option, exercisable for 30 days
from the date of the initial public offering of the SIRENs, to purchase up
to an additional $15,000,000 principal amount of SIRENs solely to cover
over-allotments. If the option is exercised in full, the Price to Public,
Underwriting Discount and Proceeds to Company will be $ ,
$ , and $ , respectively.
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The SIRENs are offered by the several Underwriters when, as and if issued
by the Company, delivered to and accepted by the Underwriters and subject to
their right to reject orders in whole or in part. It is expected that the SIRENs
will be ready for delivery through the facilities of The Depository Trust
Company on or about , 1994.
(TM)Trademark of CS First Boston Corporation
CS First Boston
PaineWebber Incorporated
Petrie Parkman & Co.
Smith Barney Shearson Inc.
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The date of this Prospectus is April , 1994.
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IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICES OF THE SIRENS OFFERED
HEREBY AND THE COMPANY'S COMMON STOCK AND PREFERRED STOCK AT LEVELS ABOVE THOSE
WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN MARKET. SUCH TRANSACTIONS MAY BE
EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE OVER-THE-COUNTER MARKET OR
OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
(MAP OF THE UNITED STATES SHOWING THE LOCATIONS OF THE COMPANY'S
MAJOR GAS FACILITIES, CORPORATE OFFICES, FIELD OFFICES
AND MAJOR PRODUCING PROPERTIES)
FOR CALIFORNIA RESIDENTS: WITH RESPECT TO SALES OF THE SIRENS BEING OFFERED
HEREBY TO CALIFORNIA RESIDENTS AS OF THE DATE OF THIS PROSPECTUS, SUCH SIRENS
MAY BE SOLD ONLY TO (1) "ACCREDITED INVESTORS" WITHIN THE MEANING OF REGULATION
D UNDER THE SECURITIES ACT OF 1933, (2) BANKS, SAVINGS AND LOAN ASSOCIATIONS,
TRUST COMPANIES, INSURANCE COMPANIES, INVESTMENT COMPANIES REGISTERED UNDER THE
INVESTMENT COMPANY ACT OF 1940, PENSION AND PROFIT SHARING TRUSTS, OR
CORPORATIONS OR OTHER ENTITIES WHICH, TOGETHER WITH SUCH CORPORATION'S OR OTHER
ENTITY'S AFFILIATES WHICH ARE UNDER COMMON CONTROL, HAVE A NET WORTH ON A
CONSOLIDATED BASIS ACCORDING TO THEIR MOST RECENT REGULARLY PREPARED FINANCIAL
STATEMENTS (WHICH SHALL HAVE BEEN REVIEWED, BUT NOT NECESSARILY AUDITED BY
OUTSIDE ACCOUNTANTS) OF NOT LESS THAN $14,000,000 AND SUBSIDIARIES OF THE
FOREGOING, (3) ANY CORPORATION, PARTNERSHIP OR ORGANIZATION (OTHER THAN A
CORPORATION, PARTNERSHIP OR ORGANIZATION FORMED FOR THE SOLE PURPOSE OF
PURCHASING THE SIRENS BEING OFFERED HEREBY) WHO PURCHASES AT LEAST $5,000,000
AGGREGATE AMOUNT OF THE SIRENS OFFERED HEREBY, OR (4) ANY NATURAL PERSON WHO (A)
HAS INCOME OF $65,000 AND A NET WORTH OF $250,000 OR (B) HAS A NET WORTH OF
$500,000 (IN EACH CASE, EXCLUDING HOME, HOME FURNISHINGS AND PERSONAL
AUTOMOBILES). EACH CALIFORNIA RESIDENT PURCHASING THE SIRENS OFFERED HEREBY WILL
BE DEEMED TO REPRESENT BY SUCH PURCHASE THAT IT COMES WITHIN ONE OF THE
AFOREMENTIONED CATEGORIES.
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PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information appearing elsewhere or incorporated by reference in this Prospectus.
All information giving effect to this Offering assumes that the Underwriters'
over-allotment option is not exercised unless otherwise noted.
THE COMPANY
Snyder Oil Corporation (the "Company") is engaged in the development and
acquisition of oil and gas properties primarily in the Rocky Mountain region of
the United States. The Company also gathers, transports, processes and markets
natural gas generally in proximity to its principal producing properties. Over
the five year period from 1988 to 1993, revenues increased from $14.7 million to
$229.9 million, net income increased from $5.1 million to $25.7 million and net
cash provided by operations increased from $8.1 million to $68.3 million. At
December 31, 1993, the Company's net proved reserves totaled 103.6 MMBOE, having
a pretax present value at constant prices of $390.4 million. Approximately 69%
of its proved reserves are natural gas.
Approximately 90% of the present value of the Company's proved reserves is
concentrated in five major producing areas located in Colorado, Wyoming and
Texas. In total, the Company's properties are located in 15 states and the Gulf
of Mexico and include 5,122 gross (2,187 net) producing wells and nine gas
transportation and processing facilities. The Company operates more than 2,100
wells which account for over 90% of its developed reserves. In addition to its
domestic operations, the Company is also participating in several international
exploration and development projects through its wholly owned subsidiary, SOCO
International, Inc., and through its 36% owned affiliate, Command Petroleum
Holdings NL. At December 31, 1993, the Company held undeveloped acreage totaling
539,000 gross acres (326,000 net) domestically and 4.3 million gross acres (3.3
million net) internationally.
The Company has pursued a balanced strategy of development drilling and
acquisitions, focusing on operating efficiency and enhanced profitability
through the concentration of assets in selected geographic areas or "hubs."
Currently, the primary emphasis of the Company's growth strategy is development
drilling in the Rockies, mainly the Wattenberg Field in the Denver-Julesburg
Basin ("DJ Basin") of Colorado where the Company drilled 323 wells in 1993. In
implementing this strategy in the Wattenberg Field over the past three years,
the Company has achieved the following: (i) drilled approximately 667 wells, 660
of which are currently producing; (ii) increased production more than five
times, from an average of 2,575 MBOE per day in 1991 to an average of 13,265
MBOE per day in 1993; (iii) increased proved reserves nearly 50% from 37.9 MMBOE
at yearend 1991 to 55.2 MMBOE at yearend 1993; and (iv) generally reduced
drilling and completion costs by over 30% through a combination of aggressive
cost cutting, economies of scale and technological improvements. Through a major
joint venture with Union Pacific Resources Company, as well as acquisitions and
leasing, the Company has accumulated a substantial inventory of potential
drilling locations, including 1,102 locations that were classified as proved
undeveloped at December 31, 1993.
In 1993, the Company embarked on a program to apply the experience gained
in the Wattenberg Field to two other large scale gas developments in the
Rockies. In the Washakie Basin of southern Wyoming (the "East Washakie
Project"), the Company currently operates 128 wells and holds a significant
inventory of potential drilling locations, including 98 locations that were
classified as proved undeveloped at December 31, 1993. The Company has also
initiated the development of a third hub in the Rockies through three purchase
transactions, as well as farmouts and leasing. As a result, the Company
currently holds a significant inventory of potential drilling locations in the
Piceance and Uinta Basins of Colorado and Utah (collectively, the "Western Slope
Project"), including 101 locations that were classified as proved undeveloped at
December 31, 1993.
During 1994, the Company intends to continue development in the DJ Basin
and to increase activity in the East Washakie and Western Slope Projects. The
Company expects to spend $175 to $200 million for development drilling and
expansion of gas facilities in 1994, including the drilling of over 650 wells,
500 of which are planned for the Wattenberg Field and up to 90 for the East
Washakie and Western Slope Projects. As part of this program, the Company will
emphasize the improvement of well economics through the use of
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technological improvements and cost saving drilling techniques, as well as the
capture of downstream margins via the Company's gas facilities. In addition to
development drilling in the Rockies, the Company intends to pursue acquisitions
to strengthen its existing asset base and secure a foothold in new geographic
areas and to continue progress in bringing its international projects to
fruition.
THE OFFERING
Securities Offered......... $100,000,000 aggregate principal amount of %
Step-up Convertible Subordinated Notes Due 2001
(Step-up Income Redeemable Equity
Notes(TM) -- SIRENs(TM) (the "SIRENs")).
Interest Rates............. Interest on the SIRENs will accrue at the rate of
% per annum from the date of issuance through
March 31, 1997 and will accrue at the rate of
% per annum from April 1, 1997 to maturity or
earlier redemption.
Interest Payment Dates..... March 31 and September 30, commencing September 30,
1994.
Conversion................. Convertible at the option of the holder into shares
of Common Stock at any time prior to maturity,
unless previously redeemed, at a conversion price
of $ per share, subject to adjustment
under certain conditions.
Redemption at Option of
Company.................. Redeemable at the option of the Company, in whole
or in part, at any time on or after March 31, 1997,
initially at % of the principal amount and at
prices declining to 100% at final maturity, in each
case together with accrued interest to the date of
redemption.
Repurchase at Option of
Holders.................. Upon a Change of Control (as defined) which
constitutes a Repurchase Event (as defined), each
holder of SIRENs will have the right, subject to
certain conditions and restrictions, to require the
Company to repurchase outstanding SIRENs owned by
such holder at 100% of the principal amount of such
SIRENs, plus accrued and unpaid interest to the
date of repurchase. Before repurchasing the SIRENs,
the Company is required, with respect to any Senior
Indebtedness (as defined) that would prohibit the
repurchase of SIRENs in the event of a Change of
Control either to repay all such Senior
Indebtedness in full or obtain the requisite
consents under such Senior Indebtedness to permit
the repurchase of the SIRENs. The inability of the
Company to repay such Senior Indebtedness or to
obtain the requisite consents under such Senior
Indebtedness to permit the repurchase of the SIRENs
could result in an Event of Default (as defined)
under the indenture (the "Indenture") with respect
to the SIRENs.
Ranking.................... Subordinated to all existing and future Senior
Indebtedness of the Company. The Indenture will not
restrict the incurrence of Senior Indebtedness or
other indebtedness by the Company or any subsidiary
of the Company. The SIRENs are effectively
subordinated to all existing and future liabilities
of the Company's subsidiaries to the extent of the
assets of such subsidiaries. Upon the sale of the
SIRENs offered hereby and application of the net
proceeds therefrom, the Company estimates that the
sum of its Senior Indebtedness and the indebtedness
of its subsidiaries will total approximately $34
million.
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Use of Proceeds............ To repay a portion of the borrowings outstanding
under the Company's bank credit facility. The
Company intends to use the resulting borrowing
capacity under its credit facility to fund
development drilling, expansion of its gas
facilities and potential acquisitions.
Book-Entry System.......... The SIRENs will be issued in the form of one or
more fully registered global securities
(collectively, the "Global Note") registered in the
name of Cede & Co., as nominee of The Depository
Trust Company ("DTC"). Except as described in this
Prospectus, beneficial interests in the Global Note
will be represented through accounts of financial
institutions acting on behalf of beneficial owners
as direct and indirect participants in DTC. Except
in limited circumstances described in this
Prospectus, owners of beneficial interests in the
Global Note will not be entitled to have SIRENs
registered in their names, will not receive or be
entitled to receive SIRENs in definitive form and
will not be considered holders thereof under the
Indenture. SIRENs will only be sold in minimum
aggregate principal amounts of $1,000 and integral
multiples thereof. See "Description of
SIRENs -- Form, Denomination and Registration."
Original Issue Discount.... For federal income tax purposes, interest on the
SIRENs is expected to accrue at a constant rate
through the stated maturity date. As a result, the
SIRENs will be considered to be issued with
original issue discount. For all periods through
March 31, 1997, holders will be required to
recognize an amount of taxable interest and OID
income that exceeds the actual cash interest
payments for such periods. For periods beginning
after March 31, 1997, cash interest payments on the
SIRENs will exceed the amount of taxable interest
and OID income recognized by the holders. See
"Certain Federal Income Tax
Considerations -- Original Issue Discount."
Sinking Fund............... None.
NYSE Common Stock
Symbol................... SNY
Unless otherwise indicated in this Prospectus, as used herein, the term
"Btu" means British Thermal Unit, the term "MMBtu" means million Btus, the term
"Mcf " means thousand cubic feet, the term "MMcf " means million cubic feet, the
term "Bcf " means billion cubic feet, the term "Bbl" means barrel, the term
"MBbl" means thousand barrels, the term "MMBbl" means million barrels, the term
"BOE" means barrel of oil equivalent, the term "MBOE" means thousand barrels of
oil equivalent and the term "MMBOE" means million barrels of oil equivalent. Gas
is converted into a barrel of oil equivalent based on six Mcf of gas to one Bbl
of oil, except as otherwise described herein. A "gross acre" or "gross well" is
an acre or well in which an interest is owned. "Net acres" or "net wells" are
obtained by multiplying gross acres or wells by the Company's working interest
in the applicable properties.
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SUMMARY FINANCIAL AND OPERATING INFORMATION
The following table presents summary financial and operating information
for each of the three years ended December 31, 1993. The following information
should be read in conjunction with the consolidated financial statements
incorporated by reference herein.
YEAR ENDED DECEMBER 31,
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1991 1992 1993
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(IN THOUSANDS, EXCEPT PER SHARE DATA)
FINANCIAL DATA
Revenues.......................................... $92,501 $120,172 $229,885
Income before accounting change and extraordinary
item........................................... 8,811 16,875 27,608
Net income........................................ 8,811 20,638 25,664
Net income available to common.................... 8,358 15,838 16,564
Weighted average shares outstanding............... 22,839 22,722 23,096
Ratio of earnings to fixed charges(a)............. 2.4x 4.5x 7.6x(b)
Ratio of EBITDA to fixed charges(c)............... 5.4x 10.9x 17.2x(b)
Net cash provided by operations................... $37,738 $ 47,911 $ 68,293
Capital expenditures.............................. 48,385 130,375(d) 166,726
Per share data
Income before accounting change and
extraordinary item........................... $ .37 $ .53 $ .80
Net income..................................... .37 .70 .72
Dividends...................................... .20 .25(e) .22
OPERATING DATA
Average daily production
Oil (Bbl)...................................... 4,074 4,851 9,455
Gas (Mcf)...................................... 50,363 63,088 96,107
BOE(f)......................................... 13,525 16,365 25,472
Average sales price
Oil (per Bbl).................................. $ 20.62 $ 18.87 $ 15.41
Gas (per Mcf)(f)............................... 1.68 1.74 1.94
BOE(f)......................................... 13.24 12.92 13.41
Average operating expense per BOE(g).............. 5.04 4.68 4.83
DECEMBER 31, 1993
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ACTUAL AS ADJUSTED(H)
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(IN THOUSANDS)
BALANCE SHEET DATA
Working capital............................................. $ 1,291 $ 1,291
Oil and gas properties and facilities, net.................. 388,361 388,361
Total assets................................................ 479,536 479,536
Senior debt................................................. 114,952 18,052
Convertible subordinated notes.............................. -- 100,000
Stockholders' equity........................................ 297,241 297,241
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(a) For the purpose of calculating the ratio of earnings to fixed charges,
"earnings" consist of income before taxes, accounting change,
extraordinary item and "fixed charges." "Fixed charges" include interest
on indebtedness and the portion of rental expense, excluding rent on
capitalized leases, estimated to be representative of the interest
factor in rental expense.
(b) The ratio of earnings to fixed charges and the ratio of EBITDA to fixed
charges, pro forma for the issuance of $100 million principal amount of
SIRENs offered hereby (based on the yield to maturity), would be 4.5x
and 10.3x, respectively.
(c) EBITDA is income before (i) accounting change and extraordinary item,
(ii) taxes, (iii) depletion, depreciation and amortization and (iv)
interest.
(d) Includes $56.1 million incurred in connection with properties acquired
in December 1992, $49.8 million of which was paid in February 1993.
(e) Due to revised payment timing, five payments were made at the $.05
quarterly rate in 1992.
(f) Gas production is converted to oil equivalents at the rate of 6 Mcf per
barrel except for Thomasville production which, through 1992, was
converted based on its price equivalency to the Company's other gas.
Average gas prices exclude Thomasville production.
(g) Includes production and severance taxes.
(h) Adjusted to give effect to the application of the estimated net proceeds
of this Offering. See "Use of Proceeds."
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SUMMARY RESERVE DATA
The following table sets forth information on estimated proved oil and gas
reserves, future net cash flow before taxes from such reserves and the pretax
present value of such cash flow, using unescalated prices and costs and a 10%
per annum discount rate ("Pretax PW10% Value"). The prices used in the yearend
reserve estimates averaged $11.49 per barrel of oil and $2.11 per Mcf of gas
over the life of the reserves.
DECEMBER 31, 1993
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DEVELOPED UNDEVELOPED TOTAL
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(IN THOUSANDS)
Estimated proved reserves:
Crude oil and liquids (Bbl)..................... 18,032 13,898 31,930
Natural gas (Mcf)............................... 268,349 161,740 430,089
BOE(a).......................................... 62,757 40,855 103,612
Future net cash flow from estimated production.... $ 474,480 $ 213,792 $688,272
Pretax PW10% Value(b)............................. $ 297,638 $ 92,771 $390,409
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(a) Natural gas reserves are converted to oil equivalents at the rate of 6
Mcf per Bbl.
(b) The after-tax present value of proved reserves totalled $340.5 million
at December 31, 1993.
The revenues generated by the Company are highly dependent upon the prices
of crude oil and gas. The volatility of energy prices makes it particularly
difficult to estimate future prices of oil and gas. Price fluctuations change
reserve values by altering the quantities of reserves that are recoverable on an
economic basis as well as the future net revenues attributable to the reserves.
Any significant decline in prices of oil or gas could have a material adverse
effect on the Company's financial condition and results of operations.
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USE OF PROCEEDS
The net proceeds from the sale of the SIRENs are estimated to be
approximately $ million ($ million if the Underwriters' over-allotment
option is exercised in full). The Company intends to use the net proceeds to
repay a portion of the borrowings outstanding under its bank credit facility.
The Company intends to use the resulting borrowing capacity under its credit
facility to fund development drilling, expansion of its gas facilities and
potential acquisitions. The Company estimates that it will expend $175 to $200
million for development drilling and expansion of gas facilities during 1994,
assuming no material changes in oil and gas prices. See "Management's Discussion
and Analysis of Financial Condition and Results of Operations."
On March 30, 1994 approximately $125.0 million was outstanding under the
Company's revolving bank credit facility. The rate of interest on this debt
fluctuates based on various rates, as selected by the Company. The weighted
average interest rate on bank borrowings at such date was 4.89%. The facility
expires on December 31, 1997. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations."
CAPITALIZATION
The following table sets forth the Company's capitalization at December 31,
1993, and as adjusted to give effect to the issuance of the SIRENs offered
hereby and the application of the estimated net proceeds therefrom.
DECEMBER 31, 1993
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ACTUAL AS ADJUSTED
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(IN THOUSANDS)
Current portion of debt............................................. $ 15 $ 15
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Long-term debt(a)
Senior debt....................................................... $114,952 $ 18,052
% Step-up Convertible Subordinated Notes Due 2001.............. -- 100,000
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Total long-term debt...................................... 114,952 118,052
Stockholders' equity
Preferred Stock, $.01 par value; 10 million shares authorized:
$4.00 Convertible Exchangeable Preferred Stock; 1,186,005
shares issued and outstanding ($50.00 liquidation preference
per share).................................................... 12 12
$6.00 Convertible Exchangeable Preferred Stock; 1,035,000
shares issued and outstanding ($100.00 liquidation preference
per share).................................................... 10 10
Common Stock, $.01 par value; 75 million shares authorized and
23,259,658 shares issued and outstanding (b)................... 233 233
Capital in excess of par value.................................... 250,574 250,574
Retained earnings................................................. 46,954 46,954
Foreign currency translation...................................... (542) (542)
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Total stockholders' equity................................ 297,241 297,241
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Total capitalization...................................... $412,193 $ 415,293
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(a) See Note 3 to the consolidated financial statements incorporated by
reference herein for a description of long-term debt.
(b) Excludes an aggregate of 14,794,950 shares of Common Stock reserved for
issuance as of March 1, 1994 upon conversion or exercise of outstanding
securities, consisting of (i) 11,463,558 shares reserved for issuance upon
conversion of preferred stock, (ii) 1,331,392 shares reserved for issuance
upon exercise of management stock options and (iii) 2,000,000 shares
reserved for issuance upon exercise of warrants held by Union Pacific
Resources Company. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
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PRICE RANGE OF COMMON STOCK AND DIVIDENDS
The Common Stock is listed on the New York Stock Exchange ("NYSE") under
the symbol "SNY." The following table sets forth, for the periods indicated, the
high and low sales prices for the Common Stock for NYSE composite transactions,
as reported by The Wall Street Journal, and the cash dividends declared.
HIGH LOW DIVIDENDS
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1992
First Quarter........................................... $ 6 7/8 $ 5 7/8 $ .05
Second Quarter.......................................... 7 3/8 6 1/8 .10(a)
Third Quarter........................................... 10 1/2 6 3/8 .05
Fourth Quarter.......................................... 10 1/8 8 5/8 .05
1993
First Quarter........................................... 16 1/8 10 .05
Second Quarter.......................................... 20 1/4 15 .05
Third Quarter........................................... 23 16 5/8 .06
Fourth Quarter.......................................... 23 14 3/4 .06
1994
First Quarter........................................... 21 3/8 17 1/2 .06
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(a) Due to revised payment timing, two payments were made at the $.05 quarterly rate in
the second quarter of 1992.
On March 31, 1994, the last reported sale price of the Common Stock on the
NYSE was $19 1/2 per share. As of December 31, 1993, there were approximately
3,500 holders of record of the Common Stock and 23.3 million shares outstanding.
Shares of Common Stock receive dividends if, as and when declared by the
Board of Directors. The amount of future dividends will depend on debt service
requirements, dividend requirements on preferred stock, capital expenditures and
other factors. The Company's debt agreements contain restrictions on its ability
to declare and pay dividends on the Common Stock in the future. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
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SELECTED HISTORICAL FINANCIAL INFORMATION
The following table presents selected financial information for each of the
five years ended December 31, 1993. The following information should be read in
conjunction with the consolidated financial statements incorporated by reference
herein.
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1989 1990 1991 1992 1993
------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
OPERATIONS
Revenues
Oil and gas sales............................... $12,479 $ 49,803 $ 65,344 $ 77,363 $124,641
Gas processing and transportation............... 10,885 29,442 21,459 38,611 94,839
Other........................................... 3,179 2,928 5,698 4,198 10,405
------- -------- -------- -------- --------
26,543 82,173 92,501 120,172 229,885
------- -------- -------- -------- --------
Expenses
Direct operating................................ 4,930 18,088 24,882 28,057 44,901
Cost of gas and transportation.................. 9,168 24,103 14,202 30,469 84,840
General and administrative...................... 1,047 5,649 7,259 6,704 6,780
Interest and other.............................. 761 7,125 9,327 5,693 7,271
Depreciation, depletion and amortization........ 3,316 17,351 25,392 31,944 51,184
Income before taxes, accounting change and
extraordinary item.............................. 7,321 9,857 11,439 17,305 34,909
Provision for income taxes
Current......................................... 400 977 230 430 --
Deferred........................................ 2,089 1,365 2,398 -- 7,301
------- -------- -------- -------- --------
2,489 2,342 2,628 430 7,301
------- -------- -------- -------- --------
Income before accounting change and extraordinary
item............................................ 4,832 7,515 8,811 16,875 27,608
Cumulative effect of change in accounting for
income taxes.................................... -- -- -- 3,763 --
Extraordinary item -- use of net operating loss
carryforward.................................... 2,089 -- -- -- --
Extraordinary item -- early extinguishment of
debt, net of taxes.............................. -- -- -- -- (1,944)
------- -------- -------- -------- --------
Net income........................................ 6,921 7,515 8,811 20,638 25,664
Dividends on preferred stock...................... -- -- 453 4,800 9,100
------- -------- -------- -------- --------
Net income available to common.................... $ 6,921 $ 7,515 $ 8,358 $ 15,838 $ 16,564
------- -------- -------- -------- --------
------- -------- -------- -------- --------
Weighted average shares outstanding............... 11,135 20,620 22,839 22,722 23,096
Per share data
Income before accounting change and
extraordinary item............................ $ .43 $ .36 $ .37 $ .53 $ .80
Net income...................................... .62 .36 .37 .70 .72
Dividends....................................... .11 .16 .20 .25(a) .22
Ratio of earnings to fixed charges(b)............. 10.6x 2.6x 2.4x 4.5x 7.6x(c)
Ratio of EBITDA to fixed charges(d)............... 15.0x 5.3x 5.4x 10.9x 17.2x(c)
CASH FLOW
Net cash provided by operations................... $11,129 $ 22,512 $ 37,738 $ 47,911 $ 68,293
Capital expenditures.............................. 14,216 171,767(e) 48,385 130,375(f) 166,726
BALANCE SHEET
Working capital................................... $ 3,499 $ 12,087 $ 17,259 $ 7,619 $ 1,291
Oil and gas properties and facilities, net........ 29,904 179,902 196,206 287,094 388,361
Total assets...................................... 56,669 227,198 252,241 346,737 479,536
Senior debt....................................... 2,325 56,172 17,108 96,568 114,952
Subordinated notes, net........................... 2,477 25,000 25,000 18,750 --
Stockholders' equity.............................. 31,149 115,187 174,696 184,393 297,241
- ---------------
(a) Due to revised payment timing, five payments were made at the $.05 quarterly
rate in 1992.
(b) For the purpose of calculating the ratio of earnings to fixed charges,
"earnings" consist of income before taxes, accounting change, extraordinary
item and "fixed charges." "Fixed charges" include interest on indebtedness
and the portion of rental expense, excluding rent on capitalized leases,
estimated to be representative of the interest factor in rental expense.
(c) The ratio of earnings to fixed charges and the ratio of EBITDA to fixed
charges, pro forma for the issuance of $100 million principal amount of
SIRENs offered hereby (based on the yield to maturity), would be 4.5x and
10.3x, respectively.
(d) EBITDA is income before (i) accounting change and extraordinary item, (ii)
taxes, (iii) depletion, depreciation and amortization and (iv) interest.
(e) Includes $130.7 million related to the acquisition of a publicly traded
limited partnership managed by the Company.
(f) Includes $49.8 million paid in February 1993 for properties acquired in
December 1992.
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS(A)
Comparison of 1993 results to 1992. Total revenues rose 91% in 1993 to
$229.9 million. Net income before taxes and extraordinary items more than
doubled to reach $34.9 million in 1993. The increase was led by a rapid rise in
production and assisted by an increase in gas processing and transportation
margins. Before the effect of a favorable $3.8 million income tax accounting
change in 1992 and a $1.9 million 1993 extraordinary charge on early retirement
of debt, earnings per common share were $.80 in 1993 compared to $.53 in 1992, a
51% increase.
The gross margin from production operations for 1993 increased 62% to $79.7
million, which was primarily related to a 65% growth in oil and gas production.
The price received per equivalent barrel decreased by 3% to $13.41. Total
operating expenses including production taxes increased 60% during 1993 although
operating cost per BOE decreased to $4.83 from $4.99 in 1992. Expense reductions
gained from wells added in the DJ Basin, where operating costs averaged $2.76
per BOE, were partially offset by the late 1992 acquisition of Wyoming wells
from a major oil company where 1993 operating costs averaged $7.45 per BOE.
For the year ended December 31, 1993, average daily production was 25,472
BOE, a 65% increase from 1992. Average daily production in the fourth quarter of
1993 climbed to 10,314 Bbls and 105.6 MMcf (27,917 BOE). The production
increases resulted primarily from acquisitions and continuing development
drilling in the DJ Basin. Domestically, $51.0 million in properties were
acquired in 1993, primarily in and around existing hubs in Colorado and Wyoming.
The acquisitions included a significant number of development locations and
should continue to add to production in 1994. In 1993, 311 wells were placed on
production in the DJ Basin, with 51 wells in various stages of drilling and
completion at yearend. Because the majority of the wells were added in the
latter part of the year, production will not be fully impacted until 1994.
Additionally, significant downtime was experienced in the fourth quarter at the
major processing plant in the DJ Basin, which increased line pressures and
hampered production. To a lesser extent, this situation continued into early
1994.
The gross margin from gas processing, transportation and marketing
activities for 1993 increased 23% to $10.0 million from $8.1 million in 1992.
The increase was primarily attributable to a $3.0 million (33%) rise in
transportation and processing margins as a result of additional DJ Basin
production and the recent expansion of the related facilities. Gas marketing
margins for 1993 decreased by $1.1 million due to reduced margins on the
Company's Oklahoma cogeneration supply contract, which declined as a result of
an imposed limitation of the contract sales price and rising gas purchase costs.
In 1993 the net contract margin was a loss of $267,000, which was $1.8 million
less than 1992. At present gas price levels, the Company foresees continued
negative or breakeven margins for the cogeneration contract through July 1994.
At that time, a change in the pricing formula should result in improved margins.
The cogeneration margin reduction was partially offset by a $667,000 (126%) rise
in other gas marketing margins in 1993 resulting from increased third party
marketing.
Other income was $10.4 million during 1993, compared to $4.2 million in
1992. The $6.2 million increase resulted from a $3.5 million gas contract
settlement received in April 1993, collection of a $1.7 million litigation
judgment and greater gains on the sales of securities.
General and administrative expenses, net of reimbursements, for 1993
represented 3% of revenues compared to 5.6% in 1992 as expenses were held
essentially flat while revenues grew 91%. Interest and other expenses increased
28% primarily as a result of a rise in outstanding debt balances. Senior debt
was
- ---------------
(a) Prior to 1993, production from the Thomasville Field, which was sold at
prices that were significantly above market, was converted to equivalent
barrels based on its price relative to the Company's other gas production.
Beginning in 1993, Thomasville production was converted to oil equivalents
at the rate of 6 Mcf per barrel. In order to provide comparability between
periods, equivalent barrel information, other than depletion rates, for 1992
and 1991 has been restated in this section to reflect Thomasville production
at the conversion rate of 6 Mcf per barrel. All equivalent barrel
information presented elsewhere in this Prospectus reflects the historical
method of conversion of Thomasville production used by the Company in the
applicable year.
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substantially reduced in April 1993 with proceeds from a preferred offering, but
increased through yearend as a result of development expenditures, acquisitions,
the investment in Command Petroleum Holdings NL and the retirement of $25.0
million in subordinated debt.
Depletion, depreciation and amortization during 1993 increased 60% from the
prior year. The increase was the direct result of the 65% rise in equivalent
production between years. The producing depletion rate per BOE for 1993 was
reduced to $4.75 from $4.79 in 1992. The rate was reduced by an ongoing drilling
cost reduction program, partially offset by an increase from the discontinuation
of converting Thomasville production to equivalent quantities based on relative
gas prices.
The Company adopted FASB Statement No. 109, "Accounting for Income Taxes,"
effective January 1, 1992. Net income for 1992 was increased by $3.8 million for
the cumulative effect of the change in method of accounting for income taxes. In
1992 the income tax provision was reduced from the statutory rate of 34% by $5.5
million due to the elimination of deferred taxes as a result of tax basis in
excess of financial basis. In 1993 the income tax provision was reduced from the
newly enacted rate of 35% to an effective rate of approximately 20% as a result
of full realization of the excess basis benefit. The Company anticipates
deferred taxes will be provided in 1994 and beyond based on the full statutory
rate and accordingly will increase substantially.
Comparison of 1992 results to 1991. Revenues rose 30% in 1992 to $120.2
million, compared to $92.5 million in 1991. Net income for 1992 was $20.6
million, a 134% increase from the $8.8 million in 1991. The increases resulted
from greater oil and gas production volumes, lower interest expense, reduced
general and administrative expenses and a $3.8 million reversal of the
cumulative effect of prior year deferred taxes with the adoption of a change in
the method of accounting for income taxes.
Average daily production for 1992 rose 24% to 15,408 BOE due mostly to
development drilling in the DJ Basin of Colorado as 189 wells were placed on
production there. As a result, the gross margin from production increased 22% to
$49.3 million in 1992. The price per BOE decreased 4% during 1992.
The gross margin from gas processing, transportation and marketing
activities for 1992 increased 12% to $8.1 million from $7.3 million in 1991. The
growth was primarily the result of increased marketing of third party gas in New
Mexico, Colorado and Wyoming. Gas processing and transportation margins
increased moderately as volumes were increased late in the year by expansions of
pipeline and plant facilities to take advantage of increasing DJ Basin
production. Other income for 1992 decreased 26% to $4.2 million from a reduction
in gains on sales of securities and lower interest on notes receivable.
Direct operating expenses including production taxes increased only 13%
during 1992 as the operating cost per BOE decreased to $4.99 from $5.47 in 1991,
due to increased DJ Basin production where operating costs have been
significantly lower than average. General and administrative expenses, net of
reimbursements, for 1992 represented less than 6% of revenues compared to 8% in
1991, as revenues rose 30%. Interest and other expenses dropped 39% in 1992 due
to lower average outstanding senior debt after the application of proceeds from
a preferred stock offering in late 1991.
DEVELOPMENT, ACQUISITION AND EXPLORATION
During 1993 the Company expended $93.1 million for oil and gas property
development and exploration, $51.0 million for acquisitions and $22.6 million
for gas facility expansion and other assets, for a total of $166.7 million in
property and equipment expenditures. Additionally, the Company made an $18.2
million investment in an Australian based exploration and production company.
The Company has concentrated a significant portion of its development
activities in the DJ Basin. Capital expenditures for DJ Basin development
totalled $75.4 million during 1993. A total of 311 newly drilled wells were
placed on production there in 1993 and 51 were in progress at yearend.
Additionally, 42 recompletions were performed in 1993, with seven in process at
yearend. In December 1993, 16 drilling rigs were in operation in the DJ Basin.
The Company anticipates putting 500 or more wells per year on production in the
DJ Basin for the next few years. With additional leasing activity and through
drilling cost reductions that add proved undeveloped locations as they become
economic, the Company has increased the inventory of available drillsites. In
December 1993, the Company entered into a letter of intent with Union Pacific
Resources Company
12
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("UPRC") whereby the Company will gain the right to drill wells on UPRC's
previously uncommitted acreage throughout the Wattenberg area. This transaction
significantly increased the Company's undeveloped Wattenberg inventory. UPRC
will retain a royalty and the right to participate as a 50% working interest
owner in each well, and received warrants to purchase two million shares of
Company stock. Of the warrants, one million expire three years from the date of
grant, and are exercisable at $25 per share, while the other one million expire
in four years and are exercisable at $27 per share. On February 8, 1995, the
exercise prices may be reduced to 120% of the average closing price of the
Company stock for the preceding 20 consecutive trading days, but not below
$21.60 per share. The expiration date of the warrants will be extended one year
if the average closing price over such 20 day trading period is less than $16.50
per share.
The Company expended $14.8 million for other development and recompletion
projects and $2.9 million for exploration during 1993. In Nebraska, 29 wells
were added to production in 1993 as an extension of a drilling program initiated
in 1992. An additional 20 wells are planned in Nebraska for 1994. In southern
Wyoming, 11 wells in the East Washakie Basin development program were
successfully drilled and completed during the last half of 1993 with three in
process at yearend. In this program, significant cost-cutting measures were
applied based on the experience gained in the DJ Basin. In central Wyoming on
the properties acquired from a major oil company in late 1992, efforts have been
focused on increasing operating efficiency with limited development drilling and
workover activity. In 1993, three successful wells were drilled in the fourth
quarter and selected development and recompletion activity is scheduled for
1994. In the Piceance Basin of western Colorado, a three well test program was
started in December of 1993 on acreage acquired there during the year, with one
well undergoing completion, the second in progress and a third scheduled for
early 1994. Current plans include a minimum of 25 wells in the basin during
1994. In South Texas, a combined operated and non-operated program was
initiated, with nine wells completed in 1993 and one well abandoned. A total of
25 additional horizontal locations have been identified and drilling should
continue with as many as 15 wells planned in 1994. In its domestic exploration
efforts, the Company initiated a seismic program in Louisiana and began drilling
early in the fourth quarter. Advanced seismic techniques are being used to
identify further prospects in Louisiana and expectations are to drill up to 20
wells in 1994.
A total of $51.0 million in domestic acquisitions were completed in 1993.
In May 1993, the Company purchased an interest in 121 producing wells and over
70 drilling locations in the DJ Basin area for $3.3 million. In July, an
incremental 25% interest in the Company's Barrel Springs and Duck Lake Fields in
Wyoming was purchased for $6.1 million. The properties are 90% gas and include
44 producing wells and 46 undeveloped locations. In August, the Company acquired
interests in 225 producing wells and 272 proved undeveloped locations in the DJ
Basin for $19.7 million. The proved reserves are 70% gas with more than two-
thirds requiring future development to produce. Late in the year, two
acquisitions were completed in the Piceance and Uinta Basins of Western Colorado
for a total of $12.5 million. The majority of the value was in undeveloped
locations as only 128 wells were currently producing. Numerous other producing
and undeveloped acquisitions totalling $9.4 million were completed, mostly in or
close to the Company's principal operating areas.
The Company's gas gathering and processing facilities have been undergoing
significant transformation since late 1992. In 1993, the Company expended $20.1
million to develop further its gas related assets. The Company spent $9.4
million toward the second phase of its DJ Basin gathering expansion to construct
a high pressure line to deliver gas directly to the major gas processing plant
in the area and expand its gathering network for the increased drilling
activity. An additional $2.6 million was expended to expand the Roggen Plant for
the production increases. A total of $5.6 million in additional transportation
and gathering facilities were constructed in the DJ Basin including a nine mile
16" interconnect line completed in October to relieve high line pressures, a 20"
western gathering extension and numerous other extensions and connections. A
gathering system that delivers third party gas to the Roggen Plant was purchased
for $703,000. The Company expended $1.4 million to complete construction of a
system to gather gas from its Nebraska drilling project. These projects are
intended to take advantage of the significant increase in drilling activity in
these areas.
In May 1993, the Company acquired 42.8% (currently 35.7%) of the
outstanding shares of Command Petroleum Holdings NL ("Command"), a Sydney based
Australian exploration and production company listed on the Australian Stock
Exchange, for $18.2 million. Command holds interests in more than 20
13
15
exploration permits and licenses and a 28.7% interest in a Netherlands
exploration and production company whose assets are located primarily in the
North Sea. Permtex, the Company's Russian joint venture, received central
government approval in August and the Company executed a finance and insurance
protocol with the Overseas Private Investment Corporation ("OPIC"), a United
States government agency. Current plans call for 25 of the existing 45 shut-in
wells to be placed on production in 1994, and that 400 development wells will be
drilled over the next ten years. Extensive seismic work began in the fourth
quarter of 1993 for 400 kilometers of data in Tunisia and 500 kilometers in
Mongolia.
The Company from time to time acquires securities of publicly traded and
private oil and gas companies. In addition to its investment in Command, the
Company owns, among other investments, more than 5% of the common stock of Lomak
Petroleum, Inc. and, as the result of purchases beginning in the third quarter
of 1993, American Exploration Company. The Company is currently evaluating a
range of possible alternatives with respect to its investment in American
Exploration Company, including the possibility of actions to enhance the value
of its common stock.
FINANCIAL CONDITION AND CAPITAL RESOURCES
At December 31, 1993, the Company had total assets of $480 million and
working capital of $1.3 million. Total capitalization was $412 million, of which
28% was represented by senior debt and the remainder by stockholders' equity.
During 1993, the Company fully retired its $25 million of 13.5% subordinated
notes and the related cumulative participating interests. During 1993, cash
provided by operations was $68.3 million, an increase of 43% over 1992. As of
December 31, 1993, commitments for capital expenditures totalled $7.5 million,
primarily for DJ Basin drilling. The Company anticipates that it will expend
$175 to $200 million for development drilling and expansion of gas facilities in
1994. The level of these and other future expenditures is largely discretionary,
and the amount of funds devoted to any particular activity may increase or
decrease significantly, depending on available opportunities and market
conditions. The Company plans to finance its ongoing development, acquisition
and exploration expenditures using internally generated cash flow, proceeds from
property dispositions and existing credit facilities. In addition, joint
ventures or future public and private offerings of securities may be utilized.
In 1992, an institutional investor agreed to contribute $7 million to a
partnership formed to monetize Section 29 tax credits to be realized from the
Company's properties, mainly in the DJ Basin. The initial $3 million was
contributed in October 1992, and at first payout in June 1993 the second
contribution of $1.5 million was received. An additional $1.5 million was
received in October 1993. This transaction should increase the Company's cash
flow and net income through 1994. A revenue increase of more than $.40 per Mcf
is realized on production generated from qualified Section 29 properties in this
partnership. The Company recognized $3.8 million of this revenue during 1993.
Discussions are in progress to expand the scope of this transaction so that the
benefits would be continued through at least 1996.
In April 1993, the Company sold 4.1 million depositary shares (each
representing a one quarter interest in one share of $100 liquidation value
stock) of convertible preferred stock through an underwritten offering for
$103.5 million. A portion of the net proceeds of $99.3 million was used to
retire the entire outstanding balance under the revolving credit facility at
that time. The preferred stock pays a 6% dividend and is convertible into common
stock at $21.00 per share. At the Company's option, the preferred stock is
exchangeable into 6% convertible debentures on any dividend payment date on or
after March 31, 1994. The preferred stock is redeemable at the option of the
Company on or after March 31, 1996.
Effective July 1, 1993, the Company renegotiated its bank credit facility
and increased it from $150 million to $300 million. The new facility is divided
into a $50 million short-term portion and a $250 million long-term portion that
expires on December 31, 1997. However, management's policy is to request renewal
of the facility annually. Credit availability is adjusted semiannually to
reflect changes in reserves and asset values. At December 31, 1993, the elected
borrowing base was $150 million. The majority of the borrowings currently bear
interest at LIBOR plus 1.25% with the remainder at prime. The Company also has
the option to select the CD rate plus 1.375%. Financial covenants limit debt,
require maintenance of minimum working capital and restrict certain payments,
including stock repurchases, dividends and contributions or advances to
unrestricted subsidiaries. Based on such limitations, $86.5 million would have
been
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available for the payment of dividends and other restricted payments as of
December 31, 1993. The Company does not currently plan to make, and is not
committed to make, any advances or contributions to unrestricted subsidiaries
that would materially affect its ability to pay dividends under this limitation.
The Company maintains a program to divest marginal properties and assets
that do not fit its long range plans. For 1992 and 1993, proceeds from these
sales were $3.0 million and $5.5 million, respectively. Included in the 1993
proceeds were $4.0 million of cash receipts previously accrued for late 1992
sales. The Company intends to continue to evaluate and dispose of nonstrategic
assets.
The Company believes that its capital resources are more than adequate to
meet the requirements of its business. However, future cash flows are subject to
a number of variables including the level of production and oil and gas prices,
and there can be no assurance that operations and other capital resources will
provide cash in sufficient amounts to satisfy debt service requirements and to
maintain planned levels of capital expenditures or that increased capital
expenditures will not be undertaken.
INFLATION AND CHANGES IN PRICES
While certain of its costs are affected by the general level of inflation,
factors unique to the petroleum industry result in independent price
fluctuations. Over the past five years, significant fluctuations have occurred
in oil and gas prices. Although it is particularly difficult to estimate future
prices of oil and gas, price fluctuations have had, and will continue to have, a
material effect on the Company.
BUSINESS AND PROPERTIES
GENERAL
Snyder Oil Corporation is engaged in the development and acquisition of oil
and gas properties primarily in the Rocky Mountain region of the United States.
The Company also gathers, transports, processes and markets natural gas
generally in proximity to its principal producing properties. Over the five year
period from 1988 to 1993, revenues increased from $14.7 million to $229.9
million, net income increased from $5.0 million to $25.7 million and net cash
provided by operations increased from $8.1 million to $68.3 million. At December
31, 1993, the Company's net proved reserves totaled 103.6 MMBOE, having a pretax
present value at constant prices of $390.4 million. Approximately 69% of its
proved reserves are natural gas.
The Company is headquartered at 777 Main Street, Fort Worth, Texas 76102
(telephone 817-338-4043). The Company also maintains administrative offices in
Denver and New York and has eight field offices in Colorado, Wyoming, Texas, New
Mexico and Nebraska.
DEVELOPMENT
GENERAL. Since 1990, development drilling has become the primary focus of
the Company's growth strategy. The Company believes that its existing properties
have extensive development drilling and enhancement potential, primarily in the
DJ Basin of Colorado, the Washakie Basin in southern Wyoming, the Piceance and
Uinta Basins in western Colorado and Utah and in the Giddings Field in southern
Texas. The Company designs its major drilling programs to reduce risk, create
synergies with its gas management operations and exploit the potential for
continuous cost improvement. In 1994, the Company expects to drill over 650
wells, including approximately 500 wells in the Wattenberg Field, where the size
of its operations enables it to continue to refine the application of new
drilling, completion and operating techniques, and to apply the experience
gained there to establish other large scale development projects in the Rockies.
In its large scale development projects, the Company also attempts to
acquire and maintain a sizeable inventory of potential drilling locations, many
of which may not be economic at current cost and price levels, but which the
Company believes may ultimately prove attractive to develop if reservoir
assumptions are validated and well economics improve over the life of the
project through cost reductions or price increases. No assurances can be given
that such conditions will be satisfied and, accordingly, that such locations
will be drilled.
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Assuming no material changes in product prices and capital availability,
the Company estimates that it will expend from $150 to $200 million per year for
development drilling and gas facilities over the next three to five years. Such
expenditures totalled $64.8 million in 1992 and $112.8 million in 1993,
primarily in the Wattenberg Field.
DJ BASIN
WATTENBERG FIELD. The Wattenberg Field is the Company's largest base of
operations, representing over 55% of total proved reserves. Between 1991 and
1993, the Company drilled a total of 667 wells in Wattenberg, of which 323 were
drilled during 1993. At yearend, the Company had interests in more than 1,400
producing wells, of which the Company operated over 1,100. Through a major joint
venture with UPRC, complementary acquisitions and an extensive leasing program,
the Company has accumulated up to 6,000 potential drilling locations in the
Wattenberg Field. The Company expects that over half of these sites will
ultimately prove attractive to develop. The Company expects to drill
approximately 500 wells per year in the Wattenberg Field for at least the next
several years.
At yearend 1993, the net proved reserves attributed to the Wattenberg
properties were 16.9 million barrels of oil and 229.9 Bcf of gas. The reserves
were attributable to 1,437 producing wells, 51 wells in progress, 1,102 proved
undeveloped locations and approximately 387 proved behind pipe zones. The
Company expects proved reserves to be assigned to other locations as drilling
progresses.
The Company acquired its first properties in Wattenberg during 1986. In
1990, it substantially increased its acreage position by acquiring rights to the
Codell and Niobrara formations underlying 32,985 net acres from Amoco Production
Company ("Amoco") for $14.4 million. Several farm-ins from Amoco in 1992,
financed primarily through a transfer of Section 29 tax credits, resulted in
earning additional Codell/Niobrara rights as well as rights to the Sussex,
J-Sand and Dakota formations in a number of locations. During 1993, a series of
purchases added nearly 9 MMBOE at a net cost of under $3.50 per barrel as well
as several pipeline and processing facilities that complement existing
facilities. See "-- Acquisition Program."
In early 1994, the Company finalized an agreement with UPRC under which the
Company has the right for up to six years to drill wells on locations of its
choosing on UPRC's previously uncommitted undeveloped acreage throughout the
Wattenberg area. This transaction substantially increased the Company's
Wattenberg undeveloped acreage inventory. Many of the locations have the
potential for improved economics through completion in one or more of the
Shannon, Sussex, J-Sand or Dakota formations, as well as the Codell and
Niobrara. During the venture's initial three-year term, the Company is required
to drill a minimum of 120, 120 and 60 wells per year. After the initial period,
the Company can, at its option, extend the venture annually for up to three
additional years by drilling at least 150 wells per year. There is no limit on
the maximum number of wells that can be drilled, and wells in excess of the
required minimum in any year will reduce the number of wells required in the
following year by up to 50%. If the Company drills less than the minimum number
of wells, it is required to pay UPRC $20,000 per well for the shortfall. On each
well that is drilled on UPRC's mineral acreage under the venture, UPRC retains a
15% mineral owner royalty and has the option either to receive an additional 10%
royalty interest after pay-out or to participate in the well as a 50% working
interest owner. On leasehold acreage, UPRC does not have the right to
participate in the well but will retain a royalty interest that will result in a
total royalty burden of 25%. As compensation for committing its acreage position
to the Company, UPRC was granted warrants to purchase two million shares of the
Company's Common Stock. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Development, Acquisition and
Exploration."
Drilling. The Company began drilling operations in Wattenberg in early
1991. From 1991 to December 1993, the Company expended $151.1 million to drill
667 wells, of which 323 were drilled in 1993. At yearend, 609 of these wells
were producing, 51 were in various stages of drilling and completion and seven
were dry holes.
The size of the Wattenberg drilling program has resulted in numerous
advantages. The Company acts as operator on all its development sites in the
Wattenberg Field and much of the acreage is held by production. As a result, the
Company has significant operational control over the timing of the development
program. The
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18
actual drilling locations and schedule are selected to minimize costs associated
with rig moves, surface facilities, location preparation and gathering system
and pipeline connections and to evaluate and quantify incremental reserve
potential across the acreage position.
The Company's success in continuing to reduce its costs of drilling and
operations, as well as applying new technology, will be important to the full
development of its undeveloped acreage in Wattenberg. The Company has selected
procedures for drilling and completing wells that it believes maximize
recoverable reserves and economics. The Company has also been able to reduce its
costs of drilling, completing and operating wells significantly by negotiating
favorable prices with suppliers of drilling and completion services because of
the size of its drilling program. These cost reductions often allow the Company
to earn an attractive rate of return even on lower reserve wells. The reductions
have been achieved by several methods. One of the most significant is the
formation of alliances with selected vendors who work with Company personnel to
improve coordination and reduce both parties' costs. The resultant reductions
are credited wholly or in large part to the Company while vendors' margins are
maintained or increased.
In addition to cost reduction, the Company seeks to employ new technology
or to creatively apply existing technology to reduce costs or to produce
reserves that would otherwise remain unrecovered. One example is the drilling of
four or more wells from a single drilling pad in residential areas, under
reservoirs and on inaccessible acreage.
The Codell formation, which is the primary objective of the drilling, is a
blanket siltstone formation that exists under much of the Wattenberg acreage at
depths of 6,700 to 7,500 feet. Codell reserves have a high degree of
predictability due to uniform deposition and gradual transition from high to low
gas/oil ratio areas. The Company generally dually completes the Niobrara chalk
formation, which lies immediately above the Codell, to enhance drilling
economics. The Codell/Niobrara wells produce most prolifically in the first six
to twelve months, after which production declines to a fraction of initial
rates. More than half of a typical well's reserves are recovered in the first
three years of production. As a result, each well contributes significantly more
production in its first year than in subsequent years. However, the declining
production of individual wells is expected to be offset by continuing
development drilling.
During 1992 and 1993, the Company expanded its drilling targets to include
both deeper and shallower formations. The J sand lies approximately 400 feet
below the Codell. It is a low permeability sandstone generally found to be
productive throughout the DJ Basin with performance varying proportionately with
porosity and thickness. The Dakota formation lies approximately 150 feet below
the J sand. It is a low permeability sand occasionally naturally fractured with
less predictable commercial accumulations and varied performance results. The
Sussex formation is at average depths of 4,500 feet. The Sussex sands were
deposited as bars and exhibit variable reservoir quality with a moderate degree
of predictability.
Because the Codell, Niobrara and J formations are continuous reservoirs
over a large portion of the DJ Basin, the Company believes that drilling in the
Wattenberg Field is relatively low risk. In addition, the Company has compiled a
comprehensive geologic and production database for approximately 12,000 wells
within a 4,350 square mile area between Denver and the Wyoming border and has
had considerable success in predicting variations in thickness, porosity,
gas/oil ratios and productivity. Of the 667 wells drilled between 1991 and 1993,
only seven have been dry holes. Dry holes cost an average of only $65,000 per
well. The average net cost of a completed well approximated $193,000 during 1993
with only 30 days usually elapsing between spud date and initial production.
CHEYENNE. During 1993, 29 wells were placed on stream in a shallow gas
producing area on the northeast flank of the DJ Basin. This project, known as
the Cheyenne Project, began with the acquisition of five shut-in gas wells in
1990 when the Company determined that it could capitalize on new open access
rules of the Federal Energy Regulatory Commission ("FERC") by constructing a
gathering system to transport gas to a nearby interstate pipeline. After
acquiring almost 50,000 acres of leases in the area and selling an approximate
27.5% interest to other parties on a promoted basis, the Company has drilled 54
successful wells and six dry holes in the area and constructed a gathering
system having a capacity of 10 MMcf per day to transport the gas to the
interstate pipeline. The Company currently operates 61 wells in this area that
produce from the Niobrara formation and plans to drill approximately 20
additional wells during 1994.
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19
EAST WASHAKIE
During 1993, the Company initiated a major project to apply the
cost-cutting and improved drilling and completion techniques learned in the
Wattenberg Field to develop fluvial Mesaverde sands in the eastern Washakie
Basin. An eleven well pilot project was completed in 1993 to test drilling and
completion techniques and confirm cost estimates. A second drilling program is
currently being initiated. After final evaluation of the drilling, the Company
may initiate a large scale drilling program in this area upon completion of a
required environmental impact statement. The environmental impact statement was
filed in October 1993, and clearance is currently expected in the second half of
1994. Depending on the timing of environmental clearance and continued
evaluation of drilling results, the Company expects to drill up to 60 wells in
East Washakie during 1994.
Since the mid-1980's, the Company's properties in the Barrel Springs Unit
and the Blue Gap Field of southern Wyoming, together with its gas gathering and
transportation facilities there, have been one of its most significant assets.
See "-- Properties" and "-- Gas Management." The Company currently operates 128
wells in this area and holds up to 1,200 potential drilling locations, 98 of
which were classified as proved undeveloped at yearend 1993. The Company
believes that more than half of the potential locations may ultimately prove
attractive to develop. The Company currently holds interests in 95,000 gross
(76,000 net) undeveloped acres in the Washakie Basin. This includes 36,000 gross
(32,000 net) undeveloped acres added during 1993.
WESTERN SLOPE
During 1993, the Company initiated the Western Slope Project by
establishing a sizable position in the Piceance Basin on the western slope of
Colorado and in the Uinta Basin in northeastern Utah. The Company formed the
53,000 acre Hunter Mesa Unit in the southeast corner of the Piceance Basin.
Through purchases and farmouts, the Company obtained a majority interest and
acts as unit operator. Immediately adjacent to the Hunter Mesa Unit, a 100%
working interest was purchased in the 26,000 acre Divide Creek Unit for $6.2
million. The acquisition of this Unit, which has six wells producing from the
Mesaverde and Cameo Coal formations, added 17.6 Bcf of proved gas reserves as
well as an established operating base. Near yearend, the Company also purchased
interests in 122 producing wells, 29 non-producing wells and 69 proved
undeveloped locations. In total, this purchase included 55,000 net acres in
various fields in the Piceance and Uinta Basins.
Through these purchases, farmouts and a leasing program, the Company
currently holds acreage with up to 1,000 potential drilling locations, of which
the Company believes 40% could ultimately prove to be attractive to develop. Of
these locations, 101 were classified as proved undeveloped at yearend 1993. The
development of the Mesaverde sands in the Piceance Basin began with the spudding
of the initial test well near the end of 1993. The development will continue
with a 10 well test program during 1994 to confirm cost estimates and improved
recovery techniques. If successful, the Company may drill up to 30 wells in 1994
and approximately 100 wells per year thereafter. The Company's ability to
continue to develop the Piceance Basin is in part dependent on arranging
gathering and transportation at a reasonable cost. The company is exploring
options for gathering and transporting future gas production, including the
possibility of constructing Company owned facilities.
OTHER DEVELOPMENT
At the end of 1992, the Company acquired interests in four large producing
fields in central Wyoming from a major oil company at a cost of $56.1 million.
Two of the fields, the Hamilton Dome and Riverton Dome Fields, are operated by
the Company. During 1993, the Company evaluated opportunities in the fields and
instituted programs to enhance production in the latter part of the year. In the
Hamilton Dome Field, improvement of the water injection system and completion of
two new wells increased daily production 8%
18
20
above the levels projected at the time of the acquisition. A third well should
be completed in the second quarter of 1994. In the Riverton Dome Field,
workovers and recompletions increased daily production over 10% above the levels
projected at the time of the acquisition. Additional workovers and development
drilling are scheduled for both fields during 1994. The Company is attempting to
work with the major oil companies that operate the other two fields purchased,
both of which are producing slightly below acquisition projections.
The Company operates the Adair waterflood property in Gaines County, Texas,
which it purchased in September 1991. Initial development of the Adair Unit in
1992 cost approximately $1.7 million net to the Company. Based on production
response from the initial phase of development, the Company spent an additional
$.9 million in 1993 to conduct a pilot program which reduced well spacing on a
portion of the Unit. This program increased the unit production from 150 barrels
per day to 260 barrels per day. The Company plans to spend an additional $1.1
million to implement an infill development program throughout the Unit.
In the Giddings Field in Southeast Texas, the Company has undertaken a
horizontal drilling program to further exploit existing properties in the area.
During 1993, the Company spent $2.2 million to re-enter or drill 10 wells, of
which nine were completed and one abandoned. The Company is encouraged by the
results to date and plans to increase its expenditures in the field during 1994.
At yearend, 25 locations were classified as having proved undeveloped reserves.
ACQUISITION PROGRAM
The Company believes that acquisitions continue to be an attractive method
of increasing its reserve base and cash flow. In its acquisition efforts, the
Company plans to focus on purchasing properties that strengthen its strategic
position and complement its large-scale gas development projects in the Rockies,
as well as provide opportunities to establish meaningful positions in new areas.
From 1983 through 1993 the Company, on behalf of itself, its affiliates and
other investors, purchased oil and gas properties and related assets with an
aggregate cost of nearly $650 million. The Company actively seeks to acquire
incremental interests in existing properties, acreage with development
potential, gas gathering, transportation and processing facilities and related
assets, particularly in proximity to existing properties. Purchases of
incremental interests or adjacent properties are generally small in size but in
aggregate represent a sizeable opportunity that is relatively easy to pursue.
Due to its rate of return requirements and the high cost of pursuing
potential acquisitions, the Company generally prefers negotiated transactions to
auctions. Complex transactions involving legal, financial or operational
difficulties have frequently permitted purchase of assets at favorable prices.
Past acquisitions of corporations laid the groundwork for the Wattenberg hub,
and may in the future provide opportunities to expand in other areas.
Acquisitions of incremental interests are being given particular emphasis to
take advantage of systems and operational knowledge already in place. The
Company has extensive experience in completing numerous types of acquisitions
using varied financing sources in addition to internal cash flow.
During 1993 domestic acquisitions having a total cost of $51.0 million were
completed, primarily to strengthen Wattenberg and establish two new hubs that
the Company believes have the potential to develop into large scale gas
development projects. In Wattenberg a series of purchases added nearly 9 million
BOE of proved reserves at a net cost of under $3.50 per barrel as well as
several pipeline and processing facilities that complement the Company's
existing gathering systems. In the largest of these acquisitions, the Company
paid $19.7 million and, after an exchange of interests with a third party,
acquired an approximate 80% working interest in 153 producing wells and 284
undeveloped locations having total proved reserves estimated to exceed 7 million
BOE. A portion of the value of the transaction lay in the large volume of
undedicated gas located in close proximity to the Company's gas lines.
In the Washakie Basin, the Company expended over $7.8 million to acquire a
25% incremental interest in its Barrel Springs properties and interests in 44
producing wells and 7 undeveloped locations, as well as a gathering system that
expands the existing gathering infrastructure in the area. These acquisitions
added approximately 3.6 million BOE of proved reserves and, together with an
active leasing program, formed the basis for the East Washakie Project, the
Company's second operating hub in the Rockies. See "-- Development -- East
Washakie."
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21
Through three purchase transactions, as well as farmouts and leasing, the
Company established a substantial position in the Piceance and Uinta Basins
during 1993, laying the foundation of the Western Slope Project, a third gas
development hub in the Rockies. A $6.2 million purchase gave the Company a 100%
working interest in the 26,000 acre Divide Creek Unit in the southeast Piceance
Basin. The Company also formed the adjacent 53,000 acre Hunter Mesa Unit and
through purchases and farmouts obtained a majority working interest position and
became unit operator. Near yearend the Company also acquired interests in 122
producing wells, 29 non-producing wells and 69 proved undeveloped locations in
various fields in the Uinta and Piceance Basins. See "-- Development -- Western
Slope."
The following table summarizes acquisition activity since 1983:
PURCHASE PRICE
---------------------------------
YEAR MAJOR ASSETS ACQUIRED COMPANY AFFILIATES TOTAL
---- --------------------------------------------- ------- ---------- ------
(MILLIONS)
1983 Louisiana gas pipeline $ 3.5 $ -- $ 3.5
1984 Various producing properties 27.8 -- 27.8
1985 Utah, Texas and Oklahoma properties 56.1 -- 56.1
1986 Colorado and Wyoming properties 61.8 15.4 77.2
1987 Mississippi and Colorado properties, Roggen
gas plant, Wyoming gas facilities 71.0 -- 71.0
1988 Various producing properties 33.8 18.5 52.3
1989 Various producing properties 12.3 56.9 69.2
1990 Wattenberg properties, incremental interests 161.2 (a) -- 161.2
1991 Waterflood properties, incremental interests 9.9 -- 9.9
1992 Wyoming properties, incremental interests 63.6 -- 63.6
1993 Colorado and Wyoming properties, incremental
interests, acreage 51.0 -- 51.0
------- ---------- ------
Total $552.0 $ 90.8 $642.8
------- ---------- ------
------- ---------- ------
- ---------------
(a) Includes the acquisition of a publicly traded limited partnership managed
by the Company.
GAS MANAGEMENT
General. The Company expanded its gas gathering and processing capacity
during 1993 with the construction of additonal gathering facilities and
expansion of the Roggen plant in Wattenberg, as well as the acquisition of
additional gas facilities in Wattenberg and in Wyoming. By yearend, operated
processing capacity had increased to more than 80 MMcf per day and gathering
system capacity was increased to more than 200 MMcf per day, while marketed net
volumes reached 100 MMcf per day. The gas management unit complements the
Company's development and acquisition activities by providing additional cash
flow and enhancing returns. The segment is also increasingly profitable in its
own right. During 1993, gross margin increased by approximately 23% to $10
million. See "-- Customers and Marketing."
Colorado Facilities. The largest concentration of gas facilities is in the
Wattenberg area. These facilities include two major gathering systems, the
Enterprise system and Energy Pipeline, the Roggen processing plant, and a number
of minor facilities. By yearend 1993, the Roggen plant capacity had reached 60
MMcf per day. During the fourth quarter of 1993, average throughput had reached
54 MMcf per day. The plant is expected to process gas from currently undeveloped
locations, new third party sources and permanently released locations on acreage
acquired from Amoco, plus additional gas from current suppliers. Gas developed
through the UPRC joint venture is not dedicated to a processing plant and will
significantly increase future volumes of gas available to be processed in the
Company's facilities.
The gas produced from the majority of the new Wattenberg wells drilled on
acreage acquired from Amoco is dedicated for the life of the lease to Amoco's
Wattenberg gas processing plant. If Amoco were unable to process Company
production at its plant for any reason, including a shut-down of the plant, it
would
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22
have a short-term adverse impact on the Company. The Company has expanded its
processing facilities in Wattenberg in order to process Company and third party
gas that is not dedicated to Amoco. The Company intends to continue to expand
its facilities during 1994 to handle additional gas developed through continued
drilling activity. These facilities will also enable the Company to partially
mitigate the effects of significant downtime at the Amoco plant.
At the Roggen plant, gas is processed to recover gas liquids, primarily
propane and a butane/gasoline mix, from gas supplied by the Company and third
parties. The liquids are then sold separately from the residue gas. The liquids
are marketed to local and regional distributors and the residue gas is sold to
utilities, independent marketers and end users through an intrastate system and
the Colorado Interstate Gas ("CIG") pipeline. A liquids line permits the direct
sale of Roggen's liquids products through an Amoco line to the major interchange
at Conway, Kansas. In addition, Phillips Petroleum began reactivation of an old
interconnect, which should be operational by the end of the second quarter of
1994, which will connect the Roggen plant to the Phillips Powder River liquids
pipeline.
The Company's Wattenberg gathering systems include over 600 miles of
pipeline that collect, compress and deliver gas from over 1,400 wells to the
Roggen plant. During 1993, the Company substantially increased the capacity of
its gathering systems through the expansion of existing facilities and the
acquisition of new facilities. The Company also completed the second phase of
the Enterprise system during 1993. Enterprise collects a portion of the
Company's gas produced from acreage acquired from Amoco and delivers it to the
Amoco Wattenberg plant. Enterprise includes 26 miles of 20" diameter trunk and
29 miles of associated lateral gathering lines connecting 20 of the Company's
existing central delivery points. As a result of the completion of the second
phase, the Enterprise system has the capacity to deliver 75 MMcf per day to the
Amoco Wattenberg plant.
During 1993, the Company also expanded its gathering system by constructing
a nine mile 16" pipeline loop on the western portion of its Energy Pipeline
system, which came on line in October 1993. This expansion provides pressure
relief and additional capacity for further development in the area. In addition,
the Company acquired a pipeline that expands its gathering capacity to the north
of the Roggen plant, which may be converted to a residue line allowing for the
delivery of residue gas from the tailgate of the Roggen plant to the Williams
Natural Gas System.
The Company has negotiated a transportation arrangement with CIG that, in
conjunction with the gathering fees to be charged on the Enterprise system,
allows the delivery of gas to the Amoco Wattenberg plant at a favorable rate. In
addition to reducing the Company's exposure to future escalation in gathering
costs applicable to the Company's production, Enterprise provides an enhanced
degree of operational control. Because the Enterprise system interconnects with
the Company's other Colorado facilities, the Roggen plant and other plants in
the area can serve as a backup for processing a portion of the Company's gas in
the event of any curtailment at the Amoco Wattenberg plant. While shut downs of
Amoco's plant reduce the Company's production, diversion of gas to the Roggen
plant and, to a lesser degree, two other plants in the area, enabled the Company
to produce significant volumes that would have otherwise been curtailed.
Given the continued expansion of the Company's drilling program in 1994 and
beyond and the potential for third party connections, the Company is continuing
to explore opportunities to expand its Wattenberg gas facilities. Subsequent to
yearend, the decision was made to double the Company's processing capacity
through the construction of a new plant on the west side of the field. The new
plant is scheduled to be operational in late 1994.
Wyoming Facilities. The Company operates two pipeline systems in Wyoming
that enhance its ability to market gas produced from its properties in the
Washakie Basin. Wyoming Gathering and Production Company ("WYGAP") gathers gas
produced from 53 operated wells in the Barrel Springs Unit. The system has a
capacity of 26 MMcf per day. Throughput averaged 10 MMcf and 14 MMcf per day
during 1992 and 1993, respectively. WYGAP delivers gas to Western Transmission
Corporation ("Westrans"), a Company-owned interstate pipeline system which
operates under FERC jurisdiction. At the beginning of 1993, the Company assumed
operations of CIG's Carbon County Blue Gap gathering system pursuant to a lease.
The Company has exercised an option to acquire the system subject to regulatory
approval. The Company also
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purchased Blue Gap gathering facilities formerly owned by Williams Field
Services. Both systems extend the Company's transportation capabilities to the
south.
The Westrans system consists of a 26-mile main pipeline, a smaller 9.2-mile
line and related gathering facilities. The system gathers and transports gas
under open access transportation service agreements on an interruptible basis.
The main line extends from the Washakie Basin area of Carbon County, Wyoming to
connections with Williams' and CIG's interstate pipelines in Sweetwater County,
Wyoming. Gas transported on Westrans also has access to California markets
through the Kern River Pipeline which was completed in February 1992 via
interconnects with CIG and Williams. Westrans is located near several other
interstate pipelines, providing the potential for additional interconnects that
offer alternative transportation routes to end markets. In addition to the gas
from WYGAP, which accounts for over 90% of its volumes, Westrans transports
volumes from other operated wells and third parties. The capacity of Westrans is
65 MMcf per day. Throughput volumes generally vary from 13 to 20 MMcf per day.
Daily throughput averaged 15 MMcf during 1992 and 1993. If the planned
acceleration of drilling in East Washakie occurs, volumes of gas on the
Company's gas pipeline in the area may be substantially increased. As the East
Washakie Project progresses, the Company expects to further expand its gathering
network in the area.
Other Facilities. The Company expanded its gathering system in southern
Nebraska during 1993 to gather gas produced from newly developed Cheyenne County
properties for delivery to various markets accessible through an interstate
pipeline. The Cheyenne system includes 9.5 miles of 4" to 6" trunkline and 6
miles of 3" lateral gathering lines. During the fourth quarter of 1993,
throughput averaged 3 MMcf per day of gas from 60 producing wells. Included in
the December 1992 acquisition of Wyoming properties was a gas processing plant
in Fremont County, Wyoming. The plant has a 20 MMcf per day capacity with
current throughput of 8 MMcf per day from the 28 producing wells in the Riverton
Dome Field.
In conjunction with the growing level of acquisition and development
activity in the Western Slope Project, the Company is actively exploring
alternatives to gather and transport future gas production, including the
possible construction of a Company-owned gathering and transportation line.
Traditionally, the lack of sufficient pipeline capacity has been a major
deterrent to development in the Piceance Basin.
INTERNATIONAL ACTIVITIES
The Company's strategy internationally is to develop projects that have the
potential for a major impact in the future. The Company attempts to structure
the projects to limit its financial exposure and mitigate political risk by
minimizing financial commitments in the early phases of a project and seeking
industry partners and investors to fund the majority of the equity capital. A
wholly owned subsidiary of the Company, SOCO International, Inc., is the holding
company for all the Company's international operations. During 1993, the Company
purchased from Edward T. Story, President of SOCO International, the 10% of SOCO
International held by him and canceled Mr. Story's option to purchase an
additional 20% of the company. In connection with the purchase, the Company
granted Mr. Story an option to purchase 10% of the currently outstanding shares
of SOCO International, which is financed primarily by Company loans, through
April 1998 for $600,000. The option price is subject to adjustment in certain
circumstances.
Russian Joint Venture. In early 1993, the Company formed Permtex, a joint
drilling venture with Permneft, a Russian oil and gas company, to develop four
major proven oil fields located in the Volga-Urals Basin of the Perm Region of
Russia, approximately 800 miles east of Moscow. During 1993, Permtex was
registered by the Russian authorities, representing governmental approval of the
terms of the joint venture and authorization for Permtex to commence business.
In early 1994, the Company executed a finance and insurance protocol with OPIC,
an agency of the United States government that provides financing and political
risk insurance for American investment in developing countries, related to the
financing of Permtex.
Permtex holds exploration and development rights to over 300,000 acres in
the Volga-Urals Basin. The contract area contains four major fields and four
minor fields as well as a number of prospects. The Company estimates that the
four major fields could ultimately produce 115 million barrels of oil. The major
fields have been delineated through 45 previously drilled wells, none of which
had been placed on production as of yearend 1993. It is anticipated that 25 of
the existing wells will be placed on production, of which four should
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go on stream in the first half of 1994, and that 400 additional development
wells will be drilled over the next five to ten years. The joint venture will
primarily utilize Russian personnel and equipment and Western technology under
joint Russian/American management.
As of March 1, 1994, the Company holds a 28.1% interest in Permtex, after
giving effect to the purchases by each of Command, the Company's Australian
affiliate, and Holland Sea Search NV ("HSSH"), a Dutch affiliate of Command, of
6.25% interests in Permtex. Recently, a major Japanese trading company has also
committed to purchase a 10 to 20% interest in Permtex, which would reduce the
Company's interest to 20.6% if the full amount is purchased.
Command Petroleum Holdings NL. In May 1993, the Company purchased 42.8% of
the outstanding shares of Command for approximately $18.2 million. At the time
of the purchase, Thomas J. Edelman, President of the Company, Edward T. Story,
President of SOCO International, and two other designees were elected to
Command's eight-person board of directors. Command is an exploration and
production company based in Sydney, Australia and listed on the Australian Stock
Exchange. Following a private placement of equity securities in early 1994,
Command had working capital of $35 million and no debt. Its current market
capitalization approximates US$150 million. Command currently holds interests in
more than 20 exploration permits and production licenses primarily in the
Southwestern Pacific Rim including Australia and Papua New Guinea. Until
recently, Command held a 28.7% interest in HSSH, a publicly traded Dutch
exploration and production company whose primary asset is an interest in the
North Sea's Markham gas field. After yearend 1993, Command increased its
position in HSSH to nearly 48%. Recently, Command purchased a 6.25% interest in
Permtex, acquired an interest in an offshore Tunisian permit operated by
Marathon Oil Company and acquired an 11.4% interest in the East Shabwa Contract
Area in Yemen. Command funded the expenditures with a portion of a $16.4 million
privately placed equity offering which reduced the Company's ownership to 35.7%.
If as expected, all of Command's warrants expiring in November 1994 are
exercised, the Company's ownership would be decreased to 29.6%.
The Company believes that Command's exploration expertise, experienced
technical staff and inventory of prospects complement the Company's acquisition
and development expertise and position the Company to play a larger role in
overseas development of oil and gas reserves. In addition, Command and HSSH
provide access to international capital markets which could provide additional
sources of financing for international projects.
Mongolia. The Company further expanded its international efforts by
entering into a production sharing agreement with Mongol Petroleum Company, the
national oil company of Mongolia. The Company believes this agreement is the
first such contract ever awarded by Mongolia. The agreement covers 11,400 square
kilometers, or approximately 2.8 million gross acres, in the Tamstag Basin of
northeastern Mongolia. In addition, the Company received a right of first
refusal from Mongol Petroleum for the adjacent block which covers 11,130 square
kilometers. As a consequence, the Company controls over 5 million acres in this
basin which, although previously unexplored and remote from existing markets, is
highly prospective. These concessions offset the Hailar Basin of China, a
portion of which is included in the China National Petroleum Corporation's round
of invitations for bidding in 1994. During 1993, the Company initiated seismic
work to broadly define the subsurface and this work is expected to continue into
1995.
Tunisia. During 1993 the Company completed its 400 kilometer seismic
acquisition program in the Fejaj Permit area of central Tunisia. The permit area
encompasses approximately 1.2 million gross acres and is predominately onshore,
with a small portion extending into the Gulf of Gabes. After the Company
integrates the newly acquired seismic work with over 1,400 kilometers of
reprocessed data and extensive geological field information, the Company will
seek industry partners for a 1995 exploratory well.
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PRODUCTION, REVENUE AND PRICE HISTORY
The following table sets forth information regarding net production of
crude oil and liquids and natural gas, revenues and expenses attributable to
such production and to natural gas transportation, processing and marketing and
certain price and cost information for the five years ended December 31, 1993.
DECEMBER 31,
-----------------------------------------------------
1989 1990 1991 1992 1993
------- ------- ------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PRICE AND PER BARREL EXPENSES)
PRODUCTION
Oil (MBbl)............................... 277 1,049 1,487 1,776 3,451
Gas (MMcf)............................... 4,027 12,769 18,382 23,090 35,080
MBOE(a).................................. 948 3,497 4,937 5,989 9,297
REVENUES
Oil production........................... $ 5,069 $24,806 $30,667 $ 33,512 $ 53,174
Gas production(b)........................ 7,410 24,997 34,677 43,851 71,467
------- ------- ------- -------- --------
Subtotal......................... 12,479 49,803 65,344 77,363 124,641
------- ------- ------- -------- --------
Transportation, processing and
marketing............................. 10,885 29,442 21,459 38,611 94,839
Interest and other....................... 3,179 2,928 5,698 4,198 10,405
------- ------- ------- -------- --------
Total............................ $26,543 $82,173 $92,501 $120,172 $229,885
------- ------- ------- -------- --------
------- ------- ------- -------- --------
OPERATING EXPENSES
Production............................... $ 4,930 $18,088 $24,882 $ 28,057 $ 44,901
Transportation, processing and
marketing............................. 9,168 24,103 14,202 30,469 84,840
------- ------- ------- -------- --------
$14,098 $42,191 $39,084 $ 58,526 $129,741
------- ------- ------- -------- --------
------- ------- ------- -------- --------
GROSS MARGIN............................... $12,445 $39,982 $53,417 $ 61,646 $100,144
------- ------- ------- -------- --------
------- ------- ------- -------- --------
PRODUCTION DATA
Average sales price(c)
Oil (Bbl)............................. $ 18.30 $ 23.65 $ 20.62 $ 18.87 $ 15.41
Gas (Mcf)(a)(b)....................... 1.65 1.69 1.68 1.74 1.94
BOE(a)................................ 12.97 14.18 13.24 12.92 13.41
Average operating expense/BOE............ $ 5.20 $ 5.17 $ 5.04 $ 4.68 $ 4.83
- ---------------
(a) Gas production is converted to oil equivalents at the rate of 6 Mcf per
barrel except for Thomasville production which through 1992 was converted
based on its price equivalency to the Company's other gas. Average gas
prices exclude Thomasville production. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations."
(b) Sales of natural gas liquids are included in gas revenues. Gas revenues for
the year ended December 31, 1989 and 1990 include nonrecurring receipts of
$183,000 and $219,000, respectively, in settlement of contract claims, which
have been excluded from average sales price computations.
(c) The Company estimates that its composite net wellhead prices at December 31,
1993 were approximately $2.11 per Mcf of gas and $11.49 per barrel of oil.
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DRILLING RESULTS
The following table sets forth information with respect to wells drilled
during the past three years. The information should not be considered indicative
of future performance, nor should it be assumed that there is necessarily any
correlation between the number of productive wells drilled, quantities of
reserves found or economic value. Productive wells are those that produce
commercial quantities of hydrocarbons whether or not they produce a reasonable
rate of return.
1991 1992 1993
----- ----- -----
Development wells
Productive
Gross.................................................. 143.0 241.0 382.0
Net.................................................... 117.2 207.5 316.0
Dry
Gross.................................................. 3.0 6.0 10.0
Net.................................................... 2.8 2.7 5.5
Exploratory wells
Productive
Gross.................................................. 5.0 -- 2.0
Net.................................................... 1.8 -- 2.0
Dry
Gross.................................................. 5.0 -- 6.0
Net.................................................... 1.5 -- 3.3
As of December 31, 1993, the Company had 61 gross (50.9 net) development
wells in progress. Between yearend and February 28, 1994, the Company spudded
118 wells. At that date 135 gross (116.7 net) wells, including wells in progress
at yearend, had been completed, two wells (1.5 net) had been abandoned and 42
gross (36.3 net) development wells were in progress.
FIELD OPERATIONS
In its capacity as operator, the Company supervises day-to-day field
activities, generally employing a combination of its personnel and contract
pumpers. The Company maintains eight district field offices and one division
office.
As operator, the Company charges overhead fees to all working interest
owners according to the applicable operating agreements. As of the end of 1991,
1992 and 1993, respectively, the Company operated 1,442, 1,745 and 2,176 wells.
The Company received overhead reimbursements for operations and drilling of
$10.1 million, $12.9 million and $15.5 million during 1991, 1992 and 1993,
respectively (including reimbursements attributable to the Company's interest).
The increase in reimbursements is attributable to the increase in operated
drilling and producing wells and contractual escalations. Based on the time
allocated to operations, these reimbursements in aggregate generally have
exceeded the costs of such activities.
PROPERTIES
The Company's reserves are concentrated in several major producing areas.
These include the Wattenberg Field in Colorado, central and southern Wyoming,
the Piceance and Uinta Basins in the Western Slope of Colorado and Utah, the
Giddings area in South Texas, the Spraberry Trend in West Texas, waterflood
units in Texas, and the Appalachian Basin in eastern Ohio and Pennsylvania.
At December 31, 1993, the Company had interests in 5,122 gross (2,187 net)
producing oil and gas wells located in 15 states and in the Gulf of Mexico. As
of December 31, 1993, estimated proved reserves totalled 31.9 million barrels of
oil and 430.1 Bcf of gas. In addition to its oil and gas reserves, the Company
holds interests in nine gas transportation and processing facilities. See
"-- Gas Management."
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Significant Properties. Although the Company's properties are widely
dispersed geographically, emphasis has been placed on establishing hubs in
certain producing basins. Interests in five producing areas accounted for
approximately 90% of Pretax PW10% Value at December 31, 1993. This concentration
of assets results in economic efficiencies in the management of assets and
permits identification of complementary acquisition candidates. Summary
information regarding the five most significant properties is set forth below.
PROVED RESERVE
QUANTITIES PRETAX PW10% VALUE
------------------------ ------------------------
CRUDE OIL NATURAL
AND LIQUIDS GAS AMOUNT PERCENT
----------- -------- -------------- -------
(MBBL) (MMCF) (IN THOUSANDS)
DJ Basin (CO, NE).......................... 16,984 242,155 $245,617 62.9%
East Washakie (WYO)........................ 1,334 72,871 41,903 10.7
Central Wyoming (WYO)...................... 7,207 28,913 30,905 7.9
Western Slope (CO & UT).................... 439 41,070 22,113 5.7
Giddings Field (TX)........................ 752 7,987 10,960 2.8
----------- -------- -------------- -------
Subtotal......................... 26,716 392,996 351,498 90.0
Other...................................... 5,214 37,093 38,911 10.0
----------- -------- -------------- -------
Total............................ 31,930 430,089 $390,409 100.0%
----------- -------- -------------- -------
----------- -------- -------------- -------
Proved Reserves. The following table sets forth estimated yearend proved
reserves for the three years ended December 31, 1993.
DECEMBER 31,
-------------------------------
1991 1992 1993
------- ------- -------
Crude oil and liquids (MBbl)
Developed........................................... 9,094 21,116 18,032
Undeveloped......................................... 10,584 11,086 13,898
------- ------- -------
Total....................................... 19,678 32,202 31,930
------- ------- -------
------- ------- -------
Natural gas (MMcf)
Developed........................................... 136,229 194,621 268,349
Undeveloped......................................... 110,940 93,037 161,740
------- ------- -------
Total....................................... 247,169 287,658 430,089
------- ------- -------
------- ------- -------
Total MBOE (a).............................. 66,641 84,393 103,612
------- ------- -------
------- ------- -------
- ---------------
(a) Natural gas reserves are converted to oil equivalents at the rate of 6 Mcf
per barrel, except Thomasville gas reserves prior to 1993. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations."
The following table sets forth pretax future net revenues from the
production of proved reserves and the Pretax PW10% Value of such revenues.
DECEMBER 31, 1993
-----------------------------------------
DEVELOPED UNDEVELOPED(A) TOTAL
--------- -------------- --------
(IN THOUSANDS)
1994............................................ $ 81,401 $(24,109) $ 57,292
1995............................................ 59,421 1,220 60,641
1996............................................ 47,148 8,472 55,620
Remainder....................................... 286,510 228,209 514,719
--------- -------------- --------
Total................................. $ 474,480 $213,792 $688,272
--------- -------------- --------
--------- -------------- --------
Pretax PW10% Value.............................. $ 297,638 $ 92,771 $390,409(b)
--------- -------------- --------
--------- -------------- --------
- ---------------
(a) Net of estimated capital costs, including estimated costs of $68.9 million
during 1994.
(b) The after tax PW10% value of proved reserves totalled $340.5 million at
yearend 1993.
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The quantities and values in the preceding tables are based on prices in
effect at December 31, 1993, averaging $11.49 per barrel of oil and $2.11 per
Mcf of gas. Price reductions decrease reserve values by lowering the future net
revenues attributable to the reserves and will reduce the quantities of reserves
that are recoverable on an economic basis. Price increases have the opposite
effect. Any significant decline in prices of oil or gas could have a material
adverse effect on the Company's financial condition and results of operations.
Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are proved reserves that are expected to be
recovered from new wells drilled to known reservoirs on undrilled acreage for
which the existence and recoverability of such reserves can be estimated with
reasonable certainty, or from existing wells where a relatively major
expenditure is required to establish production.
Future prices received for production and future production costs may vary,
perhaps significantly, from the prices and costs assumed for purposes of these
estimates. There can be no assurance that the proved reserves will be developed
within the periods indicated or that prices and costs will remain constant. With
respect to certain properties that historically have experienced seasonal
curtailment, the reserve estimates assume that the seasonal pattern of such
curtailment will continue in the future. There can be no assurance that actual
production will equal the estimated amounts used in the preparation of reserve
projections.
The present values shown should not be construed as the current market
value of the reserves. The 10% discount factor used to calculate present value,
which is specified by the Securities and Exchange Commission ("SEC"), is not
necessarily the most appropriate discount rate, and present value, no matter
what discount rate is used, is materially affected by assumptions as to timing
of future production, which may prove to be inaccurate. For properties operated
by the Company, expenses exclude the Company's share of overhead charges. In
addition, the calculation of estimated future net revenues does not take into
account the effect of various cash outlays, including, among other things,
general and administrative costs and interest expense.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and timing of
development expenditures. The data in the above tables represent estimates only.
Oil and gas reserve engineering must be recognized as a subjective process of
estimating underground accumulations of oil and gas that cannot be measured in
an exact way, and estimates of other engineers might differ materially from
those shown above. The accuracy of any reserve estimate is a function of the
quality of available data and engineering and geological interpretation and
judgment. Results of drilling, testing and production after the date of the
estimate may justify revisions. Accordingly, reserve estimates are often
materially different from the quantities of oil and gas that are ultimately
recovered.
Netherland, Sewell & Associates, Inc. ("NSAI"), independent petroleum
consultants, prepared estimates of or audited the Company's proved reserves
which collectively represent more than 80% of Pretax PW10% Value as of December
31, 1993. Approximately 38% of the yearend Pretax PW10% Value was estimated
internally by the Company and 62% was estimated independently by NSAI. No
estimates of the Company's reserves comparable to those included herein have
been included in reports to any federal agency other than the SEC.
Producing Wells. The following table sets forth certain information at
December 31, 1993 relating to the producing wells in which the Company owned a
working interest. The Company also held royalty interests in 240 producing
wells. Wells are classified as oil or gas wells according to their predominant
production stream.
AVERAGE
PRINCIPAL GROSS NET WORKING
PRODUCT STREAM WELLS WELLS INTEREST
----------------------------------------------------- ----- ----- -------
Crude oil and liquids................................ 3,026 1,297 43%
Natural gas.......................................... 2,096 890 42%
----- ----- -------
Total...................................... 5,122 2,187 43%
----- ----- -------
----- ----- -------
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CUSTOMERS AND MARKETING
The Company's oil and gas production is principally sold to refiners and
others having pipeline facilities near its properties. Where there is no access
to gathering systems, crude oil is trucked to storage facilities. In 1992 and
1993, Amoco accounted for approximately 27% and 12% of revenues, respectively,
as the result of the contractual dedication, which terminated at the end of
1993, of a portion of the Company's natural gas and natural gas liquids produced
from certain of its Wattenberg acreage. Historically, this arrangement provided
for average prices in excess of spot due to participation in certain fixed price
contracts, many of which are expected to expire over the next two years. The
Company exercised its option to release its natural gas and natural gas liquids
and began marketing its production beginning January 1, 1994. The Company
believes, however, that it can obtain pricing comparable to that which would
have been obtainable through Amoco. The marketing of oil and gas by the Company
can be affected by a number of factors that are beyond its control and whose
future effect cannot be accurately predicted. The Company does not believe,
however, that the loss of any of its customers would have a material adverse
effect on its operations.
In addition to marketing a significant portion of its own gas, in 1992 the
Company initiated an effort to supplement its cash flow through the purchase and
resale of gas owned by third parties. Gross margins during 1992 and 1993 from
third party marketing activities was $.6 million and $1.2 million, respectively,
as average third party volumes increased from 58.7 to 89.9 MMcf per day. The
Company expects to continue increasing its role in third party gas marketing.
In June 1991, the Company entered into a contract to supply gas to a
cogeneration facility through August 2004. The contract calls for the Company to
supply 10,000 MMBtu per day. This plant, which requires up to 24,500 MMBtu per
day of gas, began operations in 1989 and is located at a manufacturing facility
in Oklahoma City. The facility has firm fifteen-year sales agreements with a
utility company for electricity and with a tire manufacturer for steam. The
effect of this contract depends on market prices for gas and its choice of
alternative sources of gas (including the spot market) to meet its supply
commitments. Gross margin generated from the contract was approximately $1.5
million for both 1991 and 1992. A contractual limitation of the contract sales
price and rising gas purchase costs resulted in a net loss of $267,000 on the
contract during 1993. At present gas price levels, the Company foresees
continued negative or breakeven margins for this contract through July 1994. At
that time, a change in the pricing formula should result in improved margins.
DESCRIPTION OF SIRENS
The SIRENs are to be issued under an Indenture to be dated as of April 1,
1994 (the "Indenture"), between the Company, as issuer, and Texas Commerce Bank
National Association, as trustee (the "Trustee"), a copy of which is filed as an
exhibit to the Registration Statement of which this Prospectus is a part. The
terms of the Indenture are governed by certain provisions contained in the Trust
Indenture Act of 1939, as amended. The following summaries of certain provisions
of the Indenture do not purport to be complete, and where particular provisions
of the Indenture are referred to, such provisions, including definitions of
certain terms capitalized in this Prospectus, are incorporated by reference as a
part of such summaries, which are qualified in their entirety by reference to
the provisions of the Indenture. The section ("Section") and article ("Article")
references appearing below are to sections and articles of the Indenture.
GENERAL
The SIRENs will be unsecured subordinated obligations of the Company, will
mature on March 31, 2001, and will be in the aggregate principal amount of
$100,000,000 ($115,000,000 aggregate principal amount if the Underwriters'
over-allotment option is exercised in full). The SIRENs will bear interest at
the rate of percent per annum from the date of issuance to and including
March 31, 1997 and will bear interest at the rate of percent per annum from
and including April 1, 1997 to maturity or earlier redemption. Interest will be
payable semi-annually on March 31 and September 30 of each year, commencing
September 30, 1994, to the persons in whose names such SIRENs (or any
predecessor SIRENs) are registered at the close of business on the March 15 or
September 15 preceding such Interest Payment Date
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(Sections 301 and 307). The SIRENs will be treated for tax purposes as being
issued with original issue discount. See "Certain Federal Income Tax
Considerations -- Original Issue Discount."
The Indenture does not limit the incurrence of additional indebtedness,
including Senior Indebtedness, by the Company.
FORM, DENOMINATION AND REGISTRATION
The statements set forth herein under "Form, Denomination and Registration"
and "Definitive Form of SIRENs" include summaries of certain rules and operating
procedures of The Depository Trust Company ("DTC") which affect transfers of
interests in the Global Note (as hereinafter defined).
Although DTC has agreed to the procedures described below in order to
facilitate transfers of SIRENs among participants of DTC, DTC is under no
obligation to perform or continue to perform such procedures and such procedures
may be discontinued at any time. Neither the Company nor the Security Registrar
or the Trustee will have any responsibility for the performance by DTC
participants or indirect participants of their respective obligations under the
rules and procedures governing their operations.
The SIRENs will be issued in the form of one or more global securities
(collectively, the "Global Note") registered in the name of Cede & Co. ("Cede"),
as nominee of DTC. The Global Note will be held by the Security Registrar, as
custodian for DTC. The SIRENs will be issued only in fully registered form,
without coupons, in denominations of $1,000 and any integral multiple thereof
(Section 302).
Except as set forth below, the Global Note may be transferred, in whole or
in part, only to another nominee of DTC or to a successor of DTC or its nominee.
Beneficial interests in the Global Note will be represented through
accounts of financial institutions acting on behalf of beneficial owners as
direct and indirect participants in DTC. Investors may hold SIRENs directly
through DTC if they are participants in DTC or indirectly through organizations
that are participants in DTC.
DTC may grant proxies or otherwise authorize DTC participants (or persons
holding beneficial interests in the SIRENs through such DTC participants) to
exercise any rights of a holder or take any other actions a holder is entitled
to take under the Indenture. Under its usual procedures, DTC will mail an
omnibus proxy to the Company assigning Cede's consenting or voting rights to
those DTC participants to whose accounts the SIRENs are credited on a record
date as soon as possible after such record date.
Persons who are not DTC participants may beneficially own SIRENs held by
DTC only through direct or indirect participants in DTC. So long as Cede, as the
nominee of DTC, is the registered owner of the Global Note, Cede for all
purposes will be considered the sole holder of the SIRENs under the Indenture.
Except as provided below under "Definitive Form of SIRENs," holders of
beneficial interests in the Global Note will not be entitled to have SIRENs
registered in their names, will not receive or be entitled to receive physical
delivery of SIRENs in definitive form, and will not be considered the holders
thereof under the Indenture.
Because DTC can only act on behalf of DTC participants, who in turn act on
behalf of indirect DTC participants and certain banks, the ability of a holder
of a beneficial interest in the Global Note to pledge such interest to persons
or entities that do not participate in the DTC system, or otherwise take actions
in respect of such interest, may be limited by the lack of a physical
certificate for such interest.
DTC is a limited purpose trust company organized under the laws of the
State of New York, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the Uniform Commercial Code and a "clearing
agency" registered pursuant to the provisions of Section 17A of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"). DTC was created to hold
securities for its participants and facilitate the clearance and settlement of
securities transactions between participants through electronic book-entry
changes in accounts of its participants, thereby eliminating the need for
physical movement of certificates. DTC participants include securities brokers
and dealers, banks, trust companies and clearing corporations and may include
certain other organizations such as the Underwriters. Indirect access to the
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DTC system also is available to indirect DTC participants such as banks,
brokers, dealers and trust companies that clear through or maintain a custodial
relationship with a DTC participant, either directly or indirectly.
PAYMENT
Payment of principal of and interest on the Global Note will be made to
Cede, the nominee for DTC, as the registered owner. The principal of and
interest on the SIRENs will be payable in U.S. dollars or in such other coin or
currency of the United States of America as at the time of payment is legal
tender for the payment of public and private debts.
Upon receipt of any payment of interest on the Global Note, DTC shall
immediately credit DTC participants' accounts with payments in amounts
proportionate to their respective beneficial interests in the principal amounts
of the Global Note as shown on the records of DTC. Payments by DTC participants
to owners of beneficial interests in the Global Note held through such
participants will be the responsibility of such participants, as is now the case
with securities held for the accounts of customers registered in "street name."
Neither the Company nor the Security Registrar or the Trustee will have any
responsibility or liability for any aspect of the records relating to or
payments made on account of beneficial ownership interests in the Global Note or
for maintaining, supervising or reviewing any records relating to such
beneficial ownership interests.
DEFINITIVE FORM OF SIRENS
If DTC is at any time unwilling or unable to continue as depositary and a
successor depositary is not appointed by the Company within 90 days, the Company
will issue SIRENs in definitive form in exchange for the Global Note (Section
305).
CONVERSION RIGHTS
The SIRENs will be convertible, in whole or from time to time in part (in
denominations of $1,000 or integral multiples thereof), at the option of the
holder thereof, into Common Stock of the Company, initially at the conversion
price stated on the cover page hereof, at any time prior to maturity, unless
previously redeemed by the Company. In the case of SIRENs called for redemption,
conversion rights will terminate at the close of business on the fifth business
day preceding the Redemption Date. Notwithstanding anything to the contrary in
the foregoing, the SIRENs will not be convertible at any time when payments on
the SIRENs are prohibited under the subordination provisions of the Indenture as
described under "-- Subordination of SIRENs" (Section 1201).
The SIRENs may be presented for conversion at the office or agency
maintained by the Company for such purpose, which will initially be the office
of the Trustee located at 80 Broad Street, Fourth Floor, New York, New York
10004 (Section 1202).
If the Company, by dividend or otherwise, declares or makes a distribution
on its Common Stock of the type referred to in clause (iv) or (v) below, the
holder of each SIREN, upon the conversion thereof subsequent to the close of
business on the date fixed for the determination of stockholders entitled to
receive such distribution and prior to the effectiveness of the conversion price
adjustment in respect of such distribution pursuant to clause (iv) or (v) below,
will be entitled to receive for each share of Common Stock into which such SIREN
is converted the portion of the evidences of indebtedness, shares of capital
stock, cash and other assets so distributed applicable to one share of Common
Stock; provided, however, that the Company may, with respect to all holders so
converting, in lieu of distributing any portion of such distribution not
consisting of cash or securities of the Company, pay such holder cash in an
amount equal to the fair market value thereof, as determined in good faith by
the Board of Directors (Section 1201).
The conversion price will be subject to adjustment in certain events
including: (i) dividends (and other distributions) payable in Common Stock on
any class of capital stock of the Company; (ii) the issuance to all holders of
Common Stock of rights, warrants or options entitling them to subscribe for or
purchase Common Stock at less than the current market price (as provided in the
Indenture); provided, however, that if such
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rights, warrants or options are only exercisable upon the occurrence of certain
triggering events, then the conversion price will not be adjusted until such
triggering events occur; (iii) subdivisions and combinations of Common Stock;
(iv) distributions to all holders of Common Stock of evidences of indebtedness
of the Company, shares of any class of capital stock, cash or other assets
(including securities, but excluding those dividends, rights, warrants, options
and distributions referred to in clauses (i) and (ii) above and excluding
dividends and distributions exclusively paid in cash up to the greater of (x)
retained earnings of the Company on the date such distribution or dividend was
declared or (y) Net Income (as defined below) of the Company during the four
full fiscal quarters preceding the date such distribution or dividend was
declared, and other than in connection with a tender offer or other negotiated
purchase made by the Company or any Subsidiary for all or a portion of the
Common Stock); provided, however, that if any rights, warrants or options in
respect of which an adjustment is provided for in this clause (iv) are only
exercisable upon the occurrence of certain triggering events, then the
conversion price will not be adjusted until such triggering events occur; (v)
distributions consisting exclusively of cash (specifically including
distributions paid in cash up to the greater of (x) retained earnings of the
Company on the date such distribution or dividend was declared or (y) Net Income
of the Company during the four full fiscal quarters preceding the date such
distribution or dividend was declared, but excluding any cash distributions for
which an adjustment has been made pursuant to a preceding clause of this
paragraph) to all holders of Common Stock in an aggregate amount that, together
with (A) other all-cash distributions made within the preceding 12 months not
triggering a conversion price adjustment and (B) all Excess Tender Payments (as
defined below) in respect of each tender or exchange offer by the Company or any
Subsidiary for Common Stock concluded within the preceding 12 months not
triggering a conversion price adjustment, exceeds an amount equal to 20% of the
Company's deemed market capitalization on the date fixed for the determination
of stockholders entitled to receive such distribution (calculated as set forth
in the Indenture); (vi) issuances of Common Stock to an Affiliate for a net
consideration per share less than the current market price per share (other than
issuances of Common Stock under certain management benefit plans); and (vii)
payment of an Excess Tender Payment in respect of a tender or exchange offer by
the Company or any Subsidiary for Common Stock, if the aggregate amount of such
Excess Tender Payment, together with (A) the aggregate amount of any all-cash
distributions made within the preceding 12 months not triggering a conversion
price adjustment and (B) all Excess Tender Payments in respect of each tender or
exchange offer by the Company or any Subsidiary for Common Stock concluded
within the preceding 12 months not triggering a conversion price adjustment,
exceeds an amount equal to 20% of the Company's deemed market capitalization on
the expiration of such tender offer (calculated as set forth in the Indenture)
(Section 1204). For purposes of these conversion price adjustments, the term (i)
"Excess Tender Payment" means the excess of (A) the aggregate of the cash and
value of other consideration paid by the Company with respect to the shares
acquired in the tender or exchange transaction over (B) the market value of such
acquired shares after the completion of the tender or exchange offer (calculated
as set forth in the Indenture) and (ii) "Net Income" of any Person means the net
income of such Person net of non-cash charges taken as a result of accounting
changes required to be made by the Financial Accounting Standards Board after
the date of the Indenture.
No adjustments in the conversion price are required for any dividend or
distribution referred to above if the holders may participate in the dividend or
distribution (on a basis determined in good faith to be fair by the Board of
Directors) and receive the same consideration they would have received if they
had converted the SIRENs (Section 1213).
No adjustment of the conversion price will be required to be made until
cumulative adjustments amount to 1% or more of the conversion price as last
adjusted. In addition to the foregoing adjustments, the Company will be
permitted to make such reductions in the conversion price as it considers to be
advisable in order that any event treated for federal income tax purposes as a
dividend of stock or stock rights will not be taxable to the holders of the
Common Stock (Section 1204).
Subject to any applicable right of the holders to receive the Change of
Control Purchase Price (as described below), in the case of certain
consolidations or mergers to which the Company is a party or the transfer or
lease of the Company's properties or assets substantially as an entirety, each
holder has the right to convert each SIREN only into the kind and amount of
securities, cash and other property receivable upon the
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consolidation, merger, transfer or lease by a holder of the number of shares of
Common Stock into which such SIREN might have been converted immediately prior
to such consolidation, merger, transfer or lease (assuming such holder of Common
Stock is not a Constituent Person and such holder failed to exercise any rights
of election and received per share the kind and amount of consideration received
per share by a plurality of non-electing shares) (Section 1211).
Fractional shares of Common Stock will not be issued upon conversion, but,
in lieu thereof, the Company will pay a cash adjustment based upon the market
price of a share of Common Stock (Section 1203). Except as provided below, no
adjustment will be made upon a conversion of SIRENs for interest accrued
thereon. The Company's delivery to the holder of the fixed number of shares of
Common Stock into which the SIREN is convertible will be deemed to satisfy the
Company's obligation to pay the principal amount of the SIREN and all accrued
interest and original issue discount that has not previously been paid. The
Common Stock is treated as issued first in payment of accrued interest and
original issue discount and then in payment of principal. Thus accrued interest
and original issue discount, if any, will be treated as paid rather than
canceled, extinguished or forfeited. If a SIREN is surrendered for conversion
during the period from the close of business on any Regular Record Date next
preceding any Interest Payment Date to the close of business on any Interest
Payment Date, then notwithstanding such conversion, interest payable in respect
of the SIREN so surrendered will be paid in cash to the person in whose name
such SIREN is registered at the close of business on such Regular Record Date,
and (except in the case of SIRENs with a Maturity Date prior to such Interest
Payment Date) when so surrendered for conversion, such SIREN must be accompanied
by payment of a amount equal to the interest thereon which the registered holder
as of the close of business on such Regular Record Date is to receive (Sections
307 and 1202).
SUBORDINATION OF SIRENS
The payment of the principal of and premium, if any, and interest on the
SIRENs is, to the extent set forth in the Indenture, subordinated in right of
payment to the prior payment in full of all Senior Indebtedness, whether now
outstanding or incurred in the future (Section 1301). Upon any payment or
distribution of assets of the Company to creditors upon any liquidation,
dissolution, winding up, assignment for the benefit of creditors or marshalling
of assets and liabilities or any bankruptcy, insolvency, receivership,
liquidation, reorganization or similar proceedings of the Company, the holders
of all Senior Indebtedness will first be entitled to receive payment in full of
all amounts due or to become due thereon before the holders of the SIRENs will
be entitled to receive any payment (other than any payment in the form of
Permitted Junior Securities) on account of the principal of or premium, if any,
or interest on the SIRENs, including payment of the Redemption Price and the
Change of Control Purchase Price of the SIRENs, and before the SIRENs may be
converted into Common Stock (Section 1302).
No payment (other than any payment in the form of Permitted Junior
Securities) on account of principal of and premium, if any, or interest on the
SIRENs, including payment of the Redemption Price and the Change of Control
Purchase Price on the SIRENs, may be made, and the SIRENs may not be converted
into Common Stock, if a Payment Event of Default shall have occurred and be
continuing. In addition, no payment (other than any payment in the form of
Permitted Junior Securities) on account of principal of or premium, if any, or
interest on the SIRENs, including payment of the Redemption Price and the Change
of Control Purchase Price on the SIRENs, may be made, and the SIRENs may not be
converted into Common Stock, if a Non-payment Event of Default shall have
occurred and be continuing, for the period (a "Payment Blockage Period")
commencing on receipt of notice of such event of default by the Trustee from a
holder of any Designated Senior Indebtedness (or any trustee or other
representative therefor) and ending on the earlier of (i) the date such
Non-payment Event of Default has been cured or waived or has ceased to exist or
any acceleration of such Designated Senior Indebtedness has been rescinded or
annulled or such Designated Senior Indebtedness shall have been discharged and
(ii) the date 176 days after such receipt of notice. Any number of such notices
may be given; provided, however, that, during any 360-day period, the aggregate
Payment Blockage Periods shall not exceed 176 days and there shall be a period
of at least 184 consecutive days when no Payment Blockage Period is in effect.
No default existing or continuing when a Payment Blockage Period begins may be
the basis for any subsequent Payment Blockage Period unless such default has
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been cured for a period of at least 90 consecutive days. In the event that,
notwithstanding the restrictions described in the preceding sentences, the
Company makes any payment to the Trustee or a holder of SIRENs prohibited by any
such restriction, with such Trustee or holder, as the case may be, knowing of
such contravention before receipt thereof, then such payment will be required to
be paid over and delivered forthwith to the Company to the extent necessary to
pay in full all such Senior Indebtedness (Section 1303).
The subordination rights of holders of Senior Indebtedness will not be
prejudiced or impaired by any acts or failures to act by the Company or by any
such holder (Section 1308). The subordination of the SIRENs set forth above will
not prevent the occurrence of any Event of Default under the Indenture.
Furthermore, the subordination of the SIRENs as set forth above will not impair,
as between the Company, the holders of the SIRENs and creditors of the Company
other than holders of Senior Indebtedness, the obligations of the Company to
make payments on the SIRENs in accordance with their terms. In certain
circumstances, as set forth in the Indenture, the holders of SIRENs will be
subrogated to certain rights of the holders of Senior Indebtedness upon payment
in full of all Senior Indebtedness (Section 1302).
By reason of such subordination, in the event of insolvency of the Company,
the holders of Senior Indebtedness (as well as other creditors of the Company
who are holders of indebtedness that is not subordinated to the Senior
Indebtedness) may recover more, ratably, than the holders of the SIRENs.
The SIRENs will also be effectively subordinated to all liabilities,
including trade payables and capitalized lease obligations, if any, of the
Company's subsidiaries. Any right of the Company to receive the assets of any of
its subsidiaries upon their liquidation or reorganization (and the consequent
right of the holders of the SIRENs to participate in those assets) will be
subject to the prior payment of claims of that subsidiary's creditors (including
trade creditors), except to the extent that the Company is itself a creditor of
such subsidiary, in which case the claims of the Company would still be subject
to the prior payment of claims secured by security interests in the assets of
such subsidiary and any other indebtedness of such subsidiary senior to that
held by the Company.
Immediately following the sale of the SIRENs offered hereby and application
of the proceeds therefrom, the sum of the Company's Senior Indebtedness and the
indebtedness of the Company's subsidiaries will total approximately $34 million.
There are no restrictions in the Indenture on the creation of Senior
Indebtedness (or any other indebtedness). The agreements under which Senior
Indebtedness may be outstanding in the future could contain provisions which may
require repayment of such respective Senior Indebtedness prior to repayment of
the SIRENs upon, among other things, a Change of Control. If the Company is
unable to obtain the requisite consents under its Senior Indebtedness to enable
it to repurchase the SIRENs or is unable to repay all Senior Indebtedness, there
would be both an Event of Default under the SIRENs and an event of default under
such Senior Indebtedness, as a result of which events the Company would be
prohibited by the subordination terms of the Indenture from repurchasing SIRENs
or making other payments in respect thereof. Furthermore, the exercise by the
holders of their right to require the Company to repurchase the SIRENs could
cause a default under the Designated Senior Indebtedness of the Company, even if
the Change of Control itself does not, due to the financial effect of such
repurchase on the Company. As a result, the repurchase of the SIRENs could be
blocked pursuant to the subordination terms of the Indenture. Finally, the
Company's ability to pay cash to the holders of SIRENs upon a repurchase may be
limited by the Company's then existing financial resources. Failure of the
Company to pay the Change of Control Purchase Price will create an Event of
Default with respect to the SIRENs, whether or not such repurchase is permitted
by the subordination terms of the Indenture. See " -- Repurchase of SIRENs at
the Option of the Holder Upon a Change of Control."
"Bank Credit Facility" means the Company's existing bank credit facility
and any renewals, amendments, extensions, supplements, modifications,
refinancings or replacements thereof (Section 101).
"Designated Senior Indebtedness" means (i) all Senior Indebtedness under
the Bank Credit Facility if the sum of the amounts outstanding under the Bank
Credit Facility and the amounts available for borrowing thereunder is equal to
or greater than $25,000,000 and (ii) all other Senior Indebtedness having an
outstanding principal amount equal to or greater than $25,000,000 (provided,
however, that the agreements, indentures or other instruments evidencing any
Senior Indebtedness referred to in this clause (ii) specifically
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state that such Senior Indebtedness shall be classified as "Designated Senior
Indebtedness" for purposes of the Indenture) (Section 101).
"Indebtedness" of any Person means, without duplication, (i) every
obligation of such Person for money borrowed; (ii) every obligation of such
Person evidenced by bonds, debentures, notes or similar instruments, including
obligations incurred in connection with the acquisition of property, assets or
businesses; (iii) every obligation of such Person under conditional sale or
other title retention agreements relating to assets or property purchased by
such Person or issued or assumed as the deferred purchase price of property,
assets or services (but excluding trade accounts payable or accrued liabilities
arising in the ordinary course of business that are not overdue by more than 90
days or are being contested by such Person in good faith); (iv) every Capital
Lease Obligation of such Person; (v) every obligation of such Person with
respect to any Sale and Leaseback Transaction to which such Person is a party;
(vi) every obligation of such Person with respect to letters of credit, bankers
acceptances or similar facilities issued for the account of such Person; (vii)
the maximum fixed redemption or repurchase price of outstanding Redeemable Stock
of such Person; (viii) every obligation of such Person with respect to
performance, surety or similar bonds; (ix) every obligation of such Person under
interest rate, commodity or foreign currency swap, cap, hedge, exchange or
similar agreements; (x) every obligation of the type referred to in clauses (i)
through (ix) and clause (xi) of another Person the payment of which such Person
has Guaranteed or is otherwise responsible for or liable for, directly or
indirectly, as obligor, Guarantor or otherwise; and (xi) every amendment,
modification, renewal and extension of an obligation of the type referred to in
clauses (i) through (x) (Section 101).
"Non-payment Event of Default" means any event (other than a Payment Event
of Default) the occurrence of which entitles any one or more persons to
accelerate the maturity of any Designated Senior Indebtedness (Section 101).
"Payment Event of Default" means any default in the payment of principal of
or premium, if any, or interest on any Designated Senior Indebtedness when due
(whether at maturity, upon acceleration or otherwise) (Section 101).
"Permitted Junior Securities" means subordinated debt securities of the
Company or any successor obligor with respect to the Senior Indebtedness
provided for by a plan of reorganization or readjustment that are subordinated
in right of payment to all Senior Indebtedness that may be outstanding to
substantially the same extent as, or to a greater extent than, the SIRENs are
subordinated as provided in the Indenture (Section 101).
"Senior Indebtedness" means all obligations of the Company for Indebtedness
(other than Indebtedness described in clause (vii) of the definition of
Indebtedness), whether now existing or hereafter incurred or assumed; provided
that, Senior Indebtedness shall not include (A) any obligation owed to a
Subsidiary or an Affiliate or Related Person of the Company, (B) any obligation
that by its terms is not superior in right of payment to the SIRENs, (C) any
obligation in respect of the Company's 8% Convertible Subordinated Debentures
and 6% Convertible Subordinated Debentures, if and when issued, for which the
Company's existing preferred stock is exchangeable (the SIRENs not being senior
in right of payment to such debentures) or (D) any obligation constituting a
trade account payable (Section 101).
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REDEMPTION
The SIRENs will be redeemable, at the Company's option, as a whole or from
time to time in part, at any time on or after March 31, 1997, upon not less than
20 nor more than 60 days notice mailed to the registered holders thereof, at the
redemption prices (expressed as a percentage of the principal amount thereof)
set forth below if redeemed during the 12-month period beginning March 31 of the
years indicated:
YEAR PERCENTAGE
----- ----------
1997.............................................. %
1998.............................................. %
1999.............................................. %
2000.............................................. %
2001.............................................. %
together, in each case, with accrued interest to the Redemption Date (subject to
the right of holders of record on the relevant record date to receive interest
due on an Interest Payment Date that is on or prior to the Redemption Date)
(Sections 203, 1101, and 1107).
If less than all the SIRENs are to be redeemed, the SIRENs to be redeemed
shall be selected by the Trustee in such manner as the Trustee shall deem
appropriate and fair (Section 1104).
The Company's existing bank credit facility prohibits the Company from
redeeming any SIRENs unless (i) such redemption is permitted under the
restricted payment covenant contained in such bank credit facility and (ii) at
the time of such redemption and after giving effect thereto, no default shall
have occurred under such bank credit facility.
REPURCHASE OF SIRENS AT THE OPTION OF THE HOLDER UPON A CHANGE OF CONTROL
In the event of any Change of Control (as defined below) with respect to
the Company which constitutes a Repurchase Event (as defined below), each holder
of SIRENs will have the right, at such holder's option, subject to the terms and
conditions of the Indenture, to require the Company to repurchase all or any
part (provided that the principal amount must be $1,000 or an integral multiple
thereof) of the holder's SIRENs on the date (the "Change of Control Purchase
Date") that is 60 days after the date the Company's Change of Control Notice (as
defined below) is mailed (or such later date as is required by law), at a cash
price equal to 100% of the principal amount plus accrued interest to the Change
of Control Purchase Date (the "Change of Control Purchase Price"). The Change of
Control Purchase Price may be less than the fair market value of the SIRENs on
the Change of Control Purchase Date. Promptly, but in any event within 29 days
following any Change of Control, the Company is required, with respect to any
Senior Indebtedness that would prohibit the repurchase of SIRENs by the Company
in the event of such Change of Control, either to repay all such Senior
Indebtedness in full or obtain the requisite consents under such Senior
Indebtedness to permit the repurchase of the SIRENs as provided below. The
Company first is required to comply with the covenants in the preceding sentence
before it is required to repurchase SIRENs pursuant to a Change of Control. The
foregoing will in no way limit the occurrence of an Event of Default, including
an Event of Default arising from a default under the covenants of the second
sentence of this paragraph (Section 1401 and 1402).
Within 29 days after a Change of Control which constitutes a Repurchase
Event, the Company is obligated to mail to the Trustee and to all holders of
SIRENs at their addresses shown in the register of the Security Registrar (and
to beneficial owners as required by applicable law) a notice (the "Change of
Control Notice") regarding the Change of Control. The Change of Control Notice
will describe: (i) the events causing the Change of Control; (ii) the Change of
Control Purchase Price; (iii) the Change of Control Purchase Date; (iv)
information regarding the conversion rights of the SIRENs; and (v) the
procedures for withdrawing a Change of Control Purchase Notice. The Change of
Control Notice will also state whether or not the Company has satisfied its
obligations regarding Senior Indebtedness referred to in the preceding paragraph
(Section 1401).
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To exercise the right to have SIRENs repurchased following a Change of
Control, a holder must deliver a Change of Control Purchase Notice to the Paying
Agent at its office maintained for such purpose, prior to the close of business
on the Change of Control Purchase Date. The Change of Control Purchase Notice
shall state: (i) the certificate numbers of the SIRENs to be delivered by the
holder thereof for purchase by the Company; (ii) the portion of the principal
amount of SIRENs to be repurchased, which portion must be $1,000 or an integral
multiple thereof; and (iii) that such SIRENs are to be repurchased by the
Company pursuant to the applicable provision of the Indenture (Section 1401). A
holder of record of SIRENs shall be entitled to deliver a Change of Control
Purchase Notice with respect to any or all SIRENs held by it; provided, however,
that such holder may be required to provide evidence satisfactory to the Company
that, with respect to each beneficial holder of the SIRENs to be delivered to
the Company, such beneficial holder is exercising the right to require the
repurchase of all of the SIRENs in which it has a beneficial interest.
Any Change of Control Purchase Notice may be withdrawn by the holder by a
written notice of withdrawal delivered to the Paying Agent prior to the close of
business on the Change of Control Purchase Date. The notice of withdrawal shall
state the principal amount and the certificate numbers of the SIRENs as to which
the withdrawal notice relates and the principal amount, if any, which remains
subject to a Change of Control Purchase Notice (Sections 1401 and 1402).
Payment of the Change of Control Purchase Price for SIRENs for which a
Change of Control Purchase Notice has been delivered and not withdrawn is
conditioned upon delivery of such SIRENs (together with necessary endorsements)
to the Paying Agent at its office maintained for such purpose, at any time
(whether prior to, on, or after the Change of Control Purchase Date) after the
delivery of such Change of Control Purchase Notice. Payment of the Change of
Control Purchase Price for such SIRENs will be made promptly following the later
of the Change of Control Purchase Date and the time of delivery of such SIRENs
(Sections 1401 and 1402).
"Change of Control" shall occur when: (i) all or substantially all of the
Company's assets are sold as an entirety to any person or related group of
persons; (ii) there shall be consummated any consolidation or merger of the
Company (A) in which the Company is not the continuing or surviving corporation
(other than a consolidation or merger with a wholly-owned subsidiary of the
Company in which all shares of Common Stock outstanding immediately prior to the
effectiveness thereof are changed into or exchanged for the same consideration)
or (B) pursuant to which the Common Stock would be converted into cash,
securities or other property, in each case, other than a consolidation or merger
of the Company in which the holders of the Common Stock immediately prior to the
consolidation or merger have, directly or indirectly, at least a majority of the
Common Stock of the continuing or surviving corporation immediately after such
consolidation or merger; or (iii) any person or any persons acting together
which would constitute a "group" for purposes of Section 13(d) of the Exchange
Act (other than the Company, any Subsidiary, any employee stock purchase plan,
stock option plan or other stock incentive plan or program, retirement plan or
automatic dividend reinvestment plan or any substantially similar plan of the
Company or any Subsidiary or any person holding securities of the Company for or
pursuant to the terms of any such employee benefit plan), together with any
affiliates thereof, shall Beneficially Own, directly or indirectly, at least 50%
of the total Voting Stock of the Company (Section 1401). As noted above, one of
the events that constitutes a Change of Control is a sale of all or
substantially all of the assets of the Company as an entirety to any person or
related group of persons. The Indenture will be governed by New York law, and
there is no established quantitative definition under New York law of
"substantially all" of the assets of a corporation. This uncertainty may make it
more difficult for a holder of SIRENs to determine whether a Change of Control
has occurred in the event that the Company were to engage in a transaction in
which it sold less than all of its assets.
A Change of Control as described above shall constitute a Repurchase Event
unless (i) the closing price per share of the Common Stock on the five
consecutive Trading Days selected by the Company out of the 10 consecutive
Trading Days ending immediately after the later of the Change of Control or the
public announcement of the Change of Control (in the case of a Change of Control
under clauses (i) or (ii) of the definition of Change of Control) or ending
immediately before the Change of Control (in the case of a Change of Control
under clause (iii) of the definition of Change of Control) is at least equal to
105% of the conversion price of the SIRENs in effect immediately preceding the
time of such Change of Control, or
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(ii) all of the consideration (excluding cash payments for fractional shares) in
the transaction giving rise to such Change of Control to the holders of Common
Stock consists of shares of common stock that are, or immediately upon issuance
will be, listed on a national securities exchange or quoted in the Nasdaq
National Market, and as a result of such transaction the SIRENs become
convertible solely into such Common Stock and neither Moody's Investors Service,
Inc. nor Standard & Poor's principally as a result of the Change of Control, has
downgraded the rating on the SIRENs by one or more gradations below the rating
of the SIRENs on the original issuance date thereof within 90 days after the
date of the public announcement of the Change of Control (which period shall be
extended so long as the rating of the SIRENs is under publicly announced
consideration for possible downgrade by any of the rating agencies), or (iii)
the consideration in the transaction giving rise to such Change of Control to
the holders of Common Stock consists of cash, securities that are, or
immediately upon issuance will be, listed on a national securities exchange or
quoted in the Nasdaq National Market, or a combination of cash and such
securities, and the aggregate fair market value of such consideration (which, in
the case of such securities, shall be equal to the average of the daily closing
prices of such securities on the five consecutive Trading Days selected by the
Company out of the 10 consecutive Trading Days following consummation of such
transaction) is at least 105% of the conversion price of the SIRENs in effect on
the date immediately preceding the closing date of such transaction (Section
1401).
The Company, to the extent applicable and if required by law, will comply
with the provisions of Rule 13e-4 and any successor or similar provision under
the Exchange Act which may then be applicable and will file a Schedule 13E-4 or
any successor or similar schedule required thereunder in connection with any
offer by the Company to purchase SIRENs at the option of holders upon a Change
of Control (Section 1405). The Change of Control purchase feature of the SIRENs
may in certain circumstances make more difficult or discourage a takeover of the
Company and, thus, the removal of incumbent management. The Change of Control
purchase feature, however, is not the result of management's knowledge of any
specific effort to accumulate shares of Common Stock or to obtain control of the
Company by means of a merger, tender offer, solicitation or otherwise, or part
of any plan by management to adopt a series of anti-takeover provisions.
Instead, the Change of Control purchase feature is a result of negotiations
between the Company and the Underwriters. Management has no present intention to
engage in a transaction involving a Change of Control, although it is possible
that the Company would decide to do so in future. Subject to the limitation on
mergers discussed below, the Company could, in the future, enter into certain
transactions, including certain recapitalizations, sales of assets, or the
liquidation of the Company, that would not constitute a Change of Control under
the Indenture, but that would increase the amount of Senior Indebtedness (or any
other indebtedness) outstanding at such time or substantially reduce or
eliminate the Company's assets. There are no restrictions in the Indenture on
the creation of additional Senior Indebtedness (or any other indebtedness), and,
under certain circumstances, the incurrence of significant amounts of additional
indebtedness could have an adverse effect on the Company's ability to service
its indebtedness, including the SIRENs. If a Change of Control were to occur,
there can be no assurance that the Company would have sufficient funds to pay
the Change of Control Purchase Price for all SIRENs tendered by the holders
thereof.
No SIREN may be purchased pursuant to the Change of Control provisions if
there has occurred and is continuing an Event of Default described under
" -- Events of Default" (Section 1402).
The Company's existing bank credit facility prohibits the Company from
repurchasing any SIRENs unless (i) such repurchase is permitted under the
restricted payment covenant contained in such bank credit facility and (ii) at
the time of such repurchase and after giving effect thereto, no default shall
have occurred under such bank credit facility. In addition, the agreements under
which Senior Indebtedness may be outstanding in the future could contain
provisions which may require repayment of such respective Senior Indebtedness
prior to repayment of the SIRENs upon, among other things, a Change of Control.
If the Company is unable to obtain the requisite consents under its Senior
Indebtedness to enable it to repurchase the SIRENs or is unable to repay all
Senior Indebtedness, there would be both an Event of Default under the SIRENs
and an event of default under such Senior Indebtedness, as a result of which
events the Company could be prohibited by the subordination provisions of the
Indenture from repurchasing SIRENs or making other payments in respect thereof.
Furthermore, the exercise by the holders of their right to require the
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Company to repurchase the SIRENs could cause a default under the Senior
Indebtedness of the Company, even if the Change of Control itself does not, due
to the financial effect of such repurchase on the Company. As a result, the
repurchase of the SIRENs could be blocked pursuant to the subordination terms of
the Indenture. Finally, the Company's ability to pay cash to the holders of
SIRENs upon a repurchase may be limited by the Company's then existing financial
resources. Failure of the Company to pay the Change of Control Purchase Price
will be a default under the Indenture and could result in an Event of Default
with respect to the SIRENs, whether or not such repurchase is permitted by the
subordination provisions. See "-- Events of Default."
LIMITATION ON MERGERS
The Company may, without the consent of the holders of the SIRENs,
consolidate with or merge into any other entity or convey, transfer or lease its
properties and assets substantially as an entirety to any person, provided that:
(1) the entity formed by such consolidation or into which the Company is merged
or the person that acquires by conveyance or transfer, or which leases the
properties and assets of the Company substantially as an entirety, must be a
corporation, partnership or trust organized and existing under the laws of the
United States, any state thereof or the District of Columbia; (2) the successor
entity expressly assumes, by a supplemental indenture executed and delivered to
the Trustee, in form satisfactory to the Trustee, the due and punctual payment
of the principal of and premium, if any and interest on all SIRENs and the
performance of every covenant of the Indenture on the part of the Company to be
performed or observed and provides for conversion rights in accordance with the
Indenture; and (3) immediately after giving effect to such transaction, no Event
of Default, and no event which, after notice or lapse of time, or both, would
become an Event of Default, shall have occurred and be continuing (Section 801).
Upon compliance with these provisions by a successor entity, the Company (except
in the case of a lease) would be relieved of its obligations under the Indenture
and the SIRENs (Section 802).
MODIFICATION AND WAIVER
Modifications and amendments of the Indenture, with certain exceptions, may
be made by the Company and the Trustee, only with the consent of the holders of
not less than a majority in aggregate principal amount of the SIRENs at the time
outstanding, and holders of not less than a majority in aggregate principal
amount of the SIRENs at the time outstanding may waive compliance by the Company
with certain provisions of the Indenture; provided, however, that no such
modification, amendment or waiver may, without the consent of the holder of each
outstanding SIREN affected thereby, (i) change the Stated Maturity of the
principal of or the due date of any installment of interest on any SIREN, (ii)
reduce the principal amount of, or the rate of interest on, or any premium
payable upon redemption of, any SIREN, (iii) change the currency of payment of
principal of, or premium, if any, or interest on, any SIREN, (iv) impair the
right to institute suit for the enforcement of any payment on or with respect to
any SIREN on or after the Stated Maturity, or the Redemption Date in case of the
redemption of any SIREN, (v) adversely affect the right of a holder to convert
SIRENs, (vi) modify the provisions of the Indenture with respect to the
subordination of the SIRENs in a manner adverse to the holders, (vii) reduce the
above-stated percentage of outstanding SIRENs necessary to modify or amend the
Indenture, or (viii) reduce the percentage in aggregate principal amount of
outstanding SIRENs necessary for waiver of compliance with certain provisions of
the Indenture or for waiver of certain defaults (Sections 902 and 1009).
The holders of a majority in aggregate principal amount of the outstanding
SIRENs may waive any past default under the Indenture except, among other
things, a default in the payment of principal of or premium, if any, or interest
on any SIREN, including the Redemption Price, or a default with respect to right
of holders to convert the SIRENs (Section 513).
EVENTS OF DEFAULT
The following will be Events of Default under the Indenture: (i) failure to
pay principal of, premium, if any, or Redemption Price when due on any SIREN,
whether or not such payment is prohibited by the subordination provisions of the
indenture; (ii) failure to pay any interest on any SIREN 30 days after payment
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is due, whether or not such payment is prohibited by the subordination
provisions of the Indenture; (iii) failure to perform any other covenant of the
Company in the Indenture, and such failure continues for 60 days after written
notice by the Trustee or the holders of at least 25% in principal amount of the
outstanding SIRENs as provided in the Indenture; (iv) default under any
mortgage, indenture or instrument under which there may be issued, or by which
there may be secured or evidenced, any indebtedness of the Company in excess of
an aggregate of $10,000,000 either for borrowed money or representing any Senior
Indebtedness (other than indebtedness which is nonrecourse to the Company beyond
the property securing such indebtedness) resulting in the acceleration of such
indebtedness prior to its express maturity (provided however, that the Event of
Default under this clause (iv) shall be automatically deemed remedied and cured
if the default under such accelerated indebtedness is remedied or cured by the
Company or waived by the holder of such indebtedness); and (v) certain events of
bankruptcy, insolvency or reorganization of the Company (Section 501).
Notwithstanding the 60-day period and notice requirement referred to in
clause (iii) above, with respect to a default under the Change of Control
provisions, (1) the 60-day period referred to in clause (iii) above will be
deemed to have begun as of the date the Change of Control Notice is required to
be sent in the event the Change of Control Notice indicates (or would, if sent,
indicate) that the Company has not complied with its obligation to either repay
or obtain the requisite consents under any Senior Indebtedness that would
prohibit the repurchase of the SIRENs, and either (a) the holders duly elect to
have at least 25% in principal amount of outstanding SIRENs repurchased, or (b)
the holders of at least 25% in principal amount of the outstanding SIRENs or the
Trustee thereafter gives the Notice of Default to the Company and, if
applicable, the Trustee, and (2) if the breach or default is a result of a
default in the payment when due of the Change of Control Purchase Price on the
Change of Control Purchase Date, such default shall arise on the Change of
Control Purchase Date, provided that either the holders of at least 25% in
principal amount of the SIRENs or the Trustee thereafter gives the Notice of
Default to the Company and, if applicable, the Trustee (Section 501).
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 (Sections 601 and 603).
Subject to such provisions for the indemnification of the Trustee, the holders
of a majority in aggregate principal amount of the outstanding SIRENs 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 (Section 512).
If an Event of Default shall occur and be continuing, other than an event
of bankruptcy, insolvency or reorganization of the Company, either the Trustee
or the holders of at least 25% of the principal amount of the outstanding SIRENs
may accelerate the maturity of all SIRENs upon the earlier of (1) five business
days after notice of such acceleration is received by the Company (and the
Trustee if given by holders) and (2) a payment default under or acceleration of
any Senior Indebtedness or such other earlier time as the final maturity date
for such Senior Indebtedness occurs. If an Event of Default shall occur and be
continuing which is an event of bankruptcy, insolvency or reorganization of the
Company, the maturity of all SIRENs shall immediately accelerate without any act
on the part of the Trustee or any holder. If an Event of Default shall occur and
be continuing as a result of an acceleration of indebtedness of the type
described in clause (iv) above, a declaration of acceleration under the
Indenture shall automatically be annulled if the holders of the accelerated
indebtedness described in clause (iv) above have rescinded their declaration of
acceleration within 90 days thereof and no other Event of Default has occurred
during such 90-day period which has not been cured or waived. After acceleration
upon the Event of Default, but before a judgment or decree based on
acceleration, the holders of a majority in aggregate principal amount of
outstanding SIRENs may, under certain circumstances, rescind and annul such
acceleration if, among other things, all Events of Default, other than the
non-payment of accelerated principal, have been cured or waived as provided in
the Indenture (Section 502). For information as to waiver of defaults, see
" -- Modification and Waiver."
No holder of any SIREN will have any right to institute any proceeding with
respect to the Indenture or for any remedy thereunder, unless such holder shall
have previously given to the Trustee written notice of a continuing Event of
Default, the holders of at least 25% in aggregate principal amount of the
outstanding SIRENs shall have made written request, and offered reasonable
indemnity, to the Trustee to institute such
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proceeding as trustee, the Trustee shall not have received from the holders of a
majority in aggregate principal amount of the outstanding SIRENs a direction
inconsistent with such request and the Trustee shall have failed to institute
such proceeding within 60 days after such notice (Section 507). However, such
limitations do not apply to a suit instituted by a holder of a SIREN for the
enforcement of payment of the principal of or premium, if any, or interest on
such SIREN or the Redemption Price on or after the respective due dates
expressed in such SIREN or of the right to convert such SIREN in accordance with
the Indenture (Section 508).
The Company will be required annually to furnish to the Trustee a statement
as to any default in its performance of certain of its obligations under the
Indenture (Section 1004).
DISCHARGE OF INDENTURE; DEFEASANCE
The Company may terminate substantially all obligations under the Indenture
at any time by delivering all outstanding SIRENs to the Trustee for cancellation
and paying any other sums payable under the Indenture (Article IV).
The Indenture also provides that the Company may elect:
(a) to defease and be discharged from any and all obligations with
respect to the SIRENs and that the provisions of the Indenture (including
the provisions described under " -- Subordination of SIRENs") will no
longer be in effect with respect to the SIRENs (except for the obligations
to register the transfer or exchange of the SIRENs, to replace temporary or
mutilated, destroyed, lost or stolen SIRENs, to maintain an office or
agency in respect of SIRENs and to hold monies for payment in trust)
("Defeasance"); or
(b) to be released from its obligations with respect to the SIRENs
under certain restrictive covenants of the Indenture, and that the event of
the type described under the clause (iv) under " -- Events of Default" will
not be deemed to be an Event of Default under the indenture and that the
provisions described under " -- Subordination of SIRENs" will not apply
("Covenant Defeasance").
Such Defeasance or Covenant Defeasance will take effect only upon the
deposit with the Trustee (or other qualifying trustee), in trust for such
purpose, of money or U.S. Government Obligations that, through the payment of
principal and interest in accordance with their terms, will provide money, in an
amount sufficient to pay the principal of and premium, if any, and interest on
the SIRENs on the dates such payments are due, which may include one or more
Redemption Dates designated by the Company (other than in connection with a
Change of Control occurring after such Defeasance or Covenant Defeasance), in
accordance with the terms of the SIRENs (Article XV).
Such a trust may be established with respect to the SIRENs only if, among
other things: (i) such Defeasance or Covenant Defeasance will not result
(whether immediately or with notice or lapse of time or both) in an Event of
Default under the Indenture; (ii) such deposit will not be prohibited by the
provisions of any agreement or instrument to which the Company is a party or is
bound; (iii) such deposit will not cause the Trustee to have any conflicting
interest with respect to other securities of the Company; (iv) the Company has
delivered to the Trustee an Opinion of Counsel to the effect that the holders of
the SIRENs will not recognize income, gain or loss for federal income tax
purpose as a result of such Defeasance or Covenant Defeasance and will be
subject to federal income tax on the same amounts, in the same manner and at the
same times as would have been the case if such Defeasance or Covenant Defeasance
had not occurred; and (v) the Company has delivered an Officers' Certificate and
an Opinion of Counsel, each to the effect that all conditions precedent relating
to such Defeasance or Covenant Defeasance have been satisfied. Such Opinion of
Counsel, in the case of Defeasance, must refer to and be based upon a ruling of
the Internal Revenue Service or a change in applicable federal income tax law
occurring after the issue date (Article XV).
If the Company omits to comply with its remaining obligations under the
Indenture after Covenant Defeasance in respect of the SIRENs issued thereunder
and the SIRENs are declared due and payable because of the occurrence of an
Event of Default, the amount of money or U.S. Government Obligations on deposit
with the Trustee may be insufficient to pay amounts due on the SIRENs at the
time any acceleration
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of the maturity thereof resulting from such Event of Default. However, the
Company will remain liable in respect of such payments (Article XV).
GOVERNING LAW
The Indenture and the SIRENs will be governed by and construed in
accordance with the laws of the State of New York.
THE TRUSTEE
Texas Commerce Bank National Association is the Trustee under the
Indenture. In the ordinary course of business the Company maintains other
commercial relationships with the Trustee and its affiliates. If the Trustee
shall acquire any conflicting interest (as defined in Section 301(b) of the
Trust Indenture Act of 1939, as amended) after a default under the Indenture,
the Trustee either shall eliminate such conflicting interest or resign as
Trustee.
DESCRIPTION OF CAPITAL STOCK
AUTHORIZED CAPITAL STOCK
The Company's authorized capital stock consists of 75,000,000 shares of
common stock, par value $.01 per share (the "Common Stock"), of which 23,259,658
were issued and outstanding at December 31, 1993, and 10,000,000 shares of
preferred stock, par value $.01 per share (the "Preferred Stock"), of which
2,221,005 were issued and outstanding as of December 31, 1993.
COMMON STOCK
All shares of Common Stock have equal rights to participate in dividends
and, in the event of liquidation, assets available for distribution to
stockholders, subject to any preference established with respect to Preferred
Stock. Each holder of Common Stock is entitled to one vote for each share held
on all matters submitted to a vote of stockholders, and voting rights for the
election of directors are noncumulative. Shares of Common Stock carry no
conversion, preemptive or subscription rights, and are not subject to
redemption. All outstanding shares of Common Stock are, and any shares of Common
Stock issued upon conversion of convertible securities will be, validly issued,
fully paid and nonassessable. The Company pays dividends on Common Stock when,
as and if declared by the Board of Directors. Dividends may be declared in the
discretion of the Board of Directors from funds legally available therefor,
subject to restrictions under agreements related to Company indebtedness.
The transfer agent for the Common Stock is Society National Bank, 3200
Renaissance Tower, 1201 Elm Street, Dallas, Texas 75270.
PREFERRED STOCK
The Preferred Stock is issuable in one or more series or classes, any or
all of which may have such voting powers, full or limited, or no voting powers,
and such designations, preferences and related, participating, optional or other
special rights and qualifications, limitations or restrictions thereof, as are
set forth in the Company's Certificate of Incorporation, as amended, or in the
resolution or resolutions providing for the issue of such stock adopted by the
Board, which is expressly authorized to set such terms for any such issue.
In November 1991, the Company issued 1,200,000 shares of $4.00 Exchangeable
Convertible Preferred Stock, of which 1,186,005 shares were outstanding on
December 31, 1993. Holders of such Preferred Stock are entitled to receive,
when, as and if declared by the Board of Directors out of funds legally
available therefor, cash dividends at an annual rate of $4.00 per share, payable
quarterly in arrears. Upon liquidation, such holders are entitled to receive a
preference of $50.00 per share, plus accrued and unpaid dividends to the payment
date. Each share of such Preferred Stock is convertible into 5.51 shares of
Common Stock at any time prior to redemption (subject to adjustment), equivalent
to a conversion price of $9.07 for each share of
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Common Stock. The Company has the right to exchange the shares of such Preferred
Stock for the Company's 8% Convertible Subordinated Debentures due 2006 on any
dividend payment date and, subject to certain restrictions, the right to redeem
such Preferred Stock beginning January 1, 1995.
In April 1993, the Company issued 1,035,000 shares (represented by
4,140,000 depositary shares) of $6.00 Exchangeable Convertible Preferred Stock,
all of which were outstanding on December 31, 1993. Holders of such Preferred
Stock are entitled to receive, when, as and if declared by the Board of
Directors out of funds legally available therefor, cash dividends at an annual
rate of $6.00 per share ($1.50 per depositary share), payable quarterly in
arrears. Upon liquidation, such holders are entitled to receive a preference of
$100.00 per share ($25.00 per depositary share), plus accrued and unpaid
dividends to the payment date. Each share of such Preferred Stock is convertible
into 4.762 shares of Common Stock at any time prior to redemption (subject to
adjustment), equivalent to a conversion price of $21.00 for each share of Common
Stock. The Company has the right to exchange the shares of such Preferred Stock
for the Company's 6% Convertible Subordinated Debentures due 2008 on any
dividend date payment on or after March 31, 1994 and the right to redeem such
Preferred Stock beginning March 31, 1996.
The existing series of Preferred Stock rank prior to the Common Stock, and
on a parity with each other, as to dividends and upon liquidation, dissolution
or winding up.
FACTORS AFFECTING ACQUISITIONS OF CONTROL
The Company's Certificate of Incorporation, as amended, provides that the
Board of Directors, in its discretion, may establish one or more class or series
of Preferred Stock having such number of shares, designations, relative voting
rights, dividend rates, liquidation and other rights, preferences and
limitations as may be fixed by the Board of Directors without any further
stockholder approval. Such rights, preferences, privileges and limitations could
have the effect of impeding or discouraging the acquisition of control of the
Company.
The Company is a Delaware corporation and is subject to Section 203 of the
Delaware General Corporation Law (the "DGCL"). In general, Section 203 prevents
an "interested stockholder" (defined generally as a person owning 15% or more of
a corporation's outstanding voting stock) from engaging in a "business
combination" (as defined) with a Delaware corporation for three years following
the date such person became an interested stockholder unless (i) before such
person became an interested stockholder, the board of directors of the
corporation approved the transaction in which the interested stockholder became
an interested stockholder or approved the business combination; (ii) upon
consummation of the transaction that resulted in the interested stockholder's
becoming an interested stockholder, the interested stockholder owned at least
85% of the voting stock of the corporation outstanding at the time the
transaction commenced (excluding stock held by directors who are also officers
of the corporation and by employee stock plans that do not provide employees
with the right to determine confidentially whether shares held subject to the
plan will be tendered in a tender or exchange offer); or (iii) following the
transaction in which such person became an interested stockholder, the business
combination is approved by the board of directors of the corporation and
authorized at a meeting of stockholders by the affirmative vote of the holders
of two-thirds of the outstanding voting stock of the corporation not owned by
the interested stockholder. Under Section 203, the restrictions described above
also do not apply to certain business combinations proposed by an interested
stockholder following the announcement or notification of one of certain
extraordinary transactions involving the corporation and a person who had not
been an interested stockholder during the previous three years or who became an
interested stockholder with the approval of a majority of the corporation's
directors, if such extraordinary transaction is approved or not opposed by a
majority of the directors who were directors prior to any person's becoming an
interested stockholder during the previous three years or who were recommended
for election or elected to succeed such directors by a majority of such
directors.
DIRECTORS' LIABILITY
The Company's Certificate of Incorporation, as amended, also provides for
the elimination of directors' liability for monetary damages for a breach of
certain fiduciary duties and for the indemnification of directors,
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officers, employees or agents as permitted by the DGCL. These provisions cannot
be amended without the affirmative vote of the holders of at least a majority in
interest of the outstanding shares entitled to vote.
The Company has entered into indemnification agreements with all directors
and executive officers and may, in the future, enter into such agreements with
employees and agents. Such indemnification agreements provide generally that
such persons will be indemnified, to the extent permitted by applicable law, for
expenses (including attorneys' fees), judgments, penalties, fines and amounts
paid in settlement actually and reasonably incurred by such persons in
connection with any proceeding (including, to the extent permitted by law, any
derivative action) to which such persons are, or are threatened to be made, a
party by reason of their status in such positions. Such indemnification
agreements do not change the basic legal standards for indemnity under
applicable law or as set forth in the Certificate of Incorporation.
CERTAIN FEDERAL INCOME TAX CONSIDERATIONS
The following discussion is a summary of certain federal income tax
considerations relevant to the purchase, ownership and disposition of SIRENs
that are acquired in this Offering. The summary is based on the Internal Revenue
Code of 1986, as amended through the date hereof (the "Code"), existing
regulations, and judicial and administrative determinations, all of which are
subject to change at any time, possibly on a retroactive basis. The summary
relates only to SIRENs, or Common Stock received upon conversion thereof, that
are held as "capital assets" within the meaning of Section 1221 of the Code by
persons who are citizens or residents of the United States or domestic
corporations or domestic partnerships. No information is provided herein with
respect to state, local or foreign tax consequences, nor does this summary
discuss tax consequences to categories of holders that are subject to special
rules such as foreign persons, tax-exempt organizations, insurance companies,
banks, and dealers in stocks and securities. Tax consequences may vary depending
on the particular status of an investor. No rulings will be sought from the
Internal Revenue Service ("IRS") with respect to the federal income tax
consequences of holding and disposing of the SIRENs.
THIS SUMMARY DOES NOT PURPORT TO DEAL WITH ALL ASPECTS OF FEDERAL INCOME
TAXATION THAT MAY BE RELEVANT TO AN INVESTOR'S DECISION TO PURCHASE SIRENS. EACH
INVESTOR SHOULD CONSULT WITH ITS OWN TAX ADVISOR CONCERNING THE APPLICATION OF
THE FEDERAL INCOME TAX LAWS AND OTHER TAX LAWS TO ITS PARTICULAR SITUATION
BEFORE DETERMINING WHETHER TO PURCHASE SIRENS.
QUALIFIED STATED INTEREST ON THE SIRENS
Interest constituting "qualified stated interest" paid on a SIREN will be
taxable to a holder as ordinary interest income at the time it accrues or is
received, in accordance with the holder's usual method of accounting for federal
income tax purposes.
In general, "qualified stated interest" is stated interest that is
unconditionally payable in cash or in property (other than debt instruments of
the issuer), at least annually during the entire term of the debt instrument, at
a single fixed rate of interest (which rate reflects accrual periods of
different lengths, if any). Because interest on the SIRENs will be fixed for the
period from and including the date of issuance through March 31, 1997 at a rate
of % per annum, which will be lower than the rate of % per annum that
will be fixed thereafter, only interest computed at the initial stated interest
rate will be treated as qualified stated interest. The additional interest that
accrues on the SIRENs beginning April 1, 1997 in excess of interest computed at
the initial stated interest rate (the "Additional Interest") will not be treated
as qualified stated interest but, instead, will be included in the original
issue discount ("OID") on the SIRENs, reportable in the holder's income under
the rules described under " -- Original Issue Discount."
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ORIGINAL ISSUE DISCOUNT
SIRENs will be issued with OID within the meaning of Section 1273(a) of the
Code.
The application of the OID rules will cause holders of SIRENs to recognize
the Additional Interest that is payable on the SIRENs after March 31, 1997 as
ordinary income (on a constant yield to maturity basis) over the term of the
SIRENs beginning on the date of issuance of the SIRENs. As a result, the amount
of taxable interest and OID income recognized by a holder of a SIREN from the
date of issuance through March 31, 1997 will exceed the actual cash interest
payments for such period. For the period from April 1, 1997 to maturity,
however, cash interest payments on the SIRENs will exceed the amount of OID and
interest income recognized by the holder.
The amount of OID on the SIRENs will equal the excess of their "redemption
price" over their "issue price." The "redemption price" will equal the stated
principal amount of the SIRENs, plus the Additional Interest payable after March
31, 1997. The "issue price" of the SIRENs will equal the initial offering price
to the public at which a substantial amount of the SIRENs are sold.
A holder of a SIREN must generally include in gross income for federal
income tax purposes the sum of the daily portions of OID for each day during the
taxable year or portion thereof during which the holder holds the SIREN, whether
or not the holder actually receives a payment relating to OID in such year. The
daily portion is determined by allocating to each day of the relevant "accrual
period" (as defined below) a pro rata portion of an amount equal to (a) the
product of (i) the "adjusted issue price" (as defined below) of the SIREN at the
beginning of each accrual period, and (ii) the constant yield to maturity of the
SIREN (taking into account the length of the particular accrual period), less
(b) the sum of any qualified stated interest payments allocable to the accrual
period. The "accrual period" for a SIREN will generally be the six month period
(or, in the case of the initial period, the shorter period) ending on March 31
and September 30 of each calendar year. The "adjusted issue price" of a SIREN at
the beginning of any accrual period is its issue price, plus all accrued OID for
prior accrual periods, less all prior cash payments other than qualified stated
interest payments.
The right to convert SIRENs into Common Stock is ignored for purposes of
computing the amount and accrual of OID. Moreover, since an early redemption of
the SIRENs would result in a higher yield to maturity than that determined by
reference to the stated maturity date of the SIRENs, the possibility of early
redemption is ignored for purposes of computing the amount and accrual of OID.
A holder's initial tax basis in a SIREN will generally equal the price paid
therefor, and will be increased by the amount of OID included in the holder's
income and reduced by the amount of all payments on the SIREN other than
qualified stated interest payments.
CONVERSION OF SIRENS
A holder of SIRENs generally will not recognize gain or loss upon the
conversion of the SIRENs into Common Stock, except as follows. A holder
receiving cash in lieu of a fractional share will recognize capital gain or loss
in an amount equal to the difference between the amount of cash received and the
amount of basis in the converted SIREN allocable to the fractional share. In
addition, a holder of SIRENs who converts the SIRENs into Common Stock between
interest payment dates may be obligated to recognize as ordinary income the
qualified stated interest accruing for the short period from the last interest
payment date to the conversion date and will be required to recognize the OID
accruing before the conversion date. A holder's aggregate tax basis in shares of
Common Stock received upon conversion will be equal to the holder's tax basis in
the SIRENs converted, less the portion of such basis that is allocated to any
cash received in lieu of a fractional share of Common Stock, plus the amount of
qualified stated interest recognized as ordinary income for the period ending on
the conversion date. The holding period for the shares of Common Stock received
upon conversion will include the holding period of the SIREN converted, except
the holding period of Common Stock, if any, allocable to accrued qualified
stated interest or accrued OID will commence on the day following the date of
conversion.
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MARKET DISCOUNT
The market discount rules may affect resale of the SIRENs. If a person
purchases a SIREN at a market discount and thereafter recognizes gain upon
disposition of the SIREN (or the Common Stock into which it is converted), such
gain will be taxable as ordinary interest income to the extent of the market
discount that accrued during the period the purchaser held the SIREN. Generally,
market discount will exist on the purchase of a SIREN if the purchase price is
less than the adjusted issue price of the SIREN (i.e., the issue price of the
SIREN, as defined in "-- Original Issue Discount," plus the OID accrued thereon
prior to such purchase, less the amount of payments other than qualified stated
interest payments made on the SIREN). Thus, market discount will not exist on
SIRENs that are purchased in the Offering, except for those SIRENs (if any) that
are purchased for less than the issue price.
SALE, EXCHANGE OR REDEMPTION
Upon the sale, exchange or redemption (excluding conversion) of a SIREN or
upon a sale or exchange of Common Stock, a holder generally will recognize gain
or loss in an amount equal to the difference between the amount received
(exclusive of any amount received for qualified stated interest in the case of a
SIREN) and the holder's adjusted tax basis in the property sold. Such gain or
loss will be capital gain or loss, and will be long term capital gain or loss if
the property sold has been held for more than one year at the time of the sale,
exchange or redemption. In addition, in the case of a SIREN, the holder will
recognize ordinary interest income in an amount equal to the portion of the
amount realized on the sale, exchange or other disposition that is attributable
to qualified stated interest on the SIREN that accrued from the last interest
payment date.
CONSTRUCTIVE DIVIDEND
If at any time the Company makes a distribution of property to shareholders
which would be taxable to such shareholders as a dividend (e.g., a distribution
of cash or other assets or evidence of indebtedness of the Company but not a
stock dividend or right to subscribe for Common Stock), the conversion price for
the SIRENs may be adjusted pursuant to the anti-dilution provisions applicable
to the SIRENs. Such adjustment may be deemed to be a taxable dividend payment to
holders or beneficial owners of the SIRENs for federal income tax purposes. The
Company may make such reductions in the conversion price as it considers to be
advisable in order to prevent a taxable dividend resulting from the adjustment
in the conversion price.
BACKUP WITHHOLDING
Under the Code, a holder of a SIREN or Common Stock may be subject, under
certain circumstances, to "backup withholding" at a 31% rate with respect to
payments of interest and OID on the SIREN, payments of dividends on the Common
Stock, or gross proceeds from the disposition of either, unless the holder (i)
provides evidence that it is a corporation or that it is within certain other
exempt categories or (ii) provides a correct taxpayer identification number,
certifies as to no loss of exemption from backup withholding, and otherwise
complies with the applicable requirements of the backup withholding rules. Any
amount withheld from a payment to a holder under the backup withholding rules is
allowable as a credit against such holder's federal income tax liability.
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UNDERWRITING
Subject to the terms and conditions set forth in an underwriting agreement
(the "Underwriting Agreement") among the Company, CS First Boston Corporation,
PaineWebber Incorporated, Petrie Parkman & Co., Inc. and Smith Barney Shearson
Inc., as underwriters (the "Underwriters"), the Company has agreed to sell to
each of the Underwriters, and each of the Underwriters has severally agreed to
purchase, the principal amount of SIRENs set forth opposite its name below.
PRINCIPAL
UNDERWRITER AMOUNT
----------- ------------
CS First Boston Corporation............................................ $
PaineWebber Incorporated...............................................
Petrie Parkman & Co., Inc..............................................
Smith Barney Shearson Inc..............................................
------------
Total........................................................ $100,000,000
------------
------------
The Underwriting Agreement provides that the obligations of the
Underwriters are subject to certain conditions precedent and that the
Underwriters will be obligated to purchase all of the SIRENs offered hereby if
any are purchased.
The Company has been advised by the Underwriters that they propose to offer
the SIRENs to the public initially 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 per SIREN; that the
Underwriters and such dealers may allow a discount not in excess of % of
such principal amount on sales to certain other dealers; and that after the
initial public offering, the public offering price, concession and discount may
be changed.
The Company has granted to the Underwriters an option, exercisable within
30 days after the date of this Prospectus, to purchase up to an additional
$15,000,000 aggregate principal amount of the SIRENs at the public offering
price set forth on the cover page of this Prospectus less the underwriting
discount. The Underwriters may only exercise such option to cover
over-allotments, if any, in the sale of the initial $100,000,000 aggregate
principal amount of SIRENs offered hereby.
The Company and each of John C. Snyder, Thomas J. Edelman and John A.
Fanning, the Chairman, President and Executive Vice President, respectively, of
the Company, have agreed that, for a period of 90 days after the date of this
Prospectus, they will not, without the prior written consent of CS First Boston
Corporation, directly or indirectly, sell, agree to sell, contract to sell, or
otherwise dispose of any shares of the Company's Common Stock or Preferred Stock
or any other security convertible into or exchangeable for Common Stock other
than upon conversion of convertible securities outstanding on the date hereof or
pursuant to employee benefit plans (including, but not limited to, stock option
plans).
The Company has agreed to indemnify the Underwriters against certain
liabilities, including liabilities under the Securities Act of 1933, as amended,
or to contribute to payments the Underwriters may be required to make in respect
thereof.
Each of the Underwriters has provided during the past 12 months and may
provide in the future investment banking services to the Company for which they
have received or may receive customary fees.
The SIRENs are a new issue of securities with no established trading
market, and the Company has no present intention to list the SIRENs on a
national securities exchange. The Underwriters have advised the Company that
each of them currently intends to make a market in the SIRENs, but they are not
obligated to do so and may discontinue any such market making at any time
without notice. No assurance can be given that an active market will develop for
the SIRENs or as to the liquidity thereof.
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LEGAL OPINIONS
The validity of the SIRENs and the Common Stock issuable upon conversion of
the SIRENs will be passed upon by Peter E. Lorenzen, Vice President -- General
Counsel of the Company. Mr. Lorenzen owns 7,000 shares of Common Stock and holds
options to purchase 67,800 shares of Common Stock. Kelly, Hart & Hallman (a
professional corporation), Fort Worth, Texas, special tax counsel to the
Company, will pass on "Certain Federal Income Tax Considerations." Certain legal
matters in connection with this Offering will be passed upon for the
Underwriters by Baker & Botts, L.L.P., Dallas, Texas.
EXPERTS
The audited financial statements and schedules incorporated in this
Prospectus by reference have been audited by Arthur Andersen & Co., independent
public accountants, as indicated in their reports with respect thereto, and are
incorporated herein by reference in reliance upon the authority of said firm as
experts in accounting and auditing.
The information appearing in this Prospectus and incorporated herein by
reference to the Company's Annual Report on Form 10-K for the year ended
December 31, 1993 regarding proved reserves and related future net revenues and
the present value thereof is derived, as and to the extent described herein and
therein, from reserve reports and reserve report audits prepared by NSAI,
independent oil and gas consultants, and, to such extent, are included and
incorporated by reference herein in reliance upon the authority of such firm as
experts with respect to the matters contained in such reports and audits.
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Exchange
Act, and in accordance therewith files reports, proxy statements and other
information with the Securities and Exchange Commission ("SEC"). Such reports,
proxy statements and other information can be inspected and copied at the public
reference facilities maintained by the SEC at Judiciary Plaza, Room 1024, 450
Fifth Street, N.W., Washington, D.C. 20549; at Suite 1400, Northwestern Atrium
Center, 500 West Madison Street, Chicago, Illinois 60661; and at 7 World Trade
Center, New York, New York 10048. Copies of such material may also be obtained
by mail at prescribed rates from the Public Reference Section of the SEC,
Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549. In addition,
the Common Stock is traded on the NYSE, and such reports, proxy statements and
other information may be inspected at the NYSE, 20 Broad Street, New York, New
York 10005.
The Company has filed with the SEC a Registration Statement on Form S-3
(together with any amendments thereto, the "Registration Statement") under the
Securities Act of 1933, as amended, with respect to the SIRENs offered by this
Prospectus. This Prospectus does not contain all the information set forth in
the Registration Statement and the exhibits thereto. For further information
with respect to the Company and the SIRENs, reference is made to the
Registration Statement and the exhibits thereto. Copies of the Registration
Statement are available from the SEC in the manner provided above. Statements
contained in this Prospectus concerning the provisions of documents filed with
the Registration Statement as exhibits are necessarily summaries of such
documents, and each such statement is qualified in its entirety by reference to
the copy of the applicable document filed with the SEC.
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INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE
The following document heretofore filed by the Company with the SEC
pursuant to Section 13 of the Exchange Act is incorporated herein by reference:
The Company's Annual Report on Form 10-K for the year ended December 31,
1993.
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 SIRENs 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 A
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 SNYDER OIL CORPORATION, 1625 BROADWAY, SUITE
2200, DENVER, COLORADO 80202, ATTENTION: INVESTOR RELATIONS, (303) 592-8638.
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APPENDIX
(GRAPHIC IMAGE OMITTED ON PAGE 2 OF THE PROSPECTUS IS DESCRIBED AS: MAP OF THE
UNITED STATES SHOWING THE LOCATIONS OF THE COMPANY'S MAJOR GAS FACILITIES,
CORPORATE OFFICES, FIELD OFFICES AND MAJOR PRODUCING PROPERTIES)
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NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS OTHER THAN THOSE CONTAINED OR
INCORPORATED BY REFERENCE IN 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 UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE
SECURITIES OFFERED HEREBY, OR AN OFFER TO SELL OR A SOLICITATION OF AN OFFER TO
BUY THE SECURITIES OFFERED BY THIS PROSPECTUS, IN ANY JURISDICTION OR TO ANY
PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH OFFER OR SOLICITATION IN SUCH
JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE
INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR
THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE.
---------------------
TABLE OF CONTENTS
PAGE
----
Prospectus Summary...................... 3
Use of Proceeds......................... 8
Capitalization.......................... 8
Price Range of Common Stock and
Dividends............................. 9
Selected Historical Financial
Information........................... 10
Management's Discussion and Analysis of
Financial Condition and Results of
Operations............................ 11
Business and Properties................. 15
Description of SIRENs................... 28
Description of Capital Stock............ 41
Certain Federal Income Tax
Considerations........................ 43
Underwriting............................ 46
Legal Opinions.......................... 47
Experts................................. 47
Available Information................... 47
Incorporation of Certain Documents by
Reference............................. 48
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(SOCO LOGO)
Snyder Oil Corporation
$100,000,000
% Step-up Convertible
Subordinated Notes Due 2001
(Step-up Income Redeemable
Equity Notes(TM) -- SIRENs(TM))
---------------------------
PROSPECTUS
---------------------------
CS First Boston
PaineWebber Incorporated
Petrie Parkman & Co.
Smith Barney Shearson Inc.
(TM)Trademark of CS First Boston Corporation
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52
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.
Except for the Registration Fee and the NASD Filing Fee, the following
itemized table sets forth estimates of those expenses payable by the Company in
connection with the offer and sale or exchange of the securities offered hereby:
Registration Fee......................................................... $39,656
NASD Filing Fee.......................................................... 12,000
Printing and Engraving Expenses.......................................... *
Legal Fees and Expenses.................................................. *
Blue Sky Fees and Expenses............................................... *
Accountants' Fees and Expenses........................................... *
Engineers' Fees and Expenses............................................. *
Rating Agency Fees....................................................... *
Miscellaneous Fees and Expenses.......................................... *
-------
Total.......................................................... $ *
-------
-------
---------------
* To be supplied by amendment
ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
The Registrant is incorporated in Delaware. Under Section 145 of the DGCL,
a Delaware corporation has the power, under specified circumstances, to
indemnify its directors, officers, employees and agents in connection with
actions, suits or proceedings brought against them by a third party or in the
right of the corporation, by reason of the fact that they were or are such
directors, officers, employees or agents, against expenses and liabilities
incurred in any such action, suit or proceeding so long as they acted in good
faith and in a manner that they reasonably believed to be in, or not opposed to,
the best interests of such corporation, and with respect to any criminal action,
that they had no reasonable cause to believe their conduct was unlawful. With
respect to suits by or in the right of such corporation, however,
indemnification is generally limited to attorneys' fees and other expenses and
is not available if such person is adjudged to be liable to such corporation
unless the court determines that indemnification is appropriate. A Delaware
corporation also has the power to purchase and maintain insurance for such
persons. Article Ninth of the Certificate of Incorporation of the Registrant
provides for mandatory indemnification of directors and officers to the fullest
extent permitted by Section 145 of the DGCL. Reference is made to the
Certificate of Incorporation of the Registrant.
Reference is also made to the indemnification provisions of Section 7 of
the Underwriting Agreement, the form of which has been filed as Exhibit 1.1
hereto, under which the Underwriters have agreed to indemnify the Registrant,
its directors and officers and certain other persons against liabilities,
including liabilities under the Securities Act of 1933, with respect to
information furnished in writing to the Registrant for use in this Registration
Statement.
The Registrant has entered into indemnification agreements with each of its
officers and directors and may in the future enter into such indemnification
agreements with its directors, officers, employees and agents. Such
indemnification agreements are intended to provide a contractual right to
indemnification, to the extent permitted by law, for costs, expenses (including
attorneys' fees and disbursements), judgments, penalties, fines and amounts paid
in settlement actually and reasonably incurred by the person to be indemnified
in connection with any proceeding (including, to the extent permitted by law,
any derivative action) to which they are, or are
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53
threatened to be made, a party by reason of their status or decisions or actions
in such positions. Such indemnification agreements do not change the basic legal
standards for indemnification set forth in DGCL or the Certificate of
Incorporation of the Registrant. Such provisions are intended to be in
furtherance, and not in limitation of, the general right to indemnification
provided in the certificate of incorporation and Bylaws of the Registrant.
Section 102(b)(7) of the DGCL provides that a certificate of incorporation
may contain a provision eliminating or limiting the personal liability of a
director to the corporation or its stockholders for monetary damages for breach
of fiduciary duty as a director provided that such provision may not eliminate
or limit the liability of a director (i) for any breach of the director's duty
of loyalty to the corporation or its stockholders, (ii) for acts or omissions
not in good faith or which involve intentional misconduct or a knowing violation
of law, (iii) under Section 174 (relating to liability for unauthorized
acquisitions or redemptions of, or dividends on, capital stock) of the DGCL or
(iv) for any transaction from which the director derived an improper personal
benefit. Article Tenth of the Registrant's Certificate of Incorporation contains
such a provision.
The above discussion of the Registrant's Certificate of Incorporation and
Sections 102(b)(7) and 145 of the DGCL is not intended to be exhaustive and is
qualified in its entirety by such Certificate of Incorporation and statutes.
ITEM 16. EXHIBITS.
1.1 -- Form of Underwriting Agreement.*
4.1.1 -- Certificate of Incorporation of Registrant -- incorporated by
reference from Exhibit 3.1 to the Registrant's Registration Statement
on Form S-4 (Registration No. 33-33455).
4.1.2 -- Certificate of Amendment to Certificate of Incorporation of
Registrant filed February 9, 1990 -- incorporated by reference from
Exhibit 3.1.1 to the Registrant's Registration Statement on Form S-4
(Registration No. 33-33455).
4.1.3 -- Certificate of Amendment to Certificate of Incorporation of
Registrant filed May 22, 1991 -- incorporated by reference from
Exhibit 3.1.2 to the Registrant's Registration Statement on Form S-1
(Registration No. 33-43106).
4.1.4 -- Certificate of Amendment to Certificate of Incorporation of
Registrant filed May 24, 1993 -- incorporated by reference from
Exhibit 3.1.5 to the Registrant's Form 10-Q for the quarter ended
June 30, 1993 (File No. 1-10509).
4.1.5 -- Certificate of Designations, Powers, Preferences and Rights of the
Registrant's $4.00 Convertible Exchangeable Preferred
Stock -- incorporated by reference from Exhibit 3.1.3 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1991 (File No. 1-10509).
4.1.6 -- Certificate of Designations of the Registrant's $6.00 Convertible
Exchangeable Preferred Stock -- incorporated by reference from
Exhibit 3.1.4 to the Registrant's Form 10-Q for the quarter ended
June 30, 1993 (File No. 1-10509).
4.2 -- By-Laws of Registrant -- incorporated by reference from Exhibit 3.2
to the Registrant's Registration Statement on Form S-4 (Registration
No. 33-33455).
4.3 -- Form of Indenture.**
4.4 -- Form of Note (included in Exhibit 4.3).
5.1 -- Opinion of Peter E. Lorenzen, Vice President and General Counsel of
the Registrant, as to legality of the securities registered hereby.**
8.1 -- Opinion of Kelly, Hart & Hallman as to certain federal income tax
consequences.**
12.1 -- Computation of Ratio of Earnings to Fixed Charges.***
23.1 -- Consent of Kelly, Hart & Hallman to use of their opinion filed as
Exhibit 8.1 (set forth in their opinion filed as Exhibit 8.1).
23.2 -- Consent of Arthur Andersen & Co.***
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54
23.3 -- Consent of Netherland, Sewell, & Associates, Inc.***
23.4 -- Consent of Peter E. Lorenzen, Esq., Vice President and General
Counsel, to the use of his opinion filed as Exhibit 5.1 (set forth in
his opinion filed as Exhibit 5.1).
24.1 -- Powers of attorney (set forth on the signature page hereof).
25.1 -- Statement of Eligibility of Trustee on Form T-1.*
99.1 -- Report of Netherland, Sewell & Associates, Inc. dated February 10,
1994 relating to certain of the Registrant's property
interests -- incorporated by reference from Exhibit 28.1 to the
Registrant's Annual Report on Form 10-K for the year ended December
31, 1993 (File No. 1-10509).
99.2 -- Report of Netherland, Sewell & Associates, Inc. dated February 11,
1994 relating to their audit of reserve estimates -- incorporated by
reference from Exhibit 28.2 to the Registrant's Annual Report on Form
10-K for the year ended December 31, 1993 (File No. 1-10509).
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* Filed herewith
** To be filed by amendment
*** Previously filed
ITEM 17. UNDERTAKINGS.
(a) The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus 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 posteffective 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.
(b) The undersigned Registrant hereby further 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 15(d) of the
Securities Exchange Act of 1934 (and, where applicable, each filing of an
employee benefit plan's annual report pursuant to Section 15(d) of the
Securities Exchange Act of 1934) that is incorporated by reference in the
Registration Statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.
(c) 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 SEC such indemnification
is against public policy as expressed in the Act and is, therefore,
unenforceable. In the event that claim for indemnification against such
liabilities (other than the payment by the Registrant of expenses incurred or
paid by a director, officer or controlling persons 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.
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SIGNATURES
Pursuant to the requirements of the Securities Act, the Registrant
certifies that it has reasonable grounds to believe that it meets all the
requirements for filing on Form S-3 and has duly caused this Amendment to
Registration Statement to be signed on its behalf by the undersigned, thereunto
duly authorized, in the City of Fort Worth, State of Texas, on March 31, 1994.
SNYDER OIL CORPORATION
By /s/ PETER E. LORENZEN
Peter E. Lorenzen,
Vice President
Pursuant to the requirements of the Securities Act of 1933, this Amendment
to Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.
SIGNATURE TITLE DATE
- --------------------------------------------- ------------------------------ ----------------
* Director and Chairman March 31, 1994
John C. Snyder (Principal Executive Officer
of Registrant)
* Director and President March 31, 1994
Thomas J. Edelman (Principal Financial Officer
of Registrant)
* Director and Executive Vice March 31, 1994
John A. Fanning President
* Director March 31, 1994
Roger W. Brittain
* Director March 31, 1994
John A. Hill
* Director March 31, 1994
B. J. Kellenberger
* Director March 31, 1994
John H. Lichtblau
* Director March 31, 1994
James E. McCormick
* Director March 31, 1994
Alfred M. Micallef
* Vice President and Controller March 31, 1994
James H. Shonsey (Principal Accounting
Officer)
*By /s/ PETER E. LORENZEN
Peter E. Lorenzen, Attorney-in-Fact
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