<PAGE> 1
Filed Pursuant to Rule 424(b)((4)
Registration No. 33-52807
<TABLE>
<S> <C>
(LOGO) $75,000,000
Snyder Oil Corporation
</TABLE>
7% Convertible Subordinated Notes Due 2001
Interest Payable May 15 and November 15 Due May 15, 2001
------------------
The Notes 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 $23.1575 per share, subject to adjustment in
certain events. On May 10, 1994, the last reported sale price for the
Common Stock on the New York Stock Exchange
(Symbol: SNY) was $19 5/8 per
share.
The Notes are redeemable, in whole or in part, at the option of the Company at
any time on or after May 15, 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 Notes will have the right, subject to certain conditions
and restrictions, to require the Company to repurchase outstanding
Notes owned by such holder at their principal amount plus accrued
interest. The Notes are subordinated to all Senior Indebtedness
(as defined) of the Company.
The Notes have been approved for listing on the New York Stock Exchange.
------------------
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.
<TABLE>
<CAPTION>
Underwriting
Price to Discounts and Proceeds to
Public(1) Commissions Company(1)(2)
------------------------------------------------------
<S> <C> <C> <C>
Per Note........................................... 100% 2.75% 97.25%
Total(3)........................................... $75,000,000 $2,062,500 $72,937,500
</TABLE>
- ---------------
(1) Plus accrued interest, if any, from May 18, 1994.
(2) Before deduction of expenses payable by the Company estimated at $500,000.
(3) The Company has granted the Underwriters an option, exercisable for 30 days
from the date of this Prospectus, to purchase up to an additional
$11,250,000 principal amount of Notes in order to cover over-allotments of
Notes. If the option is exercised in full, the total price to public will be
$86,250,000, underwriting discounts and commissions will be $2,371,875, and
proceeds to the Company will be $83,878,125.
The Notes 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 delivery of the
Notes, in temporary or definitive fully registered form, will be made on or
about May 18, 1994. If temporary Notes are delivered, definitive Notes will be
available for exchange as soon as practicable after such date.
CS First Boston
PaineWebber Incorporated
Petrie Parkman & Co.
Smith Barney Shearson Inc.
The date of this Prospectus is May 11, 1994.
<PAGE> 2
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICES OF THE NOTES 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)
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.
<PAGE> 3
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 2.6 MBOE per day in 1991 to an average of 13.3 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 approximately 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 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.
3
<PAGE> 4
THE OFFERING
Securities Offered......... $75,000,000 aggregate principal amount of 7%
Convertible Subordinated Notes Due 2001 (the
"Notes").
Interest Payment Dates..... May 15 and November 15, commencing November 15,
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 $23.1575 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 May 15, 1997,
initially at 103.51% of the principal amount and at
prices declining to 100% at May 15, 2000, 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 Notes will have the right, subject to
certain conditions and restrictions, to require the
Company to repurchase outstanding Notes owned by
such holder at 100% of the principal amount of such
Notes, plus accrued and unpaid interest to the date
of repurchase. Before repurchasing the Notes, the
Company is required, with respect to any Senior
Indebtedness (as defined) that would prohibit the
repurchase of Notes 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 Notes. The Company's existing
bank credit facility contains covenants that may
prohibit the Company from repurchasing the Notes
upon the occurrence of a Change of Control.
Furthermore, the Company's ability to repurchase
the Notes may be limited by its financial resources
at the time a Change of Control occurs.
Ranking.................... Subordinated to all existing and future Senior
Indebtedness of the Company. The indenture (the
"Indenture") with respect to the Notes will not
restrict the incurrence of Senior Indebtedness or
other indebtedness by the Company or any subsidiary
of the Company. The Notes are effectively
subordinated to all existing and future liabilities
of the Company's subsidiaries to the extent of the
assets of such subsidiaries. Immediately following
the sale of the Notes 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 $78 million.
By reason of the subordination of the Notes, in the
event of insolvency of the Company, the holders of
Senior Indebtedness and of indebtedness of the
Company's subsidiaries may recover more, ratably,
than the holders of the Notes.
Sinking Fund............... None.
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.
Listing.................... The Notes have been approved for listing on the New
York Stock Exchange (the "NYSE").
NYSE Common Stock
Symbol................... SNY
4
<PAGE> 5
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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1991 1992 1993
------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C>
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
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31, 1993
----------------------------
ACTUAL AS ADJUSTED(H)
--------- --------------
(IN THOUSANDS)
<S> <C> <C>
BALANCE SHEET DATA
Working capital............................................. $ 1,291 $ 1,291
Oil and gas properties and facilities, net.................. 388,361 388,361
Total assets................................................ 479,536 482,099
Senior debt................................................. 114,952 42,514
Convertible subordinated notes.............................. -- 75,000
Stockholders' equity........................................ 297,241 297,241
</TABLE>
- -------------
(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 $75 million principal amount of
Notes offered hereby, would be 4.8x and 10.9x, 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."
5
<PAGE> 6
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.
<TABLE>
<CAPTION>
DECEMBER 31, 1993
--------------------------------------
DEVELOPED UNDEVELOPED TOTAL
--------- ----------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
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
-------------
</TABLE>
(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.
6
<PAGE> 7
RECENT DEVELOPMENTS
For the three months ended March 31, 1994, the Company's revenues increased
38% to $61.8 million from $44.9 million for the three months ended March 31,
1993. This increase is attributable to a 26% increase in production volumes and
increases in gas processing and transportation revenues, which were partially
offset by a 16% drop in the price realized per equivalent barrel of production.
Income before taxes and extraordinary item rose 33% to $8.6 million from $6.5
million in the 1993 period. Net income remained at $6 million despite a $2.6
million deferred tax provision in the 1994 period. For the three months ended
March 31, 1993, income taxes were reduced from the statutory rate by $2.1
million as a result of the Company's adoption of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes," as of January 1,
1992. Net income per share before extraordinary item fell to $.14 from $.23 in
the prior year period due to the $2.6 million deferred tax provision and $1.5
million of additional preferred stock dividends relating to the April 1993
offering of convertible preferred stock.
Production in the first quarter reached an average of 30,405 BOE per day.
The production increase was primarily due to continued development drilling in
the Wattenberg Field. The Company's average wellhead price for oil in the
quarter fell to $12.02 per barrel from $16.62 for the 1993 period. The net
wellhead price for gas decreased 3% to $1.98 per Mcf from $2.05 per Mcf in the
1993 period.
<TABLE>
<CAPTION>
THREE MONTHS ENDED
MARCH 31,
---------------------
1993 1994
------- -------
<S> <C> <C>
(IN THOUSANDS, EXCEPT
PER SHARE DATA)
FINANCIAL DATA
Revenues............................................................. $44,873 $61,815
Income before taxes and extraordinary item........................... 6,457 8,595
Income before extraordinary item..................................... 6,367 6,003
Net income........................................................... 5,983 6,003
Net income available to common....................................... 4,783 3,264
Weighted average shares outstanding.................................. 22,895 23,307
Per share data
Income before extraordinary item.................................. $ .23 $ .14
Net income........................................................ .21 .14
OPERATING DATA
Average daily production
Oil (Bbl)......................................................... 9,178 11,656
Gas (Mcf)......................................................... 90,033 112,467
BOE............................................................... 24,189 30,405
Average sales price
Oil (per Bbl)..................................................... $ 16.62 $ 12.02
Gas (per Mcf)..................................................... 2.05 1.98
BOE............................................................... 14.25 11.93
Average operating expense per BOE.................................... 5.22 4.37
</TABLE>
7
<PAGE> 8
USE OF PROCEEDS
The net proceeds from the sale of the Notes are estimated to be
approximately $72.4 million ($83.4 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 May 10, 1994 approximately $145.0 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 5.36%. 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 Notes offered hereby
and the application of the estimated net proceeds therefrom.
<TABLE>
<CAPTION>
DECEMBER 31, 1993
--------------------------
ACTUAL AS ADJUSTED
-------- -----------
(IN THOUSANDS)
<S> <C> <C>
Current portion of debt............................................. $ 15 $ 15
-------- -----------
-------- -----------
Long-term debt(a)
Senior debt....................................................... $114,952 $ 42,514
7% Convertible Subordinated Notes Due 2001..................... -- 75,000
-------- -----------
Total long-term debt...................................... 114,952 117,514
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)
-------- -----------
Total stockholders' equity................................ 297,241 297,241
-------- -----------
Total capitalization...................................... $412,193 $ 414,755
-------- -----------
-------- -----------
</TABLE>
- -------------
(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 15,199,568 shares of Common Stock reserved for
issuance as of April 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) 1,736,010 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."
8
<PAGE> 9
PRICE RANGE OF COMMON STOCK AND DIVIDENDS
The Common Stock is listed on the 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 per share of Common Stock.
<TABLE>
<CAPTION>
HIGH LOW DIVIDENDS
---- ---- ---------
<S> <C> <C> <C>
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
Second Quarter (through May 10)......................... 20 3/8 17 1/2 --
-------------
(a) Due to revised payment timing, two payments were made at the $.05 quarterly rate in
the second quarter of 1992.
</TABLE>
On May 10, 1994, the last reported sale price of the Common Stock on the
NYSE was $19 5/8 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."
9
<PAGE> 10
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.
<TABLE>
<CAPTION>
AS OF OR FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1989 1990 1991 1992 1993
------- -------- -------- -------- --------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- ---------------
(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 $75 million principal amount of Notes
offered hereby, would be 4.8x and 10.9x, 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 (49%) 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 substantially reduced in April 1993 with proceeds from a preferred offering,
but increased through yearend as
- ---------------
(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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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 ("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
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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 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
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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
with a syndicate of banks for whom NationsBank of Texas, N.A. acts as agent 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%. The Company's bank credit facility
contains certain restrictive covenants (including restrictions on mergers and
asset sales, the payment of dividends, the incurrence of additional indebtedness
and the creation of liens) and requires that the Company meet certain financial
ratios and tests. Among other things, such facility generally limits the amount
of dividends and other restricted payments (including payments of principal on
the Notes prior to their stated maturity) by the Company to an amount equal to
the sum of (i) $10,000,000,
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(ii) the net cash proceeds to the Company from all equity offerings completed
after March 31, 1993 and (iii) 50% of the Company's consolidated cash flow after
March 31, 1993. Based on such limitations, $86.5 million would have been
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.
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No assurances can be given that such conditions will be satisfied and,
accordingly, that such locations will be drilled.
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.
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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 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 in the Codell/Niobrara formations cost
an average of only $65,000 per well. The average net cost of a completed well in
these formations 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
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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.
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,
18
<PAGE> 19
improvement of the water injection system and completion of two new wells
increased daily production 8% 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
$.4 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
19
<PAGE> 20
basis for the East Washakie Project, the Company's second operating hub in the
Rockies. See "-- Development -- East Washakie."
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:
<TABLE>
<CAPTION>
PURCHASE PRICE
---------------------------------
YEAR MAJOR ASSETS ACQUIRED COMPANY AFFILIATES TOTAL
---- --------------------------------------------- ------- ---------- ------
(MILLIONS)
<S> <C> <C> <C> <C>
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
------- ---------- ------
------- ---------- ------
</TABLE>
- ---------------
(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 additional 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.
20
<PAGE> 21
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 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-
21
<PAGE> 22
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 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 6.5 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
22
<PAGE> 23
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 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.
23
<PAGE> 24
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.
<TABLE>
<CAPTION>
DECEMBER 31,
-----------------------------------------------------
1989 1990 1991 1992 1993
------- ------- ------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT PRICE AND PER BARREL EXPENSES)
<S> <C> <C> <C> <C> <C>
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
</TABLE>
- ---------------
(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.
24
<PAGE> 25
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.
<TABLE>
<CAPTION>
1991 1992 1993
----- ----- -----
<S> <C> <C> <C>
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
</TABLE>
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."
25
<PAGE> 26
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.
<TABLE>
<CAPTION>
PROVED RESERVE
QUANTITIES PRETAX PW10% VALUE
------------------------ ------------------------
CRUDE OIL NATURAL AMOUNT PERCENT
AND LIQUIDS GAS -------------- -------
----------- -------- (IN THOUSANDS)
(MBBL) (MMCF)
<S> <C> <C> <C> <C>
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%
----------- -------- -------------- -------
----------- -------- -------------- -------
</TABLE>
Proved Reserves. The following table sets forth estimated yearend proved
reserves for the three years ended December 31, 1993.
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------------
1991 1992 1993
------- ------- -------
<S> <C> <C> <C>
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
------- ------- -------
------- ------- -------
</TABLE>
- ---------------
(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.
<TABLE>
<CAPTION>
DECEMBER 31, 1993
-----------------------------------------
DEVELOPED UNDEVELOPED(A) TOTAL
--------- -------------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
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)
--------- -------------- --------
--------- -------------- --------
</TABLE>
- ---------------
(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.
26
<PAGE> 27
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.
<TABLE>
<CAPTION>
AVERAGE
PRINCIPAL GROSS NET WORKING
PRODUCT STREAM WELLS WELLS INTEREST
----------------------------------------------------- ----- ----- -------
<S> <C> <C> <C>
Crude oil and liquids................................ 3,026 1,297 43%
Natural gas.......................................... 2,096 890 42%
----- ----- -------
Total...................................... 5,122 2,187 43%
----- ----- -------
----- ----- -------
</TABLE>
27
<PAGE> 28
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 NOTES
The Notes are to be issued under an Indenture to be dated as of May 1, 1994
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 "Trust Indenture Act"). 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 the definitions of certain capitalized terms used 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 Notes will be unsecured subordinated obligations of the Company, will
mature on May 15, 2001 and will be in the aggregate principal amount of
$75,000,000 ($86,250,000 aggregate principal amount if the Underwriters'
over-allotment option is exercised in full). The Notes will bear interest from
the date of issuance at the rate per annum shown on the cover page of this
Prospectus. Interest will be payable semi-annually on May 15 and November 15 of
each year, commencing November 15, 1994, to the persons in whose names such
Notes (or any predecessor Notes) are registered at the close of business on the
May 1 or November 1 preceding such Interest Payment Date (Sections 301 and 307).
28
<PAGE> 29
Principal of and premium, if any, and interest on the Notes will be
payable, and the Notes will be convertible and may be presented for transfer and
exchange, at the office or agency maintained by the Company for such purposes,
which will initially be the office of the Trustee located at 80 Broad Street,
Fourth Floor, New York, New York 10004. However, at the option of the Company,
payment of interest on the Notes may be made by check mailed to the address of
persons entitled thereto as shown in the register of the Security Registrar. No
service charge will be made upon any registration of transfer or exchange of the
Notes, but the Company may require payment of a sum sufficient to cover any tax
or other governmental charge payable in connection therewith.
The Indenture does not limit the incurrence of additional indebtedness,
including Senior Indebtedness, by the Company.
CONVERSION RIGHTS
The Notes 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 Notes called for redemption,
conversion rights will terminate at the close of business on the fifth business
day preceding the Redemption Date, except that, with respect to any redemption
occurring on May 15, 1997 or within five business days thereafter, conversion
rights will terminate at the close of business on the Redemption Date such that
all holders of Notes to be redeemed will be entitled to receive the May 15, 1997
interest payment (assuming such holders held the Notes on May 1, 1997).
Notwithstanding anything to the contrary in the foregoing, the Notes will not be
convertible at any time when payments on the Notes are prohibited under the
subordination provisions of the Indenture as described under "-- Subordination
of Notes" (Section 1201).
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 Note, 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 Note
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 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)
29
<PAGE> 30
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 Notes (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 recipient (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 Note only into the kind and amount of
securities, cash and other property receivable upon the consolidation, merger,
transfer or lease by a holder of the number of shares of Common Stock into which
such Note 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 Notes for interest accrued thereon.
The Company's delivery to the holder of the fixed number of shares of Common
Stock into which the Note is convertible will be deemed to satisfy the Company's
obligation to pay the principal amount of the Note and all accrued interest that
has not previously been paid. If a Note 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 Note so
surrendered will be paid in cash to the person in whose name such Note is
registered at the close
30
<PAGE> 31
of business on such Regular Record Date, and (except in the case of Notes with a
Maturity Date prior to such Interest Payment Date) when so surrendered for
conversion, such Note 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 NOTES
The payment of the principal of and premium, if any, and interest on the
Notes 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 Notes 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 Notes, including payment of the Redemption Price and the Change
of Control Purchase Price of the Notes, and before the Notes 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
Notes, including payment of the Redemption Price and the Change of Control
Purchase Price on the Notes, may be made, and the Notes 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 Notes, including payment of the Redemption Price and the Change
of Control Purchase Price on the Notes, may be made, and the Notes 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
holders of at least a majority in principal amount 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 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 Notes 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 Notes set forth above will
not prevent the occurrence of any Event of Default under the Indenture.
Furthermore, the subordination of the Notes as set forth above will not impair,
as between the Company, the holders of the Notes and creditors of the Company
other than holders of Senior Indebtedness, the obligations of the Company to
make payments on the Notes in accordance with their terms. In certain
circumstances, as set forth in the Indenture, the holders of Notes 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 Notes.
31
<PAGE> 32
The Notes 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 Notes 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 Notes offered hereby and application
of the proceeds therefrom, the Company estimates that the sum of its Senior
Indebtedness and the indebtedness of its subsidiaries will total approximately
$78 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 Notes 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 Notes or is unable to repay all Senior
Indebtedness, there would be both an Event of Default under the Notes 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 Notes or making other payments in respect thereof. Furthermore, the
exercise by the holders of their right to require the Company to repurchase the
Notes 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
Notes could be blocked pursuant to the subordination terms of the Indenture.
Finally, the Company's ability to pay cash to the holders of Notes 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 Notes, whether or not such repurchase is
permitted by the subordination terms of the Indenture. See " -- Repurchase of
Notes 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 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
32
<PAGE> 33
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 Notes 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 Notes, (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 Notes not being senior
in right of payment to such debentures) or (D) any obligation constituting a
trade account payable (Section 101).
REDEMPTION
The Notes will be redeemable, at the Company's option, as a whole or from
time to time in part, at any time on or after May 15, 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 May 15 of the
years indicated:
<TABLE>
<CAPTION>
YEAR REDEMPTION PRICE
--------------------------------------------- ----------------
<S> <C>
1997......................................... 103.51%
1998......................................... 102.34%
1999......................................... 101.17%
2000......................................... 100.00%
</TABLE>
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 Notes are to be redeemed, the Notes 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 Notes 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. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Financial Condition and Capital
Resources."
REPURCHASE OF NOTES 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 Notes 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
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<PAGE> 34
(provided that the principal amount must be $1,000 or an integral multiple
thereof) of the holder's Notes 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 Notes 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 Notes 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 Notes as provided below. The
Company first is required to comply with the covenants in the preceding sentence
before it is required to repurchase Notes 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
Notes 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 Notes; 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).
To exercise the right to have Notes 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 Notes to be delivered by the
holder thereof for purchase by the Company; (ii) the portion of the principal
amount of Notes to be repurchased, which portion must be $1,000 or an integral
multiple thereof; and (iii) that such Notes are to be repurchased by the Company
pursuant to the applicable provision of the Indenture (Section 1401).
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 Notes 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 Notes for which a
Change of Control Purchase Notice has been delivered and not withdrawn is
conditioned upon delivery of such Notes (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 Notes will be made promptly following the later
of the Change of Control Purchase Date and the time of delivery of such Notes
(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
consolida-
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<PAGE> 35
tion 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 Notes 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 Notes in effect immediately preceding the
time of such Change of Control, or (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 Notes 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 Notes by one
or more gradations below the rating of the Notes 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 Notes 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 Notes in effect on the date immediately preceding the closing date
of such transaction (Section 1401).
A Change of Control that is initiated or supported by the Company,
management of the Company or affiliates of such parties and which constitutes a
Repurchase Event will entitle holders of the Notes to the same rights to require
the Company to repurchase their Notes as any other Change of Control which
constitutes a Repurchase Event.
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 Notes at the option of holders upon a Change of
Control (Section 1405). The Change of Control purchase feature of the Notes 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,
35
<PAGE> 36
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 Notes. 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
Notes tendered by the holders thereof.
No Note 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 Notes 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. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Financial Condition
and Capital Resources." 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 Notes 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 Notes or is unable to repay all Senior Indebtedness, there
would be both an Event of Default under the Notes 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
Notes or making other payments in respect thereof. Furthermore, the exercise by
the holders of their right to require the Company to repurchase the Notes 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 Notes could be blocked pursuant
to the subordination terms of the Indenture. Finally, the Company's ability to
pay cash to the holders of Notes 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 Notes, 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 Notes,
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 Notes 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 Notes (Section 802).
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<PAGE> 37
MODIFICATION AND WAIVER
Modifications and amendments of the Indenture may be made by the Company
and the Trustee with the consent of the holders of not less than a majority in
aggregate principal amount of the Notes at the time outstanding, and holders of
not less than a majority in aggregate principal amount of the Notes 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 Note affected
thereby, (i) change the Stated Maturity of the principal of or the due date of
any installment of interest on any Note, (ii) reduce the principal amount of, or
the rate of interest on, or any premium payable upon redemption of, any Note,
(iii) change the currency of payment of principal of, or premium, if any, or
interest on, any Note, (iv) impair the right to institute suit for the
enforcement of any payment on or with respect to any Note on or after the Stated
Maturity, or the Redemption Date in case of the redemption of any Note, (v)
adversely affect the right of a holder to convert Notes, (vi) modify the
provisions of the Indenture with respect to the subordination of the Notes in a
manner adverse to the holders, (vii) reduce the above-stated percentage of
outstanding Notes necessary to modify or amend the Indenture, or (viii) reduce
the percentage in aggregate principal amount of outstanding Notes necessary for
waiver of compliance with certain provisions of the Indenture or for waiver of
certain defaults (Sections 902 and 1009). The Indenture also contains provisions
permitting the Company and the Trustee to effect certain minor modifications of
the Indenture not adversely affecting the rights of holders of Notes in any
material respect. (Sections 901 and 902).
The holders of a majority in aggregate principal amount of the outstanding
Notes 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
Note, including the Redemption Price, or a default with respect to right of
holders to convert the Notes (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 Note,
whether or not such payment is prohibited by the subordination provisions of the
indenture; (ii) failure to pay any interest on any Note 30 days after payment 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 Notes 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 Notes, and either (a) the holders duly elect to
have at least 25% in principal amount of outstanding Notes repurchased or (b)
the holders of at least 25% in principal amount of the outstanding Notes 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 Notes or the Trustee thereafter gives the Notice of
Default to the Company and, if applicable, the Trustee (Section 501).
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<PAGE> 38
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 Notes 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 Notes
may accelerate the maturity of all Notes 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 Notes 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 Notes 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 Note 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 Notes shall have made written request, and offered reasonable
indemnity, to the Trustee to institute such proceeding as trustee, the Trustee
shall not have received from the holders of a majority in aggregate principal
amount of the outstanding Notes 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 Note for the enforcement of payment of the principal
of or premium, if any, or interest on such Note or the Redemption Price on or
after the respective due dates expressed in such Note or of the right to convert
such Note 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 Notes 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 Notes and that the provisions of the Indenture (including
the provisions described under " -- Subordination of Notes") will no longer
be in effect with respect to the Notes (except for the obligations to
register the transfer or exchange of the Notes, to replace temporary or
mutilated, destroyed, lost or stolen Notes, to maintain an office or agency
in respect of Notes and to hold monies for payment in trust)
("Defeasance"); or
(b) to be released from its obligations with respect to the Notes
under certain restrictive covenants of the Indenture, and that the event of
the type described under the clause (iv) under " -- Events of
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<PAGE> 39
Default" will not be deemed to be an Event of Default under the indenture
and that the provisions described under " -- Subordination of Notes" 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 Notes 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 Notes (Article XV).
Such a trust may be established with respect to the Notes 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 Notes 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 Notes issued thereunder
and the Notes 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 Notes at the time any
acceleration 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 Notes 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) after a default under the Indenture, the Trustee either
shall eliminate such conflicting interest or resign as Trustee.
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<PAGE> 40
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 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.
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<PAGE> 41
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, 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.
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<PAGE> 42
UNDERWRITING
The underwriters named below (the "Underwriters") have severally agreed to
purchase from the Company the following respective principal amounts of Notes:
<TABLE>
<CAPTION>
PRINCIPAL
UNDERWRITER AMOUNT
------------------------------------------------------------------------ -----------
<S> <C>
CS First Boston Corporation............................................. $18,750,000
PaineWebber Incorporated................................................ 18,750,000
Petrie Parkman & Co., Inc............................................... 18,750,000
Smith Barney Shearson Inc............................................... 18,750,000
-----------
Total......................................................... $75,000,000
-----------
-----------
</TABLE>
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 Notes offered hereby, if
any are purchased.
The Company has granted to the Underwriters an option, expiring at the
close of business on the 30th day after the date of this Prospectus, to purchase
up to an additional $11,250,000 aggregate principal amount of the Notes at the
initial public offering price less the underwriting discount, all as set forth
on the cover page of this Prospectus. The Underwriters may exercise such option
only to cover over-allotments in the sale of the Notes.
The Company has been advised by the Underwriters that they propose to offer
the Notes 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 of 1.65% of the principal amount per Note; that the Underwriters and
such dealers may allow a discount of 0.25% of such principal amount per Note on
sales to certain other dealers; and that after the initial public offering, the
public offering price and concession and discount to dealers may be changed by
the Underwriters.
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, in the case of the Company, 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 civil liabilities under the Securities Act of 1933 or to
contribute to payments which 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 Notes have been approved for listing on the NYSE.
CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the Notes in Canada is being made only on a private
placement basis exempt from the requirement that the Company prepare and file a
prospectus with the securities regulatory authorities in each province where
trades of Notes are effected. Accordingly, any resale of the Notes in Canada
must be made in accordance with applicable securities laws, which will vary
depending on the relevant jurisdiction and which may require resales to be made
in accordance with available statutory exemptions or pursuant to a
42
<PAGE> 43
discretionary exemption granted by the applicable Canadian securities regulatory
authority. Purchasers are advised to seek legal advice prior to any resale of
the Notes.
REPRESENTATIONS OF PURCHASERS
Each purchaser of Notes in Canada who receives a purchase confirmation will
be deemed to represent to the Company and the dealer from whom such purchase
confirmation is received that (i) such purchaser is entitled under applicable
provincial securities laws to purchase such Notes without the benefit of a
prospectus qualified under such securities laws, (ii) where required by law,
that such purchaser is purchasing as principal and not as agent and (iii) such
purchaser has reviewed the text above under "-- Resale Restrictions."
NOTICE TO ONTARIO RESIDENTS
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
section 32 of the Regulation under the Securities Act (Ontario). As a result,
Ontario purchasers must rely on other remedies that may be available, including
common law rights of action for damages or rescission or rights of action under
the civil liability provisions of the U.S. federal securities laws.
All of the Company's directors and officers, as well as the experts named
herein, may be located outside of Canada and, as a result, it may not be
possible for Ontario purchasers to effect service of process within Canada upon
the Company or such persons. All or a substantial portion of the assets of the
Company and such persons may be located outside of Canada and, as a result, it
may not be possible to satisfy a judgment against the Company or such persons in
Canada or to enforce a judgment obtained in Canadian courts against the Company
or persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of Notes to whom the Securities Act (British Columbia) applies
is advised that such purchaser is required to file with the British Columbia
Securities Commission a report within ten days of the sale of any Notes acquired
by such purchaser pursuant to this Offering. Such report must be in the form
attached to British Columbia Securities Commission Blanket Order BOR No. 88-5, a
copy of which may be obtained from the Company. Only one such report must be
filed in respect of Notes acquired on the same date and under the same
prospectus exemption.
LEGAL OPINIONS
The validity of the Notes and the Common Stock issuable upon conversion of
the Notes 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. 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
43
<PAGE> 44
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 Notes 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 Notes, 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.
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, as amended by Form 10-K/A1 dated April 22, 1994.
All documents filed by the Company pursuant to Section 13(a), 13(c), 14 or
15(d) of the Exchange Act subsequent to the date of this Prospectus and prior to
the termination of the offering of the Notes 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.
44
<PAGE> 45
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)
<PAGE> 46
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NO DEALER, SALESPERSON OR ANY OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS AND, IF GIVEN OR MADE, SUCH INFORMATION OR
REPRESENTATION 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 OF THE SECURITIES OFFERED HEREBY IN ANY
JURISDICTION 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
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary...................... 3
Recent Developments..................... 7
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 Notes.................... 28
Description of Capital Stock............ 40
Underwriting............................ 42
Canadian Residents...................... 42
Legal Opinions.......................... 43
Experts................................. 43
Available Information................... 44
Incorporation of Certain Documents by
Reference............................. 44
</TABLE>
- -----------------------------------------------------------------------------
- -----------------------------------------------------------------------------
(LOGO)
Snyder Oil Corporation
$75,000,000
7% Convertible Subordinated
Notes Due 2001
PROSPECTUS
CS First Boston
PaineWebber Incorporated
Petrie Parkman & Co.
Smith Barney Shearson Inc.
- ----------------------------------------------------------------------------
