<PAGE> 1
This filing is made pursuant
to Rule 424(b)(4) under
the Securities Act of
1933 in connection with
Registration No. 33-94678
$11,000,000
[LOGO] SABA PETROLEUM COMPANY
9% CONVERTIBLE SENIOR SUBORDINATED DEBENTURES DUE 2005
The Debentures are convertible at any time prior to maturity, unless
previously redeemed, into shares of Common Stock of Saba Petroleum Company
("Saba" or "Company") at a conversion price of $8.75 per share, subject to
adjustment in certain events. The Common Stock of the Company is listed on the
American Stock Exchange ("AMEX") under the symbol "SAB" and the Debentures have
been approved for listing on the AMEX under the symbol "SAB.A." On December 19,
1995, the last reported sale price of the Common Stock on the AMEX was $7.88.
Interest on the Debentures is payable semi-annually on June 15 and December
15 of each year commencing June 15, 1996. The Debentures are redeemable in whole
or in part at the option of the Company at any time prior to maturity at the
redemption prices set forth herein, plus accrued interest, provided that the
Debentures may not be redeemed prior to December 15, 1997. Mandatory sinking
fund payments of 15% of the original principal amount of the Debentures,
required annually commencing December 15, 2000, are calculated to retire 75% of
the original principal amount of the Debentures prior to maturity.
The Debentures are unsecured and subordinated to all present and future
Senior Debt (as defined) of the Company ($17.8 million at September 30, 1995)
and are effectively subordinated to all liabilities of subsidiaries of the
Company ($4.7 million at September 30, 1995). See "Description of the
Debentures."
AN INVESTMENT IN THE DEBENTURES INVOLVES A HIGH DEGREE OF RISK. SEE "RISK
FACTORS" AT PAGE 10.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES
COMMISSION PASSED UPON THE ACCURACY OR ADEQUACY OF
THIS PROSPECTUS. ANY REPRESENTATION TO THE
CONTRARY IS A CRIMINAL OFFENSE.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
PRICE TO UNDERWRITING PROCEEDS TO THE
PUBLIC DISCOUNT(1) COMPANY(2)
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Per Debenture............................... $1,000 $80 $920
- -----------------------------------------------------------------------------------------------------------
Total(3).................................... $11,000,000 $880,000 $10,120,000
- -----------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------
</TABLE>
(1) See "Underwriting" for information concerning indemnification of the
Underwriters and other matters.
(2) Before deducting expenses payable by the Company estimated at $900,000.
(3) The Company has granted to the Underwriters an option, exercisable within 45
days of the date hereof, to purchase up to $1,650,000 in principal amount of
additional Debentures at the Price to Public less the Underwriting Discount
for the purpose of covering over-allotments, if any. If the Underwriters
exercise this option in full, the Price to Public will total $12,650,000,
the Underwriting Discount will total $1,012,000, and the Proceeds to the
Company will total $11,638,000.
The Debentures offered by this Prospectus are offered by the Underwriters
subject to prior sale when, as and if 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 Debentures will be made at the offices of Van
Kasper & Company, San Francisco, California on or about December 26, 1995.
VAN KASPER & COMPANY
December 20, 1995
<PAGE> 2
[ARTWORK]
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE DEBENTURES OR
THE COMMON STOCK OF THE COMPANY ON THE AMEX, IN THE OVER-THE-COUNTER MARKET OR
OTHERWISE AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH STABILIZING, IF COMMENCED, MAY BE DISCONTINUED AT ANY TIME.
<PAGE> 3
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information appearing elsewhere in this Prospectus. Unless otherwise indicated
or the context otherwise requires, (i) references to the "Company" or "Saba" are
to Saba Petroleum Company and its subsidiaries and (ii) the information in this
Prospectus does not give effect to the exercise of the Underwriters'
over-allotment option. See "Description of the Debentures -- Certain
Definitions" and "Glossary" for the definition of certain terms used herein.
THE COMPANY
Saba is an international oil and gas producer with producing properties in
the United States, Canada and Colombia.
In 1991, subsequent to becoming the majority shareholder of the Company,
Mr. Ilyas Chaudhary instituted a business strategy of positioning the Company
for future growth and profitability by increasing its oil and gas reserves. The
Company has pursued this objective through the acquisition of producing oil and
gas properties, including properties that have development potential, and
companies with oil and gas reserves. The following table shows certain increases
that have resulted from the Company's pursuit of this strategy from 1991 through
1994:
<TABLE>
<CAPTION>
AT OR FOR THE YEAR ENDED
DECEMBER 31,
-------------------------- PERCENTAGE
1991 1994 INCREASE
----------- ----------- ----------
<S> <C> <C> <C>
TOTAL REVENUES......................................... $ 3,944,000 $12,954,000 228%
PRODUCTIVE OIL AND GAS WELLS:
Gross............................................... 280 605 116%
Net................................................. 82 224 173%
PRODUCTION:
Oil (Bbls).......................................... 149,000 738,000 395%
Gas (Mcf)........................................... 479,000 1,453,000 203%
BOE(1).............................................. 229,000 980,000 328%
RESERVE INFORMATION:
Proved reserves(2)(3):
Oil (Bbls)........................................ 1,324,000 7,136,000 439%
Gas (Mcf)......................................... 3,492,000 9,792,000 180%
BOE............................................... 1,906,000 8,768,000 360%
Future net revenues (before income taxes)(4)........ $15,268,000 $40,167,000 163%
Discounted future net revenues (before income
taxes)(4)......................................... $11,126,000 $26,014,000 134%
Future net cash flows (net of income taxes)(5)...... $11,307,000 $31,711,000 180%
Discounted future net cash flows (net of income
taxes)(5)......................................... $ 8,234,000 $21,127,000 157%
</TABLE>
RECENT DEVELOPMENTS
Since January 1, 1995, Saba has completed several significant transactions
that have added materially to its proved reserves and its future net revenues
and discounted future net revenues. See "Summary Pro Forma Combined Financial
and Oil and Gas Data" below.
In September 1995, the Company acquired from a subsidiary of Texaco Inc.
(Texaco and the subsidiary are each referred to below as "Texaco") one-half of
Texaco's 50% interest in the Teca and Nare oil fields (the "Teca/Nare Fields")
and one-half of Texaco's 100% interest in the Velasquez-Galan pipeline (the
"Velasquez-Galan Pipeline"), both of which are located in Colombia, South
America. As part of this transaction, the Company has entered into a contract
with Texaco to acquire later in 1995 one-half of Texaco's 100% interest
- ---------------
(1) Barrels of oil equivalent.
(2) The components of the Company's reserves (different grades of crude oil and
natural gas) and year-end oil and gas prices can materially impact the
information shown. The average year-end prices expressed in BOE were $15.16,
$13.95, $10.52 and $11.60 on December 31, 1991, 1992, 1993 and 1994,
respectively.
(3) See "Supplemental Information About Oil and Gas Producing Activities
(Unaudited)" following the Notes to the Consolidated Financial Statements of
the Company.
(4) Future net revenues and discounted future net revenues are based on reserve
reports prepared by independent petroleum engineers on a pre-tax basis using
sales prices and costs in effect as of the respective dates of the reports
and a 10% discount rate. See footnotes (2), (3) and (5).
(5) Future net cash flows and discounted future net cash flows represent the
estimated after-tax amounts of the future net revenues and discounted future
net revenues set forth above, applying the statutory income tax rates in
effect as of the dates for which the information is presented, in accordance
with Statement of Financial Accounting Standards No. 69. See footnotes (2),
(3) and (4). Neither this information, nor such information on a pre-tax
basis (footnote (4)), should be viewed as estimates of future cash flows or
of the current value of the Company.
3
<PAGE> 4
in the adjacent Cocorna oil field (the "Cocorna Field" and together with the
Teca/Nare Fields and the Velasquez-Galan Pipeline, the "TNC Fields"). During the
first nine months of 1995, the Company also acquired a 25% fee interest in the
Velasquez oil field in Colombia (the "Velasquez Field") and leasehold interests
in oil and gas fields in Texas (the "Cabot Properties").
The Company's gross acquisition cost for the interests in the Teca/Nare
Fields and the Velasquez-Galan Pipeline was $12.25 million, which was reduced by
the Company's share of production credits from the properties from January 1,
1995 to the closing date (approximately $3.95 million), leaving a net purchase
price of approximately $8.3 million. In addition, the Company assumed an oil
imbalance obligation of approximately $930,000 in connection with the
acquisition. The Company's gross acquisition cost for the Cocorna Field is
$750,000, which will be reduced by the Company's share of production credits
from the property from January 1, 1995 to the closing date (approximately
$200,000 at September 30, 1995), leaving a net purchase price of approximately
$550,000. In connection with these acquisitions, the Company is required to
pledge collateral consisting of either a $1.75 million certificate of deposit or
a commitment of $1.75 million against the Company's borrowing base under its
bank credit facility to the operator of the fields to secure payments due third
party vendors at the Teca/Nare Fields.
The Company financed the purchase price of the Teca/Nare Fields and the
Velasquez-Galan Pipeline in part through a loan of $700,000 from Capco Resources
Ltd. ("Capco"), the majority shareholder of the Company, a $1.5 million loan
from Capco Resources, Inc. ("CRI"), which, until December 1995, was a
wholly-owned subsidiary of Capco and is now a majority-owned subsidiary of
Capco, and a $4.7 million loan from a bank. Of the $700,000 loan, $600,000 will,
at or prior to the closing of the Offering, be converted into 75,000 shares of
Common Stock of the Company (a conversion price of $8.00 per share) (the "Capco
Common Stock Conversion"). Effective at the closing, the maturity of the $1.5
million loan from CRI and the $100,000 balance of the loan from Capco will be
extended to April 1, 2006, and such loans (collectively, the "CRI Subordinated
Debt") will be subordinated to the same extent the Debentures are subordinated
(the extension of maturity and subordination of the CRI Subordinated Debt are
referred to below as the "CRI Debt Conversion"). Mr. Chaudhary is the majority
shareholder of Capco and has guaranteed the $4.7 million bank loan. See "Use of
Proceeds."
In addition, in order to increase margins on heavy crude oil from the
Company's oil and gas producing operations in Santa Barbara County, California,
the Company acquired from Conoco Inc. and Douglas Oil Company of California an
asphalt refinery in Santa Maria, California that had been inoperative since
October 1993. The Company refurbished the refinery and, in May 1995, completed a
re-permitting and environmental impact review process with Santa Barbara County
and received a Conditional Use Permit to operate the refinery. The refinery
re-commenced operations in June 1995. Under a processing agreement with Petro
Source Refining Corporation ("Petro Source"), previously a subsidiary of Bechtel
Inc., Petro Source purchases crude oil (including crude oil produced by the
Company), delivers it to the refinery, reimburses the Company's
out-of-pocket-costs for refining, markets the asphalt and other products
produced or refined and generally shares any profits equally with the Company.
Throughput at the refinery is currently 1,500 barrels of oil per day ("BOPD").
The refinery has the capacity to process approximately 8,000 BOPD.
The Company intends to continue its business plan of acquiring additional
producing oil and gas properties, including properties that have development
potential, and companies that have oil and gas reserves, both domestically and
internationally; it is from time to time, including at the present time, engaged
in negotiations to do so; and it may make such acquisitions for one or more of
cash, notes or its securities.
SUMMARY PRO FORMA COMBINED FINANCIAL AND OIL AND GAS DATA
The following unaudited pro forma combined financial and oil and gas data
of the Company for the year ended December 31, 1994 and the nine months ended
September 30, 1995 reflects (i) the acquisition by the Company of its interests
in the Teca/Nare Fields and the Velasquez-Galan Pipeline, which was completed in
September 1995, and the Cocorna Field, which is anticipated to be completed in
the first quarter of 1996, (ii) the acquisition by the Company of the Velasquez
Field and Cabot Properties (acquired in January and May 1995, respectively) and
(iii) the merger of the Company's Canadian subsidiary into a publicly-held
Canadian company, completed in October 1995, and an approximately $350,000
investment by the Company in the Canadian company (anticipated to be completed
in the first quarter of 1996) (together, the "CRPL Business Combination" and,
together with the acquisitions of the Velasquez Field and Cabot Properties, the
"Net Other Transactions"), as if each of these transactions and related
financings had occurred on January 1, 1994 or January 1, 1995. The summary pro
forma combined financial and oil and gas data is presented for illustrative
purposes only and is not necessarily indicative of the consolidated statements
of operations data,
4
<PAGE> 5
production data, proved reserves, future net revenues, discounted future net
revenues, future net cash flows or discounted future net cash flows the Company
would have had if these transactions had occurred at the beginning of the
periods presented, nor is it intended to be indicative of future operations or
production.
In connection with the preparation of the pro forma financial data, it was
assumed, in accordance with Securities and Exchange Commission (the
"Commission") requirements, that the purchase price for the TNC Fields as of
January 1, 1995 was the purchase price paid in September 1995 (for the Teca/Nare
Fields and Velasquez-Galan Pipeline) and to be paid in the first quarter of 1996
(for the Cocorna Field). The purchase price so paid and payable ($8.8 million
plus an oil imbalance obligation of approximately $900,000) is less than the
contract price of $13.0 million plus assumption of the oil imbalance obligation
because, under the contract, which was signed in February 1995, the purchase
price is adjusted for production from January 1, 1995 to closing. Accordingly,
had the purchases been completed on January 1, 1995, the purchase price and
related debt incurred by the Company would have been significantly higher. See
note 5 on page 6.
<TABLE>
<CAPTION>
TNC NET OTHER PRO FORMA
COMPANY(1) FIELDS(2)(3) TRANSACTIONS(2) COMBINED(3)
----------- ---------------- --------------- -----------
<S> <C> <C> <C> <C>
CONSOLIDATED STATEMENT OF OPERATIONS DATA:
YEAR ENDED DECEMBER 31, 1994:
Revenues................................... $12,954,000 $11,516,000 $3,147,000 $27,617,000
Direct operating expenses(4)............... 7,547,000 5,247,000 1,734,000 14,528,000
----------- ---------- --------- -----------
Revenues in excess of direct operating
expenses.............................. $ 5,407,000 $ 6,269,000 $1,413,000 $13,089,000
=========== ========== ========= ===========
NINE MONTHS ENDED SEPTEMBER 30, 1995:
Revenues................................... $11,393,000 $ 9,793,000 $ 794,000 $21,980,000
Direct operating expenses(4)............... 6,923,000 3,726,000 270,000 10,919,000
----------- ---------- --------- -----------
Revenues in excess of direct operating
expenses.............................. 4,470,000 6,067,000 524,000 11,061,000
General and administrative expenses........ 1,406,000 98,000 230,000 1,734,000
Depletion, depreciation and
amortization(5).......................... 1,931,000 1,015,000 254,000 3,200,000
----------- ---------- --------- -----------
Operating income........................... 1,133,000 4,954,000 40,000 6,127,000
Other income............................... 50,000 -- -- 50,000
Interest expense(5)........................ (778,000) (568,000) (126,000) (1,472,000)
(Provision) benefit for taxes on income.... (175,000) (1,886,000) 16,000 (2,045,000)
Minority interest.......................... -- -- 5,000 5,000
----------- ---------- --------- -----------
Net income (loss)(5)..................... $ 230,000 $ 2,500,000 $ (65,000) $ 2,665,000
=========== ========== ========= ===========
Net income per common share(5)........... $ 0.05 $ 0.61
=========== ===========
Fully diluted net income per common
share(6).............................. $ 0.54
===========
PRODUCTION:
YEAR ENDED DECEMBER 31, 1994:
Oil (Bbls)................................. 738,000 1,034,000 283,000 2,055,000
Gas (Mcf).................................. 1,453,000 -- 374,000 1,827,000
BOE........................................ 980,000 1,034,000 346,000 2,360,000
Average sales price (per unit):
Oil (Bbls)............................... $ 13.08 $ 9.61 $ 8.53 $ 10.71
Gas (Mcf)................................ 1.73 -- 1.84 1.76
BOE...................................... 12.42 9.61 8.99 10.69
NINE MONTHS ENDED SEPTEMBER 30, 1995:
Oil (Bbls)................................. 746,000 712,000 47,000 1,505,000
Gas (Mcf).................................. 1,052,000 -- 106,000 1,158,000
BOE........................................ 921,000 712,000 65,000 1,698,000
Average sales price (per unit):
Oil (Bbls)............................... $ 12.82 $ 11.77 $ 13.59 $ 12.35
Gas (Mcf)................................ 1.35 -- 1.31 1.34
BOE...................................... 11.92 11.77 12.02 11.86
RESERVE INFORMATION AT DECEMBER 31, 1994(7):
Proved Reserves(8):
Oil (Bbls)................................. 7,136,000 5,302,000 3,253,000 15,691,000
Gas (Mcf).................................. 9,792,000 -- 1,076,000 10,868,000
BOE........................................ 8,768,000 5,302,000 3,432,000 17,502,000
Future net revenues (before income
taxes)(9).................................. $40,167,000 $28,551,000 $9,162,000 $77,880,000
Discounted future net revenues (before income
taxes)(9).................................. $26,014,000 $22,070,000 $6,506,000 $54,590,000
Future net cash flows (net of income
taxes)(10)................................. $31,711,000 $20,480,000 $7,816,000 $60,007,000
Discounted future net cash flows (net of
income taxes)(10).......................... $21,127,000 $16,117,000 $5,753,000 $42,997,000
</TABLE>
(footnotes on following page)
5
<PAGE> 6
SUMMARY OIL AND GAS INFORMATION
The following table contains certain summary oil and gas information, based
in part upon reports of independent petroleum engineers:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
--------------------------------------------------------
1991 1992 1993 1994
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
PRODUCTION:
Oil (Bbls)....................... 149,000 285,000 573,000 738,000
Gas (Mcf)........................ 479,000 637,000 1,096,000 1,453,000
BOE.............................. 229,000 391,000 756,000 980,000
Average sales price (per unit):
Oil (Bbls)..................... $ 17.83 $ 16.59 $ 13.56 $ 13.08
Gas (Mcf)...................... 1.63 2.02 2.15 1.73
BOE............................ 15.02 15.39 13.41 12.42
RESERVE INFORMATION:
Proved reserves (year end)(8):
Oil (Bbls)..................... 1,324,000 2,709,000 3,052,000 7,136,000
Gas (Mcf)...................... 3,492,000 8,044,000 7,013,000 9,792,000
BOE............................ 1,906,000 4,049,000 4,221,000 8,768,000
Future net revenues (before
income taxes)(9)............... $15,268,000 $28,016,000 $17,771,000 $40,167,000
Discounted future net revenues
(before income taxes)(9)....... $11,126,000 $18,489,000 $11,895,000 $26,014,000
Future net cash flows (net of
income taxes)(10).............. $11,307,000 $21,383,000 $14,133,000 $31,711,000
Discounted future net cash flows
(net of income taxes)(10)...... $ 8,234,000 $14,110,000 $10,845,000 $21,127,000
</TABLE>
- ---------------
(footnotes to the tables above and on page 5)
(1) The column reflects, for the nine months ended September 30, 1995,
operations and production of the Company, including the operations and
production attributable to the TNC Fields and Net Other Transactions to the
extent they were part of the Company's operations or production in the
period shown.
(2) These columns reflect, for the nine months ended September 30, 1995,
operations and production of the TNC Fields and Net Other Transactions to
the extent they were not part of the Company's operations or production in
that period.
(3) See the introductory paragraphs to "Summary Pro Forma Combined Financial
and Oil and Gas Data," Note 2 of Notes to Consolidated Financial Statements
of the Company -- Nine Months Ended September 30, 1995 (Unaudited) and
Historical Summaries of Gross Revenues and Direct Operating Expenses of the
TNC Fields.
(4) Direct operating expenses do not include certain material expenses, such as
overhead, depletion, depreciation and amortization, general and
administrative expenses or interest expense. In September 1995, Texaco
settled certain labor negotiations by increasing the wages of unionized and
certain other workers, whose wages had not been increased subsequent to
June 30, 1994, by an annual adjustment of 22%. Had this increase been in
effect from July 1, 1994, with one-half of the annual increase payable in
1994 and the entire increase payable in 1995, direct operating expenses
would have been greater in 1994 by $47,000 and in the first nine months of
1995 by $100,000.
(5) Had the Company acquired the TNC Fields as of January 1, 1995 at the
contract price of $13.0 million plus an oil imbalance obligation of
approximately $2.0 million, depletion, depreciation and amortization and
interest expense would have increased by $874,000 and $304,000,
respectively, and pro forma combined net income and net income per common
share would have declined to $2.0 million and $0.46, respectively. No
assurance can be given that, had the purchase occurred on January 1, 1995,
actual results would not have otherwise varied or that the variances would
not have been material.
(6) The pro forma fully diluted net income per common share assumes the sale of
the Debentures and the conversion thereof at the initial conversion price
into 1,257,000 shares of the Company's Common Stock as of January 1, 1995.
Had the Company acquired the TNC Fields on January 1, 1995 at the contract
price (see footnote (5)), pro forma net income per common share on a fully
diluted basis would have been $0.42.
(7) The Company generally commissions reserve reports on an annual basis and
has not commissioned reserve reports at any date subsequent to January 1,
1995 for the purposes of this Offering or otherwise. Accordingly, the
information shown has not been adjusted for production for the nine-month
period ended September 30, 1995, which was 921,000, 712,000, and 65,000 BOE
for the Company, the TNC Fields and Net Other Transactions, respectively.
The pro forma combined data includes the following proved reserve amounts
attributable to the approximately 30% minority interest in the post-CRPL
Business Combination entity, as if the CRPL Business Combination occurred
on December 31, 1994, as follows:
<TABLE>
<S> <C>
Oil (Bbls)................................................................. 139,000
Gas (Mcf).................................................................. 688,000
BOE........................................................................ 254,000
Future net revenues (before income taxes).................................. $1,045,000
Discounted future net revenues (before income taxes)....................... $ 816,000
</TABLE>
(8) See footnotes (2) and (3) on page 3.
(9) See footnote (4) on page 3.
(10) See footnote (5) on page 3.
6
<PAGE> 7
SUMMARY CONSOLIDATED FINANCIAL DATA
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------- -----------------
1991 1992 1993 1994 1994 1995
------ ------ ------- ------- ------ -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales..................... $3,438 $6,021 $10,130 $12,170 $8,965 $10,976
Other................................. 506 484 400 784 269 417
------ ------ ------- ------- ------ -------
Total revenues................... 3,944 6,505 10,530 12,954 9,234 11,393
Depletion, depreciation and
amortization. 650 1,102 1,853 2,041 1,727 1,931
Operating income........................ 610 790 317 1,484 699 1,133
Interest expense, net(1)................ (98) (301) (426) (609) (472) (763)
Net income (loss)....................... 478 365 (88) 509 238 230
PER SHARE DATA:
Net income (loss) per share............. $ 0.17 $ 0.13 $ (0.02) $ 0.13 $ 0.06 $ 0.05
Weighted average common and common
equivalent shares outstanding......... 2,811 2,907 3,533 3,998 3,966 4,355
OTHER DATA:
EBITDA(2)............................... $1,252 $1,908 $ 2,171 $ 3,568 $2,520 $ 3,114
Ratio of EBITDA to net interest
expense(2)............................ 12.8:1 6.3:1 5.1:1 5.9:1 5.3:1 4.0:1
Ratio of earnings to fixed charges(3)... 4.8:1 2.4:1 (4) 2.0:1 1.3:1 1.4:1
</TABLE>
<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1995
-----------------------------------------------------------
AS ADJUSTED FOR
AS ADJUSTED FOR ACQUISITIONS, RELATED
ACQUISITIONS AND FINANCINGS AND ISSUANCE
ACTUAL RELATED FINANCINGS(5) OF DEBENTURES(6)
------- ---------------------- ------------------------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Current portion of long-term debt............. $ 8,520 $ 8,520 $ 1,120
Long-term debt(7)............................. 11,511 11,361 10,261
9% Convertible Senior Subordinated
Debentures.................................. -- -- 11,000
9% CRI Subordinated Debt...................... -- -- 1,600
Stockholders' equity.......................... 6,970 7,570 7,570
</TABLE>
- ---------------
(1) Interest expense, net of interest income and capitalized interest, if any.
(2) EBITDA is defined as earnings before interest expense, income tax expense
(benefit), depreciation and amortization. The Company has included
information concerning EBITDA and the ratio of EBITDA to net interest
expense because they are used by certain investors as a measure of the
ability of issuers of debt securities to service their debt. EBITDA is not
required by GAAP and should not be considered as an alternative to net
income or any other measure of performance required by GAAP or as an
indicator of the Company's operating performance. This information should be
read in conjunction with the Consolidated Statements of Cash Flows contained
in the Consolidated Financial Statements of the Company included elsewhere
in this Prospectus.
(3) The ratio of earnings to fixed charges is calculated by dividing earnings by
fixed charges. For this purpose, "earnings" means earnings (loss) from
continuing operations before income taxes plus fixed charges minus
capitalized interest. "Fixed charges" means total interest, whether
capitalized or expensed, plus amortization of deferred financing costs and
the interest portion of rental expense.
(4) For the year ended December 31, 1993, the Company's earnings were
insufficient to cover its fixed charges by $126,000.
(5) Adjusted to give effect to the acquisition of the Cocorna Field, the CRPL
Business Combination and the Capco Common Stock Conversion, as though such
transactions and related financings had occurred as of September 30, 1995.
(6) Adjusted to give effect to the acquisition of the Cocorna Field, providing
$1.75 million of required security in connection with the operation of the
Teca/Nare Fields, the CRPL Business Combination, the Capco Common Stock
Conversion and the CRI Debt Conversion, as though such transactions and
related financings had occurred as of September 30, 1995, and (ii) sale of
the Debentures and the application of the estimated net proceeds therefrom.
See "Use of Proceeds."
(7) For information on terms and interest, see Note 9 of Notes to Consolidated
Financial Statements of the Company.
7
<PAGE> 8
THE OFFERING
Debentures Offered............ $11,000,000 principal amount of 9% Convertible
Senior Subordinated Debentures due 2005 (the
"Debentures"). The Company has granted the
Underwriters an option to purchase up to
$1,650,000 additional principal amount of
Debentures solely to cover over-allotments.
Interest Payments............. Interest on the Debentures is payable at the
rate stated on the cover page of this
Prospectus, semi-annually on each June 15 and
December 15, commencing June 15, 1996.
Conversion Rights............. The Debentures are convertible at any time
prior to maturity into shares of Common Stock
at a conversion price of $8.75 per share
(equivalent to a conversion rate of
approximately 114 shares per $1,000 principal
amount of Debentures), subject to adjustment in
certain events, unless previously redeemed.
Debentures called for redemption will be
convertible up to and including, but not after,
the close of business on the redemption date.
Optional Redemption........... The Debentures are redeemable in whole or in
part at the option of the Company at any time
prior to maturity at the redemption prices set
forth herein, plus accrued interest, except
that the Debentures may not be redeemed prior
to December 15, 1997.
Mandatory Sinking Fund........ The Company is required to redeem 15% of the
original principal amount of Debentures issued
pursuant to this Prospectus on December 15,
2000 and on each December 15 thereafter through
December 15, 2004 at a redemption price of 100%
of the principal amount of the Debentures
redeemed, plus accrued interest thereon to the
redemption date. These mandatory sinking fund
payments are calculated to retire 75% of the
original principal amount of the Debentures
prior to maturity.
Change of Control............. The Company is required to offer to purchase
the Debentures upon a Change of Control (as
defined) at 102% of the principal amount
thereof, plus accrued interest to the date of
purchase.
Subordination................. The Debentures are subordinated in right of
payment to all present and future Senior Debt
of the Company. Senior Debt aggregated
approximately $17.8 million, excluding accrued
interest, at September 30, 1995. The Company
will not issue other subordinated debt that is
subordinated to any Senior Debt but senior to
the Debentures.
Capco Common Stock Conversion
and CRI Debt
Conversion............... The Company borrowed $2.2 million from Capco
and CRI to finance, in part, its acquisition of
the Teca/Nare Fields and the Velasquez-Galan
Pipeline. At the closing of the Offering,
$600,000 of this indebtedness will be converted
into 75,000 shares of Common Stock and the
balance of $1.6 million will be converted into
9% debt which will be due April 1, 2006 and
subordinated to the same extent as the
Debentures are subordinated.
Use of Proceeds............... To (i) retire certain of the Company's
indebtedness, including $4.7 million of bank
debt incurred to finance the acquisition of the
Teca/Nare Fields and the Velasquez-Galan
Pipeline (which bor-
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rowing has been guaranteed by Mr. Chaudhary),
and $300,000 of debt incurred in connection
with the acquisition of the Company's asphalt
refinery and (ii) invest approximately $350,000
in Beaver Lake Energy Corporation in connection
with the CRPL Business Combination. The balance
of the net proceeds of the Offering is
anticipated to be used to repay borrowings
outstanding under the Company's revolving
credit agreement, which amounts may be
reborrowed in the future. See "Use of Proceeds"
and "Management -- Certain Relationships and
Related Transactions."
Risk Factors.................. An investment in the Debentures involves a high
degree of risk. See "Risk Factors."
Listing....................... The Company's Common Stock is listed on the
AMEX under the symbol "SAB." The Debentures
have been approved for listing on the AMEX
under the symbol "SAB.A."
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RISK FACTORS
In addition to the other information in this Prospectus, the following risk
factors should be considered carefully in evaluating the Company and its
business before investing in the Debentures.
DEPENDENCE ON MR. CHAUDHARY
The Company is dependent upon the efforts and skills of Ilyas Chaudhary,
the Chairman of the Board, President and Chief Executive Officer of the Company.
The loss of the services of Mr. Chaudhary would have a material adverse effect
on the Company. The Company has entered into an employment agreement with Mr.
Chaudhary which will expire in January 2000. See "Management." The Trustee, on
behalf of the Debentureholders, and the Company are the beneficiaries of a $5
million policy insuring Mr. Chaudhary's life. The proceeds of the policy, but
not more than one-half in principal amount of the Debentures outstanding from
time to time, are payable to the Trustee, for the benefit of the holders of the
Debentures, with any balance payable to the Company. See "Description of the
Debentures -- Certain Covenants -- Insurance on the Life of Ilyas Chaudhary." In
August 1995, Mr. Chaudhary had an angioplasty procedure but returned to work
full time within two weeks. According to the physician who performed the
procedure, Mr. Chaudhary's prognosis is excellent.
The Company's future profitability also will be dependent upon the
Company's ability to attract and retain other qualified management personnel.
There can be no assurance that the Company will be successful in hiring or
retaining such requisite personnel.
LEVERAGE; FIXED CHARGES COVERAGE; WORKING CAPITAL DEFICIT; ADDITIONAL CAPITAL
NEEDS
Substantial Leverage; Fixed Charges Coverage
As of September 30, 1995, on a pro forma basis after giving effect to the
acquisition of the Cocorna Field, the CRPL Business Combination, providing $1.75
million as required security in connection with the operations of the Teca/Nare
Fields, the Capco Common Stock Conversion, the CRI Debt Conversion and the sale
of the Debentures and the anticipated use of the estimated net proceeds
therefrom, the Company would have had total consolidated indebtedness of
approximately $24.0 million and a ratio of consolidated indebtedness to
shareholders' equity of approximately 3.17 to 1.00. The earnings of the Company
for the year ended December 31, 1993 were insufficient to cover its fixed
charges by $126,000. The Company's ability to cover its fixed charges, including
interest on and principal of the Debentures, in the future will be dependent on
cash flows from its existing and acquired producing properties, principally the
Teca/Nare Fields. See "-- Risks Relating to Colombian and Other Foreign
Operations." There can be no assurance that the cash flows generated by the
Company will be sufficient to cover its fixed charges in the future. See
"Capitalization."
Working Capital Deficit
The Company had a working capital deficit of $9.16 million at September 30,
1995. Included in current liabilities in determining the working capital deficit
was the then $8.52 million current portion of long-term debt and an $842,000
obligation payable from future oil production at the Teca/Nare Fields. The
Company's assets, consisting primarily of oil and gas properties, are not
immediately liquid and are subject to various restrictions on transfer.
The Company is currently experiencing significant cash flow difficulties
caused, in part, by borrowings incurred in connection with the acquisition of
the Teca/Nare Fields, the fact that, in the ordinary course, no significant cash
flow will be available to the Company from the Teca/Nare Fields until December
1995, the need to fund operating expenses of the Teca/Nare Fields and the
Velasquez-Galan Pipeline on a current basis, the fact that the Company has no
remaining available borrowing capacity under its bank credit facility and that
facility prohibits the Company from incurring other indebtedness without the
lender's consent, and delays in the completion of this Offering (see "Risks
Relating to Corporate Matters -- Background"). The Company does not currently
have sufficient capital resources to fund its share of the working capital
requirements for the Teca/Nare Fields and Velasquez-Galan Pipeline, but will
when this Offering is completed. Completion of this
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Offering, however, will increase interest expense of the Company. Upon
completion of this Offering, after giving effect to the application of the net
estimated proceeds therefrom, the Company anticipates that it will have
approximately $1.6 million of borrowing capacity available under its bank credit
facility. The Company believes that the borrowing capacity remaining after using
$1.75 million as collateral to secure payments due to third party vendors at the
Teca/Nare Fields, plus anticipated cash flows from operations, will be
sufficient to fund its presently expected working capital requirements.
Need for Additional Capital Resources; Additional Indebtedness
The Company believes that it will require additional financing, which may
be in the form of debt financing, to fund future acquisitions and growth. Except
as provided in the Company's principal credit agreement, the Company will not be
restricted in the amount of indebtedness it may incur in the future. The
Company's amount of leverage will affect its cost of funds, which may limit the
financing available to the Company for its operations, make it more vulnerable
to economic downturns and limit its ability to withstand adverse changes or to
capitalize on business opportunities. If the Company is at any time unable to
generate sufficient cash flow from operations to service its debt, refinancing
of all or a portion of that debt or obtaining additional financing may be
required to avoid defaults (including cross-defaults) on some or all of its
indebtedness. There can be no assurance that any such refinancing would be
possible or that any additional financing could be obtained, or obtained on
terms that are favorable or acceptable to the Company.
SUBORDINATION OF THE DEBENTURES
The Debentures will be subordinate and junior in right of payment to all
Senior Debt of the Company. At September 30, 1995, on a pro forma basis after
giving effect to the acquisition of the Cocorna Field, the CRPL Business
Combination, the Capco Common Stock Conversion and the sale of the Debentures
and the anticipated use of the estimated net proceeds therefrom, the Senior Debt
of the Company would have been $11.4 million. The Indenture will not restrict
the amount of indebtedness or Senior Debt the Company may incur from time to
time.
Because of the subordination of the Debentures, in the event of any payment
or distribution of assets of the Company in any dissolution, insolvency,
bankruptcy or other similar proceeding, holders of Senior Debt must be paid in
full before the holders of the Debentures may be paid, and amounts otherwise
payable to the holders of Debentures will be paid to the holders of Senior Debt
until the Senior Debt is paid in full. By reason of this subordination, in the
event of the dissolution, insolvency or bankruptcy of the Company, holders of
the Debentures may recover less, ratably, than holders of Senior Debt and other
creditors of the Company, or may recover nothing. In addition, the Company may
be required to stop making payments of principal and interest on the Debentures
if there is a continuing default with respect to certain Senior Debt that would
permit the holders of such Senior Debt to accelerate payment of that debt and
the Company receives notice of the default from a holder of such Senior Debt
entitled to give that notice.
In addition, all of the operations of the Company are conducted through
subsidiaries, and therefore the Company is dependent on the cash flow of its
subsidiaries to meet its debt obligations, including its obligations under the
Debentures. Except to the extent the Company may itself be a creditor with
recognized claims against its subsidiaries, the claims of creditors of the
subsidiaries will have priority with respect to the assets and earnings of the
subsidiaries over the claims of creditors of the Company, including holders of
the Debentures, even though subsidiary obligations do not constitute Senior
Debt. Even if the Company had such recognized claims, however, the claims of the
Company would still be effectively junior to any indebtedness of the
subsidiaries to the extent the creditors holding that indebtedness are entitled
to the benefit of security interests in the assets of the subsidiary, as well as
to any indebtedness of the subsidiary senior to that held by the Company. At
September 30, 1995, the Company's subsidiaries had $4.7 million of liabilities.
The Indenture will not restrict the amount of liabilities or secured
indebtedness the subsidiaries of the Company may incur from time to time.
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VOLATILITY OF OIL PRICES; DEPENDENCE ON KEY CUSTOMERS
The revenue of the Company is highly dependent upon prevailing spot market
prices for oil and gas. Oil and gas prices fluctuate widely in response to
changes in supply of, and demand for, oil and gas, market uncertainty and a
variety of additional factors which are beyond the control of the Company. Such
factors include political conditions, weather conditions, governmental
regulations, the price of oil set by the Organization of Petroleum Exporting
Countries (OPEC), the price and availability of alternative fuels and overall
economic conditions. See "-- Risks Relating to Colombian and Other Foreign
Operations," "-- Governmental Regulation and Environmental Risks" and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
In 1994, approximately 18.1% and 30.5% of the Company's oil and gas
revenues were derived from sales to two purchasers, Texaco and Unocal
Corporation ("Unocal"), respectively. In January 1995, Unocal canceled its
purchase contract, effective March 1, 1995, for the Company's production from
one of its major properties near Santa Maria, California, which accounted for
approximately 25% of the Company's United States oil sales in 1994. The Company
replaced Unocal with other purchasers on terms generally as favorable as the
terms of the contract with Unocal.
RISKS RELATING TO COLOMBIAN AND OTHER FOREIGN OPERATIONS
Foreign Operations Generally
An important component of the Company's business strategy is to seek to
acquire foreign oil and gas producing properties. Currently, the Company has
properties in Colombia and Canada.
Risks inherent in foreign operations generally include loss of revenue,
property and equipment from such hazards as expropriation, nationalization, war,
insurrection and other political risks; risks of increases in taxes and
governmental royalties; renegotiation of contracts with governmental entities;
and abrupt changes in governments and in laws and policies governing foreign
operations. Other risks inherent in foreign operations are local currency
instability, the risk of realizing economic currency exchange losses when
transactions are completed in currencies other than United States dollars, and
the ability to repatriate earnings under existing exchange control laws.
Properties in Colombia; TNC Fields
The Company's Colombian properties are generally subject to all of the
foregoing risks. The Company expects that it may be dependent on revenue
generated by the Teca/Nare Fields, which are located in Colombia, to provide the
funds necessary to make payments for the principal of, and interest on, the
Debentures. Colombia, which has a history of political instability, is currently
experiencing such instability due to insurgent guerilla activity, which has
impacted other oil production and pipeline operations, drug-related violence and
actual and alleged drug-related political payments, as has been widely reported
in the press. In November 1995, the President of Colombia, whose campaign has
been alleged to have received substantial drug-related contributions, declared a
national state of emergency. The President of Colombia had previously declared a
national state of emergency in August 1995. There can be no assurance that such
matters will not affect the TNC Fields (or impact national policy that affects
the TNC Fields) in the future.
All of the Company's oil production in Colombia is, and, as a practical
matter, can be sold only to Empresa Colombiana de Petroleos ("Ecopetrol"), the
government-owned oil company, which also owns 50% of the Teca/Nare Fields.
Ecopetrol has the power to determine the prices that the Company will receive
for all oil produced in Colombia, and it currently pays widely divergent prices
for similar grades of oil and gas based on a variety of factors. There can be no
assurance that Ecopetrol will not decrease the prices it pays for the Company's
oil in the future. In this regard, the formula that determines the prices paid
by Ecopetrol for oil produced at the TNC Fields has been adjusted to yield a
lower post-adjustment price in each of the past several years. The formula is
expected to be adjusted again in January 1996 and, based on prior experience,
the adjustment is expected to be downward. Any such decrease, if materially in
excess of that experienced in prior
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years, could have a material adverse effect on the Company's future operations
and on its ability to pay the principal of and interest on the Debentures.
The operation of the TNC Fields has been affected by environmental concerns
in the past and may be so affected in the future. The Colombian Ministry of
Environment issued a resolution (the "Resolution") in June 1995 directing Texaco
to correct certain environmental deficiencies allegedly found at the Nare oil
field which is part of the TNC Fields. The Resolution ordered Texaco to
temporarily close one of its five production modules (surface vessels through
which crude is treated to separate the gas and water from the oil) and any wells
whose crude oil was processed in that module until Texaco provided the Ministry
of Environment a written timetable setting forth Texaco's scheduled
implementation of requisite corrective measures. The requested timetable was
delivered to the Ministry of Environment on July 6, 1995. On August 8, 1995,
Texaco received a communication from the Ministry of the Environment requesting
certain revisions to the timetable. The temporary closing of the module has not
had a substantial effect on total production because substantially all of the
crude oil which would otherwise have been processed in the closed module has
been diverted to other production modules. The Resolution also ordered the
opening of an environmental investigation of Texaco's operation of the TNC
Fields. Texaco estimated that the costs of compliance with the Resolution
attributable to Saba's interest in the TNC Fields will not exceed $250,000.
Texaco has formally appealed the Resolution and is currently awaiting a response
from the Ministry of Environment. See Note 6 of Notes to Historical Summaries of
Gross Revenues and Direct Operating Expenses of the TNC Fields. Under the terms
of the Company's agreement with Texaco, the Company takes Texaco's interests "as
is" and could be subject to liability materially greater than $250,000. The
Company engaged an independent consultant to perform an environmental compliance
survey of the Nare oil field. That survey estimated that the costs of
environmental compliance attributable to the Company's interest in the TNC
Fields would not exceed $375,000. In addition, consistent with the survey,
Omimex de Colombia, Ltd., the operator of the Teca/Nare Fields, estimates that
as much as $250,000 may be expended to upgrade waste water disposal
capabilities, including currently anticipated reinjection of certain polluted
water.
Colombia has seismically active areas. The Velasquez Field and the
Teca/Nare and Cocorna Fields are located adjacent to the Velasquez earthquake
fault. A significant earthquake near these fields could have a material adverse
effect on the Company and its ability to pay interest on and the principal of
the Debentures.
Omimex de Colombia, Ltd., which purchased and is purchasing the remaining
one-half of Texaco's interests in the Teca/Nare and Cocorna Fields,
respectively, and which operates the Teca/Nare Fields and will operate the
Cocorna Field, maintains a $2 million general liability and a $4 million
umbrella insurance policy, including insurance against certain environmental
pollution, relating to the Velasquez Field operations (which it owns jointly
with the Company and operates), and has informed the Company that it intends to
obtain similar coverage, but for a greater amount, relating to the TNC Fields.
The Company has purchased business interruption insurance for its Colombian
properties.
The Company relied on information provided by Texaco, Omimex de Colombia,
Ltd.'s investigation and the Company's knowledge of the area through its
ownership of its 25% ownership in the adjacent Velasquez Field in determining to
purchase the TNC Fields. No Company officer, director or employee visited the
TNC Fields prior to purchasing an interest in them.
WELLS OPERATED UNDER JOINT OPERATING AGREEMENTS
Many of the Company's business activities are conducted through joint
operating agreements in which the Company owns a partial interest in oil and gas
wells and the wells are operated by the Company or another joint owner. At
September 30, 1995, the Company owned interests in 282 gross (217.8 net) oil and
gas wells where it is the operator (57.4% of such net wells) and 788 gross
(161.5 net) oil and gas wells where it is not the operator (42.6% of such net
wells). To the extent the Company is not the operator, it has risks because it
must reimburse its share of costs, but does not have control over normal
operating procedures and expenditures. To the extent the Company is the
operator, it is at risk if one of the joint owners does not reimburse its share
of costs. Since the Company does not have a majority position with respect to
those wells
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in which it has an interest but is not the operator and, in most or all cases,
there is a majority owner of those wells, the Company may not be in a position
to remove the operator in the event of poor performance.
As of September 30, 1995, approximately 39.2% of the Company's oil and gas
production was derived from joint operating agreements with the Omimex Group, a
Fort Worth, Texas-based private oil and gas producer, which includes Omimex de
Colombia, Ltd. As to substantially all of the properties in which the Company
has common ownership with the Omimex Group, an Omimex subsidiary is the operator
and owner of at least 50% of each such combined interest.
RISKS RELATING TO CERTAIN CORPORATE MATTERS
Background
The Company was incorporated in 1979. Prior to 1989, including at times
when the Company did not have significant operations, the Company did not make
various required filings with the Commission, may not have complied with
requisite corporate formalities and, in a 1988 amendment to its Articles of
Incorporation, may have inadvertently subjected itself to having preemptive
rights or may have failed to validly adopt a material amendment to its Articles
of Incorporation. In addition, the Company has been unable to locate all of its
original minutes of meetings or other records of the Board of Directors and
shareholders and stock records for much of the time since its incorporation.
When these matters were discovered in connection with preparing for this
Offering, the Offering was delayed and the Company (i) instructed its counsel to
investigate these matters, (ii) retained Colorado-based counsel to assist in the
investigation and advise as to certain matters of Colorado law and (iii) took
certain corrective, ratifying and other actions described below.
The various risks associated with these matters are discussed below. The
number of shares and per share amounts set forth below give effect to the 1 for
100 reverse stock split in 1991.
Outstanding Stock
In 1979, the Company issued 25,000 shares of Common Stock in a private
placement for approximately $1 per share and 125,000 shares of its Common Stock
in a public offering for $10 per share. Records are incomplete with respect to
approval of these issuances by the Board of Directors. With respect to the
issuance of 125,000 shares, the Company has located an unsigned draft of minutes
for a meeting of the Board of Directors, which draft contains resolutions
approving the issuance, but has not located signed minutes and is unable to
determine from the draft whether it was prepared in advance of, or after, a
meeting of the Board of Directors or to determine from contemporaneous records
whether such a meeting occurred.
The Company's current Board of Directors has ratified and approved these
issuances in 1979, and the Company has obtained a factual certificate from a
director of the Company at such time certifying that such issuances were duly
and validly approved and issued. However, there is no authority in Colorado on
whether corporate action taken by the vote of shares issued without due
corporate authorization may, if the issuance of those shares is later voided,
also be invalidated. Accordingly, there can be no assurance that the failure to
duly and validly approve and issue such shares at the time of issuance would not
result in rendering invalid any corporate actions, including elections of
directors and issuances of shares and acquisitions of assets, taken after such
date. Such invalidation of corporate action would have a material adverse effect
on the Company.
Further, due to incomplete corporate records, the Company is unable to
determine whether certain of its Common Stock was issued free of any violation
of any state or federal securities laws. However, the Company has not been
subject to any enforcement action, judicial or administrative proceeding or
claim from any person regarding failure to comply with such securities laws.
Preemptive Rights
The Colorado law under which the Company was incorporated and which
continues to govern the Company in this respect, notwithstanding subsequent
amendments to that law, provides that unless specifically denied in the
Company's Articles of Incorporation, shareholders are entitled to preemptive
rights, subject to certain exceptions. Preemptive rights generally give the
shareholders of a corporation the right, with
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certain exceptions, to purchase, before they can be sold to others, (i) common
stock issued by the corporation for cash and (ii) other securities issued by the
corporation for cash that are convertible into its common stock (for example,
convertible preferred stock or convertible debentures). Preemptive rights
thereby give shareholders the ability to preserve their proportionate ownership
of the corporation. Article IV of the Company's original Articles of
Incorporation, filed in 1979, specifically provided that the shareholders were
not entitled to preemptive rights. On December 27, 1988, however, the Company
amended and restated Article IV of its Articles of Incorporation (the "1988
Amendment") to increase the Company's number of authorized shares of Common
Stock. The amended and restated Article IV omitted the provision denying
preemptive rights to shareholders, thus, in effect, possibly entitling
shareholders to preemptive rights in the future. The Company believes that the
omission was inadvertent. Upon discovery of the error, the Company submitted to
the shareholders for their approval an amendment to its Articles of
Incorporation to restate the omitted provision denying preemptive rights to
shareholders. On October 19, 1995, the shareholders of the Company approved the
amendment and the Company thereafter filed a corrective amendment to the
Company's Articles of Incorporation. Accordingly, preemptive rights will not
apply to the issuance of the Debentures or the shares of Common Stock issuable
on conversion of the Debentures. However, by law, the amendment cannot be
retroactive. As a result, certain shares of Common Stock issued by the Company
from December 1988 through the date the amendment was filed may have been issued
in violation of the preemptive rights. During this period, the Company issued
994,333 shares of its Common Stock at an average price of $2.63 per share in
transactions as to which, under Colorado law, preemptive rights, if applicable,
would apply.
To the extent preemptive rights may have been available to shareholders
with respect to these issuances, the Company has obtained waivers of any such
preemptive rights from the holders of approximately 90% of the Company's Common
Stock at the time of each issuance.
The Company is aware of one Colorado court decision in which, in a
preemptive rights context, the shareholder who was not given the opportunity to
exercise his preemptive rights obtained the alternative remedies of being able
to (i) purchase, at the issue price, a number of shares sufficient to preserve
that shareholder's proportionate ownership in the corporation or (ii) have the
shares issued in violation of his preemptive rights canceled. Because, among
other reasons, that case involved a closely-held corporation of which the
complaining shareholder owned 50%, while Saba is a publicly held corporation,
the Company has been advised that this case is readily distinguishable and that,
if the matter is presented to a Colorado court, the remedy of invalidating any
shares issued in violation of preemptive rights should not be awarded.
If any person who may have preemptive rights and who has not waived those
rights should seek to assert them, the Company intends to vigorously defend the
matter. If, however, the Company were obligated to issue shares to satisfy the
preemptive rights of any such person, Capco has agreed to sell or cause to be
sold to the Company a like number of shares, at the same price at which the
Company is obligated to issue the shares, thereby eliminating any effect on the
Company. To the extent Capco does not perform this obligation, the antidilution
provisions applicable to the Debentures would provide certain protections to the
then holders of the Debentures. However, if the remedy of cancellation of shares
issued in violation of preemptive rights were granted, the effect on the Company
could be materially adverse.
IMPRECISION OF RESERVES ESTIMATES
The proved developed and undeveloped oil and gas reserve figures presented
in this Prospectus are estimates based on reserve reports prepared by
independent petroleum engineers. The estimation of reserves requires substantial
judgment on the part of the petroleum engineers, resulting in imprecise
determinations, particularly with respect to new discoveries. Estimates of
reserves and of future net revenues prepared by different petroleum engineers
may vary substantially, depending, in part, on the assumptions made, and may be
subject to material adjustment either up or down in the future. The accuracy of
any reserve estimate depends on the quality of available data as well as
engineering and geological interpretation and judgment. Results of drilling,
testing and production or price changes subsequent to the date of the estimate
may result in revisions to such estimates. The estimates of future net revenues
in this Prospectus reflect oil and gas prices and production costs as of the
date of estimation, without escalation, except where changes in prices were
fixed
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under existing contracts. There can be no assurance that such prices will be
realized or that the estimated production volumes will be produced during the
periods indicated. Future performance that deviates significantly from the
reserve reports could have a material adverse effect on the Company. The Company
generally commissions reserve reports on an annual basis and has not
commissioned reserve reports at any date subsequent to January 1, 1995 for the
purposes of this Offering or otherwise. No assurance is given that any such
later-date reserve reports would not indicate reserves lower than those at
December 31, 1994 reflected in this Prospectus. See "Business -- Description of
Property -- Oil and Gas Properties -- Proved Reserves and Future Net Revenues."
GOVERNMENTAL REGULATION AND ENVIRONMENTAL RISKS
Governmental Regulation Generally
The production and sale of oil and gas are subject to a variety of federal,
state and local governmental regulations, including regulations concerning the
prevention of waste, the discharge of materials into the environment, the
conservation of natural oil and gas, pollution, the issuance of permits for
drilling operations, drilling bonds, reports concerning operations, the spacing
of wells, the unitization and pooling of properties, and various other matters,
including taxes. Many jurisdictions have at various times imposed limitations on
the production of oil and gas by restricting the rate of flow for oil and gas
wells below their actual production capacity. In addition, many states have
raised state taxes on energy sources and additional increases may occur.
Environmental Matters
The oil and gas industry is also subject to environmental hazards, such as
oil spills, oil and gas leaks, ruptures and discharges of oil and toxic gases,
which could expose the Company to substantial liability due to environmental
damage. The Company has not obtained environmental compliance surveys, including
so-called Phase I reports, which would disclose matters of public record and
could disclose evidence of environmental contamination requiring remediation, on
producing properties outside of Michigan or California in which it holds an
interest. The Company has had Phase I or more limited environmental assessments
done for substantially all of its California and Michigan oil and gas
properties. These assessments disclose environmental impacts typical of oil
field operations and certain areas of potentially greater environmental concern,
including possible groundwater impact at certain properties in which the Company
has up to a 25% working interest and as to which the seller is generally
responsible for remediation costs in excess of $2 million (up to $500,000 to the
Company), that have not been resolved or further investigated. Generally, the
assessments done are not more recent than two or three years and do not disclose
any more recent environmental matters. The Company's oil and gas properties as
to which environmental assessments have not been performed should also be
expected to have environmental concerns typical of oil field operations
generally.
Pursuant to the purchase and sale agreement of the asphalt refinery in
Santa Maria, California, the sellers have agreed to perform certain remediation
and other environmental activities on portions of the refinery property for a
period of five years. The Company may also incur remediation obligations with
respect to the refinery and engaged an independent consultant to perform an
environmental compliance survey for the refinery. The survey did not disclose
required remediation in areas other than those where the seller is responsible
for remediation, but did disclose that it was possible that all of the required
remediation may not be completed in the five-year period.
Environmental compliance surveys such as those the Company has had
performed are limited in their scope and should not be expected to disclose all
environmental contamination as may exist.
The Company is required to plug and abandon well facility sites on its
properties after production operations are completed. The Company has a
significant contingent liability with respect to its obligation to plug and
abandon wells on certain California properties. See Note 13 of Notes to
Consolidated Financial Statements of the Company. No assurance can be given that
the costs of closure of others of the Company's oil and gas properties may not
be materially adverse to the Company.
16
<PAGE> 17
For these and other reasons, there can be no assurance that material costs
for remediation or other environmental compliance will not be incurred in the
future. See "-- Risks Relating to Colombian and Other Foreign
Operations -- Properties in Colombia; TNC Fields." The incurrence of such
environmental compliance costs could be materially adverse to the Company.
NECESSITY TO REPLACE RESERVES; COMPETITION
The Company's success will be largely dependent on its ability to replace
and expand its oil and gas reserves through the acquisition of producing
properties and the development of oil and gas reserves, both of which involve
substantial risks. Successful acquisition of producing properties generally
requires accurate assessments of recoverable reserves, future oil and gas prices
and operating costs, potential environmental and other liabilities and other
factors. Such assessments are necessarily inexact and their accuracy inherently
uncertain. There can be no assurance that the Company's acquisition and
development activities will result in the successful replacement of, or
additions to, the Company's reserves.
There is significant competition for the acquisition of properties
producing or capable of producing oil and gas. The Company faces competition
from a substantial number of companies, many of which have greater financial and
other resources than does the Company. As a result of this competition, the
Company may be unable to acquire attractive oil and gas producing properties on
terms it considers acceptable. In addition, the Company faces competition for
the sale of its oil and gas from a substantial number of companies, many of
which have greater financial or other resources than the Company.
OPERATIONAL HAZARDS AND INSURANCE
Operations in the oil and gas industry entail a number of operating risks,
such as the risks of fire, blowouts, explosions, cratering, pipe failure, casing
collapse and abnormally pressured formations, the occurrence of which in
substantial number or magnitude could materially and adversely affect the
Company. The Company maintains insurance which covers, among other things,
environmental risks; however, there can be no assurance that the insurance the
Company carries will be adequate to cover any loss or exposure to liability, or
that such insurance will continue to be available on terms acceptable to the
Company. See "-- Governmental Regulation and Environmental Risks."
CHANGE OF CONTROL OFFER
Upon a Change of Control of the Company, the Company will be required to
offer to repurchase the Debentures at 102% of the principal amount thereof plus
accrued interest. See "Description of the Debentures -- Put Option Upon a Change
of Control" and "-- Certain Covenants -- Change of Control." There is no
assurance that the Company will have sufficient funds to repurchase the
Debentures upon such a Change of Control. Moreover, the repurchase of Debentures
as a result of a Change of Control could create an event of default under
existing or future Senior Debt of the Company, even if the Change of Control
itself does not, due to the financial effect on the Company of such repurchase.
Such a default or potential default could affect the ability of the Company to
make the required offer to purchase the Debentures upon a Change of Control.
CONTROL BY MR. CHAUDHARY
Upon completion of this Offering and after giving effect to the Capco
Common Stock Conversion, Mr. Chaudhary, through the companies he controls, Capco
and Sedco, Inc. ("Sedco"), will own approximately 66.8% of the Company's Common
Stock and will have the power to elect all of the Company's directors and to
control the vote on all matters submitted to a vote of the Company's
stockholders, including approval of mergers and sales of all or substantially
all of the Company's assets. See "Principal Stockholders" and "Description of
Capital Stock."
SHARES ELIGIBLE FOR FUTURE SALE
On November 10, 1995, the Company had outstanding 4,189,590 shares of
Common Stock. Of these shares, 1,372,660 shares of Common Stock are freely
transferable and tradeable without restriction or further
17
<PAGE> 18
registration under the Securities Act of 1933, as amended (the "Securities
Act"). Except for other persons who in the aggregate held less than 1% of the
total outstanding Common Stock, the remaining 2,816,930 shares of Common Stock
are held, directly or beneficially, by Capco, the majority shareholder of the
Company, and executive officers and directors of the Company, each of whom has
agreed with the Underwriters not to sell or otherwise dispose of any shares of
Common Stock for a period of 180 days after the Closing Date without the prior
written consent of Van Kasper & Company, the Representative of the Underwriters.
Although the Company can make no prediction as to the effect, if any, that such
sales of shares of Common Stock would have on the market price prevailing from
time to time, sales of substantial amounts of Common Stock, or the availability
of such shares for sale, could adversely affect prevailing market prices for the
Common Stock. Sales or transfers of Common Stock by Mr. Chaudhary could also
result in another person or entity becoming the controlling stockholder of the
Company. See "-- Change of Control Offer" and "Shares Eligible For Future Sale."
In addition, the Company intends to file a registration statement under the
Securities Act covering approximately 425,000 shares of Common Stock issued to
Capco, certain employees and others. However, substantially all of these shares
may not be sold, without the prior consent of Van Kasper & Company, until 180
days after the date of this Prospectus.
NO PRIOR PUBLIC MARKET FOR DEBENTURES
Prior to the Offering, there has been no public market for the Debentures.
Although the Debentures have been approved for listing on the AMEX, there can be
no assurance that an active trading market will develop or, if a market does
develop, that it will continue until maturity of the Debentures. It is not
expected that the Debentures will be assigned a credit rating by any of the
nationally recognized statistical rating agencies. The absence of such a rating
may affect the market for the Debentures.
18
<PAGE> 19
USE OF PROCEEDS
The net proceeds to the Company from the sale of the Debentures after
deduction of the underwriting discount and commission and estimated offering
expenses payable by the Company, are estimated to be approximately $9.2 million
($10.7 million if the Underwriters' over-allotment option is exercised in full).
The Company intends to use the net proceeds of the Offering to (a) repay
outstanding indebtedness, including (i) borrowings outstanding under the
Company's revolving credit agreement which were incurred in connection with the
acquisition of properties and for general working capital purposes, which
amounts the Company may reborrow in the future, and which, as of September 30,
1995, bore interest at 9.75% per annum and mature June 1, 2000, (ii) a $4.7
million loan from a bank that was incurred to finance, in part, the Company's
acquisition of the Teca/Nare Fields and the Velasquez-Galan Pipeline and which
is guaranteed by Mr. Chaudhary, (iii) $300,000 under a promissory note due to
Conoco incurred in connection with the Company's acquisition of its asphalt
refinery, and (b) to invest approximately $350,000 in Beaver Lake Energy
Corporation in connection with the CRPL Business Combination. The Company
intends to reborrow under its revolving credit agreement to fund the anticipated
$450,000 balance of the purchase price of the Cocorna Field, to provide the
$1.75 million required in connection with providing required security in
connection with the operation of the Teca/Nare Fields and for working capital
and other general corporate purposes.
CAPITALIZATION
The following table sets forth the capitalization of the Company at
September 30, 1995, and as adjusted to give effect to (i) the acquisition of the
Cocorna Field, providing $1.75 million as required security in connection with
the operations of the Teca/Nare Fields, the Capco Common Stock Conversion, the
CRI Debt Conversion and the CRPL Business Combination, as though such
transactions and related financings had occurred as of September 30, 1995, and
(ii) such transactions and the receipt and application of the estimated net
proceeds from the offering of the Debentures, assuming no exercise of the
Underwriters' over-allotment option.
<TABLE>
<CAPTION>
AT SEPTEMBER 30, 1995
------------------------------------------------
AS ADJUSTED FOR
AS ADJUSTED ACQUISITIONS,
FOR RELATED
ACQUISITIONS FINANCINGS
AND RELATED AND ISSUANCE OF
ACTUAL FINANCINGS DEBENTURES
------- --------------- ----------------
(IN THOUSANDS)
<S> <C> <C> <C>
Current portion of long-term debt.................... $ 8,520 $ 8,520 $ 1,120
Long-term debt(1).................................... 11,511 11,361 10,261
9% Convertible Senior Subordinated Debentures........ -- -- 11,000
9% CRI Subordinated Debt............................. -- -- 1,600
Stockholders' equity................................. 6,970 7,570 7,570
------- ------- -------
Total capitalization................................. $27,001 $27,451 $31,551
======= ======= =======
</TABLE>
- ---------------
(1) For information on terms and interest, see Note 9 of Notes to Consolidated
Financial Statements of the Company.
19
<PAGE> 20
COMMON STOCK PRICE RANGE AND DIVIDEND POLICY
The following table sets forth the high and low bid prices of the Common
Stock from January 1 to September 15, 1993 and the closing prices of the Common
Stock subsequent to September 15, 1993. Since May 22, 1995, the Common Stock has
traded on the AMEX under the symbol "SAB." From September 15, 1993 to May 22,
1995, the Common Stock was traded in the Emerging Company Marketplace at the
AMEX. Prior to September 15, 1993, the Common Stock was traded in the
over-the-counter market. The prices set forth below for the periods prior to
September 15, 1993 represent bid prices between dealers, which do not include
retail markups, markdowns, or commissions, and may not represent actual
transactions.
<TABLE>
<CAPTION>
HIGH LOW
----- -----
<S> <C> <C>
1993
First Quarter................................................ $3.94 $2.30
Second Quarter............................................... 6.04 3.42
Third Quarter................................................ 3.50 2.00
Fourth Quarter............................................... 3.25 1.31
1994
First Quarter................................................ 2.50 1.50
Second Quarter............................................... 4.00 1.37
Third Quarter................................................ 3.50 2.44
Fourth Quarter............................................... 2.63 1.63
1995
First Quarter................................................ 5.25 2.13
Second Quarter............................................... 8.19 5.00
Third Quarter................................................ 8.25 7.50
Fourth Quarter (through December 19)......................... 8.00 6.88
</TABLE>
During the year ended December 31, 1994 and for the nine months ended
September 30, 1995, the average daily trading volume of the Common Stock was
approximately 5,950 shares and 8,790 shares, respectively. As of September 30,
1995, there were 3,124 holders of record of the Company's Common Stock. On
December 19, 1995, the last reported sales price of the Common Stock on the AMEX
was $7.88.
The Company has not paid cash dividends on its Common Stock and does not
anticipate doing so in the foreseeable future. The Indenture for the Debentures
and the Company's principal credit agreement include provisions which restrict
the payment of dividends by the Company.
20
<PAGE> 21
SELECTED CONSOLIDATED FINANCIAL DATA
The following financial data included in this table has been derived from
the consolidated financial statements of the Company for the periods indicated.
The financial data is qualified in its entirety by, and should be read in
conjunction with, the Consolidated Financial Statements of the Company and the
notes thereto and "Management's Discussion and Analysis of Financial Condition
and Results of Operations," contained elsewhere in this Prospectus. The results
of operations for the nine months ended September 30, 1994 and 1995 are not
necessarily indicative of those that may be expected for a full year.
<TABLE>
<CAPTION>
AT OR FOR THE
--------------------------------------------------------
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------ -----------------
1991 1992 1993 1994 1994 1995
------ ------- ------- ------- ------- -------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND RATIOS)
<S> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA:
Revenues:
Oil and gas sales.................. $3,438 $ 6,021 $10,130 $12,170 $ 8,965 $10,976
Other.............................. 506 484 400 784 269 417
------ ------- ------- ------- ------- -------
Total revenues.................. 3,944 6,505 10,530 12,954 9,234 11,393
------ ------- ------- ------- ------- -------
Expenses:
Production costs................... 2,284 3,371 5,857 7,547 5,490 6,923
General and administrative......... 400 1,242 2,503 1,882 1,318 1,406
Depletion, depreciation and
amortization.................... 650 1,102 1,853 2,041 1,727 1,931
------ ------- ------- ------- ------- -------
Total expenses.................. 3,334 5,715 10,213 11,470 8,535 10,260
------ ------- ------- ------- ------- -------
Operating income..................... 610 790 317 1,484 699 1,133
------ ------- ------- ------- ------- -------
Other income (expense):
Interest expense, net(1)........... (98) (301) (426) (609) (473) (778)
Other.............................. (31) 1 (16) 18 94 50
------ ------- ------- ------- ------- -------
Total other income (expense).... (129) (300) (442) (591) (379) (728)
------ ------- ------- ------- ------- -------
Income (loss) before income taxes.... 481 490 (125) 893 320 405
Provision (benefit) for taxes on
income............................. 3 125 (37) 384 82 175
------ ------- ------- ------- ------- -------
Net income (loss).................... $ 478 $ 365 $ (88) $ 509 $ 238 $ 230
====== ======= ======= ======= ======= =======
Net income (loss) per share.......... $ 0.17 $ 0.13 $ (0.02) $ 0.13 $ 0.06 $ 0.05
Weighted average common and common
equivalent shares outstanding...... 2,811 2,907 3,533 3,998 3,966 4,355
OTHER DATA:
EBITDA(2)............................ $1,252 $ 1,908 $ 2,171 $ 3,568 $ 2,520 $ 3,114
Ratio of EBITDA to net interest
expense(2)......................... 12.8:1 6.3:1 5.1:1 5.9:1 5.3:1 4.0:1
Ratio of earnings to fixed
charges(3)......................... 4.8:1 2.4:1 (4) 2.0:1 1.3:1 1.4:1
BALANCE SHEET DATA:
Total assets......................... $5,006 $12,214 $13,261 $18,108 $33,040
Current portion of long-term debt.... -- $ 27 $ 1,440 $ 2,357 $ 8,520
Long-term debt(5).................... $1,130 $ 5,470 $ 4,875 $ 5,323 $11,511
Stockholders' equity................. $2,151 $ 4,010 $ 4,407 $ 6,283 $ 6,970
</TABLE>
- ---------------
(1) Interest expense, net of interest income and capitalized interest, if any.
(2) See footnote (2) on page 7.
(3) See footnote (3) on page 7.
(4) See footnote (4) on page 7.
(5) For information on terms and interest, see Note 9 of Notes to Consolidated
Financial Statements of the Company.
21
<PAGE> 22
SELECTED OIL AND GAS DATA
The following table contains certain selected information regarding oil and
gas production and, based upon independent engineers' reports, estimated proved
reserves of the Company.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------------------------------------- -----------------------
1991 1992 1993 1994 1994 1995
----------- ----------- ----------- ----------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
PRODUCTION:
Oil (Bbls).......... 149,000 285,000 573,000 738,000 558,000 746,000
Gas (Mcf)........... 479,000 637,000 1,096,000 1,453,000 1,037,000 1,052,000
BOE................. 229,000 391,000 756,000 980,000 730,000 921,000
Average sales price
(per unit):
Oil (Bbls)....... $ 17.83 $ 16.59 $ 13.56 $ 13.08 $ 12.74 $ 12.82
Gas (Mcf)........ 1.63 2.02 2.15 1.73 1.80 1.35
BOE.............. 15.02 15.39 13.41 12.42 12.28 11.92
RESERVE INFORMATION:
Proved reserves
(period end):
Oil (Bbls)....... 1,324,000 2,709,000 3,052,000 7,136,000 * *
Gas (Mcf)........ 3,492,000 8,044,000 7,013,000 9,792,000 * *
BOE.............. 1,906,000 4,049,000 4,221,000 8,768,000 * *
Future net revenues
(before income
taxes)(1)........ $15,268,000 $28,016,000 $17,771,000 $40,167,000 * *
Discounted future
net revenues
(before income
taxes)(1)........ $11,126,000 $18,489,000 $11,895,000 $26,014,000 * *
Future net cash
flows (net of
income
taxes)(2)........ $11,307,000 $21,383,000 $14,133,000 $31,711,000 * *
Discounted future
net cash flows
(net of income
taxes)(2)........ $ 8,234,000 $14,110,000 $10,845,000 $21,127,000 * *
</TABLE>
- ---------------
* The Company generally commissions reserve reports on an annual basis.
(1) See footnote (4) on page 3.
(2) See footnote (5) on page 3.
The following table sets forth (i) production data for the Company for the
nine months ended September 30, 1995, (ii) pro forma production data for the TNC
Fields (including the Teca/Nare Fields for the period January 1 to September 12,
1995) and Net Other Transactions (including the Velasquez Field for January 1995
and Cabot Properties for the period January 1 to May 18, 1995) as if the
acquisition of the TNC Fields and Net Other Transactions had occurred on January
1, 1995, and (iii) combined pro forma production data for the Company and such
transactions as if such transactions had occurred on January 1, 1995.
<TABLE>
<CAPTION>
NET OTHER PRO FORMA
COMPANY TNC FIELDS TRANSACTIONS COMBINED
--------- ---------- ------------ ---------
<S> <C> <C> <C> <C>
Oil (Bbls)................................. 746,000 712,000 47,000 1,505,000
Gas (Mcf).................................. 1,052,000 -- 106,000 1,158,000
BOE........................................ 921,000 712,000 65,000 1,698,000
Average sales price (per unit):
Oil (Bbls)............................... $12.82 $11.77 $13.59 $12.35
Gas (Mcf)................................ 1.35 -- 1.31 1.34
BOE...................................... 11.92 11.77 12.02 11.86
</TABLE>
22
<PAGE> 23
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in conjunction with
the Consolidated Financial Statements of the Company and the related notes.
OVERVIEW
The Company's long-term business strategy is to acquire oil and gas
reserves for current and future production and the enhancement and development
of such reserves. Capital utilized to acquire such reserves has been provided
primarily by secured bank financing, the creation of joint interest operations
and production payment obligations and sales of the Company's equity securities.
In pursuit of its business strategy, the Company has made significant
acquisitions of oil and gas producing properties in recent years. The extent and
timing of these acquisitions complicates period to period comparisons.
The Company's oil and gas producing activities are accounted for using the
full cost method of accounting. Accordingly, the Company capitalizes all costs,
in separate cost centers for each country, incurred in connection with the
acquisition of oil and gas properties and with the exploration for and
development of oil and gas reserves. Such costs include lease acquisition costs,
geological and geophysical expenditures, costs of drilling both productive and
non-productive wells, and overhead expenses directly related to land acquisition
and exploration and development activities. Proceeds from the disposition of oil
and gas properties are accounted for as a reduction in capitalized costs, with
no gain or loss recognized unless such disposition involves a significant change
in reserves, in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and gas properties, including
estimated future development costs, is provided using the equivalent
unit-of-production method based upon estimates of proved oil and gas reserves
and production which are converted to a common unit of measure based upon their
relative energy (BTU) content. Unproved oil and gas properties are not amortized
but are individually assessed for impairment. The cost of any impaired property
is transferred to the balance of oil and gas properties being depleted.
The Company's operating performance is influenced by several factors, the
most significant of which are the price received for its oil and gas and the
Company's sales volumes. The world price for crude oil has an overall influence
on the prices that the Company receives for its domestically-produced oil. The
prices received for different grades of oil are based upon the world price for
crude oil, which is then adjusted based upon the particular grade, such that,
typically, light oil is sold at a premium while heavy grades of crude are
discounted. Additional factors influencing operating performance include
production expenses, overhead requirements, the Company's method of depleting
reserves, and cost of capital.
In May 1995, the Company completed the re-permitting and environmental
impact review process of its Santa Maria refinery with the County of Santa
Barbara and in June 1995 re-commenced refinery operations. The Company entered
into a processing agreement with Petro Source, under which Petro Source
purchases crude oil (including crude oil purchased from the Company), delivers
it to the refinery, reimburses the Company's out-of-pocket costs for refining,
markets the asphalt and other products and generally shares any profits equally
with the Company.
Operations at two of the Company's properties in the Santa Maria Valley
area of California were significantly affected by adverse weather conditions and
a reduction in water disposal availability during the Spring of 1995. Production
in the first quarter of 1995 decreased approximately 11,000 BOE as a result of
these conditions. Heavy rains resulted in additional expenses for surface
remediation and equipment repairs which were necessary to keep wells on
production. Shutting in certain wells due to weather related incidents resulted
in decreased production during the period. In addition, the Company's water
disposal vendor instituted a reduction in the amount of waste water which could
be disposed, which adversely affected production. The Company developed
alternative means of water disposal during the period, allowing for an increase
in oil production by the end of the period.
23
<PAGE> 24
RESULTS OF OPERATIONS
The following table sets forth for the periods indicated the percentage of
total revenues represented by each item reflected on the Company's statements of
operations.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED SEPTEMBER 30,
----------------------------------- -------------------
1991 1992 1993 1994 1994 1995
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Revenues:
Oil and gas sales...................... 87.2% 92.6% 96.2% 93.9% 97.1% 96.3%
Other.................................. 12.8 7.4 3.8 6.1 2.9 3.7
----- ----- ----- ----- ----- -----
Total revenues................. 100.0 100.0 100.0 100.0 100.0 100.0
----- ----- ----- ----- ----- -----
Expenses:
Production costs....................... 57.9 51.8 55.6 58.2 59.4 60.8
General and administrative............. 10.1 19.1 23.8 14.5 14.3 12.3
Depletion, depreciation and
amortization........................ 16.5 16.9 17.6 15.8 18.7 17.0
----- ----- ----- ----- ----- -----
Total expenses................. 84.5 87.8 97.0 88.5 92.4 90.1
----- ----- ----- ----- ----- -----
Operating income......................... 15.5 12.2 3.0 11.5 7.6 9.9
----- ----- ----- ----- ----- -----
Other income (expense):
Interest expense, net.................. (2.5) (4.7) (4.0) (4.7) (5.1) (6.8)
Other.................................. (0.8) -- (0.2) 0.1 1.0 0.4
----- ----- ----- ----- ----- -----
Total other income (expense)... (3.3) (4.7) (4.2) (4.6) 4.1 (6.4)
----- ----- ----- ----- ----- -----
Income (loss) before income taxes........ 12.2 7.5 (1.2) 6.9 3.5 3.5
Provision (benefit) for taxes on
income................................. 0.1 1.9 -- 3.0 0.9 1.5
----- ----- ----- ----- ----- -----
Net income (loss)........................ 12.1% 5.6% (1.2)% 3.9% 2.6% 2.0%
===== ===== ===== ===== ===== =====
</TABLE>
In the third quarter of 1995, net income increased by $6,000, or 5.3%, to
$120,000 from $114,000 in the third quarter of 1994. Oil and gas sales increased
$540,000, or 15.8%, to $3.96 million for the three months ended September 30,
1995, from $3.42 million for the same period of 1994, due to production from the
Company's Colombian properties which were acquired in January and September
1995. Production costs increased $510,000, or 24.9%, to $2.56 million for the
third quarter of 1995 from $2.05 million for the same period of 1994, due to an
increase in production of 72,000 BOE, or 27.7%, to 332,000 BOE in the third
quarter of 1995 from 260,000 BOE in the third quarter of 1994. Depletion,
depreciation and amortization increased $51,000, or 7.7%, to $712,000 for the
three months ended September 30, 1995 from $661,000 for the three months ended
September 30, 1994, due principally to an increase in cost depletion of $47,000
resulting from increased production. Interest expense increased $172,000, or
101.8%, to $341,000 for the third quarter of 1995 from $169,000 for the same
period of 1994 due principally to an increase in the average balance outstanding
under the Company's revolving line of credit of $5.35 million, or 96.2%, from
$5.56 million to $10.91 million, and an increase in that facility's weighted
average interest rate of 131 basis points, or 15.5%, from 8.46% to 9.77%.
NINE MONTHS ENDED SEPTEMBER 30, 1995 AND SEPTEMBER 30, 1994
Oil and Gas Sales
Oil and gas sales increased $2.01 million, or 22.4%, to $10.98 million for
the nine months ended September 30, 1995, from $8.97 million for the same period
of 1994. The increase was primarily the result of an increase of 5.9% in the
United States of the average sales price per BOE from $12.57 in the nine months
ended September 30, 1994 to $13.31 for the same period of 1995, and increases in
the Company's oil and gas production. Of such increase, $465,000 was
attributable to the average sales price per BOE increase in the United States. A
decrease of 7.8% in Canada of the average sales price per BOE from $10.70 in the
nine months ended September 30, 1994 to $9.87 for the same period of 1995 due to
declining gas prices resulted in
24
<PAGE> 25
a decrease in oil and gas sales of $97,000. Increases in the Company's oil and
gas production represented $1.64 million of the increase of oil and gas sales.
Of such production increase, $974,000 was due to production from the Velasquez
Field, which was acquired in January 1995, $491,000 was due to production from
the Teca/Nare Fields, which were acquired in September 1995, and the remaining
$177,000 stemmed from a net production increase of 14,000 BOE in the United
States and Canada, resulting from acquisitions in the latter part of 1994 and
the first half of 1995, reduced by property divestitures, normal production
declines and production interruptions resulting from severe weather conditions
in California in the first quarter of 1995.
Other Revenues
Other revenues increased $148,000, or 55.0%, to $417,000 for the nine
months ended September 30, 1995, from $269,000 for the same period of 1994, due
principally to fees invoiced to a third party in 1995 for the use of Company
facilities and to pipeline tariffs charged for the Company's share of the
Velasquez-Galan Pipeline.
Production Costs
Production costs increased $1.43 million, or 26.0%, to $6.92 million for
the nine months ended September 30, 1995, from $5.49 million for the same period
of 1994. Of this increase, $498,000 was the result of an average production cost
per BOE increase of $0.79 in the United States, due principally to operations at
the Company's heavy-oil properties in the Santa Maria, California area. The
combined production increase of 14,000 BOE in the United States and Canada was
responsible for a cost increase of $108,000 in the first nine months of 1995,
compared to the same period of 1994. From their acquisition dates of January 31,
1995 and September 12, 1995, the Velasquez Field and Teca/Nare Fields incurred
production costs of $583,000 and $275,000, respectively, in the period ended
September 30, 1995.
General and Administrative Expenses
General and administrative expenses increased $90,000, or 6.8%, to $1.41
million for the nine months of 1995, from $1.32 million for the same period of
1994, due principally to general and administrative expenses incurred by the
Company's refinery and real estate subsidiaries, which did not begin operations
until the third and fourth quarters of 1994, respectively.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased $204,000, or
11.8%, to $1.93 million in the first nine months of 1995, from $1.73 million for
the same period of 1994. Oil and gas depletion expense increased $199,000, or
12.3%, to $1.81 million for the first nine months of 1995, from $1.61 million
for the same period of 1994. In the United States, production of oil and gas
increased 13,000 BOE, or 2.1%, to 627,000 BOE for the first nine months of 1995,
from 614,000 BOE for the same period of 1994. Depletion expense in the United
States decreased $22,000 to $1.28 million, or $2.03 per BOE, for the first nine
months of 1995, from $1.30 million, or $2.11 per BOE, for the same period of
1994, due principally to an increase in proved reserves at January 1, 1995. In
Canada, production of oil and gas increased 1,000 BOE, or 0.9%, to 117,000 BOE
for the first nine months of 1995, from 116,000 BOE for the same period of 1994.
Depletion expense in Canada increased $6,000 to $322,000, or $2.75 per BOE, for
the first nine months of 1995, from $316,000, or $2.71 per BOE, for the same
period of 1994. Depletion expense in Colombia was $215,000, or $1.21 per BOE,
for the first nine months of 1995. Depreciation and amortization expense
increased $5,000, or 4.4%, to $119,000 for the first nine months of 1995, from
$114,000 for the same period of 1994.
Net Interest Expense
Interest expense increased $305,000, or 64.5%, to $778,000 for the nine
months ended September 30, 1995, from $473,000 for the same period of 1994, due
principally to the Company's bank borrowings under its revolving line of credit
facility. The average debt balance outstanding under the Company's revolving
line of credit for the nine months ended September 30, 1995 increased $2.43
million, or 40.7%, to $8.38 million, from
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<PAGE> 26
$5.95 million for the same period of 1994, due principally to the use of
proceeds to fund property acquisitions which closed during 1995. The weighted
average interest rate for the Company's revolving line of credit increased 209
basis points, or 26.9%, to 9.86% for the nine months ended September 30, 1995
from 7.77% for the same period of 1994. Interest expense incurred by CRPL
decreased by $37,000, or 30.3%, to $85,000 for the nine months ended September
30, 1995, from $122,000 for the same period of 1994, due to monthly principal
reductions under the term loan and retirement of a note payable in January 1995.
The Company's refinery subsidiary incurred interest expense of $65,000 in the
nine month period ended September 30, 1995.
Other Income (Expense)
Other income (expense) decreased $44,000, or 46.8%, to income of $50,000
for the nine month period ended September 30, 1995, from income of $94,000 for
the same period of 1994. The change was primarily due to non-recurring expenses
of $119,000 in 1994 resulting from the Company's sale of its oil and gas
environmental services business effective March 31, 1994, and proceeds of
$198,000 realized in settlement of litigation in June 1994. Land rental income
of $45,000 was realized in the nine month period ended September 30, 1995.
1994 COMPARED TO 1993
Oil and Gas Sales
Oil and gas sales increased $2.04 million, or 20.1%, to $12.17 million in
fiscal year 1994, from $10.13 million in fiscal year 1993. The increase was
primarily the result of increases in the Company's oil and gas production. An
increase of 225,000 BOE in the Company's oil and gas production in fiscal year
1994 represented $2.6 million of the increase in oil and gas sales. Of such
production increase, $2.24 million (196,500 BOE) was due to the Company's
acquisition of new producing properties in the State of California and in
Alberta, Canada. Offsetting the production increase, the average sales price per
BOE decreased $0.99, or 7.4%, to $12.42 in fiscal year 1994 from $13.41 in
fiscal year 1993. This decrease was primarily due to the increase in production
from the Company's heavy crude oil properties located in the Santa Maria,
California area. The sales price of crude oil from these properties is generally
lower than the sales price of crude oil from other properties held by the
Company.
Other Revenues
Other revenues increased $384,000, or 96.0%, to $784,000 in fiscal year
1994, from $400,000 in fiscal year 1993. Substantially all of such increase was
attributable to the sale of real estate in Orange County, California in November
1994. Divestiture of non-strategic and non-profitable properties and operations
in fiscal year 1993 and the first quarter of 1994 resulted in a decrease in
revenues in fiscal year 1994 of $133,000. The remainder of the change was due to
additional fees earned by the Company in its capacity as operator of producing
oil and gas properties.
Production Costs
Production costs increased $1.69 million, or 28.9%, to $7.55 million ($7.70
per BOE) in fiscal year 1994, from $5.86 million ($7.75 per BOE) in fiscal year
1993. The overall increase was due to higher production levels in fiscal year
1994. On a BOE basis, production costs for properties located in the United
States increased $0.44, due primarily to higher average production costs per BOE
at the Company's North Belridge and Santa Maria properties in California and the
Company's Michigan properties. Production costs for the Canadian properties were
$5.19 per BOE in fiscal year 1994.
General and Administrative Expenses
General and administrative expenses decreased $621,000, or 24.8%, to $1.88
million in fiscal year 1994, from $2.5 million in fiscal year 1993.
Substantially all of such decrease was attributable to the Company's actions in
the second half of 1993 to consolidate office locations, eliminate duplicative
administrative services and replace contract labor personnel with Company
employees. Cost cutting measures enacted at the end of
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<PAGE> 27
the first quarter of fiscal year 1994, including the disposition of
non-profitable business operations, also contributed to the decrease. General
and administrative expenses attributable to CRPL were $176,000 for fiscal year
1994.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased approximately
$189,000, or 10.0%, to $2.04 million in fiscal year 1994, from $1.85 million in
fiscal year 1993. Oil and gas depletion expense increased $141,000, or 8.0%, to
$1.9 million in fiscal year 1994, from $1.77 million in fiscal year 1993. In the
United States, production of oil and gas increased 8.7% to 821,000 BOE in fiscal
year 1994, from 755,000 BOE for fiscal year 1993. However, proved reserves in
the United States increased 3.65 million BOE to 7.87 million BOE at December 31,
1994, from 4.22 million BOE at December 31, 1993, which resulted in depletion
expense in the United States decreasing $314,000 to $1.45 million, or $1.77 per
BOE, in fiscal year 1994, from $1.76 million, or $2.34 per BOE, in fiscal year
1993. Depletion expense in Canada was $455,000, or $2.86 per BOE, in fiscal year
1994. Depreciation and amortization expense increased $47,000, or 53.4%, to
$135,000 in fiscal year 1994 from $88,000 in fiscal year 1993. The increase was
due principally to a full year's amortization of costs incurred in obtaining the
Company's revolving credit facility in September 1993.
Net Interest Expense
Interest expense increased $191,000, or 43.1%, to $634,000 in fiscal year
1994, from $443,000 in fiscal year 1993. The average amount of applicable
interest-bearing debt in the United States in fiscal years 1993 and 1994 was
$5.28 million and $5.69 million, respectively. The higher amounts outstanding
under the Company's principal credit agreement in 1994 compared to 1993,
partially offset by the lower rate of interest in 1994, resulted in an increase
in U.S. interest expense of $19,000 for 1994 compared to 1993. Interest expense
of CRPL was $172,000 in fiscal year 1994.
Other Income (Expense)
Other income (expense) increased $34,000, or 212.5%, to income of $18,000
in fiscal year 1994 from net expense of $16,000 in fiscal year 1993. Included
for fiscal year 1994 are net proceeds of $198,000 received in settlement of
litigation with a third party, and expenses of $119,000 attributed to the
Company's sale of its oil and gas environmental services business effective
March 31, 1994.
Income Tax
The Company's effective tax rate for 1994 was 43%. The effective rate for
fiscal year 1993 was (29.6%), resulting in a tax benefit of $37,000 on a pretax
loss of $125,000.
1993 COMPARED TO 1992
Oil and Gas Sales
Oil and gas sales increased $4.11 million, or 68.3%, to $10.13 million in
fiscal year 1993 from $6.02 million in fiscal year 1992. The increase was
primarily the result of increases in the Company's oil and gas production. An
increase of 364,195 BOE in the Company's oil and gas production in fiscal year
1993 represented $5.60 million of the increase in oil and gas sales. Such
production increase was due primarily to the Company's acquisition of new
producing properties in California and Michigan. The average sales price per BOE
decreased $1.98, or 12.9%, to $13.41 in fiscal year 1993, from $15.39 in fiscal
year 1992, resulting in a decline in oil and gas sales of $1.49 million. This
decrease was primarily due to reduced world oil prices and lower prices received
for the heavy crude oil production from certain of the Company's California
producing properties.
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<PAGE> 28
Other Revenues
Other revenues decreased $84,000, or 17.4%, to $400,000 in fiscal year 1993
from $484,000 in fiscal year 1992. Such decrease was due principally to the
discontinuance of contract pumping services in July 1993.
Production Costs
Production costs increased $2.49 million, or 73.9%, to $5.86 million ($7.75
per BOE) in fiscal year 1993 from $3.37 million ($8.61 per BOE) in fiscal year
1992. The overall increase was due to higher production levels in fiscal year
1993. The decrease of $0.86 per BOE was the result of the lower average
production costs per BOE at the Company's California and Michigan properties.
General and Administrative Expenses
General and administrative expenses increased $1.26 million, or 102%, to
$2.50 million in fiscal year 1993, from $1.24 million in fiscal year 1992. Of
such increase, $332,000 was attributable to costs associated with closing
regional offices in Texas and California, relocation of the corporate offices to
Irvine, California, and related employee severance, relocation and employment
costs. The remaining increase was primarily the result of the increased level of
staffing necessary for the larger volume of business in fiscal year 1993.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased $751,000, or
68.3%, to $1.85 million in fiscal year 1993, from $1.10 million in fiscal year
1992. Of such increase, $699,000 was attributable to depletion expense, due
principally to higher levels of production in fiscal year 1993. Depletion
expense per BOE decreased $0.39 to $2.34 in fiscal year 1993 from $2.73 in 1992,
due principally to higher reserve quantities at the end of 1993.
Net Interest Expense
Interest expense increased $127,000, or 40.0%, to $443,000 in fiscal year
1993, from $316,000 in fiscal year 1992. This increase was attributable to an
increase in the average amount of long-term debt outstanding in fiscal year
1993.
Income Tax
The Company's effective tax rate for fiscal year 1993 was (29.6%),
resulting in a tax benefit of $37,000 on a pretax loss of $125,000. The
Company's effective tax rate for fiscal year 1992 was 25.5%, resulting in an
income tax of $125,000.
LIQUIDITY AND CAPITAL RESOURCES
The Company is currently experiencing significant cash flow difficulties
caused, in part, by borrowings incurred in connection with the acquisition of
the Teca/Nare Fields, the fact that, in the ordinary course, no significant cash
flow will be available to the Company from the Teca/Nare Fields until December
1995, the need to fund operating expenses of the Teca/Nare Fields and the
Velasquez-Galan Pipeline on a current basis, the fact that the Company has no
remaining available borrowing capacity under its bank credit facility and that
facility prohibits the Company from incurring other indebtedness without the
lender's consent, and delays in the completion of this Offering. The Company
does not currently have sufficient capital resources to fund its share of the
working capital requirements for the Teca/Nare Fields and Velasquez-Galan
Pipeline, but will when this Offering is completed. Completion of this Offering,
however, will increase interest expense of the Company. Upon completion of this
Offering, after giving effect to the application of the net estimated proceeds
therefrom, the Company anticipates that it will have approximately $1.6 million
of borrowing capacity available under its bank credit facility. The Company
believes that the borrowing capacity remaining after using $1.75 million as
collateral to secure payments due to third party vendors at the Teca/Nare
Fields,
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plus anticipated cash flows from operations, will be sufficient to fund its
presently expected working capital requirements.
At September 30, 1995, the Company's total current assets were $4.45
million and its total current liabilities were $13.62 million. Included in
current liabilities was $8.52 million attributable to the current portion of
long-term debt, and an $842,000 obligation due for repayment from future oil
production.
The Company's operating activities during the nine month period ended
September 30, 1995 provided net cash flow of $2.14 million. Net income of
$230,000, adjusted for non-cash charges (primarily depletion, depreciation and
amortization) in the amount of $2.06 million, was the primary source of this
cash flow. Cash flows from operating activities provided net cash flow of $3.35
million in fiscal year 1994. Net income of $509,000, adjusted for non-cash
charges (primarily depletion, depreciation and amortization) in the amount of
$2.41 million, was the principal source of the fiscal year 1994 cash flow.
Investing activities during the nine month period ended September 30, 1995
resulted in a net cash outflow of $15.17 million. Of this amount, oil and gas
property acquisition, development and exploration expenditures totaled $13.17
million, and a deposit in the amount of $100,000 was made in connection with an
acquisition of oil and gas properties in Colombia, which is scheduled for
closing in the first quarter of 1996. An additional $1.98 million was expended
for other assets, consisting principally of an oil transmission pipeline and
related oilfield equipment, which were acquired in connection with a property
acquisition in Colombia.
Investing activities during fiscal year 1994 resulted in a utilization of
cash amounting to $3.93 million. Expenditures for oil and gas property
acquisitions and exploration and development activities totaled $3.69 million.
An additional $798,000 of cash was utilized for other equipment purchases. Sales
of producing oil and gas properties provided cash of $530,000.
Financing activities during the nine month period ended September 30, 1995,
which provided net cash flow of $12.39 million, consisted principally of
activity on the Company's revolving line of credit, a bank term loan of $4.7
million, a loan from the Company's parent company of $2.2 million, and
retirement of a $606,000 note payable that was outstanding at December 31, 1994.
Advances from affiliated companies in the amount of $387,000 were used to
partially fund the note payable payoff.
Financing activity directed to advances and repayments on the Company's
revolving line of credit resulted in a net debt reduction under that credit
facility of $1.32 million for the fiscal year 1994. A term loan of $2.0 million
was used in connection with the acquisition of oil and gas properties in Canada,
of which $535,000 was repaid in fiscal year 1994. Proceeds of $510,000 were
realized from the exercise of options for 200,000 shares of the Company's Common
Stock. Contributed surplus represents capital contributed to CRPL in fiscal year
1994 by its former parent company prior to its acquisition by the Company.
The Company has expanded its operations through acquisitions of oil and gas
producing properties, and intends to do so in the future by means of additional
financing. The Company funded its acquisition of the Teca/Nare Fields and
Velasquez-Galan Pipeline in part by obtaining loans of $700,000 and $1.5
million, bearing interest at prime plus one percent per annum, from Capco, its
majority shareholder, and CRI, which, until December 1995, was a wholly-owned
subsidiary of Capco and is now a majority-owned subsidiary of Capco,
respectively, and in part by borrowing $4.7 million from a bank, which borrowing
has been guaranteed by Ilyas Chaudhary, the controlling shareholder of Capco. Of
such $700,000 loan, $600,000 will, prior to the close of the Offering, be
converted into 75,000 shares of Common Stock of the Company at a conversion
price of $8.00 per share. The Company intends to fund its acquisition of the
Cocorna Field in part by reborrowing $450,000 under its bank credit facility
following the completion of this Offering and the application of the net
proceeds therefrom. In connection with the acquisition of the Teca/Nare Fields,
the Company is required to pledge collateral consisting of, at the option of
Omimex de Colombia, Ltd. and its bank, either a $1.75 million certificate of
deposit or a commitment of $1.75 million against the Company's borrowing base
under its bank credit facility to secure payments due third party vendors at the
Teca/Nare Fields.
Effective at the closing of the Offering, the maturity of the $1.5 million
loan from CRI and the $100,000 balance of the loan from Capco will be extended
to April 1, 2006, and such loans will be subordinated to the same extent the
Debentures are subordinated. Such loans may be prepaid in whole or in part from
the
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<PAGE> 30
proceeds of the public or private sale by the Company for cash of (i) equity
securities or (ii) debt securities (other than the Debentures) that rank pari
passu in right of payment with, mature on or after the maturity date of and are
subordinated to the same extent as, or are subordinated and junior in right of
payment to, the Debentures. These loans may also be prepaid in part from time to
time in amounts proportionate to any reduction in the aggregate amount of
Debentures.
The Company has a reducing, revolving line of credit with Bank One, Texas,
N.A. At September 30, 1995, the borrowing base under the credit agreement was
$10.7 million, subject to a monthly reduction of $200,000. Outstanding debt at
September 30, 1995 under this revolving line of credit was $10.7 million.
Should the Company be unable to obtain equity and/or debt financing in
amounts sufficient to fund projected activities, it may be constrained in its
ability to acquire and/or develop additional oil and gas properties.
NEW ACCOUNTING STANDARDS
In March 1995, the Financial Accounting Standards Board adopted Statement
of Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," which the
Company will be required to implement in 1996. Management is currently assessing
the impact, if any, which this new accounting standard, when adopted, will have
on the Company.
IMPACT OF INFLATION
The price the Company receives for its oil and gas has been impacted
primarily by the world oil market and the domestic market for natural gas,
respectively, rather than by any measure of general inflation. Because of the
relatively low rates of inflation experienced in the United States in recent
years, the Company's production costs and general and administrative expenses
have not been impacted significantly by inflation.
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BUSINESS
OVERVIEW
Saba is an international oil and gas producer with principal producing
properties located in the United States, Canada and Colombia. In fiscal years
1993 and 1994, oil and gas sales accounted for 96.2% and 93.9%, respectively, of
the Company's gross revenues. Until 1994, all of the Company's principal assets
were located in the United States. In 1994 and the first nine months of fiscal
year 1995, the Company acquired interests in producing properties in the United
States, Canada and Colombia. For the nine months ended September 30, 1995,
approximately 23.9% of the Company's gross revenues from oil and gas production
were derived from its international operations. The percentage of the Company's
gross revenues derived from international operations is anticipated to increase
significantly following the acquisition of the TNC Fields, including acquisition
of the Teca/Nare Fields completed in September 1995.
Saba's principal business strategy is to increase its oil and gas reserves
through the acquisition of producing oil and gas properties, which may include
certain properties with developmental potential, and through the acquisition of
companies with oil and gas reserves, both domestically and internationally. From
time to time, including at the present time, the Company is engaged in
negotiations to acquire such properties and companies, and it may endeavor to
make such acquisitions in exchange for one or more of cash, notes or its
securities. There can be no assurance that any such properties or companies
could be acquired, or acquired on terms that are favorable or acceptable to the
Company.
The Company's proved reserves have increased each year since 1991 at an
annual rate of approximately 120%. As of September 30, 1995, the Company owned
working interests in 907 producing oil wells and 163 producing natural gas wells
and royalty interests in 164 wells, with net proved reserves of approximately
14.7 million barrels of oil and 10.9 million Mcf of natural gas.
Saba, formerly known as Bordeaux Petroleum Company ("Bordeaux"), was
incorporated in 1979 in Colorado. Ilyas Chaudhary acquired approximately 46% of
the then-outstanding stock of Bordeaux in 1988. In 1991, when Bordeaux did not
have any significant operations, Bordeaux acquired Saba Energy of Texas,
Incorporated, of which Mr. Chaudhary owned 87% of the outstanding common stock,
in exchange for 2.3 million shares of Bordeaux common stock. Since this
transaction, the Company has grown substantially through continuing acquisitions
of oil and gas producing properties in North and South America.
The principal executive offices of the Company are located at 17512 Von
Karman Avenue, Irvine, California, 92714 and the Company's telephone number at
this location is (714) 724-1112.
ACQUISITION OF PRODUCING PROPERTIES AND RELATED OPERATIONS
For the period commencing January 1, 1992 and ending September 30, 1995,
the Company expended approximately $24.4 million for the acquisition of
producing properties. As a result of this series of acquisitions, the Company
has established an experienced acquisitions group of employees and consultants
with engineering, accounting, geological and financial expertise, allowing the
Company to respond promptly and efficiently to acquisition opportunities. The
Company's process for evaluating properties includes numerous factors, such as
estimated reserves, projected cash flows from production, estimated future oil
and gas prices, and other considerations affecting the marketing of production.
The table on the following page lists certain properties in which the
Company acquired an interest since 1992, including acquisition of the Cocorna
Field (scheduled to be completed in the first quarter of 1996). All
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properties listed below are oil and gas producing properties except the
Company's asphalt refinery located in Santa Maria, California and the
Velasquez-Galan Pipeline.
<TABLE>
<CAPTION>
TYPE OF CONTRACT
DESCRIPTION OF PROPERTY INTEREST YEAR ACQUIRED PURCHASE PRICE
----------------------- -------------- ------------- --------------
<S> <C> <C> <C>
United States:
Michigan............................. Leasehold 1992 $ 6,177,000
Richfield East Dome Unit (CA)........ Leasehold 1992 712,000
North Belridge Field (CA)............ Leasehold 1992 940,000
Weldon Canyon (CA)................... Leasehold 1992 25,500
Cat Canyon/Gato Ridge Field (CA)..... Leasehold/Fee 1993 800,000
Bunker Gas Field (CA)................ Leasehold 1993 103,000
Various Royalties (CA)............... Leasehold 1993 50,000
South Mountain Field (CA)............ Leasehold 1993 73,000
Hill Pool (CA)....................... Leasehold 1993 90,000
Santa Maria Refinery (CA)............ Fee 1994 1,700,000
Dutch Slough Field (CA).............. Leasehold 1994 29,000
Casmalia (CA)........................ Leasehold 1994 505,000
Huntington Beach (CA)................ Leasehold 1994 232,000
Santa Maria Valley (CA).............. Leasehold/Fee 1995 400,000
Cabot (TX)........................... Leasehold 1995 2,249,000
Mitchell (TX and NM)................. Leasehold 1995 324,000
Canada:
Wainright, Sounding Lake, Utikuma,
Craigmyle, Rumsey (Alberta)....... Leasehold 1994 3,059,500
Colombia:
Velasquez Field...................... Fee 1995 1,250,000
Teca/Nare Fields and Velasquez-Galan
Pipeline.......................... Leasehold 1995 12,250,000
Cocorna Field........................ Leasehold Acquisition 750,000
Pending
</TABLE>
ACQUISITION OF THE TNC FIELDS
In April 1995, the Company and Omimex de Colombia, Ltd., a member of the
Omimex Group, a group of privately held companies based in the United States, as
the successful parties in a sealed bidding process, executed an agreement with
Texaco, under which each acquired one-half of Texaco's 50% interest in the
Teca/Nare Fields and one-half of Texaco's 100% interest in the Velasquez-Galan
Pipeline and under which each will acquire one-half of Texaco's 100% interest in
the Cocorna Field. Ecopetrol, the Colombian government-owned oil company, holds
the other 50% interest in the Teca/Nare Fields. The Company completed the
Teca/Nare Fields and Velasquez-Galan Pipeline acquisition in September 1995 and
anticipates completing the Cocorna Field acquisition in the first quarter of
1996, each with an effective date of January 1, 1995. The Company's gross
acquisition cost for the Teca/Nare Fields and Velasquez-Galan Pipeline was
$12.25 million, which was reduced by the Company's share of production credits
from the properties from January 1, 1995 to the closing date (approximately
$3.95 million), leaving a net purchase price of approximately $8.3 million. The
Company financed the purchase price through application of a $1.4 million
deposit made in April 1995, a loan of $700,000 from Capco, a corporation of
which Mr. Chaudhary is the majority shareholder and which is the majority
shareholder of the Company, a loan of $1.5 million from CRI, which, until
December 1995 was a wholly-owned subsidiary of Capco and is now a majority-owned
subsidiary of Capco, and a $4.7 million loan from a bank, guaranteed by Mr.
Chaudhary. Of such $700,000 loan from Capco, $600,000 will, prior to the close
of the Offering, be converted into 75,000 shares of Common Stock. The maturity
of the $1.5 million loan from CRI and the $100,000 balance of the loan from
Capco will, effective at the closing of the Offering, be extended to April 1,
2006, and such loans will be subordinated to the
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<PAGE> 33
same extent the Debentures are subordinated. The Company's gross acquisition
cost for the Cocorna Field is $750,000, which will be reduced by the Company's
share of production credits from the property from January 1, 1995 to the
closing date (approximately $200,000 at September 30, 1995), leaving a net
purchase price of approximately $550,000. The Company has made a $100,000
deposit with Texaco and intends to finance the balance of the purchase price by
reborrowing $450,000 under its bank credit facility following the completion of
this Offering and the application of the net proceeds therefrom. See "Use of
Proceeds."
In connection with the acquisition of the Teca/Nare Fields, Ecopetrol has
required that Omimex de Colombia, Ltd. obtain a letter of credit for the benefit
of Ecopetrol in the amount of $3.5 million to secure payments due third party
vendors at the Teca/Nare Fields. Such letter of credit was issued in November
1995. Under the terms of such letter of credit, which expires in October 1996,
Ecopetrol may draw thereon should Omimex de Colombia, Ltd. fail to pay third
party vendors at the Teca/Nare Fields. In connection with the issuance of the
letter of credit, Omimex de Colombia, Ltd. will require that, in December 1995,
the Company pledge collateral consisting of, at the option of Omimex de
Colombia, Ltd. and its lender, a $1.75 million certificate of deposit or a
commitment of $1.75 million against the Company's borrowing base under its bank
credit facility.
The 117 mile long Velasquez-Galan pipeline connects the Company's Velasquez
Field to the Colombian government-owned refinery at Barrancabermeja. In addition
to the Velasquez Field production, the pipeline also transports crude oil
produced from the Cocorna oil field, the Nare oil field and Ecopetrol crude oil
used as diluent for the Cocorna and Nare heavy crude oil. The Company expects
the pipeline to generate revenues through collection of tariffs for use of the
pipeline.
The Company has entered into a joint operating agreement with Omimex de
Colombia, Ltd., under which Omimex de Colombia, Ltd. will operate the TNC
Fields. The Company currently anticipates attempting to increase production at
the Teca/Nare Fields and, in this regard, the assets being purchased from Texaco
include a drilling rig, tubular goods and related oil field supplies that the
Company believes will help facilitate such an increase. Any such increase will
require, among other things, the agreement of Omimex de Colombia, Ltd. and
Ecopetrol. According to a report from Netherland, Sewell & Associates, Inc. and
after giving effect to a 200,000 barrel oil imbalance obligation, at January 1,
1995, the TNC Fields had proved reserves of 5.3 million barrels of oil. As a
result of sales subsequent to January 1, 1995, for which the Company received a
credit against the purchase price of the TNC Fields, the TNC Fields are
estimated to have increased the Company's proved reserves by approximately 4.6
million barrels of oil. For the nine months ended September 30, 1995, the TNC
Fields produced 733,000 net barrels of oil, or 2,700 BOPD.
The Teca/Nare Fields were initially developed by Texaco in 1981 under
association contracts entered into with Ecopetrol in 1980. The exploitation
period under those association contracts expires in August 2008, and is not
renewable by the Company. Under these contracts, the Company and Omimex de
Colombia, Ltd. will each receive 20% of the crude oil produced at the Teca/Nare
Fields, Ecopetrol will receive 40% of such production and 20% will be paid to
the Colombian government in royalties.
Texaco has been operating the Cocorna Field for over 30 years under a
concession contract with Ecopetrol which expires in February 1997, and is not
renewable by the Company. The Cocorna Field has proved reserves of approximately
132,000 barrels of oil, or less than 3% of the proved reserves of the TNC
Fields. After paying 7.59% of the oil produced in kind as a royalty to the
Colombian government, the Company and Omimex de Colombia, Ltd. will share
equally all oil produced from the Cocorna oil field through February 1997.
All crude oil produced at the TNC Fields that is received by the Company
must be sold to Ecopetrol at prices established by Ecopetrol. The operation of
the TNC Fields has been affected by environmental concerns in the past and may
be so affected in the future. For a discussion of these and other risks
concerning the TNC Fields, see "Risk Factors -- Risks Relating to Colombian and
Other Foreign Operations -- Operations in Colombia; TNC Fields." For information
showing the pro forma effect of the acquisition of the TNC Fields and the Net
Other Transactions on selected operating and production data, see "Prospectus
Summary -- Summary Pro Forma Combined Financial and Oil and Gas Data."
33
<PAGE> 34
OPERATION OF PRODUCING PROPERTIES
Wherever possible, the Company seeks to be named as operator for wells in
which it has acquired a significant interest, although this typically occurs
only when the Company owns at least a plurality of the working interests in a
particular well or field. The Company acts as operator of a significant number
of wells in which it owns working interests, while a significant number of wells
and fields in which it owns working interests are operated by other operators
who also own working interests in such wells or fields.
The Company exercises substantial influence over development and
enhancement of the wells that it operates, and supervises the operation and
maintenance of such wells on a day-to-day basis, making all decisions with
respect to necessary labor and equipment, construction of processing facilities
or pipelines, and marketing of production. As operator, the Company is also
responsible for payment of applicable taxes, purchase of necessary insurance,
and payment of royalties and other production expenses. The Company employs
experienced petroleum engineers, geologists and other operations and production
specialists who attempt to improve rates of production from, increase reserves
attributable to, and/or lower the cost of operating, the oil and gas properties
in which the Company owns interests.
Oil and gas properties are customarily operated under the terms of joint
operating agreements among the operator and the other parties owning working
interests in the subject properties, and accompanying joint accounting
procedures, which provide for reimbursement to the operator of its direct
expenses of operating a property and for monthly per-well supervision fees.
Per-well supervision fees vary widely depending on geographic location and
producing formation of the well, whether the well produces oil or gas, and other
factors. Such fees received by the Company range from $225 to $839 per-well, per
month. A substantial number of the Company's joint operating agreements are with
Omimex Energy, Inc., a member of the Omimex Group, and its affiliates. At
December 31, 1994, Company-operated wells accounted for 69.1% of the Company's
total proved reserves.
ASPHALT REFINERY OPERATIONS
In June 1994, in order to increase margins on heavy crude oil from the
Company's oil and gas producing operations in Santa Barbara County, California,
the Company acquired from Conoco Inc. and Douglas Oil Company of California an
asphalt refinery in Santa Maria, California that had been inoperative since
October 1993. The Company refurbished the refinery and, in May 1995, completed a
re-permitting environmental impact review process with Santa Barbara County and
received a Conditional Use Permit to operate the refinery. Under a processing
agreement with Petro Source, the refinery re-commenced operations in June 1995.
Under the processing agreement, Petro Source purchases crude oil (including
crude oil produced by the Company), delivers it to the refinery, reimburses the
Company's out-of-pocket costs for refining, markets the asphalt and other
products and generally shares any profits equally with the Company. Throughput
at the refinery is currently 1,500 BOPD. The refinery has the capacity to
process approximately 8,000 BOPD. Pursuant to the refinery purchase agreement,
the sellers are required to perform certain remediation and other environmental
activities on the refinery property for a period of five years. See "Risk
Factors -- Governmental Regulation and Environmental Risks."
STRATEGY REGARDING SUBSIDIARY COMPANIES
In order to enhance the value of the assets of each of its subsidiary
companies, the Company has established a long-term strategy of considering
transferring minority ownership in certain of its subsidiaries, either by a
public offering of the subsidiary's common stock or by combining the subsidiary
with another company. The Company's strategy is to continue to maintain a
controlling ownership interest and a majority position on the Board of Directors
of each subsidiary. See "Description of the Debentures -- Certain
Covenants -- Limitations on Restricted Payments" and "Common Stock Price Range
and Dividend Policy" for restrictions on the Company's ability to complete these
transactions.
In this regard, the Company has entered into an agreement whereby CRPL was
merged into Beaver Lake Energy Corporation ("Beaver Lake"), whose common stock
is traded on the Alberta Stock Exchange, and the Company will invest
approximately $350,000 in Beaver Lake. As a result of this merger, which was
completed
34
<PAGE> 35
in October 1995, and the investment, which is anticipated to be completed in the
first quarter of 1996, the Company will own approximately 70% of the outstanding
stock of Beaver Lake.
The Company has considered a similar strategy for its Michigan and refinery
subsidiaries, which accounted for 24.3% of consolidated assets and 16.3% of
consolidated revenues of the Company as of and for the nine months ended
September 30, 1995, and 18.3% of the Company's present value of future net
revenues (before income taxes) at December 31, 1994. However, no specific plans
have been developed or pursued.
MARKETING OF PRODUCTION
Substantially all of Saba's crude oil production is sold at the wellhead at
posted prices under short term contracts, as is customary in the industry. The
Company markets its gas on the spot market or under short term sales contracts.
The prices obtained for oil and gas are dependent on numerous factors beyond the
control of the Company, including domestic and foreign production rates of oil
and natural gas, market demand, and the effect of governmental regulations and
incentives. In fiscal year 1994, approximately 18.1% and 30.5% of the Company's
oil and gas revenues were derived from sales to two purchasers, Texaco and
Unocal, respectively. In January 1995, Unocal canceled its purchase contract,
effective March 1, 1995, for the Company's production from one of its major
properties near Santa Maria, California, which accounted for approximately 25%
of the Company's U.S. oil sales in fiscal year 1994. The Company, however,
replaced Unocal with other purchasers on terms generally as favorable as the
terms of the contract with Unocal.
DESCRIPTION OF PROPERTY -- OIL AND GAS PROPERTIES
The following is a description of the Company's oil and gas properties. At
December 31, 1994, the Company had no agreement for the sale of oil and gas to
foreign governments or authorities. All of the production, however, from the
Velasquez Field and the Teca/Nare Fields in Colombia, will be sold to Ecopetrol,
the Colombian government-owned oil company.
Proved Reserves and Future Net Revenues
Saba's proved reserves and future net revenues from proved developed and
undeveloped oil and gas properties (before income taxes) in this Prospectus have
been estimated by the following independent petroleum engineers: for 1994,
Netherland, Sewell & Associates, Inc. (as to United States reserves) and Sproule
Associates Limited (as to Canadian reserves); for 1993 and 1992, Netherland,
Sewell & Associates, Inc. (48% of future net revenues in both 1993 and 1992),
K.E. Richison & Associates Petroleum Engineering, Inc. (52% of future net
revenues in both 1993 and 1992), and, for 1991, Foster Engineering & Consulting.
There have been no reserve estimates filed with any other United States federal
authority or agency.
Saba's reserves as of December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
RESERVE CATEGORY
----------------------------------------------------
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL
------------------------- ------------------------ -------------------------
1994 OIL (BBLS) GAS (MCF) OIL (BBLS) GAS (MCF) OIL (BBLS) GAS (MCF)
- --------------------- ----------- ----------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
United States........ 4,530,000 6,583,000 2,141,000 643,000 6,671,000 7,226,000
Canada............... 465,000 1,921,000 -- 645,000 465,000 2,566,000
---------- ---------- ---------- ---------- ---------- ----------
Total...... 4,995,000 8,504,000 2,141,000 1,288,000 7,136,000 9,792,000
========== ========== ========== ========== ========== ==========
1993
United States only... 2,999,000 6,983,000 53,000 30,000 3,052,000 7,013,000
========== ========== ========== ========== ========== ==========
</TABLE>
35
<PAGE> 36
The estimated future net revenues (using current prices and costs at the
respective years end) and the present value of future net revenues (using a
discount factor of 10 percent per annum) before income taxes for Saba's proved
developed and proved undeveloped oil and gas reserves as of December 31, 1994
and 1993 are as follows:
<TABLE>
<CAPTION>
RESERVE CATEGORY
----------------------------------------------------
PROVED DEVELOPED PROVED UNDEVELOPED TOTAL
------------------------- ------------------------ -------------------------
PRESENT PRESENT PRESENT
FUTURE VALUE OF FUTURE VALUE OF FUTURE VALUE OF
NET FUTURE NET NET FUTURE NET NET FUTURE NET
1994 REVENUE REVENUE REVENUE REVENUE REVENUE REVENUE
- --------------------- ----------- ----------- ----------- ---------- ----------- -----------
<S> <C> <C> <C> <C> <C> <C>
United States........ $25,747,000 $17,734,000 $11,441,000 $5,932,000 $37,188,000 $23,666,000
Canada............... 2,895,000 2,301,000 84,000 47,000 2,979,000 2,348,000
----------- ----------- ----------- ---------- ----------- -----------
Total...... $28,642,000 $20,035,000 $11,525,000 $5,979,000 $40,167,000 $26,014,000
=========== =========== =========== ========== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
1993
- ---------------------
<S> <C> <C> <C> <C> <C> <C>
United States only... $17,327,000 $11,597,000 $ 444,000 $ 298,000 $17,771,000 $11,895,000
=========== =========== =========== ========== =========== ===========
</TABLE>
"Proved developed" oil and gas reserves are reserves that can be expected
to be recovered from existing wells with existing equipment and operating
methods. "Proved undeveloped" oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage, or from existing
wells where a relatively major expenditure is required for recompletion. In
recent years, the market for oil and gas has experienced substantial
fluctuations which have resulted in significant swings in the prices for oil and
gas. Saba cannot predict the future of oil and gas prices or whether future
declines in prices will occur. Any such decline could have a material adverse
effect on Saba.
Major Properties
The Company's major oil and gas producing properties for the fiscal year
ended December 31, 1994 and proved reserves at January 1, 1995, were as follows:
<TABLE>
<CAPTION>
OIL GAS PROVED
PRODUCTION PRODUCTION RESERVES
NAME AND LOCATION (BBLS) (MCF) (BOE)
-------------------------------------------------- ----------- ---------- --------
<S> <C> <C> <C>
UNITED STATES:
Richfield East Dome Unit (California)............. 129,000 -- 902,000
Saba (Michigan)................................... 119,000 455,000 1,113,000
North Belridge Field (California)................. 74,000 58,000 426,000
Cat Canyon/Gato Ridge Field (California).......... 217,000 95,000 3,525,000
</TABLE>
<TABLE>
<CAPTION>
CANADA:
<S> <C> <C> <C>
Wainright, Sounding Lake, Utikuma, Craigmyle,
Rumsey (Alberta)................................ 80,000 473,000 892,000
</TABLE>
Net Quantities of Oil and Gas Produced
The net quantities of oil and gas produced by the Company during each of
the last two years are as follows:
<TABLE>
<CAPTION>
1994 OIL (BBLS) GAS (MCF) BOE
-------------------------------------------------- ----------- ---------- --------
<S> <C> <C> <C>
United States..................................... 658,000 980,000 821,000
Canada............................................ 80,000 473,000 159,000
-------- --------- --------
Total................................... 738,000 1,453,000 980,000
======== ========= ========
</TABLE>
<TABLE>
<CAPTION>
1993
--------------------------------------------------
<S> <C> <C> <C>
United States only................................ 573,000 1,096,000 755,000
======== ========= ========
</TABLE>
36
<PAGE> 37
Average Sales Price and Production Cost
The following table sets forth information concerning average per unit
sales price and production cost for the Company's oil and gas production for the
periods indicated:
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED DECEMBER 31, ENDED
---------------------------- SEPTEMBER 30,
1992 1993 1994 1995
------ ------ ------ -------------
(AMOUNTS IN UNITED STATES DOLLARS)
<S> <C> <C> <C> <C>
Average sales price per BOE:
United States.......................... $15.39 $13.41 $12.67 $ 13.31
Canada................................. -- -- 11.12 9.87
Colombia............................... -- -- -- 8.31
Combined............................... 15.39 13.41 12.42 11.92
Average production cost per BOE:
United States.......................... $ 8.61 $ 7.75 $ 8.19 $ 8.79
Canada................................. -- -- 5.19 4.64
Colombia............................... -- -- -- 4.87
Combined............................... 8.61 7.75 7.70 7.51
</TABLE>
Productive Wells
The following table sets forth certain information at September 30, 1995
relating to the number of productive wells in which the Company owned a working
interest:
<TABLE>
<CAPTION>
OIL GAS TOTAL
---------------- --------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ------ ----- ----- ----- ------
<S> <C> <C> <C> <C> <C> <C>
United States................. 448 197.79 114 57.32 562 255.11
Canada........................ 88 22.12 49 9.31 137 31.43
Colombia...................... 371 92.75 -- -- 371 92.75
---- ------ ---- ----- ----- ------
907 312.66 163 66.63 1,070 379.29
==== ====== ==== ===== ===== ======
</TABLE>
- ---------------
(1) Productive wells are producing wells and wells capable of production,
including wells that are shut in.
(2) A gross well is a well in which a working interest is owned.
(3) A net well is the Company's share of a working interest in a well. The
number of net wells is the total of the Company's working interests in
wells.
The Company also held royalty interests in 164 productive wells in the
United States and Canada.
Acreage
The following table sets forth certain information at September 30, 1995
relating to oil and gas acreage in which the Company owned a working interest:
<TABLE>
<CAPTION>
DEVELOPED(1) UNDEVELOPED
------------------- -------------------
GROSS NET GROSS NET
------ -------- ------ --------
<S> <C> <C> <C> <C>
United States (nine states).............. 50,774 14,094.7 8,803 5,017.0
Canada................................... 15,512 3,253.0 15,071 8,589.0
Colombia................................. 6,398 1,599.0 5,719 1,430.0
------ -------- ------ --------
72,684 18,946.7 29,593 15,036.0
====== ======== ====== ========
</TABLE>
- ---------------
(1) Developed acreage is acreage assigned to productive wells.
A majority of the Company's oil and gas properties are in the form of
mineral leases. As is customary in the oil and gas industry, a preliminary
investigation of title is made at the time of acquisition of undeveloped
properties. Title investigations are generally completed, however, before
commencement of drilling operations
37
<PAGE> 38
or the acquisition of producing properties. The Company believes that its
methods of investigating title to, and acquisition of, its oil and gas
properties are consistent with practices customary in the industry and that it
has generally satisfactory title to the leases covering its proved reserves.
Drilling Activity
The following table sets forth certain information for the fiscal years
ended December 31, 1993 and 1994 relating to the Company's participation in the
drilling of exploratory and development wells. The Company did not participate
in the drilling of any wells in Canada in 1994. The Company did not engage in
exploratory or development drilling activity in 1992.
<TABLE>
<CAPTION>
1993 1994
-------------- --------------
GROSS NET GROSS NET
----- ---- ----- ----
<S> <C> <C> <C> <C>
Exploratory:
Oil.............................................. 1 0.06 -- --
Gas.............................................. -- -- 1 0.07
Dry.............................................. -- -- 3 0.19
Development:
Oil.............................................. 3 1.50 2 0.65
Gas.............................................. -- -- 2 0.29
Dry.............................................. -- -- 1 0.25
Total:
Oil.............................................. 4 1.56 2 0.65
Gas.............................................. -- -- 3 0.36
Dry.............................................. -- -- 4 0.44
</TABLE>
Real Estate
The Company may from time to time seek to purchase real estate in
conjunction with its acquisition of oil and gas properties. In connection with
the acquisition of oil and gas producing properties in Santa Maria, California
in June 1993, the Company purchased 247 acres in Santa Barbara County for an
aggregate purchase price of $65,000. The Company also agreed to acquire an
additional 1,460 acres in Santa Maria for an aggregate purchase price of
$400,000, the closing of which is subject to certain conditions and approval of
a subdivision map, which is currently anticipated to occur in 1995. In addition,
the Company entered into an agreement to acquire 385 fee acres in Santa Barbara
County in 1995 in connection with an acquisition of producing oil and gas
properties at a contract purchase price of $400,000, the closing of which took
place in June 1995. The Company intends to hold these properties for
exploitation of oil and gas and has no current plans to otherwise develop these
properties. In addition, the Company acquired approximately 370 acres of
undeveloped land in Santa Maria, California in June 1994 in connection with the
acquisition of its Santa Maria refinery.
OIL AND GAS PRICES
The Company's revenues are heavily dependent on the prices the Company
receives for its oil and gas, which are influenced by world prices for crude
oil. The price the Company receives for its oil and gas also depends greatly on
the grade of oil sold; typically, light oil is sold at a premium, while heavy
grades of crude oil are discounted.
EMPLOYEES
As of September 30, 1995, the Company employed 60 persons in the operation
of its business, 23 of whom were administrative employees. The Company has not
entered into any collective bargaining agreements with any unions and believes
that its overall relations with its employees are satisfactory.
38
<PAGE> 39
MANAGEMENT
EXECUTIVE OFFICERS, DIRECTORS AND KEY EMPLOYEES
The following table sets forth the name, age and position of the executive
officers, directors and key employees of the Company:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ------------------------- --- ----------------------------------------------
<S> <C> <C>
Ilyas Chaudhary 48 Chairman of the Board, President and Chief
Executive Officer
Francis J. Barker 76 Director
William N. Hagler 63 Director
William J. Hickey 64 Director
William E. Richards 69 Director
Walton C. Vance 48 Vice President, Secretary and Chief Financial
Officer
Larry R. Burroughs 58 President and Chief Operating Officer of Saba
Petroleum, Inc.
Bradley T. Katzung 43 President and Chief Operating Officer of Saba
Energy of Texas, Incorporated and Saba
Petroleum of Michigan, Inc.
Burt M. Cormany 66 President and Chief Operating Officer of Santa
Maria Refining Company
</TABLE>
Executive Officers and Directors
Ilyas Chaudhary has been a director of the Company since 1985 and has
served as Chairman of the Board since 1993. He has been Chief Executive Officer
since 1993 and President since 1994 and had also served as President during
parts of 1991, 1992 and 1993. Mr. Chaudhary is a director and controlling
shareholder of Capco, the Company's majority shareholder, whose common stock is
traded on the Alberta Stock Exchange and which owns 61.9% of the Company's
Common Stock, and the controlling shareholder of Sedco, owner of 4.9% of the
Company's Common Stock. Mr. Chaudhary has 24 years of experience in various
capacities in the oil and gas industry, including eight years of employment with
Schlumberger Well Services from 1972 to 1979. Mr. Chaudhary received a Bachelor
of Science degree in Electrical Engineering from the University of Alberta,
Canada. See "Risk Factors -- Dependence on Mr. Chaudhary."
Francis J. Barker has been a director of the Company since November 1994.
Mr. Barker has been a consultant in the oil and gas industry since 1984. Prior
to 1984, Mr. Barker served as Vice President of Operations at Unocal
Corporation, where he served in various capacities since 1947.
William N. Hagler has been a director of the Company since 1994. Mr. Hagler
is Chairman of the Board of Directors, Chief Executive Officer and President of
Unico, Inc., a company he founded in 1979. Unico is engaged in petroleum
refining, co-generation, natural gas production and the manufacturing of
methanol, a natural gas based petrochemical. Prior to 1979, Mr. Hagler was Vice
President of Plateau, Inc., a Rocky Mountain regional oil refinery. Mr. Hagler
is a member of the City of Farmington, New Mexico Public Utility Commission.
Since 1955, Mr. Hagler has been continuously engaged in various phases of
petroleum manufacturing and marketing with Exxon Corporation, Cities Service Oil
Company and Riffe Petroleum Company.
William J. Hickey has been a director of the Company since 1992, and served
as Secretary of the Company from 1992 until 1994 and as Vice President and
General Counsel of the Company in 1994. Prior to 1989, Mr. Hickey served as
General Counsel of the Business Equipment Group of Litton Industries Inc. Mr.
Hickey was Senior Vice President and a director of American Telephone+Data,
Inc., a public company,
39
<PAGE> 40
from April 1994 to July 1995. Mr. Hickey currently serves as President of
Hickey, Klein & Schumacher, Inc., a New York professional law corporation.
William E. Richards has been a director of the Company since 1993. Since
1989, Mr. Richards has been engaged in the management of his own investments,
including acquisitions in the oil and gas business. He is currently a director
of Maxx Petroleum Ltd. and Capco (the majority shareholder of the Company). Mr.
Richards spent 26 years with Dome Petroleum Limited, which was a large oil and
gas company in Canada, retiring as President in 1983.
Walton C. Vance has been the Vice President and Chief Financial Officer of
the Company since 1993 and became Secretary in 1994. From 1990 to 1993, Mr.
Vance provided accounting and financial reporting services to small businesses,
including oil and gas producers. From 1985 to 1990, Mr. Vance was the Executive
Director for a law firm in Dallas, Texas. Mr. Vance was Chief Financial Officer
of Natural Resource Management Corporation (now Edisto Resources) from 1981 to
1983 and Treasurer in 1984.
Officers of Significant Subsidiaries
Larry R. Burroughs has been President and Chief Operating Officer of Saba
Petroleum, Inc., which operates the Company's California properties, since 1994.
Mr. Burroughs has over 38 years experience in the oil and gas industry as an
engineer and producer, and as the owner of several oil and gas production
companies.
Bradley T. Katzung has been President and Chief Operating Officer of Saba
Energy of Texas, Incorporated and President of Saba Petroleum of Michigan, Inc.
since 1994. Mr. Katzung joined the Company in 1993 as Vice President of
Operations for Saba Energy of Texas, Incorporated, Saba Petroleum of Michigan,
Inc., and Saba Petroleum, Inc. Mr. Katzung has more than twenty years experience
in the oil and gas industry, including as Vice President of Operations for
Okland Oil Company and President of Midwest Oil and Gas Consultants.
Burt M. Cormany has been President of Santa Maria Refining Company since
July 1994. Mr. Cormany has worked in various capacities for the Company's Santa
Maria refinery since 1961, including refinery manager from 1974 to 1990, and was
a consultant to the Company for several months in 1994 prior to becoming
President of Santa Maria Refining Company.
Board Committees
The Executive Committee consists of Messrs. Chaudhary, Barker and Richards
and has all authority, consistent with the Colorado Business Corporation Act, as
may be granted to it by the Board. Accordingly, the Executive Committee may have
and may exercise all the powers and authority of the Board in the oversight of
the management of the business and affairs of the Company, except that the
Executive Committee will not have the power (except, to the extent authorized by
a resolution of the Board) to amend the Company's Articles of Incorporation or
By-laws, fix the designations, preferences, and other terms of any preferred
stock of the Company, adopt an agreement of merger or consolidation, authorize
the issuance of stock, declare a dividend or recommend to the stockholders of
the Company the sale, lease or exchange of all or substantially all of the
Company's property and assets, a dissolution of the Company or a revocation of
such a dissolution.
The Audit Committee, consisting of Messrs. Hagler, Hickey and Barker,
reviews the professional services to be provided by the Company's independent
auditors. The Audit Committee reviews the scope of the audit by the Company's
independent auditors, the annual financial statements of the Company and such
other matters with respect to the accounting, auditing and financial reporting
practices and procedures of the Company as it may find appropriate or as may be
brought to its attention.
The Compensation Committee, consisting of Messrs. Chaudhary, Hagler and
Hickey, reviews executive salaries, administers the stock option plans of the
Company and approves the salaries and other benefits of the executive officers
of the Company. In addition, the Compensation Committee consults with the
Company's management regarding pension and other benefit plans and compensation
policies and practices of the Company.
40
<PAGE> 41
Director Compensation
The Company does not pay additional remuneration to executive officers for
serving as directors. Directors who are not employees currently receive an
annual $7,500 retainer and meeting fees of $650 per meeting. Directors of the
Company are also reimbursed for out of pocket expenses incurred in connection
with their attendance at Board of Directors meetings, including reasonable
travel and lodging expenses.
EXECUTIVE COMPENSATION
The following table sets forth certain information as to compensation of
the Chief Executive Officer of the Company. No other executive officers of the
Company received salary and bonuses of over $100,000 in 1994.
<TABLE>
<CAPTION>
LONG TERM
COMPENSATION
ANNUAL COMPENSATION ------------
---------------------------------- SECURITIES
NAME AND PRINCIPAL OTHER ANNUAL UNDERLYING ALL OTHER
POSITION YEAR SALARY BONUS COMPENSATION OPTIONS(4) COMPENSATION
- -------------------------------- ---- ----------- ----- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C> <C>
Ilyas Chaudhary
Chairman of the Board, 1994 $120,786(2) -- (3) -- --
President and Chief 1993 $110,000(2) -- (3) -- --
Executive Officer(1) 1992 $148,000(2) -- (3) -- --
</TABLE>
- ---------------
(1) Mr. Chaudhary served as President from September 11, 1991 until July 16,
1992, when he was elected Chairman of the Board. He was again elected
President on December 23, 1992, and served in that capacity until April 26,
1993. On December 11, 1993 and February 19, 1994, respectively, Mr.
Chaudhary was elected Chief Executive Officer and President, in addition to
his position as Chairman of the Board.
(2) In 1992, 1993 and 1994 the Company reimbursed a corporation wholly owned by
Ilyas Chaudhary, Chairman of the Board, President and Chief Executive
Officer of the Company, $148,000, $110,000 and $120,786, respectively, for
management services performed by Mr. Chaudhary.
(3) "Other Annual Compensation" was less than the lesser of $50,000 or 10% of
Mr. Chaudhary's annual salary and bonus for such year.
(4) In September 1992, the Company's stockholders approved an Incentive Stock
Option Plan and a Non-Qualified Stock Option Plan, and reserved 500,000 and
250,000 shares, respectively, of unissued Common Stock for issuance under
the plans. No options were granted under either plan prior to the
cancellation of such plans in July 1995. In 1993 and 1994, the Company
issued options for 270,000 shares of Common Stock to certain employees of
the Company, other than Mr. Chaudhary. These options, which are not covered
by the Incentive Stock Option Plan or the non-qualified Stock Option Plan,
become exercisable ratably over a period of five years from the date of
issue. The exercise price of the options was the fair market value of the
shares at the date of grant and ranges from $2.50 to $3.00. Options to
acquire 74,000 shares were exercisable as of September 30, 1995.
BENEFIT PLANS AND EMPLOYMENT AGREEMENTS
Employment Agreements
The Company has entered into an employment agreement with Ilyas Chaudhary
for a term expiring in the year 2000, pursuant to which Mr. Chaudhary will serve
as President and Chief Executive Officer of the Company. A relatively small
portion of Mr. Chaudhary's time is spent working for Capco and other companies.
The Company is reimbursed for Mr. Chaudhary's time spent on such other matters.
The employment agreement provides for a base salary of $150,000 in 1995,
increasing 10% annually to $219,615 in 1999. The employment agreement also
provides Mr. Chaudhary with options to purchase 100,000 shares of the Company's
Common Stock, 20,000 of which may be exercised each year of the agreement,
beginning in 1996, for $3.00 per share. Upon termination of Mr. Chaudhary's
employment during the term of the employment agreement for any reason other than
for "cause," Mr. Chaudhary's death or permanent incapacitation, or voluntary
termination, the Company will be obligated to pay Mr. Chaudhary a lump sum
severance payment in the amount equal to Mr. Chaudhary's then current annual
base salary.
Stock Option Plans
In September 1992, the Company's stockholders approved an Incentive Stock
Option Plan and a Non-Qualified Stock Option Plan, and reserved 500,000 and
250,000 shares, respectively, of Common Stock for issuance under such plans. No
options were granted under either plan prior to the cancellation of such plans
in July 1995.
41
<PAGE> 42
In fiscal years 1993 and 1994, the Company issued options for 270,000
shares of Common Stock to certain employees of the Company, other than Mr.
Chaudhary. These options, which are not covered by the Incentive Stock Option
Plan or the Non-Qualified Stock Option Plan, become exercisable ratably over a
period of five years from the date of issue. The exercise price of the options
is the fair market value of the shares at the date of grant and ranges from
$2.50 to $3.00. Options to acquire 74,000 shares were exercisable as of
September 30, 1995.
Retirement Plan
The Company sponsors a defined contribution retirement savings plan
("401(k) Plan"). The Company currently provides matching contributions equal to
50% of each employee's contribution, subject to a maximum of 4% of employee
earnings. The Company's contributions for the 401(k) Plan were $3,245 in 1994
and $2,245 in 1993.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Sedco and Capco, corporations majority-owned by Mr. Chaudhary, own 203,495
shares (4.9%) (4.8% after giving effect to the Capco Common Stock Conversion),
and 2,571,500 shares (61.4%) (2,646,500 shares or 62.1% after giving effect to
the Capco Common Stock Conversion), respectively, of the Common Stock of the
Company.
Certain officers and directors are engaged in the oil and gas business for
their own account and have business relationships with other oil and gas
exploration and development companies or individuals. As a result, potential
conflicts of interests between such persons and the Company may arise from time
to time. The Directors have agreed, however, that oil and gas opportunities
which may become available to them will first be offered to the Company.
In 1994, the following occurred: (i) Capco and other affiliated companies
advanced approximately $160,000 to the Company; and (ii) the Company's Canadian
subsidiary provided advances of approximately $177,000 to companies controlled
by Mr. Chaudhary.
In December 1994, the Company acquired all the outstanding shares of common
stock of CRPL from Capco, holder of 61.4% of the Company's outstanding Common
Stock, in exchange for 300,000 shares of Common Stock of the Company. Mr.
Chaudhary is the controlling shareholder of Capco.
In connection with the acquisition of the Teca/Nare Fields, Capco and CRI
loaned the Company $700,000 and $1.5 million, respectively, at an interest rate
of prime plus one percent per annum, and the Company has borrowed $4.7 million
from a bank, which borrowing was guaranteed by Mr. Chaudhary. Of the borrowing
from Capco, $600,000 will, prior to the close of the Offering, be converted into
75,000 shares of Common Stock of the Company. The maturity of the $1.5 million
loan from CRI and the $100,000 balance of the loan from Capco will, effective at
the closing of the Offering, be extended to April 1, 2006, and such loans will
be subordinated to the same extent the Debentures are subordinated.
The Company had previously entered into an agreement with CRI whereby CRI
agreed to purchase from the Company, prior to the completion of this Offering,
150,000 shares of Common Stock at a purchase price of $8.00 per share. This
agreement was cancelled prior to the issuance of any shares thereunder, when in
connection with this Offering, the Company discovered that preemptive rights may
have been inadvertently granted to shareholders in connection with the 1988
Amendment to the Company's Articles of Incorporation. See "Risk Factors -- Risks
Relating to Certain Corporate Matters -- Preemptive Rights."
If the Company were obligated to issue any shares to satisfy the preemptive
rights of any shareholder of the Company, Capco has agreed to sell or cause to
be sold to the Company a like number of shares, at the same price as the Company
is obligated to issue the shares, thereby eliminating any effect on the Company.
See "Risk Factors -- Risks Relating to Certain Corporate Matters -- Preemptive
Rights."
In October 1995, the Company borrowed $250,000 from Unico, Inc., a company
controlled by William N. Hagler, a director of the Company, which indebtedness
bears interest at 10% per annum and matures April 15, 1996. In December 1995,
the Company borrowed an additional $100,000 from Unico, Inc. on the same terms.
42
<PAGE> 43
PRINCIPAL STOCKHOLDERS
The following table sets forth certain information with respect to
beneficial ownership of the Company's Common Stock as of September 30, 1995, and
as adjusted to reflect the sale and assumed conversion of the Debentures being
offered hereby (assuming no exercise of the Underwriters' over-allotment option)
by (i) each record owner and each person known to the Company to be a beneficial
owner of more than 5% of the Common Stock, (ii) each director of the Company and
(iii) all directors and officers of the Company as a group. Except as otherwise
indicated, the Company believes that the beneficial owners of the Common Stock
listed below, based on information furnished by such owners, have sole
investment and voting power with respect to such shares, subject to community
property laws where applicable.
<TABLE>
<CAPTION>
OWNERSHIP AS A PERCENT
OF COMMON STOCK
SHARES ----------------------
BENEFICIALLY AS
SHAREHOLDERS: OWNED ACTUAL ADJUSTED(1)
------------ ------ -----------
<S> <C> <C> <C>
Capco Resources Ltd.(2)............................... 2,571,500 61% 48%
950, 444 Fifth Ave. S.W.
Dayon Building
Calgary, AB, Canada T2P 2T8
Ilyas Chaudhary(3).................................... 2,775,560 66% 52%
17512 Von Karman Ave.
Irvine, California 92714
DIRECTORS OTHER THAN MR. CHAUDHARY:
Francis J. Barker..................................... 3,100 * *
William N. Hagler..................................... 1,000 * *
William J. Hickey..................................... 1,350 * *
William E. Richards................................... 100 * *
All Directors and Officers as a Group(2)(3)........... 2,782,710 66% 52%
</TABLE>
- ---------------
* Less than one percent.
(1) Adjusted to reflect the Capco Common Stock Conversion and the sale and
assumed conversion of the Debentures.
(2) Mr. Chaudhary, as the controlling shareholder of Capco, is deemed to be the
beneficial owner of these shares.
(3) Includes 2,571,500 and 203,495 shares of Common Stock of the Company owned
by Capco and Sedco, respectively. Mr. Chaudhary, as the controlling
shareholder of such companies, is deemed to be the beneficial owner of such
shares.
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<PAGE> 44
DESCRIPTION OF THE DEBENTURES
The following description of certain terms of the Debentures does not
purport to be complete and is qualified in its entirety by reference to the
Indenture pursuant to which the Debentures will be issued, a copy of the
proposed form of which is an exhibit to the Registration Statement (see
"Available Information"), and to those terms made part of the Indenture by
reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture
Act"). Terms (whether or not capitalized) used but not defined in this
"Description of the Debentures" section have the meanings given to them in the
Indenture.
AS USED BELOW IN THIS "DESCRIPTION OF THE DEBENTURES" SECTION, THE
"COMPANY" MEANS SABA PETROLEUM COMPANY, BUT NOT ANY OF ITS SUBSIDIARIES, UNLESS
THE CONTEXT REQUIRES OTHERWISE.
GENERAL
The Debentures will be general unsecured senior subordinated obligations of
the Company and will be issued under an Indenture between the Company and BNY
Western Trust Company, as Trustee (the "Trustee"). The Debentures will be
limited to an aggregate principal amount of $14,375,000 and will mature on
December 15, 2005. The Debentures will bear interest from December 26, 1995 at
the rate shown on the cover page of this Prospectus, payable semi-annually on
June 15 and December 15 of each year, commencing on June 15, 1996, to holders of
record ("Holders") at the close of business on the preceding June 1 or December
1, as the case may be, immediately preceding the respective interest payment
date. The Debentures will be issued in denominations of $1,000 and integral
multiples thereof.
The Debentures will be subordinated and junior in right of payment, to the
extent and in the manner set forth below, to all Senior Debt. The Company is a
holding company, which currently conducts its operations through subsidiaries.
This effectively subordinates the Debentures to all indebtedness (including
trade payables) of the Company's subsidiaries. Therefore, the Company's rights
and the rights of its creditors, including holders of Debentures, to participate
in the assets of any subsidiary upon the subsidiary's liquidation or
recapitalization will be subject to the prior claims of the subsidiary's
creditors, except to the extent that the Company may itself be a creditor with
recognized claims against the subsidiary. However, in that case the claims of
the Company would still be effectively junior to any indebtedness of the
subsidiaries to the extent the creditors holding that indebtedness are entitled
to the benefit of security interests in the assets of the subsidiary, as well as
to any indebtedness of the subsidiary senior to that held by the Company. In
addition, because the Company is a holding company, it is dependent on dividends
or other distributions from its subsidiaries to make payments on its
indebtedness, including the Debentures. Such dividends or other distributions to
the Company may be subject to state law, which can restrict the ability of a
corporation to pay dividends or make other distributions to its shareholders and
which protect the rights of creditors of a corporation in the event of
improperly made dividends or distributions, as well as to present or future
contractual or regulatory restrictions that could materially restrict the
subsidiaries' ability to make such payments to the Company. The Indenture will
not restrict the Company's ability to enter into contracts in the future that
limit the ability of the Company's subsidiaries to pay dividends, or make loans
or advances to it. Payments to the Company from its subsidiaries also are
contingent upon the earnings of such subsidiaries and are subject to various
business considerations, such as the working capital needs of the subsidiaries.
See "Risk Factors -- Subordination of the Debentures."
Principal, premium and interest on the Debentures will be payable, and the
Debentures may be presented for registration of transfer or exchange, at the
offices of the Trustee in Los Angeles, California. Payments may be made by check
mailed to the registered addresses of the holders of record. The Holders must
surrender their Debentures to the Paying Agent to collect principal payments.
The Company may require appropriate endorsements, transfer documents and payment
of a sum sufficient to cover any transfer tax or other governmental charge
payable in connection with certain transfers or exchanges of the Debentures.
Initially, the Trustee will act as the Paying Agent and the Registrar under the
Indenture. The Company or any of its subsidiaries may subsequently act as the
Paying Agent and/or the Registrar, except in certain circumstances described in
the Indenture, and the Company may change any Paying Agent or any Registrar
without prior notice to the Holders.
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<PAGE> 45
CONVERSION OF DEBENTURES
The holder of any Debenture will be entitled at any time prior to the close
of business on December 15, 2005, subject to prior redemption, to convert the
Debentures (or portions thereof which are in denominations of $1,000 or in
integral multiples thereof), at the principal amount thereof, into shares of
Common Stock of the Company at the conversion price set forth on the cover page
of this Prospectus, subject to adjustment as described below. Interest is
required to be paid on any semi-annual interest payment date with respect to
Debentures surrendered for conversion after the record date therefor to the
registered holder on that record date. No other payment or adjustment will be
made on conversion of any Debenture for interest accrued thereon or for
dividends on the Common Stock. The Company may not issue fractional shares upon
conversion of Debentures and in lieu thereof will pay a cash adjustment based
upon the current market price of the Common Stock on the last business day prior
to the date of conversion. In the case of Debentures called for redemption,
conversion rights will expire at the close of business on the redemption date.
The conversion price is subject to adjustment as set forth in the Indenture
in certain events, including: the issuance of stock of the Company as a dividend
or distribution on the Common Stock; subdivisions, combinations and
reclassifications of the Common Stock; the issuance to all holders of Common
Stock of certain rights (but only when the rights become exercisable) or
warrants entitling them to subscribe for Common Stock at less than the current
market price; except for cash dividends permitted by the Indenture, the
distribution to all holders of Common Stock of assets or debt securities of the
Company or rights (other than those referred to above, but only when such
additional rights become exercisable) or warrants (other than those referred to
above) to purchase assets, debt securities or other securities of the Company;
the issuance, in certain circumstances, of shares of Common Stock for less than
the then current market price; and the issuance in certain circumstances of
securities which are convertible into or exchangeable for Common Stock (other
than pursuant to transactions described above) for a consideration per share
less than the then current market price of the Common Stock. No adjustment in
the conversion price will be required unless the adjustment would require a
change of at least 1% in the conversion price then in effect, but any adjustment
that would otherwise be required to be made will be carried forward and taken
into account in any subsequent adjustment. The Company may at any time reduce
the conversion price by any amount, provided that the period during which the
reduced price is available is at least 20 days and the reduced price is
irrevocable during that period.
If the Company consolidates or merges with or into or transfers or leases
all or substantially all of its assets to any Person, the Debentures will become
convertible into the kind and amount of securities, cash or other assets which
the holders of the Debentures would have owned immediately after the transaction
had they converted the Debentures into Common Stock immediately before the
transaction occurred.
REDEMPTION OF THE DEBENTURES
Optional
The Company may redeem any or all the Debentures at any time or some of
them from time to time at any time after December 15, 1997. The redemption price
for Debentures so redeemed shall be the redemption prices (expressed in
percentages of principal amount) set forth below, plus accrued interest to the
redemption date, if redeemed during the 12-month period beginning December 15 of
the years starting with the year indicated below.
<TABLE>
<CAPTION>
YEAR PERCENTAGE
------ ----------
<S> <C>
1997............................................. 102.000%
1998............................................. 101.714%
1999............................................. 101.429%
2000............................................. 101.143%
2001............................................. 100.857%
2002............................................. 100.572%
2003............................................. 100.286%
2004 and thereafter.............................. 100.000%
</TABLE>
45
<PAGE> 46
The Company also has the option to redeem up to an additional 15% of the initial
principal amount of the Debentures in each year commencing in 2000, as described
below under "Mandatory Sinking Fund Redemption."
Mandatory Sinking Fund Redemption
The Company is required to redeem 15% of the initial principal amount of
Debentures issued pursuant to this Prospectus (including for the purpose of
determining initial principal amount, the additional principal amount of any
Debentures issued pursuant to the Underwriters' over allotment option) (which
amount shall be rounded to the next highest integral multiple of $1,000) on
December 15, 2000 and on each December 15 thereafter through and including
December 15, 2004 at a redemption price of 100% of the principal amount of the
Debentures redeemed, plus accrued interest thereon to the redemption date. At
its option, the Company may, at any such redemption date, redeem up to an
additional 15% of such initial principal amount of the Debentures (which amount
shall be rounded to the next highest integral multiple of $1,000) at the same
price, provided that the right to redeem Debentures pursuant to this sentence is
not cumulative so that, to the extent the right is not exercised at any such
redemption date, the amount of Debentures that may be acquired pursuant to this
sentence in subsequent years will not be increased. The Company may reduce the
principal amount of Debentures to be redeemed pursuant to the Mandatory Sinking
Fund Redemption by subtracting, without duplication, 100% of the principal
amount (excluding premium) of any Debentures that Holders have converted, the
Company has delivered to the Trustee for cancellation or the Company has
previously purchased, redeemed, retired or acquired, other than pursuant to the
Mandatory Sinking Fund provision or the covenant regarding insurance on the life
of Ilyas Chaudhary, provided that the Company may reduce the principal amount of
the Debentures it is so required to redeem in any year by subtracting 100% of
the principal amount of Debentures acquired pursuant to the second sentence of
this paragraph, but may do so for any Debentures so acquired only against the
Mandatory Sinking Fund Redemption payment due in the year immediately following
the year of acquisition.
Selection and Notice
If less than all of the Debentures are to be redeemed at any time,
selection of the Debentures to be redeemed will be made by the Trustee from
among the outstanding Debentures by lot (pro rata for redemption pursuant to the
covenant set forth under "-- Certain Covenants -- Insurance on the Life of Ilyas
Chaudhary") or in compliance with the requirements of the principal national
securities exchange, if any, on which the Debentures are then listed. Notice of
redemption will be mailed at least 30 days but not more than 60 days before the
redemption date to each Holder whose Debentures are to be redeemed at the
registered address of such Holder. On and after the redemption date, interest
shall cease to accrue on the Debentures or portions thereof called for
redemption.
SUBORDINATION
The Debentures will be subordinate and junior in right of payment, to the
extent and in the manner to be set forth below, to all "Senior Debt" of the
Company. The Indenture will define "Senior Debt" as all present or future "Debt"
(defined below) created, incurred, assumed or guaranteed (to the extent of the
guarantee) by the Company (and all renewals, extensions or refundings thereof),
unless the instrument under which such Debt is created, incurred, assumed or
guaranteed provides that such Debt is not senior or superior in right of payment
to the Debentures; provided, however, that Senior Debt shall not include (i) any
Debt of the Company to any of its subsidiaries, (ii) any Debt of the Company or
guarantees of Debt by the Company which by its terms or the terms of the
instrument creating or evidencing it expressly provides that such Debt or
guarantee is expressly subordinated in right of payment to any other Debt of the
Company or (iii) Guarantees by the Company of Debt (a) outstanding at the date
of the Indenture or (b) which may be outstanding in the future, except that
Senior Debt shall include any present and future guarantees that provide by
their terms that they constitute Senior Debt.
At September 30, 1995, the Senior Debt of the Company was $17.8 million.
After giving effect to the acquisition of the TNC Fields, the CRPL Business
Combination, providing $1.75 million as required security
46
<PAGE> 47
in connection with the operations of the Teca/Nare Fields, the Capco Common
Stock Conversion, the CRI Debt Conversion, and the sale of the Debentures and
the anticipated use of the net proceeds therefrom, as if they had occurred on
September 30, 1995, the Company would have had $11.4 million of Senior Debt
outstanding as of September 30, 1995.
By reason of the subordination described above, in the event of a
liquidation or dissolution of the Company or in a bankruptcy, reorganization,
insolvency, receivership or other similar proceeding relating to the Company or
its property, upon any distribution of assets, holders of Senior Debt will be
entitled to be paid principal and interest in full before principal or interest
payments may be made on the Debentures, and the Holders of Debentures will be
required to pay over their share of such distribution to the holders of Senior
Debt until such Senior Debt is paid in full, except that Holders of Debentures
may receive securities that are subordinated at least to the same extent as the
Debentures are to Senior Debt. By reason of this subordination, in the event of
dissolution, insolvency or bankruptcy of the Company, Holders of the Debentures
may recover less, ratably, than holders of Senior Debt and other creditors of
the Company, or may recover nothing.
The Company may not pay principal of, or interest on, the Debentures and
may not acquire any Debentures for cash or property (other than securities that
are subordinated to at least the same extent as the Debentures are subordinated
to Senior Debt) if (i) a default in the payment of any principal or other
obligations with respect to Designated Senior Debt occurs and is continuing
beyond any applicable grace period or (ii) a default, other than a payment
default, on Designated Senior Debt occurs and is continuing that then permits
holders of the Designated Senior Debt to accelerate its maturity and the Trustee
receives a notice of the default from a person permitted to give such notice
under the Indenture requesting that payment of principal or interest with
respect to the Debentures be prohibited. Notwithstanding the foregoing, the
Company may resume payments in respect of the Debentures upon the earlier of (a)
the date upon which the default is cured or waived or (b) in the case of a
default referred to in (ii) above, 179 days pass after notice is received (a
"Payment Blockage Period"), provided that the terms of the Indenture otherwise
permit the payment, distribution or acquisition of the Debentures at the time in
question. Only one Payment Blockage Period may be commenced within any
consecutive 365-day period with respect to the Debentures. "Designated Senior
Debt" will be defined in the Indenture to mean (i) Senior Debt of the Company
permitted to be incurred under the Indenture under any institutional credit
agreement and (ii) any other Senior Debt permitted to be incurred under the
Indenture in the principal amount of $5 million or more.
PUT OPTION UPON A CHANGE OF CONTROL
The Indenture will require the Company to make an offer to purchase all of
the outstanding Debentures upon a Change of Control. See "-- Certain
Covenants -- Change of Control." The Company's ability to purchase the
Debentures in the event of a Change of Control may be adversely affected by
covenants and restrictions in the Company's principal credit agreement and
covenants and restrictions in the Company's credit facilities in existence from
time to time in the future. See Note 9 of Notes to the Consolidated Financial
Statements of the Company. There can be no assurance that sufficient funds will
be available in the event of a Change of Control to permit the Company to make
any repurchases then required.
CERTAIN COVENANTS
Affirmative Covenants
In addition to the covenants described below, the Indenture will require
the Company, subject to certain limitations described therein, to, among other
things, do the following: (a) deliver to the Trustee copies of all reports filed
with the Commission; (b) deliver to the Trustee quarterly officers' certificates
with respect to the Company's compliance with its obligations under the
Indenture; (c) maintain its corporate existence, subject to the provisions
described below relating to mergers and acquisitions; and (d) pay its taxes when
due except where such taxes are being contested in good faith.
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<PAGE> 48
Limitations on Restricted Payments
The Indenture will provide that the Company will not, and will not permit
any of its subsidiaries to, directly or indirectly make any Restricted Payment
after the date of the Indenture, except as provided below in this Restricted
Payments covenant, if at the time of such Restricted Payment and giving effect
thereto:
(i) a Default or Event of Default shall have occurred and be
continuing or shall occur as a consequence thereof;
(ii) the amount of such Restricted Payment, when added to the
aggregate amount of all Restricted Payments (except the Restricted Payments
permitted by the last sentence of this Restricted Payments covenant) made
after the date of the Indenture, exceeds the sum of the following: (1) 20%
(50% at all times when the Consolidated Tangible Net Worth of the Company
exceeds $10 million) of the Company's Consolidated Net Earnings, excluding
net earnings of subsidiaries that are not Wholly Owned Subsidiaries except
to the extent such earnings have been received in cash by the Company or a
Wholly Owned Subsidiary of the Company, accrued during the period (taken as
one accounting period) since December 31, 1995 (or, if the aggregate
Consolidated Net Earnings of the Company shall be a deficit, minus 100% of
such aggregate deficit), plus (2) 50% (100% at all times when the
Consolidated Tangible Net Worth of the Company exceeds $10 million) of the
aggregate net proceeds, including the fair market value of property other
than cash (such fair market value to be determined by a majority of the
disinterested members of the full Board of Directors of the Company, whose
good faith determination shall be conclusive and evidenced by a resolution
certified by an Officers' Certificate and filed with the Trustee), received
by the Company from the issuance of Capital Stock of the Company (other
than to a subsidiary of the Company) that is not Disqualified Stock since
December 31, 1995, plus (3) 50% (100% at all times when the Consolidated
Tangible Net Worth of the Company exceeds $10 million) of the principal
amount of any Indebtedness of the Company (excluding the Debentures) or a
Wholly Owned Subsidiary that is converted into or exchanged for Capital
Stock of the Company that is not Disqualified Stock since December 31,
1995; and
(iii) the Company's Consolidated Fixed Charge Coverage Ratio would be
at least 3.0 to 1.0.
Clauses (i), (ii) and (iii) above will not prevent:
(a) the payment of any dividend within 60 days after the date of
declaration thereof if the payment thereof would have complied with the
limitations of this Indenture on the date of declaration; or
(b) the retirement of shares of the Company's Capital Stock in
exchange for or out of the proceeds of a substantially concurrent sale
(other than a sale to a subsidiary of the Company) of other shares of its
Capital Stock (other than Disqualified Stock).
Clauses (ii) and (iii) above will not prevent any transaction that is a
Restricted Payment under clause (iv) of the definition of Restricted Payments,
if the conditions in both subparagraph (A) below and subparagraph (B) below are
met:
(A) any transaction by which a subsidiary becomes a Former Subsidiary
(or a transaction by a subsidiary that is a Former Subsidiary but, were it
not a Former Subsidiary, would cause it to become a Former Subsidiary),
unless as a result of the transaction the shareholders' equity of the
Company will not decrease or, if there is such a decrease, the decrease is
deemed a Restricted Payment and is permissible under clauses (i), (ii) and
(iii) above; and
(B) any transaction by which a subsidiary becomes a Former Subsidiary
unless, as part of the transaction and without the payment of any
consideration therefor by the Company of any or its other subsidiaries, the
subsidiary that is to become a Former Subsidiary is, or becomes and, in
each case, remains solely liable (without any Guarantee by the Company or
any other subsidiary of the Company) for a portion of the pre-transaction
Consolidated Indebtedness of the Company equal to such pre-transaction
Consolidated Indebtedness multiplied by a fraction of which (x) the
numerator is the Consolidated Cash Flow Available For Fixed Charges of the
subsidiary that is to become a Former Subsidiary (calculated on the same
basis as if the reference to the "Company" in the definition of
48
<PAGE> 49
Consolidated Cash Flow Available For Fixed Charges were references to such
subsidiary) for the most recent four quarters for which financial results
have been reported by the Company prior to the transaction being effected
and (y) the denominator is the Consolidated Cash Flow Available For Fixed
Charges of the Company for such four quarters (if positive and, if not,
one).
Limitations on Transactions with Affiliates
The Company will not, and will cause each of its subsidiaries to not, after
the date of the Indenture, make any loan, advance, Guarantee or capital
contribution to, or for the benefit of, or sell, lease, transfer or otherwise
dispose of any of its properties or assets to, or for the benefit of, or
purchase or lease any property or assets from, or enter into or amend any
contract, agreement or understanding with, or for the benefit of, (i) any
Affiliate of the Company or any of its subsidiaries or (ii) any Person (or any
Affiliate of such Person) holding 10% or more of the Common Equity of the
Company or any of its subsidiaries (each an "Affiliate Transaction"), except on
terms that are no less favorable to the Company or the relevant subsidiary, as
the case may be, than those that could have been obtained in a comparable
transaction on an arms length basis from a Person that is not an Affiliate.
The Company will not, and will not permit any of its subsidiaries to, enter
into an Affiliate Transaction involving or having a value of more than $500,000
unless (i) such Affiliate Transaction has been approved by the disinterested
members of the full Board of Directors of the Company, a Committee of the Board
of Directors of the Company, the members of which are each disinterested, or the
non-Affiliated shareholders of the Company and (ii) for such transactions
involving in excess of $5.0 million, the Company has received an opinion from
Van Kasper & Company or another investment banking firm of national repute that
the transaction is fair to the Company or its nonaffiliated stockholders from a
financial point of view.
Notwithstanding the foregoing, the term "Affiliate Transaction" shall not
include any contract, agreement or understanding with or for the benefit of, or
plan for the benefit of, any or all employees of the Company or its subsidiaries
(in their capacity as such) that has been approved by the independent members of
the Board of Directors of the Company or a Committee of the Board of Directors
of the Company, the members of which are each disinterested.
Teca/Nare and California Oil and Gas Producing Properties
As long as any of the Debentures are outstanding, the Company will cause
its and its subsidiaries' direct or indirect interests in the Teca/Nare Fields
and its and its subsidiaries' direct and indirect interests in oil and gas
producing properties located in California at the date of the Indenture to be
held in Wholly Owned Subsidiaries of the Company and will not voluntarily
directly or indirectly sell, transfer or assign, or cooperate in the sale,
transfer or assignment of, all or any portion of or interest in the Teca/Nare
Fields or such California oil and gas producing properties, in each case other
than in exchange for cash; provided that this covenant will not restrict the
sale, transfer or assignment of (i) oil and gas properties in the ordinary
course of business other than for securities, (ii) the asphalt refinery in Santa
Maria, California that is owned by a subsidiary of the Company or (iii) any
California real property of the Company or any of its subsidiaries that is not
then used or held for oil and gas production.
Change of Control
The Indenture will provide that following any Change of Control, the
Company will make an offer (a "Change of Control Offer") to purchase all
outstanding Debentures at a purchase price equal to 102 percent of the aggregate
principal amount of the Debentures, plus accrued interest to the date of
purchase.
Within 30 days after any Change of Control, the Company, or the Trustee at
the Company's request, will mail or cause to be mailed to all Holders on the
date of the Change of Control a notice of the occurrence of such Change of
Control and of the Holders' rights arising as a result thereof. The notice will
contain all instructions and materials necessary to enable Holders to tender
their Debentures to the Company. Any Change of Control Offer will be conducted
in compliance with applicable regulations under the federal securities laws,
including Exchange Act Rule 14e-l.
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<PAGE> 50
The Company's ability to purchase Debentures pursuant to a Change of
Control Offer may be restricted by covenants in the Company's principal credit
agreement and any other credit agreements the Company may have in the future.
Also, there can be no assurance that sufficient funds will be available at the
time of any Change of Control Offer to make any required repurchases. However,
the Company's failure to comply with the Change of Control covenant will be an
Event of Default under the Indenture if such failure continues for a specified
period and the required notice is given by the Trustee or the Holders of not
less than 25 percent in principal amount of the then outstanding Debentures.
Except as described above with respect to a Change of Control, the
Indenture does not contain provisions that will afford Holders of the Debentures
protection in the event of a highly-leveraged transaction, takeover,
reorganization, restructuring, recapitalization, merger or similar transaction
involving the Company that may adversely affect Holders.
Insurance on the Life of Ilyas Chaudhary
The Indenture will require the Company to maintain in effect at all times
with an insurance company rated at least A- by Best's Key Rating Guide
(Life/Health) (or successor rating guide), so called key man life insurance on
the life of Ilyas Chaudhary in the amount of $5 million or, if less, the
aggregate principal amount of the Debentures then outstanding. To the extent of
the lesser of $5 million or the aggregate principal amount of the Debentures
outstanding from time to time, the first proceeds of the insurance policy or
policies, up to the amount stated above, will be dedicated to the Trustee for
the benefit of the Holders of the Debentures. To accomplish this, the Indenture
will require that, among other things, the Trustee be the (or a) named
beneficiary or owner of the insurance policy, with that designation not to be
changed without the prior written consent of the Trustee, to the extent of the
lesser of $5 million or the principal amount of the Debentures outstanding from
time to time, the Company use its best efforts so that the Trustee will be
entitled to timely notice from the insurance company of any non-payment of
insurance premiums and the Company take all actions required so that the Trustee
have a perfected, non-preferential first priority security interest in such
proceeds of the insurance policy. Any proceeds of the policy received by the
Trustee will be used to redeem Debentures pro rata as soon as reasonably
practicable and at a redemption price equal to the principal amount of the
Debentures being redeemed plus accrued interest to the redemption date. The
Debentures so redeemed may not be used to reduce the amount of Debentures
required to be redeemed pursuant to the Mandatory Sinking Fund redemption
provisions described above, nor shall such redemptions of Debentures reduce the
amount of additional Debentures that the Company has the option to redeem in
connection with Mandatory Sinking Fund redemptions. See "Redemption of the
Debentures -- Mandatory Sinking Fund Redemption."
Limitation on Fundamental Changes and Certain Trading Activities
As long as any of the Debentures are outstanding: (i) the primary business
of the Company and its subsidiaries taken as a whole will be activities related
to the oil and gas industry and (ii) trading in oil and gas by the Company and
each of its subsidiaries involving an unhedged risk, if any, will be done by or
under the direct supervision of Ilyas Chaudhary.
Limitations on Mergers and Consolidations of the Company
The Indenture will provide that the Company will not consolidate or merge
with or into, or sell, lease, convey or otherwise dispose of all or
substantially all of its assets (including by way of liquidation or dissolution)
to any Person, unless: (i) the Person formed by or surviving such consolidation
or merger (if other than the Company) or to which such sale, lease, conveyance
or other disposition shall be made (collectively, the "Successor"), is a
corporation or other legal entity organized and existing under the laws of the
United States or any State thereof or the District of Columbia, and the
Successor assumes by supplemental indenture in a form reasonably satisfactory to
the Trustee all of the obligations of the Company under the Debentures and the
Indenture; (ii) immediately after giving effect to such transaction, no Default
or Event of Default shall have occurred and be continuing; and (iii) immediately
after giving effect to such transaction and the use of any net proceeds
therefrom, on a pro forma basis the Consolidated Tangible Net Worth of the
Company or the Successor, as the case may be, would be at least equal to the
Consolidated Tangible Net Worth of the Company immediately prior to such
transaction. A sale, lease, conveyance or other
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disposition by the Company and/or its subsidiaries of all or substantially all
of the assets of the Company and its subsidiaries, taken as a whole, shall be
deemed a sale, lease, conveyance or other disposition of all or substantially
all of the assets of the Company. The meaning of the term "all or substantially
all of the assets" has not been definitely established, is likely to be
interpreted by reference to applicable state law if and at the time the issue
arises and will be dependent on the facts and circumstances existing at that
time. Accordingly, there may be uncertainty as to whether a Holder of Debentures
can determine whether such a sale or other disposition of all or substantially
all of the assets has occurred and exercise any remedies such Holder may have as
a result of such an occurrence.
Limitation on Ranking of Future Indebtedness
The Company will not, directly or indirectly, incur, create, assume,
guarantee or otherwise become liable for any indebtedness which is subordinated
in right of payment to any Senior Debt of the Company and senior in right of
payment to the Debentures.
EVENTS OF DEFAULT
An "Event of Default" will be defined in the Indenture as (i) failure by
the Company to pay interest on any of the Debentures when it becomes due and
payable, whether or not prohibited by the subordination provisions of the
Indenture, and the continuance of any such failure for 30 days; (ii) failure by
the Company to pay the principal on the Debentures when due, either at maturity,
upon redemption at the option of the Company, by declaration of acceleration or
otherwise, whether or not prohibited by the subordination provisions of the
Indenture; (iii) failure by the Company to comply with any agreement or covenant
in the Indenture or the Debentures and continuance of such failure for 60 days
(or for ten days in the case of the covenants described under "Certain
Covenants -- Change of Control" and "-- Insurance on the Life of Ilyas
Chaudhary") after notice of such failure has been given to the Company by the
Trustee or by the Holders of at least 25 percent of the aggregate principal
amount of the Debentures then outstanding (except that with respect to certain
covenants, such defaults shall be Events of Default with such notice but without
such passage of time); (iv) an event of default under any mortgage, indenture or
instrument under which there may be issued or by which there may be secured or
evidenced any Indebtedness for money borrowed by the Company or any of its
subsidiaries (or the payment of which is Guaranteed by the Company or any of its
subsidiaries, to the extent of the Guarantee) other than Non-Recourse
Indebtedness if (a) either (1) such event of default results from the failure to
pay any such Indebtedness when due (whether at maturity or otherwise) or (2) as
a result of such event of default the maturity of such Indebtedness has been
accelerated prior to its expressed maturity and (b) the principal amount of such
Indebtedness, together with the principal amount of any other such Indebtedness
in default for failure to pay principal when due or the maturity of which has
been so accelerated, equals or exceeds $2.0 million or more in the aggregate,
without such Indebtedness having been discharged or such acceleration rescinded
within 30 days after notice to the Company from the Trustee or the Holders of 25
percent in principal amount of the Debentures then outstanding; (v) prepayment
of the CRI Subordinated Debt when not permitted by the terms thereof or by the
terms set forth under "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources"; (vi) a
final judgment or judgments, except to the extent the judgment or judgments are
in respect of Non-Recourse Indebtedness, that exceed $2.0 million in the
aggregate, for the payment of money, being entered by a court or courts of
competent jurisdiction, and remaining undischarged for a period (during which
execution shall not be effectively stayed) of 60 days, against (x) the Company,
(y) any of its Material Subsidiaries or (z) any subsidiary which is (A) a member
of a Material Subsidiary Group and (B) material to or holds material assets of
(in each case as determined in good faith by the Board of Directors) the
specific larger asset in respect of which it is a member of the Material
Subsidiary Group; and (vii) certain events of bankruptcy, insolvency or
reorganization involving (a) the Company, (b) any of its Material Subsidiaries
or (c) any subsidiary which is at the time (1) a member of a Material Subsidiary
Group and (2) material to or holds material assets of (in each case as
determined in good faith by the Board of Directors) the specific larger asset in
respect of which it is a member of the Material Subsidiary Group.
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If an Event of Default (other than an Event of Default resulting from
bankruptcy, insolvency or reorganization involving the Company) has occurred and
is continuing, the Trustee by written notice to the Company, or the Holders of
at least 25 percent in aggregate principal amount of the Debentures then
outstanding by written notice to the Company and the Trustee, may declare all
amounts owing under the Debentures to be due and payable. Upon such declaration
of acceleration, the aggregate principal amount of, and all accrued and unpaid
interest on, the outstanding Debentures shall immediately become due and
payable. If an Event of Default results from bankruptcy, insolvency or
reorganization involving the Company, all outstanding Debentures shall become
due and payable without any further action or notice. The Holders of a majority
in aggregate principal amount of the Debentures then outstanding may waive or
annul an existing Default or Event of Default (other than any Default or Event
of Default in payment of principal or interest on the Debentures), and its
consequences, under the Indenture.
The Holders may not institute any action to enforce the provisions of the
Indenture or the Debentures (except actions for payment of overdue principal or
interest) unless (a) such Holders previously have given the Trustee written
notice of the default and continuance thereof, (b) the Holders of not less than
25 percent in principal amount of the Debentures then outstanding have requested
the Trustee to institute such action and offered the Trustee reasonable
indemnity, (c) the Trustee has not instituted such action within 60 days of the
request and (d) the Trustee has not received direction inconsistent with such
written request from the Holders of a majority in principal amount of the
Debentures then outstanding.
Subject to certain limitations, Holders of a majority in principal amount
of the Debentures then outstanding may direct the Trustee in its exercise of any
trust or power, provided that such direction does not conflict with the terms of
the Indenture and such Holders have offered to the Trustee security and
indemnity satisfactory to the Trustee. The Trustee may withhold from the Holders
notice of any continuing Default or Event of Default (except any Default or
Event of Default in payment of principal or interest on the Debentures) if the
Trustee determines that withholding such notice is in the Holders' interest.
The Company is required to deliver to the Trustee quarterly a statement
regarding compliance with the Indenture, and upon any Officer of the Company
becoming aware of any Default or Event of Default, a statement specifying such
Default or Event of Default.
The Indenture will provide that no director, officer, employee or
shareholder of the Company, as such, will have any liability for any obligations
of the Company under the Debentures or the Indenture. The Indenture and the
Debentures will each provide that each holder of the Debentures, by accepting
the Debentures, waives and releases all such liability.
DEFEASANCE AND DISCHARGE
The Company can discharge or defease its obligations under the Indenture as
set forth below.
Under terms satisfactory to the Trustee, the Company may discharge certain
obligations to Holders of Debentures that have not already been delivered to the
Trustee for cancellation and that have either become due and payable or are by
their terms due and payable within one year (or scheduled for redemption within
one year) by irrevocably depositing with the Trustee cash or United States
Government Obligations, or a combination thereof, as trust funds in an amount
certified to be sufficient to pay at maturity (or upon redemption) the principal
of and interest on such Debentures.
The Company may also discharge any and all of its obligations to Holders of
the Debentures at any time ("defeasance"), but may not thereby avoid its duty to
register the transfer or exchange of the Debentures, to replace any temporary,
mutilated, destroyed, lost or stolen Debentures or to maintain an office or
agency in respect of such Debentures and certain other obligations.
Alternatively, the Company may be released with respect to the Debentures from
the obligations imposed by specified portions of Article 4 and by Article 5 of
the Indenture (which contain, among other things, the covenant described above
limiting consolidations, mergers, asset sales and leases) and omit to comply
with such Articles or portions thereof without creating an Event of Default
("covenant defeasance"). Defeasance or covenant defeasance may be effected only
if, among other things: (a) the Company irrevocably deposits with the Trustee
cash or United States Government Obligations, or a combination thereof, as trust
funds in an amount certified to be sufficient to pay at maturity the principal
of and interest on all outstanding Debentures; (b) no Event of Default under the
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Indenture has occurred and is then continuing; (c) the defeasance or covenant
defeasance will not result in an event of default under any agreement to which
the Company is a party or by which it is bound; and (d) the Company delivers to
the Trustee an opinion of counsel to the effect that the Holders of Debentures
will not recognize income, gain or loss for federal income tax purposes as a
result of such defeasance or covenant defeasance and that such defeasance or
covenant defeasance will not otherwise alter such Holders' federal income tax
treatment of principal and interest payments on the Debentures.
MODIFICATION OF THE INDENTURE
The Indenture will provide that the Company and the Trustee may enter into
supplemental indentures without the consent of the Holders of Debentures to,
among other things: (a) cure any ambiguity or correct any inconsistency in the
Indenture; (b) make any change that does not adversely affect the legal rights
of Holders of Debentures; (c) modify, eliminate or add to the provisions of the
Indenture to the extent necessary to qualify the Indenture under applicable
federal statutes; (d) provide for uncertificated Debentures in addition to
certificated Debentures; or (e) surrender any right or power conferred by the
Indenture upon the Company.
The Indenture also will contain provisions permitting the Company and the
Trustee, with the consent of the Holders of not less than a majority in
principal amount of Debentures outstanding, to add any provision to, change in
any manner or eliminate any of the provisions of the Indenture or modify in any
manner the rights of the Holders of the Debentures so affected; provided,
however, that the Company and the Trustee may not, without the consent of the
Holder of each outstanding Debenture affected thereby, do, among other things,
any of the following: (a) reduce the amount of Debentures whose Holders must
consent to an amendment, supplement or waiver with respect to the Indenture; (b)
reduce the rate of or change the time for payment of interest on any Debentures;
(c) reduce the principal of or change the fixed maturity of any Debenture or
alter the redemption provisions with respect thereto; (d) waive a default in the
payment of the principal of, or interest on, any Debenture; (e) make any
Debenture payable in money other than that stated in the Debenture; and (f) make
any change in the provisions of the Indenture relating to waiver of past
defaults, the rights of Holders of Debentures to receive payments of principal
of or interest on the Debentures or the foregoing amendment provisions.
The Indenture may not be amended to alter the subordination of any
outstanding Debentures without the consent of each holder of Senior Debt then
outstanding which would be adversely affected in any material respect thereby.
TRANSFER AND EXCHANGE
A Holder will be able to transfer or exchange Debentures only in accordance
with the provisions of the Indenture. The Registrar and the Company may require
a Holder, among other things, to furnish appropriate endorsements and transfer
documents and to pay any taxes and fees required by law or permitted by the
Indenture. The Company is not required to (i) transfer or exchange any Debenture
selected for redemption or (ii) transfer or exchange any Debenture for a period
of 15 days before a selection of Debentures to be redeemed. The registered
Holder of a Debenture may be treated as the owner of such Debenture for all
purposes.
CONCERNING THE TRUSTEE
The Indenture will contain certain limitations on the rights of the
Trustee, should it become a creditor of the Company, to obtain payment of claims
in certain cases or to realize on certain property received in respect of any
such claim as security or otherwise. The Trustee will be permitted to engage in
other transactions; however, if it acquires any conflicting interest, it must
eliminate such conflict or resign.
The Holders of a majority in principal amount of the then outstanding
Debentures will have the right to direct the time, method and place of
conducting any proceeding for exercising any remedy available to the Trustee,
subject to certain exception. The Indenture provides that in case an Event of
Default occurs and is not cured, the Trustee will be required, in the exercise
of its power, to use the degree of care of a prudent person in similar
circumstances in the conduct of his, her or its own affairs. Subject to such
provisions, the Trustee will be under no obligation to exercise any of its
rights or powers under the Indenture at the request of any Holder, unless such
Holder shall have offered to the Trustee security and indemnity satisfactory to
the Trustee.
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CERTAIN DEFINITIONS
Set forth below is a summary of certain of the defined terms used in the
Indenture.
"Affiliate" of any Person means any Person directly or indirectly
controlling or controlled by, or under direct or indirect common control with,
the referent Person. For purposes of this definition, control of a Person shall
mean the power to direct the management and policies of such Person, directly or
indirectly, whether through the ownership of voting securities, by contract or
otherwise. Notwithstanding the foregoing, the term "Affiliate" shall not
include, with respect to the Company or any Wholly Owned Subsidiary of the
Company, any Wholly Owned Subsidiary of the Company.
"Capital Stock" of any Person means any and all shares, rights to purchase,
warrants or options (whether or not currently exercisable), participations or
other equivalents of or interests in (however designated) the equity (which
includes, but is not limited to, common stock, preferred stock and partnership
and joint venture interests) of such Person (excluding any debt securities that
are convertible into, or exchangeable for, such equity).
"Capitalized Lease Obligations" of any Person means the obligations of such
Person to pay rent or other amounts under a lease that is required to be
capitalized for financial reporting purposes in accordance with GAAP, and the
amount of such obligation shall be the capitalized amount thereof determined in
accordance with GAAP.
"Change of Control" means any of the following: (i) the sale, lease,
conveyance or other disposition of all or substantially all of the Company's
assets as an entirety or substantially as an entirety to any Person or "group"
(within the meaning of Section 13(d)(3) of the Exchange Act) in one or a series
of transactions, provided that a transaction where the holders of all classes of
Common Equity of the Company immediately prior to such transaction own, directly
or indirectly, 50 percent or more of all classes of Common Equity of such Person
or group immediately after such transaction(s) shall not be a Change of Control;
(ii) the acquisition by the Company and/or any of its subsidiaries of 50 percent
or more of the aggregate voting power of all classes of Common Equity of the
Company in one transaction or a series of related transactions; (iii) the
liquidation or dissolution of the Company, provided that a liquidation or
dissolution of the Company which is part of a transaction or series of related
transactions that does not constitute a Change of Control under the "provided"
clause of clause (i) above shall not constitute a Change of Control under this
clause (iii); or (iv) any transaction or series of transactions (as a result of
a tender offer, merger, consolidation or otherwise) that results in, or that is
in connection with, (a) any Person, including a "group" (within the meaning of
Section 13(d)(3) of the Exchange Act) that includes such Person, not theretofore
having "beneficial ownership" (as defined in Rule 13d-3 under the Exchange Act),
directly or indirectly, of 50 percent or more of the aggregate voting power of
all classes of Common Equity of the Company, acquiring such 50 percent or more
direct or indirect "beneficial ownership," provided that transfers of securities
among corporations that are affiliated by 100% common ownership (such as a
contribution by a parent corporation to a wholly owned subsidiary) shall not, of
themselves, result in a Change of Control, or (b) less than 50 percent (measured
by the aggregate voting power of all classes) of the Company's Common Equity
being listed on one of the New York Stock Exchange, the AMEX or the Nasdaq
National Market System. The meaning of the term "all or substantially all of the
assets" has not been definitely established, is likely to be interpreted by
reference to applicable state law if and at the time the issue arises and will
be dependent on the facts and circumstances existing at that time. Accordingly,
there may be uncertainty as to whether a Holder of Debentures can determine
whether a Change of Control has occurred and exercise any remedies such Holder
may have upon a Change of Control.
"Common Equity" of any Person means all Capital Stock of such Person that
is generally entitled to (i) vote in the election of directors of such Person or
(ii) if such Person is not a corporation, vote or otherwise participate in the
selection of the governing body, partners, managers or others that will control
the management and policies of such Person.
"Consolidated Cash Flow Available for Fixed Charges" of the Company means
for any period the amounts for such period of (i) Consolidated Net Earnings plus
(ii) Consolidated Income Tax Expense, plus
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(iii) amortization of capitalized interest, plus (iv) allocation of noncash
costs to operating expenses, excluding interest, plus (v) to the extent not
otherwise included, other noncash charges to earnings, net, reduced by (vi)
noncash earnings included in Consolidated Net Earnings, with each of the amounts
in clauses (i) through (vi) inclusive of this definition as determined, subject
to the definitions of Consolidated Interest Expense and Consolidated Net
Earnings, on a consolidated basis for the Company and its subsidiaries in
accordance with GAAP.
"Consolidated Fixed Charge Coverage Ratio" of the Company means, with
respect to any determination date, the ratio of (i) Consolidated Cash Flow
Available for Fixed Charges of the Company for the prior four full fiscal
quarters for which financial results have been reported immediately preceding
the determination date to (ii) the greater of the aggregate Consolidated
Interest Expense of the Company (x) incurred during such prior four fiscal
quarters or (y) reasonably anticipated in good faith by the Company to become
due during the fiscal quarter in which the determination date occurs and the
three fiscal quarters immediately subsequent to such fiscal quarter; provided,
however, that in any calculation of the Company's Consolidated Fixed Charge
Coverage Ratio for the purposes of clause (y) of this sentence, the interest on
any Indebtedness (whether existing or being incurred) bearing a floating
interest rate shall be computed as if the rate in effect on the determination
date had been the applicable rate for the entire period.
"Consolidated Income Tax Expense" of the Company for any period means the
provision for taxes based on earnings and profits of the Company and its
subsidiaries (but only to the extent such earnings or profits were included in
computing the Consolidated Net Earnings of the Company for such period).
"Consolidated Interest Expense" of the Company for any period means the
aggregate amount of interest which, in conformity with GAAP, would be set
opposite the caption "interest expense" or any like caption on the consolidated
statement of operations of the Company and its consolidated subsidiaries
(including, but not limited to, imputed interest included on Capitalized Lease
Obligations, the portion of a sale/leaseback transaction that is in effect
interest, all commissions, discounts and other fees and charges owed with
respect to letters of credit and bankers' acceptance financing, the net costs
associated with hedging obligations, amortization of other financing fees and
expenses, the interest portion of any deferred payment obligation, amortization
of discount or premium, if any, and all other noncash interest expense other
than interest amortized to operating expenses) and includes, without duplication
(including duplication of the foregoing items), all capitalized interest and
interest actually paid by the Company or a subsidiary under any Guarantee of
Indebtedness (including a Guarantee of principal, interest or any combination
thereof) of any other Person, all determined on a consolidated basis in
accordance with GAAP, provided that such interest expense for a Former
Subsidiary will not, after such subsidiary becomes a Former Subsidiary, be
included in the Consolidated Interest Expense of the Company, except to the
extent the Company or a subsidiary has directly or indirectly paid or, if the
interest has not been paid, has Guaranteed or is directly or indirectly liable
for such interest.
"Consolidated Net Earnings" of the Company for any period means the net
income (or loss) of the Company and its subsidiaries for such period determined
on a consolidated basis in accordance with GAAP; provided that there shall be
excluded from such net income (to the extent otherwise included therein),
without duplication: (i) the net income (or loss) of any Person in which any
Person other than the Company has an ownership interest, except to the extent
that any such income has actually been received by the Company or any of its
Wholly Owned Subsidiaries in the form of cash dividends or cash distributions,
provided that if any net earnings of the Wholly Owned Subsidiary(ies) receiving
such cash dividends or distributions are not then includable in the Consolidated
Net Earnings of the Company pursuant to clause (iii) of this sentence, no
portion of the net income of such person that is not a Wholly Owned Subsidiary
will be included in the consolidated net income of the Company until, without
duplication, cash dividends or distributions thereof to the Company are
permitted; (ii) except to the extent includable in the consolidated net income
of the Company pursuant to the foregoing clause (i), the net income (or loss) of
any Person that accrued prior to the date that (a) such Person becomes a
subsidiary of the Company or is merged into or consolidated with the Company or
any of its subsidiaries or (b) the assets of such Person are acquired by the
Company or any of its subsidiaries; (iii) the net earnings of any Wholly Owned
Subsidiary of the Company to the extent that (but only so long as) the
declaration or payment of cash dividends or cash distributions by such
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subsidiary of those earnings is not permitted by operation of the terms of its
charter or any agreement, instrument, judgment, decree, order, statute, rule or
governmental regulation applicable to the subsidiary during such period (and
when and to the extent such dividend or other distribution is permitted, such
income not previously recognized shall then be recognized, in the period when
such dividend or other distribution is permitted and to the extent of such
permission and any other necessary relevant permission permits cash dividends
and similar distributions to be received by the Company); (iv) any gain (but not
loss), together with any related provisions for taxes on any such gain, realized
during such period by the Company or any of its subsidiaries upon the
acquisition of any securities, or the extinguishment of any Indebtedness, of the
Company or any of its subsidiaries; (v) any extraordinary gain (but not
extraordinary loss), together with any related provision for taxes on any such
extraordinary gain, realized by the Company or any of its subsidiaries during
such period; and (vi) in the case of a successor to the Company by
consolidation, merger or transfer of its assets, any earnings of the successor
prior to such merger, consolidation or transfer of assets; provided, further,
that in calculating Consolidated Net Earnings, the Company shall be entitled to
take into consideration the tax benefits associated with any loss, but only when
and to the extent such tax benefits are realized by the Company; and, provided,
further, that any loss attributable to or recognized or incurred with respect to
the adoption of Financial Accounting Standards Board Opinion No. 121, Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed
Of, will be considered a loss in determining Consolidated Net Earnings.
"Consolidated Tangible Net Worth" of the Company as of any date means the
stockholders' equity (including any preferred stock that is classified as equity
under GAAP, other than Disqualified Stock) of the Company and its subsidiaries
on a consolidated basis at such date, as determined in accordance with GAAP,
less (i) all write-ups subsequent to December 31, 1994 in the book value of any
asset owned by the Company or any of its subsidiaries and (ii) Intangible Assets
reflected on the consolidated balance sheet of the Company and its subsidiaries
as of such date; provided that no amounts for assets, liabilities or
stockholders equity (deficit) of any Former Subsidiary, other than liabilities
or Indebtedness of Former Subsidiaries for which the Company or a subsidiary
that is not a Former Subsidiary has direct or indirect liability or has
otherwise Guaranteed, will be included in calculating the Consolidated Tangible
Net Worth of the Company.
"Default" means any event, act or condition that is, or after notice or the
passage of time or both would be, an Event of Default.
"Disqualified Stock" means any Capital Stock that, by its terms (or by the
terms of any security into which it is convertible or for which it is
exchangeable), or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, or is redeemable
at the option of the holder thereof, in whole or in part, on or prior to the
final maturity date of the Debentures.
"Exchange Act" means the Securities Exchange Act of 1934, as amended, or
any successor statute.
"Former Subsidiary" means any subsidiary or former subsidiary of the
Company of which (a) Capital Stock has been distributed to holders of the
Capital Stock of the Company as such in a transaction that is a Restricted
Payment pursuant to clause (i) of the definition of Restricted Payment or (b)
any of the Capital Stock or any of the assets were sold, transferred or
otherwise disposed of in a transaction that is a Restricted Payment pursuant to
clause (iv) of the definition of Restricted Payments, but only if such
Restricted Payment was made in compliance with the Restricted Payments covenant.
"GAAP" means generally accepted accounting principles set forth in the
authoritative literature of the American Institute of Certified Public
Accountants, the Financial Accounting Standards Board and the Securities and
Exchange Commission, in each case as in effect on the date of the Indenture.
"Guarantee" with respect to any obligation means: (i) any direct or
indirect guarantee; (ii) any direct or indirect agreement or arrangement,
contingent or otherwise, to purchase, repurchase or otherwise acquire any part
or all of such obligation; or (iii) any other direct or indirect agreement or
arrangement the practical effect of which is to assure the payment or
performance (or payment of damages in the event of nonperformance) of all or any
part of such obligation, including without limitation a keep well, make well or
net worth maintenance or income maintenance agreement.
"Indebtedness" of any Person at any date means, without duplication, (i)
all indebtedness of such Person for borrowed money (whether or not the recourse
of the lender is to the whole of the assets of such Person or
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<PAGE> 57
only to a portion thereof), (ii) all obligations of such Person evidenced by
bonds, debentures, notes or other similar instruments, (iii) all obligations of
such Person in respect of letters of credit or other similar instruments (or
reimbursement obligations with respect thereto), other than standby letters of
credit incurred by such Person in the ordinary course of business, (iv) all
obligations of such Person to pay the deferred and unpaid purchase price of
property or services, except trade payables and accrued expenses incurred in the
ordinary course of business, (v) all Capitalized Lease Obligations of such
Person, (vi) all Indebtedness of others secured by a Lien on any asset of such
Person, whether or not such Indebtedness is assumed by such Person, and (vii)
all Indebtedness of others Guaranteed by such Person to the extent of such
Guarantee. The amount of Indebtedness of any Person at any date shall be (a) the
outstanding balance at such date of all unconditional obligations described
above, (b) the maximum liability of such Person for any contingent obligations
under clause (iii) above and (c) in the case of clause (vi), the lesser of (A)
the fair market value of any asset subject to a Lien securing the Indebtedness
of others on the date that the Lien attaches or (B) the amount of the
Indebtedness secured. To the extent such Person Guarantees the obligation of
another Person to pay interest on indebtedness owed by such other Person, then a
designated percentage of the interest Guaranteed or the principal amount of the
underlying Indebtedness, as the case may be, shall be deemed Indebtedness of the
referent Person. For purposes of this definition, the amount of such deemed
Indebtedness of the referent Person shall be equal to the greater of: (a) the
aggregate principal amount of the underlying Indebtedness Guaranteed plus the
aggregate amount of any accrued but unpaid interest or (b) the aggregate amount
of interest due and payable over the term of such Indebtedness (or the term of
the Debentures, if shorter) determined based upon the rate of interest in effect
as of the date of such determination, together with the maximum prepayment
premium or penalty which could become due or payable with respect to such
Indebtedness if such Indebtedness was prepaid prior to the maturity of the
Debentures. Notwithstanding the foregoing, Indebtedness shall not include
(v) Indebtedness which has been defeased or discharged, (w) Indebtedness in
respect of interest rate swap or similar agreements intended to protect against
fluctuations in interest rates, or foreign currency hedge, exchange or similar
agreements intended to protect against fluctuations in currency exchange rates,
(x) Indebtedness arising from the honoring by a bank or other financial
institution of a check, draft or similar instrument drawn against insufficient
funds in the ordinary course of business, provided that such Indebtedness is
extinguished within five Business Days of its incurrence, (y) letters of credit
provided in the ordinary course of business securing performance (and not
financial) obligations and (z) performance, completion, surety and similar bonds
and similar purpose undertakings provided in the ordinary course of business.
"Intangible Assets" of the Company means all unamortized debt discount and
expense, unamortized deferred charges, goodwill, patents, trademarks, service
marks, trade names, copyrights, write-ups of assets over their carrying value at
December 31, 1994 or the date of acquisition, if acquired subsequent thereto,
and all other items which would be treated as intangibles on the consolidated
balance sheet of the Company and its subsidiaries prepared in accordance with
GAAP.
"Lien" means, with respect to any asset, any mortgage, deed of trust,
pledge, lien, charge, security interest, adverse claim affecting title or
resulting in a charge against such asset or encumbrance of any kind in respect
of such asset, whether or not filed, recorded or otherwise perfected under
applicable law (including any conditional sale or other title retention
agreement, any lease in the nature thereof, any option or other agreement to
sell).
"Material Subsidiary" means any subsidiary of the Company which accounted
for (a) 5% or more of the revenues of the Company on a consolidated basis for
the four full fiscal quarters for which financial results have been reported
immediately prior to the Default or Event of Default or (b) 5% or more of the
total assets of the Company on a consolidated basis as of the end of the latest
fiscal quarter for which financial results have been reported immediately prior
to the Default or Event of Default. Subsidiaries of the Company that hold assets
of a specific larger asset will be a "Material Subsidiary Group" if such
subsidiaries, when considered as one subsidiary, would be a Material Subsidiary
under the preceding sentence.
"Non-Recourse Indebtedness" means Indebtedness incurred in connection with
the acquisition of property and secured by a Lien solely on property acquired,
its income and rents, to the extent the liability for such Indebtedness (and any
interest thereon) is limited to the security of the borrower's rights in such
property and its income and rents, without liability on the part of the Company
or any of its subsidiaries for
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<PAGE> 58
any deficiency, including liability by reason of any agreement by the Company or
any of its subsidiaries to provide additional capital or maintain the financial
condition of or otherwise support the credit of the Person incurring such
indebtedness. Indebtedness which is otherwise Non-Recourse Indebtedness will not
lose its character as Non-Recourse Indebtedness because there is recourse to the
borrower, any guarantor or any other Person for (1) environmental warranties or
indemnities, (2) indemnities for fraud, misrepresentation or non-payment of
rents or profits from secured assets to be paid to the lender or (3) any other
matters which are at the relevant time customary in instruments evidencing or
securing non-recourse Indebtedness.
"Person" means any individual, corporation, partnership, joint venture,
limited liability company, limited liability partnership, incorporated or
unincorporated association, joint-stock company, trust, unincorporated
organization or government or other agency or political subdivision thereof or
other entity of any kind.
"Restricted Payment" means with respect to any Person or the Company, as
the case may be, (i) the declaration of any dividend or the making of any other
payment or distribution of cash, securities or other property or assets in
respect of Capital Stock of such Person (but, for this purpose, not of any
subsidiary of such Person), provided that a dividend payable solely in Capital
Stock (other than Disqualified Stock) of such Person shall not constitute a
Restricted Payment, (ii) any payment on account of the purchase, redemption,
retirement or other acquisition for value of such Person's Capital Stock or any
other payment or distribution made in respect thereof, either directly or
indirectly, (iii) any principal payment, redemption, repurchase, defeasance or
other acquisition or retirement of Indebtedness of the Company or its
subsidiaries which is subordinated in right of payment to the Debentures prior
to the scheduled principal payment or scheduled maturity of such Indebtedness or
(iv) any sale, transfer or other disposition (however structured, including
without limitation by ways of merger, reverse merger, consolidation, or sale of
stock or assets) of any of the non-cash assets of the Company (including any
Capital Stock of any subsidiary) or of a subsidiary of the Company, including
for this purpose unissued or treasury Capital Stock of such subsidiary, to
another Person or Persons, other than the Company or a Wholly Owned Subsidiary
of the Company, to the extent such sale, transfer or other disposition was in
consideration of or in exchange for any securities of such other Person or
Persons or any other Person or Persons; provided, however, that with respect to
the Company and its subsidiaries, Restricted Payments shall not include (a) any
payment described in clause (i) or (ii) above made to the Company or any of its
Wholly Owned Subsidiaries by any of the Company's subsidiaries, (b) any
underwritten call of Indebtedness of the Company which is convertible into
Capital Stock (other than Disqualified Stock), but only to the extent the
Company is not required to make any redemption or principal payments in respect
of Indebtedness subject to such underwritten call (other than redemption and
principal payments which are covered by the net proceeds received by the Company
from a concurrent sale of Capital Stock (other than Disqualified Stock) to the
underwriters or standby purchasers participating in such underwritten call) or
(c) the exchange by the Company of Capital Stock (other than Disqualified Stock)
for Indebtedness of the Company or a subsidiary in an exchange offer, but only
to the extent the exchange is solely for such Capital Stock. The amount of a
Restricted Payment described in clause (iv) of the preceding sentence will,
except for Restricted Payments permitted by the last sentence of the Restricted
Payments covenant, be determined by the independent members of the full Board of
Directors.
"Subsidiary" of any Person means (i) any corporation of which at least a
majority of the aggregate voting power of all classes of the Common Equity is
owned by such Person directly or through one or more other subsidiaries of such
Person and (ii) any entity other than a corporation in which such Person,
directly or indirectly, owns at least a majority of the Common Equity of such
entity.
"United States Government Obligations" means obligations for which the full
faith and credit of the United States of America is pledged and which are not
callable at the issuer's option.
"Wholly Owned Subsidiary" of any Person means (i) a subsidiary of which
100% of the Common Equity (except for directors' qualifying shares or certain
minority interests owned by other Persons solely due to local law requirements
that there be more than one stockholder, but which interest is not in excess of
what is required for such purpose) is owned directly by such Person or through
one or more other Wholly Owned Subsidiaries of such Person or (ii) any entity
other than a corporation in which such Person, directly or indirectly, owns all
of the Common Equity.
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<PAGE> 59
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 150,000,000 shares
of Common Stock, no par value, and 50,000,000 shares of Preferred Stock, no par
value ("Preferred Stock"). No shares of Preferred Stock are outstanding.
COMMON STOCK
The holders of Common Stock are entitled to one vote per share on all
matters submitted to a vote of the stockholders of the Company. In addition,
such holders are entitled to receive ratably such dividends, if any, as may be
declared from time to time by the Board of Directors out of funds legally
available therefor, subject to the payment of preferential dividends with
respect to any Preferred Stock that from time to time may be outstanding. See
"Common Stock Price Range and Dividend Policy." In the event of the dissolution,
liquidation or winding-up of the Company, the holders of Common Stock are
entitled to share ratably in all assets remaining after payment of all
liabilities of the Company and subject to the prior distribution rights of the
holders of any Preferred Stock that may be outstanding at that time. The holders
of Common Stock have cumulative voting rights but not preemptive or other rights
to acquire or subscribe for additional, unissued or treasury shares. See "Risk
Factors -- Risks Relating to Certain Corporate Matters." All outstanding shares
of Common Stock are, and, when issued, the shares of Common Stock to be issuable
upon conversion of the Debentures will be, fully paid and nonassessable.
PREFERRED STOCK
The Board has the authority to issue 50,000,000 shares of Preferred Stock
in one or more series and to fix the designations, relative powers, preferences,
rights, qualifications, limitations and restrictions of all shares of each such
series, including, without limitation, dividend rates, preemptive rights,
conversion rights, voting rights, redemption and sinking fund provisions,
liquidation preferences and the number of shares constituting each such series,
without any further vote or action by the stockholders. The issuance of
Preferred Stock could decrease the amount of earnings and assets available for
distribution to holders of Common Stock or adversely affect the rights and
powers, including voting rights, of the holders of Common Stock. The issuance of
Preferred Stock could also have the effect of delaying, deferring or preventing
a change in control of the Company without further action by the stockholders in
the event the Company no longer remained in the control of the present
controlling stockholders.
LIMITATIONS ON DIRECTORS' LIABILITIES AND INDEMNIFICATION
As permitted by the Colorado Business Corporation Act, the Articles of
Incorporation and By-laws provide that no director or officer will be liable to
the Company or its shareholders for monetary damages for breach of fiduciary
duty as a director or officer, except for liability (i) for any breach of the
director's or officer's duty of loyalty to the Company or its shareholders, (ii)
for acts or omissions not in good faith or that involve intentional misconduct
or a knowing violation of law, (iii) in respect of certain unlawful dividend
payments or stock redemptions or repurchases, and (iv) for any transaction from
which the director or officer derives an improper personal benefit. The effect
of this provision is to eliminate the rights of the Company and its shareholders
to recover monetary damages against a director or officer for breach of the
fiduciary duty of care as a director or officer (including breaches resulting
from negligent or grossly negligent behavior), except in the situations
described in clauses (i), (ii), (iii) and (iv) above. This provision does not
limit or eliminate the rights of the Company or any shareholder to seek
non-monetary relief such as an injunction or rescission in the event of a breach
of a director's or officer's duty of care. The Articles of Incorporation and
By-laws also provide that the Company shall, to the fullest extent permitted by
law, indemnify and advance expenses to each of its currently acting and former
directors and officers and may indemnify and advance expenses to each of its
currently acting and former employees and agents. The Company has a directors'
and officers' liability insurance policy.
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<PAGE> 60
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Stock is American
Securities Transfer, Inc., Denver, Colorado.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the Offering, assuming no conversion of the Debentures,
the Company will have outstanding 4,264,590 shares of Common Stock. Of these
shares, 1,372,660 shares will be freely tradeable without restriction or further
registration under the Securities Act. Of the remaining shares, 2,891,930 will
be "restricted securities" ("Restricted Shares") within the meaning of Rule 144
under the Securities Act. Sales of Restricted Shares in the public market, or
the availability of such shares for sale, could adversely affect the market
price of the Common Stock. See "Risk Factors -- Shares Eligible for Future
Sale."
In general, under Rule 144, as currently in effect, a person (or persons
whose shares are aggregated) who has beneficially owned Restricted Shares for at
least two years, including persons who may be deemed "affiliates" of the
Company, would be entitled to sell within any three-month period a number of
shares that does not exceed 1% of the number of shares of Common Stock then
outstanding or the average weekly trading volume of the Common Stock during the
four calendar weeks preceding the making of a filing with the Securities and
Exchange Commission ("Commission") with respect to such sale. Such sales under
Rule 144 are also subject to a certain manner of sale provisions and notice
requirements and to the availability of current public information about the
Company. In addition, a person who is not deemed to have been an affiliate of
the Company at any time during the 90 calendar days preceding a sale, and who
has beneficially owned for at least three years the shares proposed to be sold,
would be entitled to sell such shares under Rule 144(k) as currently in effect
without regard to the requirements as stated above. The Company is unable to
estimate accurately the number of Restricted Shares that ultimately will be sold
under Rule 144 because the number of shares will depend in part on the market
price for the Common Stock, the personal circumstances of the sellers and other
factors, although the Company and certain of its stockholders have agreed,
subject to certain limitations, not to sell any shares of Common Stock for a
period of 180 calendar days after the date of this Prospectus without the prior
consent of Van Kasper & Company. See "Underwriting."
Prior to the Offering, there has been no market for the Debentures. See
"Risk Factors -- No Prior Public Market for Debentures." The Company can make no
prediction as to the effect, if any, that sales of shares of Common Stock, or
the availability of such shares for sale, will have on the market price of the
Debentures prevailing from time to time.
In addition, the Company intends to file a registration statement under the
Securities Act covering approximately 425,000 shares of Common Stock issued to
Capco, certain employees and others. However, substantially all of these shares
may not be sold, without the prior consent of Van Kasper & Company, the
Representative of the Underwriters, until 180 days after the Closing Date.
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UNDERWRITING
Subject to the terms and conditions of the Underwriting Agreement, the
underwriters named below, for which Van Kasper & Company is acting as
Representative, have severally agreed to purchase from the Company the principal
amount of Debentures set forth opposite their names below:
<TABLE>
<CAPTION>
PRINCIPAL AMOUNT
NAME OF DEBENTURES
---- ----------------
<S> <C>
Van Kasper & Company................................................. $ 7,920,000
Hanifen, Imhoff Inc.................................................. 440,000
Jefferies & Company, Inc............................................. 440,000
Josephthal Lyon & Ross Incorporated.................................. 440,000
Offerman & Company................................................... 440,000
Rauscher Pierce Refnes, Inc.......................................... 440,000
Rodman & Renshaw, Inc................................................ 440,000
Sutro & Co. Incorporated............................................. 440,000
------------
Total......................................................... $ 11,000,000
============
</TABLE>
The Underwriting Agreement provides that the obligations of the
Underwriters are subject to certain conditions precedent and that the
Underwriters will purchase all of the Debentures offered hereby (other than
those subject to the Underwriters' over-allotment option described below) if any
of such Debentures are purchased.
Van Kasper & Company, the Representative of the several underwriters, has
advised the Company that the Underwriters propose to offer the Debentures
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus and to certain dealers at this price less a
concession not in excess of 3% of the principal amount of the Debentures. The
Underwriters may allow and these dealers may reallow a concession not in excess
of .25% of the principal amount of the Debentures to certain other dealers.
After the initial public offering of the Debentures, the offering price and
other selling terms may be changed by the Representative.
The Company has granted to the Underwriters an option, exercisable no later
than 45 days after the date of this Prospectus, to purchase up to $1,650,000 in
principal amount of additional Debentures at the initial public offering price,
less the underwriting discount set forth on the cover page of this Prospectus,
solely to cover overallotments. To the extent that the Underwriters exercise
this option, each of the Underwriters will have a firm commitment to purchase
approximately the same percentage thereof as the principal amount of Debentures
to be purchased by it shown in the above table bears to the total offering, and
the Company will be obligated, pursuant to the option, to sell such Debentures
to the Underwriters.
In the Underwriting Agreement, the Company has agreed to reimburse the
Underwriters for their out-of-pocket expenses of retaining an independent
petroleum engineer to assist in their due diligence review, the fees of counsel
to the Underwriters in connection with state securities or Blue Sky laws and
certain other fees of counsel to the Underwriters in connection with this
Offering.
The Underwriting Agreement contains covenants of indemnity between the
Underwriters, on the one hand, and, jointly and severally, the Company and
Capco, on the other, against certain civil liabilities, including liabilities
under the Securities Act.
Pursuant to the terms of certain lock-up agreements, certain holders of the
Company's Common Stock have agreed with the Underwriters that, for a period of
180 days after the effective date of the registration statement, they will not
offer to sell or otherwise sell, dispose of or grant any rights with respect to
any shares of Common Stock, now owned or hereafter acquired directly by such
holders or with respect to which they have the power of disposition, without the
prior written consent of Van Kasper & Company. The Company also has agreed not
to offer, sell, contract to sell or otherwise dispose of any shares of Common
Stock or any securities convertible into or exercisable or exchangeable for
Common Stock, or any options or warrants to purchase Common Stock other than
shares or options issued under the Company's stock and option plans, for
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<PAGE> 62
a period of 180 days after the date of this Prospectus, except with the prior
written consent of Van Kasper & Company. See "Shares Eligible for Future Sale."
Prior to this Offering there has been no public market for the Company's
Debentures. The initial public offering price for the Debentures offered hereby
has been determined by negotiation among the Company and the Underwriters. Among
the factors to be considered in making such determination are the history of and
the prospects for the industry in which the Company competes, an assessment of
the Company's management, the past and present operations of the Company, the
historical results of operations of the Company, the general condition of the
securities markets at the time of the offering and the prices of certain
publicly traded companies. The Debentures have been approved for listing on the
AMEX. However, there can be no assurance that an active or orderly trading
market will develop for the Debentures or that the Debentures will trade in the
public market subsequent to the Offering at or above the initial public offering
price.
Van Kasper & Company delivered a fairness opinion to the Company in
December 1994 in connection with the purchase by the Company of the outstanding
common stock of CRPL, for which Van Kasper & Company received a fee of $50,000,
plus reimbursement of its expenses.
CERTAIN LEGAL MATTERS
The validity of the Debentures will be passed upon for the Company by
Rogers & Wells, Los Angeles, California, counsel to the Company. Rogers & Wells
will rely on Holland & Hart, Denver, Colorado, special counsel to the Company,
with respect to certain matters of Colorado law, on Burnet, Duckworth & Palmer,
Alberta, Canada, special counsel to the Company, with respect to certain matters
of Canadian law and on Fernando Caycedo, Bogota, Colombia, special counsel to
the Company with respect to certain matters of Colombian law. Certain legal
matters will be passed upon for the Underwriters by Gibson, Dunn & Crutcher, Los
Angeles, California.
EXPERTS
The Consolidated Financial Statements of the Company as of December 31,
1994 and for the year then ended, included in this Prospectus, have been
included herein in reliance on the report of Coopers & Lybrand L.L.P. (Los
Angeles, California), independent accountants, given upon the authority of that
firm as experts in accounting and auditing.
The Consolidated Financial Statements of the Company as of December 31,
1993 and for the year then ended, included in this Prospectus, have been
included herein in reliance on the report of Jackson & Rhodes P.C., independent
accountants, given on the authority of that firm as experts in accounting and
auditing.
The change in accountants from Jackson & Rhodes P.C. to Coopers & Lybrand
L.L.P. was effective for fiscal 1994 and was not due to any disagreements
between the Company and Jackson & Rhodes P.C.
The Historical Summaries of Gross Revenues and Direct Operating Expenses of
the TNC Fields for the years ended December 31, 1993 and 1994, included in this
Prospectus, have been included herein in reliance on the report of Coopers &
Lybrand (Santafe de Bogota, Colombia), independent accountants, given upon the
authority of that firm as experts in accounting and auditing.
The information appearing in this Prospectus with respect to the Company's
proved reserves at December 31, 1991, 1992, 1993 and 1994 and to the extent
stated herein, was estimated by Netherland, Sewell & Associates, Sproule
Associates Limited, K.E. Richison & Associates Petroleum Engineering, Inc. and
Foster Engineering & Consulting, independent petroleum engineers. Such
information is included herein on the authority of such firms as experts in
petroleum engineering.
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<PAGE> 63
AVAILABLE INFORMATION
The Company is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended, and, in accordance therewith, files reports,
proxy statements and other information with the Commission. Such reports and
other information may be inspected and copied at the public reference facilities
maintained by the Commission at 450 Fifth Street, N.W., Room 1024, Washington,
D.C. 20549, and at the Commission's Regional Offices at 7 World Trade Center,
Suite 1300, New York, New York 10048 and Northwestern Atrium Center, 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of such materials
may be obtained at prescribed rates from the Public Reference Section of the
Commission at 450 Fifth Street, N.W., Washington, D.C. 20549. The Common Stock
is listed on the AMEX and such reports and other information concerning the
Company also can be obtained at the offices of the AMEX at 86 Trinity Place, New
York, New York 10006-1881.
The Company has filed with the Commission a Registration Statement on Form
SB-2 under the Securities Act with respect to the Debentures. This Prospectus,
which constitutes part of the Registration Statement, omits certain of the
information contained in the Registration Statement and the exhibits thereto on
file with the Commission pursuant to the Securities Act and the rules and
regulations of the Commission thereunder. Statements contained in this
Prospectus as to the contents of any contract or other document referred to are
not necessarily complete and in each instance reference is made to the copy of
such contract or other documents filed as an exhibit to the Registration
Statement, each such statement being qualified in all respects by such
reference.
GLOSSARY
The definitions below are used in this Prospectus.
Bbl. or barrel. 42 U.S. gallons liquid volume, usually used herein in
reference to crude oil or other liquid hydrocarbons.
BOE or barrels of oil equivalent converts gas to oil at a ratio of 6,000
cubic feet of gas to one barrel of oil, usually. Then oil and gas are added
together for total BOE.
BOPD. Barrels of oil per day.
BTU. British Thermal Unit.
Depletion. The act of emptying, reducing, or exhausting, such as depletion
of a natural resource like oil and gas. Also means a reduction in income
reflecting the amortization of the cost of mineral deposits.
Developed Acreage. The number of acres of oil and gas leases held by, or if
owned, which are allocated or assignable to, producing wells or wells capable of
production.
Development Well. A well which is drilled to and completed in a known
producing formation adjacent to a producing well in a previously discovered
field and in a stratigraphic horizon known to be productive.
Exploration. The search for economic deposits of minerals, petroleum and
other natural earth resources by any geological, geophysical, or geochemical
technique.
Field. A geographic area in which a number of oil or gas wells produce from
a continuous reservoir.
GAAP. Generally accepted accounting principles set forth in the
authoritative literature of the American Institute of Certified Public
Accountants, the Financial Accounting Standards Board and the Commission, in
each case, except as used in "Description of the Debentures," as in effect from
time to time.
Mcf. One thousand cubic feet of natural gas.
Mineral interest. Possessing the right to explore, right of ingress and
egress, right to lease, and right to receive part or all of the income from
mineral exploitation, i.e., bonus, delay rentals and royalties.
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<PAGE> 64
Net Acres or Net Wells. A "net acre" or "net well" is deemed to exist when
the sum of fractional ownership working interests in gross acres or gross wells
equals one.
Oil Wells or Gas Wells. Oil wells are those wells which generate revenue
from oil production; gas wells are those wells which generate nearly all revenue
from gas production.
Operator. The person or company actually operating an oil or gas well.
Proved Reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering data have demonstrated with
reasonable certainty to be recoverable in future years from known oil and gas
reservoirs under existing economic and operating conditions, on the basis of
prices and costs on the date the estimate is made and any price changes provided
by existing contracts.
Proved Developed Reserves. Proved Reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
Proved Undeveloped Reserves. Proved Reserves which can be expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
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INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
SABA PETROLEUM COMPANY
Report of Independent Accountants..................................................... F-2
Independent Auditors' Report.......................................................... F-3
Consolidated Balance Sheets as of December 31, 1993 and 1994, and as of September 30,
1995 (Unaudited).................................................................... F-4
Consolidated Statements of Operations for the years ended December 31, 1993 and 1994,
and for the nine month periods ended September 30, 1994 and 1995 (Unaudited)........ F-5
Consolidated Statements of Stockholders' Equity for the years ended December 31, 1993
and 1994, and for the nine months ended September 30, 1995 (Unaudited).............. F-6
Consolidated Statements of Cash Flows for the years ended December 31, 1993 and 1994,
and for the nine month periods ended September 30, 1994 and 1995 (Unaudited)........ F-7
Notes to Consolidated Financial Statements............................................ F-8
Supplemental Information About Oil and Gas Producing Activities (Unaudited)........... F-22
THE TNC FIELDS
Report of Independent Accountants..................................................... F-25
Historical Summaries of Gross Revenues and Direct Operating Expenses for the years
ended December 31, 1993 and 1994 and for the nine months ended September 30, 1995
(Unaudited)......................................................................... F-26
Notes to Historical Summaries of Gross Revenues and Direct Operating Expenses......... F-27
Supplemental Information About Oil and Gas Producing Activities (Unaudited)........... F-30
</TABLE>
F-1
<PAGE> 66
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Saba Petroleum Company
We have audited the accompanying consolidated balance sheet of Saba
Petroleum Company and subsidiaries as of December 31, 1994, and the related
consolidated statements of operations, stockholders' equity, and cash flows for
the year then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Saba Petroleum
Company and subsidiaries as of December 31, 1994, and the consolidated results
of their operations and their cash flows for the year then ended in conformity
with generally accepted accounting principles.
COOPERS & LYBRAND L.L.P.
Los Angeles, California
April 3, 1995
F-2
<PAGE> 67
INDEPENDENT AUDITORS' REPORT
The Board of Directors
Saba Petroleum Company
We have audited the accompanying consolidated balance sheet of Saba
Petroleum Company and subsidiaries as of December 31, 1993, and the related
consolidated statements of operations, changes in stockholders' equity, and cash
flows for the year then ended. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Saba Petroleum
Company and subsidiaries as of December 31, 1993, and the consolidated results
of their operations and their cash flows for the year then ended in conformity
with generally accepted accounting principles.
JACKSON & RHODES P.C.
Dallas, Texas
March 21, 1994
F-3
<PAGE> 68
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------- SEPTEMBER 30,
1993 1994 1995
----------- ----------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Current assets:
Cash and cash equivalents......................... $ 522,748 $ 798,984 $ 159,424
Accounts receivable, net of allowance for doubtful
accounts of $55,000 (1993), $62,000 (1994) and
$71,500 (1995)................................. 2,445,680 2,428,360 3,700,141
Other current assets.............................. 151,168 534,993 594,829
----------- ----------- -----------
Total current assets...................... 3,119,596 3,762,337 4,454,394
----------- ----------- -----------
Property and equipment (Note 9):
Oil and gas properties (full cost method)......... 14,526,699 18,416,330 32,422,505
Land.............................................. -- 1,166,938 1,166,938
Plant and equipment............................... 445,401 1,260,023 3,238,428
----------- ----------- -----------
14,972,100 20,843,291 36,827,871
Less accumulated depletion and depreciation....... (5,508,294) (7,363,502) (9,272,682)
----------- ----------- -----------
Total property and equipment.............. 9,463,806 13,479,789 27,555,189
----------- ----------- -----------
Other assets:
Deposits on properties............................ 134,375 50,000 150,000
Notes receivable, less current portion............ 60,000 360,290 197,579
Due from affiliates............................... 22,794 215,831 --
Deposits and other................................ 460,838 240,175 682,720
----------- ----------- -----------
Total other assets........................ 678,007 866,296 1,030,299
----------- ----------- -----------
$13,261,409 $18,108,422 $33,039,882
=========== =========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Note payable...................................... $ -- $ 606,363 $ --
Accounts payable and accrued liabilities.......... 2,539,518 3,222,187 4,258,015
Current portion of long-term debt................. 1,440,000 2,356,524 8,519,743
Oil imbalance obligation.......................... 841,552
----------- ----------- -----------
Total current liabilities................. 3,979,518 6,185,074 13,619,310
Long-term debt, net of current portion.............. 4,875,000 5,322,716 11,511,415
Other liabilities................................... -- 62,505 448,093
Deferred taxes...................................... -- 254,800 491,166
----------- ----------- -----------
Total liabilities......................... 8,854,518 11,825,095 26,069,984
----------- ----------- -----------
Commitments and contingencies (Note 13)
Stockholders' equity:
Preferred stock -- no par value, authorized
50,000,000 shares; none issued................. -- -- --
Common stock -- no par value, authorized
150,000,000 shares; issued and outstanding
3,597,037 (1993), 4,119,257 (1994) and
4,189,590 (1995)............................... 4,405,335 5,772,457 6,191,640
Cumulative translation adjustment................... -- -- 50,257
Unearned compensation............................... -- -- (12,750)
Retained earnings................................... 1,556 510,870 740,751
----------- ----------- -----------
Total stockholders' equity................ 4,406,891 6,283,327 6,969,898
----------- ----------- -----------
$13,261,409 $18,108,422 $33,039,882
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE> 69
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------- --------------------------
1993 1994 1994 1995
----------- ----------- ----------- -----------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C>
Revenues:
Oil and gas sales....................... $10,129,554 $12,170,203 $ 8,964,935 $10,976,571
Other................................... 400,194 783,688 269,303 417,286
----------- ----------- ----------- -----------
Total revenues.................. 10,529,748 12,953,891 9,234,238 11,393,857
----------- ----------- ----------- -----------
Expenses:
Production costs........................ 5,856,947 7,547,479 5,490,305 6,923,330
General and administrative.............. 2,502,543 1,881,852 1,317,055 1,406,004
Depletion, depreciation and
amortization......................... 1,853,339 2,041,032 1,727,450 1,931,031
----------- ----------- ----------- -----------
Total expenses.................. 10,212,829 11,470,363 8,534,810 10,260,365
----------- ----------- ----------- -----------
Operating income.......................... 316,919 1,483,528 699,428 1,133,492
----------- ----------- ----------- -----------
Other income (expense):
Interest income......................... 17,495 25,481 1,217 15,181
Other income (expense).................. (16,174) 18,397 92,383 34,469
Interest expense, net of interest
capitalized of $58,085 (December 31,
1994), $29,803 (September 30, 1994)
and $27,369 (September 30, 1995)..... (443,363) (634,292) (473,129) (778,461)
----------- ----------- ----------- -----------
Total other income (expense).... (442,042) (590,414) (379,529) (728,811)
----------- ----------- ----------- -----------
Income (loss) before income
taxes......................... (125,123) 893,114 319,899 404,681
Provision (benefit) for taxes on income... (37,000) 383,800 81,930 174,800
----------- ----------- ----------- -----------
Net income (loss)............... $ (88,123) $ 509,314 $ 237,969 $ 229,881
=========== =========== =========== ===========
Net income (loss) per common share........ $ (0.02) $ 0.13 $ 0.06 $ 0.05
=========== =========== =========== ===========
Weighted average common and common
equivalent shares outstanding........... 3,532,556 3,997,787 3,966,492 4,354,647
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE> 70
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
YEARS ENDED DECEMBER 31, 1993 AND 1994, AND NINE MONTHS ENDED SEPTEMBER 30, 1995
(UNAUDITED)
<TABLE>
<CAPTION>
COMMON STOCK CUMULATIVE TOTAL
---------------------- TRANSLATION UNEARNED RETAINED STOCKHOLDERS'
SHARES AMOUNT ADJUSTMENT COMPENSATION EARNINGS EQUITY
--------- ---------- ----------- ------------ --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance at December 31, 1992..... 3,421,037 $3,920,495 $ -- $ -- $ 89,679 $ 4,010,174
Issuance of common stock for
cash........................ 136,000 414,840 -- -- -- 414,840
Issuance of common stock
(Note 5).................... 40,000 70,000 -- -- -- 70,000
Net loss....................... -- -- -- -- (88,123) (88,123)
--------- ---------- ------- -------- --------- -----------
Balance at December 31, 1993..... 3,597,037 4,405,335 -- -- 1,556 4,406,891
Exercise of options............ 200,000 625,756 -- -- -- 625,756
Issuance of common stock for
interest in oil and gas
property.................... 22,220 66,660 -- -- -- 66,660
Issuance of common stock for
acquisition of subsidiary
(Note 2).................... 300,000 -- -- -- -- --
Contributed surplus............ -- 674,706 -- -- -- 674,706
Net income..................... -- -- 509,314 509,314
--------- ---------- ------- -------- --------- -----------
Balance at December 31, 1994..... 4,119,257 5,772,457 -- -- 510,870 6,283,327
Exercise of options............ 58,333 189,583 -- -- -- 189,583
Issuance of common stock for
compensation................ 12,000 25,500 -- -- -- 25,500
Cumulative translation
adjustment.................. -- -- 50,257 -- -- 50,257
Unearned compensation.......... -- -- -- (12,750) -- (12,750)
Contributed surplus............ -- 204,100 -- -- -- 204,100
Net income..................... -- -- -- -- 229,881 229,881
--------- ---------- ------- -------- --------- -----------
Balance at September 30, 1995
(Unaudited).................... 4,189,590 $6,191,640 $50,257 $(12,750) $ 740,751 $ 6,969,898
========= ========== ======= ======== ========= ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE> 71
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- ---------------------------
1993 1994 1994 1995
----------- ----------- ----------- -----------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C>
Cash flows from operating activities:
Net income (loss)....................... $ (88,123) $ 509,314 $ 237,969 $ 229,881
Adjustments to reconcile net income
(loss) to net cash provided by
operations:
Depletion, depreciation and
amortization....................... 1,853,339 2,041,032 1,727,450 1,931,031
Deferred taxes....................... (37,000) 254,800 26,000 116,070
Compensation expense attributable to
non-employee option................ -- 115,756 -- --
Amortization of unearned
compensation....................... -- -- -- 12,750
Changes in:
Accounts receivable................ (1,155,211) 100,820 (234,428) (1,271,781)
Other assets....................... (135,410) (299,830) (76,177) (167,260)
Accounts payable and accrued
liabilities..................... 65,209 624,584 604,478 1,284,321
----------- ----------- ----------- -----------
Net cash provided by operating
activities...................... 502,804 3,346,476 2,285,292 2,135,012
----------- ----------- ----------- -----------
Cash flows from investing activities:
Expenditures for oil and gas
properties........................... (1,905,023) (3,694,094) (3,554,090) (13,166,899)
Sale of oil and gas properties.......... 658,946 529,611 49,371 77,062
Expenditures for equipment, net......... (127,459) (797,690) (641,592) (1,978,199)
Change in other assets.................. (65,000) 32,250 (104,438) (100,000)
----------- ----------- ----------- -----------
Net cash used in investing
activities...................... (1,438,536) (3,929,923) (4,250,749) (15,168,036)
----------- ----------- ----------- -----------
Cash flows from financing activities:
Proceeds from notes payable and
long-term debt....................... 7,325,000 5,986,266 3,602,922 20,564,900
Principal payments on notes payable and
long-term debt....................... (4,881,293) (5,822,026) (2,682,976) (8,819,345)
(Increase) decrease in production notes
receivable........................... -- (445,073) (269,134) 137,428
Proceeds from notes receivable.......... -- 74,848 68,583 137,100
Increase in deferred financing costs.... (280,936) (11,972) (23,194) (407,553)
Net change in accounts with affiliated
companies............................ (1,619,805) (107,066) (24,700) 387,251
Net proceeds from exercise of options
and issuance of common stock......... 414,840 510,000 510,000 189,583
Increase in contributed surplus of
subsidiary........................... -- 674,706 674,706 204,100
----------- ----------- ----------- -----------
Net cash provided by financing
activities...................... 957,806 859,683 1,856,207 12,393,464
----------- ----------- ----------- -----------
Net increase (decrease) in cash........... 22,074 276,236 (109,250) (639,560)
Cash at beginning of period............... 500,674 522,748 522,748 798,984
----------- ----------- ----------- -----------
Cash at end of period..................... $ 522,748 $ 798,984 $ 413,498 $ 159,424
=========== =========== =========== ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-7
<PAGE> 72
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
o General
Saba Petroleum Company (the Company) was organized and incorporated in 1979
under the laws of the State of Colorado and is engaged in the business of
acquiring interests in and developing oil and gas properties. As of December 31,
1994, 67.4% of the Company's Common Stock is owned directly, or indirectly, by
the Company's Chief Executive Officer, or the corporation of which he is the
majority shareholder.
o Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries. All significant intercompany balances and
transactions have been eliminated.
o Interim Financial Information (Unaudited)
The consolidated financial statements at September 30, 1995, and for the
nine month periods ended September 30, 1994 and 1995, are unaudited but include
all adjustments (consisting of normal recurring accruals only) which management
considers necessary to present fairly the Company's consolidated financial
position as of September 30, 1995, and the consolidated results of operations
and cash flows for the nine month periods ended September 30, 1994 and 1995.
o Cash and Cash Equivalents
The Company considers all liquid investments with an original maturity of
three months or less to be cash equivalents.
o Oil and Gas Properties
The Company's oil and gas producing activities are accounted for using the
full cost method of accounting. Accordingly, the Company capitalizes all costs,
in separate cost centers for each country, incurred in connection with the
acquisition of oil and gas properties and with the exploration for and
development of oil and gas reserves. Such costs include lease acquisition costs,
geological and geophysical expenditures, costs of drilling both productive and
non-productive wells, and overhead expenses directly related to land acquisition
and exploration and development activities. Proceeds from the disposition of oil
and gas properties are accounted for as a reduction in capitalized costs, with
no gain or loss recognized unless such disposition involves a significant change
in reserves in which case the gain or loss is recognized.
Depletion of the capitalized costs of oil and gas properties, including
estimated future development costs, is provided using the equivalent
unit-of-production method based upon estimates of proved oil and gas reserves
and production which are converted to a common unit of measure based upon their
relative energy content. Unproved oil and gas properties are not amortized but
are individually assessed for impairment. The cost of any impaired property is
transferred to the balance of oil and gas properties being depleted.
In accordance with the full cost method of accounting, the net capitalized
costs of oil and gas properties are not to exceed their related estimated future
net revenues discounted at 10 percent, net of tax considerations, plus the lower
of cost or estimated fair market value of unproved properties.
Substantially all of the Company's exploration, development and production
activities are conducted jointly with others and, accordingly, the financial
statements reflect only the Company's proportionate interest in such activities.
F-8
<PAGE> 73
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
o Plant and Equipment
Plant, consisting of an asphalt refining facility, is stated at the
acquisition price of $500,000 plus the cost to refurbish the equipment.
Depreciation will be calculated using the straight line method over its
estimated useful life. Equipment is stated at cost. Depreciation of equipment is
calculated using the straight line method over the estimated useful lives of the
equipment, ranging from three to seven years. Depreciation expense in 1993 and
1994 was $71,739 and $74,554, respectively. Normal repairs and maintenance are
charged to expense as incurred. Upon disposition of plant and equipment, any
resultant gain or loss is recognized in current operations.
Interest is capitalized in connection with the construction of major
facilities. The capitalized interest is recorded as part of the asset to which
it relates and is amortized over the asset's estimated useful life.
o Income Taxes
The Company accounts for income taxes pursuant to Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes" (SFAS-109). SFAS-109
requires the asset and liability method of computing deferred income taxes. The
objective of the asset and liability method is to establish deferred tax assets
and liabilities for the temporary differences between the financial reporting
bases and the tax bases of the Company's assets and liabilities at enacted tax
rates expected to be in effect when such amounts are realized or settled.
Valuation allowances are established, when necessary, to reduce deferred tax
assets to the amount expected to be realized.
o Foreign Currency Translation
Assets and liabilities of foreign subsidiaries are translated at year-end
rates of exchange; income and expenses are translated at the weighted average
rates of exchange during the year. The resultant cumulative translation
adjustments are included as a separate component of stockholders' equity
(immaterial for 1994). Foreign currency transaction gains and losses are
included in net income.
o Earnings per Common Share
Per share amounts have been computed using the weighted average number of
shares of Common Stock and Common Stock equivalents (consisting of dilutive
options) outstanding for each period.
o Reclassifications
Certain previously reported financial information has been reclassified to
conform to the current period's presentation.
F-9
<PAGE> 74
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. ACQUISITIONS
YEARS ENDED DECEMBER 31, 1993 AND 1994
On December 30, 1994, the Company acquired Capco Resource Properties Ltd.
("CRPL"), a Canadian oil and gas company, from its parent company, Capco
Resources, Ltd., in exchange for 300,000 shares of the Company's Common Stock.
The transaction has been accounted for on an "as if pooled" basis and,
accordingly, the consolidated financial statements for 1994 include the accounts
of CRPL. The 1993 financial statements have not been restated as the impact was
not material.
The 1994 results of operations and total assets at December 31, 1994 of the
separate companies are as follows:
<TABLE>
<CAPTION>
SABA PETROLEUM CRPL
COMPANY (U.S.) (CANADA) TOTAL
-------------- ---------- -----------
<S> <C> <C> <C>
Oil and gas sales.......................... $ 10,403,835 $1,766,368 $12,170,203
Operating income........................... $ 1,177,814 $ 305,714 $ 1,483,528
Net income................................. $ 434,070 $ 75,244 $ 509,314
Total assets............................... $ 14,222,514 $3,885,908 $18,108,422
</TABLE>
NINE MONTHS ENDED SEPTEMBER 30, 1995 (UNAUDITED)
On September 12, 1995, the Company acquired a 25% interest in the Teca and
Nare oil producing fields and a 50% interest in a 117-mile oil transmission
pipeline in Colombia, South America. The acquisition cost of $9,223,700,
including a previously released deposit of $1,400,000 and assumption of an oil
imbalance obligation of $932,700, was funded by proceeds from a bank term loan
in the amount of $4,700,000, with additional financing provided by the Company's
parent company through an unsecured loan of $2,191,000.
As part of this transaction, but scheduled to close in the first quarter of
1996, the Company will acquire a 50% interest in an adjacent oil field, known as
the Cocorna Field. The contract price for this property is $750,000, which will
be reduced by the Company's share of production credits from the property from
January 1, 1995 to the date of closing (approximately $200,000 at September 30,
1995). The Company has placed a $100,000 deposit with the seller.
The following unaudited pro forma condensed statements of operations for
the year ended December 31, 1994 and for the nine months ended September 30,
1995 give effect to the acquisition of the Teca and Nare fields and the
Velasquez-Galan Pipeline in Colombia, South America ("Acquisition") as if it had
occurred on January 1, 1994. The Acquisition has been accounted for using the
purchase method of accounting. In connection with the preparation of the pro
forma financial data which follows, it was assumed, in accordance with
Securities and Exchange Commission (the "Commission") requirements, that the
purchase price for these acquisitions as of January 1, 1995 was the purchase
price paid in September 1995 (for the Teca and Nare fields and Velasquez-Galan
Pipeline) and to be paid in the first quarter of 1996 (for the Cocorna Field).
The purchase price so paid and payable ($8.8 million plus an oil imbalance
obligation of approximately $900,000) is less than the contract price of $13.0
million plus assumption of the oil imbalance obligation (approximately $2.0
million at January 1, 1995) because, under the contract, which was signed in
February 1995, the purchase price is adjusted for production from January 1,
1995 to closing. Accordingly, had the purchases been completed on January 1,
1995, the purchase price and related debt incurred by the Company would have
been significantly higher.
Similarly, in accordance with the Commission's requirements, the pro forma
financial data for 1994 assumes that the purchase price for these acquisitions
at January 1, 1994 was the purchase price paid and payable in September and
December 1995, without any upward adjustment to reflect production for all of
F-10
<PAGE> 75
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1994 and the portion of 1995 to the date of purchase. Thus, among other things,
the purchase price assumed in the pro forma financial data for the year ended
December 31, 1994 does not reflect the significantly higher reserves that these
properties would have had at January 1, 1994, and no assurance can be given that
these acquisitions could have been effected as of January 1, 1994 or that, if
such acquisitions could have been so completed, what the terms of such
acquisitions or the results of operations thereafter would have been. Neither
the pro forma financial data for the year ended December 31, 1994 nor such data
for the nine months ended September 30, 1995 is intended to be indicative of
future operations.
<TABLE>
<CAPTION>
HISTORICAL PRO FORMA PRO FORMA
RESULTS ADJUSTMENTS RESULTS
---------- ---------- -----------
(DOLLARS IN THOUSANDS EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1994
Total revenues.............................. $ 12,954 $ 11,516 $ 24,470
Total expenses.............................. 11,470 6,850 18,320
---------- ---------- -----------
Operating income............................ 1,484 4,666 6,150
Other income................................ 43 -- 43
Interest expense............................ 634 813 1,447
Provision for taxes......................... 384 1,657 2,041
---------- ---------- -----------
Net income.................................. $ 509 $ 2,196 $ 2,705
========== ========== ===========
Net income per common share................. $ 0.13 $ 0.68
========== ===========
NINE MONTHS ENDED SEPTEMBER 30, 1995
Total revenues.............................. $ 11,394 $ 9,793 $ 21,187
Total expenses.............................. 10,260 4,839 15,099
---------- ---------- -----------
Operating income............................ 1,134 4,954 6,088
Other income................................ 50 -- 50
Interest expense............................ 779 568 1,347
Provision for taxes......................... 175 1,886 2,061
---------- ---------- -----------
Net income.................................. $ 230 $ 2,500 $ 2,730
========== ========== ===========
Net income per common share................. $ 0.05 $ 0.63
========== ===========
PROVED RESERVES, DECEMBER 31, 1994
Oil (Bbls).................................. 7,135,731 5,301,639 12,437,370
========== ========== ===========
Gas (MCF)................................... 9,791,773 -- 9,791,773
========== ========== ===========
</TABLE>
F-11
<PAGE> 76
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. NOTES RECEIVABLE
Notes receivable are comprised of the following at December 31:
<TABLE>
<CAPTION>
1993 1994
-------- --------
<S> <C> <C>
9 3/4% production notes receivable, with monthly installments
of $16,050, plus interest, through April 1997................ $ -- $445,073
5% note receivable from a former officer of the Company, due
January 1, 1997, with 20,000 shares of Company Common Stock
as collateral................................................ 60,000 60,000
9% note receivable from sale of real estate, due July 31, 1995,
with a deed of trust covering real property as collateral.... -- 75,000
6% note receivable from purchaser of personal property, due
June 30, 1995, uncollateralized.............................. -- 11,698
12% demand note receivable, with monthly installments of
$4,448, including interest, through January 1995. Paid in
full in January 1994......................................... 64,524 --
Other.......................................................... 4,836 7,160
-------- --------
129,360 598,931
Less current portion (included in other current assets)........ 69,360 238,641
-------- --------
$ 60,000 $360,290
======== ========
</TABLE>
4. OIL AND GAS PROPERTIES, LAND, PLANT AND EQUIPMENT
Oil and gas properties, land, plant and equipment at December 31, 1993 and
1994 are as follows:
<TABLE>
<CAPTION>
UNITED STATES CANADA TOTAL
------------- ---------- -----------
<S> <C> <C> <C>
DECEMBER 31, 1993
OIL AND GAS PROPERTIES
Unevaluated oil and gas properties........... $ 166,115 $ -- $ 166,115
Proved oil and gas properties................ 14,360,584 -- 14,360,584
----------- ---------- -----------
Total capitalized costs.................... 14,526,699 -- 14,526,699
Less accumulated depletion and
depreciation............................... 5,406,569 -- 5,406,569
----------- ---------- -----------
Capitalized costs, net..................... $ 9,120,130 $ -- $ 9,120,130
=========== ========== ===========
OTHER PROPERTY AND EQUIPMENT
Plant and equipment.......................... $ 445,401 $ -- $ 445,401
Less accumulated depreciation................ 101,725 -- 101,725
----------- ---------- -----------
$ 343,676 $ -- $ 343,676
=========== ========== ===========
</TABLE>
F-12
<PAGE> 77
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
<TABLE>
<CAPTION>
UNITED STATES CANADA TOTAL
----------- ---------- -----------
<S> <C> <C> <C>
DECEMBER 31, 1994
OIL AND GAS PROPERTIES
Unevaluated oil and gas properties........... $ 339,575 $ -- $ 339,575
Proved oil and gas properties................ 15,017,287 3,059,468 18,076,755
----------- ---------- -----------
Total capitalized costs.................... 15,356,862 3,059,468 18,416,330
Less accumulated depletion and
depreciation............................... 6,857,834 380,717 7,238,551
----------- ---------- -----------
Capitalized costs, net..................... $ 8,499,028 $2,678,751 $11,177,779
=========== ========== ===========
OTHER PROPERTY AND EQUIPMENT
Land......................................... $ 1,166,938 $ -- $ 1,166,938
Plant and equipment.......................... 1,225,363 34,660 1,260,023
----------- ---------- -----------
2,392,301 34,660 2,426,961
Less accumulated depreciation................ 120,180 4,771 124,951
----------- ---------- -----------
$ 2,272,121 $ 29,889 $ 2,302,010
=========== ========== ===========
</TABLE>
Costs incurred in oil and gas property acquisition, exploration, and
development activities are as follows:
<TABLE>
<CAPTION>
UNITED
STATES CANADA TOTAL
---------- ---------- ----------
<S> <C> <C> <C>
1993
Exploration.................................. $ 252,146 $ -- $ 252,146
Development.................................. 617,165 -- 617,165
Acquisition of proved properties............. 1,266,916 -- 1,266,916
---------- ---------- ----------
Total costs incurred....................... $2,136,227 $ -- $2,136,227
========== ========== ==========
1994
Exploration.................................. $ 277,448 $ -- $ 277,448
Development.................................. 198,851 -- 198,851
Acquisition of proved properties............. 883,475 3,059,468 3,942,943
---------- ---------- ----------
Total costs incurred....................... $1,359,774 $3,059,468 $4,419,242
========== ========== ==========
</TABLE>
Oil and gas depletion expense in 1993 and 1994 was $1,765,000 and
$1,906,203, or $2.34 and $1.94 per barrel of oil equivalent, respectively.
5. STATEMENT OF CASH FLOWS
Following is certain supplemental information regarding cash flows for the
years ended December 31, 1993 and 1994 and the nine month periods ended
September 30, 1994 and 1995:
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
--------------------- ---------------------------
1993 1994 1994 1995
-------- -------- ----------- -----------
(UNAUDITED) (UNAUDITED)
<S> <C> <C> <C> <C>
Interest paid........................ $435,497 $462,639 $425,113 $754,421
======== ======== ======== ========
Income taxes paid.................... $ -- $ -- $ -- $ --
======== ======== ======== ========
</TABLE>
NON-CASH INVESTING AND FINANCING TRANSACTIONS:
Years ended December 31, 1993 and 1994
Oil and gas property with a purchase price of $231,204 was acquired in
February 1993 by an advance under the applicable production note payable.
F-13
<PAGE> 78
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In April 1993, the Company made a final payment for the acquisition of a
subsidiary by issuing 40,000 shares of Common Stock valued at $70,000.
Proceeds in the form of a reduction of affiliate indebtedness ($237,500)
and trade payables ($125,000) were realized as partial consideration in
connection with the sale of producing oil and gas properties in June 1993.
Funding in the amount of $606,363 was provided by the seller in connection
with the acquisition of oil and gas properties in February 1994.
A note in the amount of $24,346, payable to the Company in eight monthly
installments, was received as consideration for the sale of vehicles, furniture
and equipment in March 1994.
Funding in the amount of $1,200,000 was provided by the seller in
connection with the acquisition of a refinery in June 1994.
Property deposits totaling $52,125 were used in partial settlement of oil
and gas property acquisitions which closed during the year ended December 31,
1994.
The Company issued 22,220 shares of Common Stock in December 1994 as
consideration for the acquisition of an oil and gas property at a cost of
$66,660.
Accrued interest in the amount of $58,085 was capitalized in connection
with the refurbishment of the refinery facility.
The Company incurred a charge to operations, and a credit to Stockholders'
Equity, in the amount of $115,756 resulting from the exercise of stock options
by a consultant during the year ended December 31, 1994.
Nine months ended September 30, 1995 (Unaudited)
In January 1995 the Company awarded 12,000 shares of Common Stock with a
fair market value of $25,500 to an employee.
The acquisition cost of oil and gas properties which were acquired in
September 1995 included an oil imbalance obligation in the amount of $932,700
which was assumed by the Company.
Cumulative foreign currency translation gains in the amount of $50,257 were
recorded during the nine months ended September 30, 1995.
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES
Accounts payable and accrued liabilities at December 31, 1993 and 1994 are
as follows:
<TABLE>
<CAPTION>
1993 1994
---------- ----------
<S> <C> <C>
Trade accounts payable.............................. $1,829,610 $2,153,567
Undistributed revenue payable....................... 481,925 238,269
Other accrued expenses.............................. 227,983 830,351
---------- ----------
Total..................................... $2,539,518 $3,222,187
========== ==========
</TABLE>
F-14
<PAGE> 79
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. INCOME TAXES
The components of income (loss) before income taxes for the years ended
December 31, 1993 and 1994 are as follows:
<TABLE>
<CAPTION>
1993 1994
--------- --------
<S> <C> <C>
U.S................................................... $(125,123) $734,396
Canada................................................ -- 158,718
--------- --------
Total....................................... $(125,123) $893,114
========= ========
</TABLE>
Components of income tax expense (benefit) for the years ended December 31,
1993 and 1994 are as follows:
<TABLE>
<CAPTION>
1993 1994
-------- --------
<S> <C> <C>
Current:
Federal.............................................. $ -- $ 19,300
State................................................ -- 25,700
Foreign.............................................. -- 84,000
-------- --------
-- 129,000
-------- --------
Deferred:
Federal.............................................. (37,000) 164,400
State................................................ -- 90,400
-------- --------
(37,000) 254,800
-------- --------
$(37,000) $383,800
======== ========
</TABLE>
The provision (benefit) for income taxes differs from the amount that would
result from applying the federal statutory rate for the years ended December 31,
1993 and 1994 as follows:
<TABLE>
<CAPTION>
1993 1994
----- ----
<S> <C> <C>
Expected tax provision (benefit)............................ (34.0)% 34.0%
State income taxes, net of federal benefit.................. -- 5.9
Effect of foreign earnings.................................. -- 3.4
Change in valuation allowance............................... -- (2.2)
Other....................................................... 4.4 1.9
----- ----
(29.6)% 43.0%
===== ====
</TABLE>
The tax effected temporary differences which give rise to the deferred tax
provision consist of the following:
<TABLE>
<CAPTION>
1993 1994
-------- ---------
<S> <C> <C>
Property and equipment................................ $(11,700) $ 569,600
Effect of state taxes................................. -- (39,500)
Net operating losses.................................. (34,300) (212,400)
Alternative minimum tax credits....................... -- (42,600)
Change in valuation allowance......................... -- (19,700)
Other................................................. 9,000 (600)
-------- ---------
$(37,000) $ 254,800
======== =========
</TABLE>
F-15
<PAGE> 80
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The components of the deferred income tax liability as of December 31 are
as follows:
<TABLE>
<CAPTION>
1993 1994
-------- ---------
<S> <C> <C>
Property and equipment................................ $(69,100) $(638,700)
State taxes........................................... -- 39,500
Net operating losses.................................. 34,300 246,700
Alternative minimum tax credits....................... 54,500 97,100
Other................................................. -- 600
------- ---------
19,700 (254,800)
Valuation allowance................................... (19,700) --
------- ---------
Net deferred income tax liability..................... $ -- $(254,800)
======= =========
</TABLE>
At December 31, 1994, the Company had net operating loss carryforwards for
federal and state purposes of approximately $670,000 and $190,000, respectively,
which begin expiring in 2008 and 1998. The Company also has alternative minimum
tax credit carryforwards for federal and state purposes of approximately $71,400
and $25,700, respectively. The credits carry over indefinitely and can be used
to offset future regular tax to the extent of current alternative minimum tax.
In general, section 382 of the Internal Revenue Code includes provisions
which limit the amount of net operating loss carryforwards and other tax
attributes that may be used annually in the event that a greater than 50%
ownership change (as defined) takes place in any three year period. As of
December 31, 1994, the Company had not experienced such a change for purposes of
section 382.
8. NOTE PAYABLE
The note payable at December 31, 1994 represents an obligation by the
Company's Canadian subsidiary, CRPL, which was incurred in connection with an
acquisition of oil and gas properties in February 1994. The obligation is
guaranteed by the Company's parent company and is collateralized by common stock
of that company. The note bears interest at the Canadian prime rate (8% at
December 31, 1994) plus 2%, and was due on December 31, 1994. The entire
indebtedness, including accrued interest, was paid in January 1995.
9. LONG-TERM DEBT
Long-term debt at December 31, 1993 and 1994 and September 30, 1995
consists of the following:
<TABLE>
<CAPTION>
SEPTEMBER 30,
1993 1994 1995
---------- ---------- -------------
(UNAUDITED)
<S> <C> <C> <C>
Revolving loan agreement with a bank.......... $6,315,000 $4,999,000 $10,700,000
Term loan agreement with a bank............... -- -- 4,700,000
Demand loan agreement with a bank............. -- 1,480,240 1,209,258
Promissory note............................... -- 1,200,000 1,200,000
Promissory notes-Capco........................ -- -- 2,221,900
---------- ---------- -----------
6,315,000 7,679,240 20,031,158
Less current portion.......................... 1,440,000 2,356,524 8,519,743
---------- ---------- -----------
$4,875,000 $5,322,716 $11,511,415
========== ========== ===========
</TABLE>
December 31, 1993 and 1994
In September 1993 the Company entered into a Revolving Loan Agreement
("Agreement") with Bank One, Texas, NA. The loan is subject to semi-annual
borrowing base redeterminations and revolves to June 1,
F-16
<PAGE> 81
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
1996, at which time it will be converted to a three-year term loan. Funds
advanced under the facility are collateralized by substantially all of the
Company's U.S. oil and gas producing properties and the common stock of its U.S.
subsidiaries and bear interest at the prime rate (8.5% at December 31, 1994)
plus 1%. The Company is charged a commitment fee equal to .5% of the available,
but not used, loan amount.
The initial authorized borrowing base was established at $7,500,000.
Effective January 1, 1995, the borrowing base was increased to $8,100,000. In
accordance with the terms of the Agreement, $1,575,000 is classified as
currently payable at December 31, 1994. The Agreement requires, among other
things, that the Company maintain at least a 1 to 1 working capital ratio,
stockholders' equity of $3,800,000 and adjusted quarterly net income equal to
8.3 percent of the quarter end loan balance, all as defined in the Agreement.
Additionally, the Company is restricted from paying dividends and advancing
funds to affiliates. The Company was in compliance with the terms of the
Agreement at December 31, 1994.
CRPL has a demand non-revolving bank loan with principal repayments of
$53,500 on the first day of every month. The loan bears interest at a variable
rate equal to the Canadian prime rate (8.0% at December 31, 1994) plus 1-3/4%
per annum. The loan is collateralized by the Company's Canadian oil and gas
producing properties, the common stock of CRPL and a guarantee from the
Company's parent company in the amount of $1,500,000. Effective March 1, 1995,
CRPL was granted an extension on its bank loan which allows CRPL to defer
principal repayments for March to May 1995. Terms of the loan agreement require
that, based on an annual engineering report, the discounted net present value of
the collateralized properties exceed 200% of the outstanding loan balance and
that estimated annual future net revenue exceed 175% of that period's debt
service. Although the bank can demand payment in full of the note at any time,
it has committed not to do so except in the event of a default.
The promissory note is due to the seller of an oil refining facility which
was acquired by the Company in June 1994. Payment of the note, which bears
interest at the prime rate in effect on the note anniversary date plus two
percent (9.25% at December 31, 1994), is due in annual installments of $300,000,
$450,000 and $450,000. The note is collateralized by a deed of trust on the
acquired assets.
Maturities of long term debt are as follows:
<TABLE>
<S> <C>
1995............................. $2,356,524
1996............................. 2,537,699
1997............................. 1,598,017
1998............................. 791,333
1999............................. 395,667
</TABLE>
September 30, 1995 (Unaudited)
The revolving loan ("Agreement") is subject to semi-annual borrowing base
redeterminations and revolves to June 1, 1997, at which time it will be
converted to a three year term loan. Effective September 29, 1995, the borrowing
base was increased from $10,200,000 to $10,700,000. On September 7, 1995, the
Agreement was amended to provide for a term loan ("Term Loan"), in addition to
the revolving loan, in the amount of $4,700,000, with a maturity date of October
1, 1996. Amounts outstanding under the Term Loan bear interest at the rate of
prime plus 1% through October 31, 1995, and prime plus 4% thereafter. Required
minimum monthly principal payments are equal to the greater of monthly cash flow
from the Company's Colombian properties, or $300,000. In accordance with the
terms of the Agreement, $7,100,000 of the revolving and term loans is classified
as currently payable at September 30, 1995. The Agreement, as amended, requires,
among other things, that the Company maintain at least a .75 to 1 working
capital ratio, stockholders' equity of $6,250,000, a ratio of cash flow to debt
service of not less than 1.25 to 1.0 and general and administrative expenses at
a level not greater than 20% of revenue, all as defined in the Agreement.
Additionally, the Company is restricted from paying dividends and advancing
funds in excess of specified
F-17
<PAGE> 82
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
limits to affiliates. For such time that funds remain outstanding under the Term
Loan, the repayment of all amounts outstanding under the Agreement are
guaranteed by Mr. Ilyas Chaudhary.
On September 21, 1995 the payment date for the principal payment of
$300,000 due on the $1.2 million promissory note was extended to November 15,
1995. Amounts outstanding under the note bear interest at the prime rate in
effect on the note anniversary date plus 1.75% (10.75% on September 30, 1995).
The promissory notes-Capco are due to the Company's parent company, Capco
Resources Ltd. and to Capco Resources, Inc., formerly wholly-owned by Capco
Resources Ltd. and now majority-owned by Capco Resources Ltd. Payment of the
notes, which bear interest at the current prime rate (8.75% at September 30,
1995) plus 1%, is due September 14, 2000. The loan proceeds were utilized by the
Company principally in connection with the acquisition of producing oil and gas
properties in Colombia. Prior to the completion of a debenture offering, which
is expected to close in December 1995, $600,000 of the loan amount due Capco
Resources Ltd. will be converted into 75,000 shares of the Company's Common
Stock. The maturity of the $1.5 million loan from Capco Resources, Inc., and the
$100,000 balance of the loan from Capco Resources Ltd. will, effective at the
closing of the Offering, be extended to April 1, 2006, and such loans will be
subordinated to the same extent the Debentures are subordinated.
10. RELATED PARTY TRANSACTIONS
Related party transactions are described as follows:
Included in accounts receivable at December 31, 1993 is $96,703, which
is due from an affiliated company.
In 1993 and 1994, the Company sold certain oil and gas producing
properties to an affiliated company for total consideration of $475,000 and
$20,630, respectively.
In 1993 and 1994, the Company charged its affiliates $45,000 and
$105,312, respectively, and was charged $110,000 in 1993 by affiliates for
reimbursement of certain general and administrative expenses.
In 1994, the Company charged its affiliates $24,800 for costs related
to property settlements.
In 1994, the Company's parent company and other affiliated companies
advanced $157,938 to the Company.
In 1994, the Company's Canadian subsidiary provided advances totaling
$176,719 to affiliated companies.
11. COMMON STOCK AND STOCK OPTIONS
December 31, 1993 and 1994
In 1993, the Company issued 136,000 shares of Common Stock for cash
consideration of $414,840. In 1994, the Company issued 200,000 shares of Common
Stock to an independent consultant upon exercise of nonqualified options for
cash consideration of $510,000. The Company incurred a charge to current period
operations of $115,756 in recognition of the compensation element of this
transaction.
In September 1992, the Company's stockholders approved an Incentive Stock
Option Plan and a Non-qualified Stock Option Plan, and reserved 500,000 and
250,000 shares, respectively, of unissued Common Stock for issuance under the
plans. The exercise price of each option shall be the fair market value of the
shares at the date of grant. The options may be exercised in cumulative annual
increments of 25%, beginning one year from the date of grant and expire five
years from the date of issue. No options have been granted under either Plan as
of December 31, 1994.
F-18
<PAGE> 83
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In 1993 and 1994, the Company issued options for 445,000 shares of Common
Stock to certain employees of the Company. These options, which are not covered
by the Incentive or Nonqualified Stock Option Plans, become exercisable ratably
over a period of five years from the date of issue. The exercise price of the
options is the fair market value of the shares at the date of grant and ranges
from $2.50 to $3.00. Options to acquire 30,000 shares were exercisable as of
December 31, 1994.
September 30, 1995 (Unaudited)
In January 1995, the Company awarded 12,000 shares of Common Stock to an
employee pursuant to the terms of an employment agreement. The cost of the stock
award, based on the stock's fair market value at the award date, was charged to
stockholders' equity and is amortized against earnings over the contract term.
In January 1995, the Company issued options for 100,000 shares of Common
Stock to the Company's Chief Executive Officer. These options, which are not
covered by the Incentive or Nonqualified Stock Option Plans, become exercisable
ratably over a period of five years from the date of issue. The exercise price
of the options is $3.00. No options were exercisable at September 30, 1995.
In July 1995, the Company cancelled its Incentive and Nonqualified Stock
Option Plans. No options were granted under either plan prior to its
cancellation.
During the nine month period ended September 30, 1995, the Company issued
options to an independent consultant for the purchase of 100,000 shares of the
Company's Common Stock. The options had an exercise price of $3.25 and were
exercisable for a period of one year, beginning January 2, 1995. Options to
acquire 58,333 shares of Common Stock were exercised during the nine month
period ended September 30, 1995. In July 1995, the consulting arrangement was
terminated and the balance of the options was canceled.
12. RETIREMENT PLAN
The Company sponsors a defined contribution retirement savings plan
("401(k) Plan") for its U.S. employees. The Company currently provides matching
contributions equal to 50% of each employee's contribution, subject to a maximum
of 4% of employee earnings. The Company's contributions to the 401(k) Plan were
$2,245 in 1993 and $3,245 in 1994.
13. COMMITMENTS AND CONTINGENCIES
Contingencies
The Company is subject to extensive Federal, state, local and foreign
environmental laws and regulations. These laws, which are constantly changing,
regulate the discharge of materials into the environment. The Company believes
that it is in substantial compliance with existing laws and regulations.
The Company has a significant contingent liability in connection with the
plugging and abandonment ("P&A") of approximately 225 wells on certain
California property acquired by the Company during 1993. The Company acquired
the mineral rights and fee title to the property. The Company intends to operate
the producing wells on the property as long as economically feasible and will
decide in the future regarding the ultimate disposition of the land. If the
Company chooses to sell the property, it may decide to sell the land "as is" or
incur the P&A costs, thus enhancing the property's value. The Company estimates
that the P&A costs will range from $20,000 to $25,000 per well, for a total of
$4,500,000 to $5,625,000. Management believes that the fair market value of this
land, after restoration, will exceed the estimated P&A costs.
The Company is a defendant in various legal proceedings and claims which
arise in the normal course of business. Based on discussions with legal counsel,
management does not believe that the ultimate resolution of such actions will
have a significant effect on the Company's financial statements or operations.
F-19
<PAGE> 84
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Leases
The Company leases office space, vehicles and office equipment under
non-cancelable operating leases expiring in the years 1995 through 2000. Future
minimum lease payments under all leases are as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31,
------------
<S> <C>
1995......................... $158,913
1996......................... 144,122
1997......................... 133,751
1998......................... 89,718
1999......................... 4,089
Remaining years.............. 167
--------
$530,760
========
</TABLE>
Rent expense amounted to $93,636 and $92,349 for the years ended December
31, 1993 and 1994, respectively.
Concentration of Credit Risk
The Company invests its cash primarily in deposits with major banks.
Certain deposits may, at times, be in excess of federally insured limits
($483,259 at December 31, 1994). The Company has not incurred losses related to
such cash balances.
The Company's accounts receivable result from its activities in the oil and
gas industry. Concentrations of credit risk with respect to trade receivables
are limited due to the large number of joint interest partners comprising the
Company's customer base. Ongoing credit evaluations of the financial condition
of joint interest partners are performed and, generally, no collateral is
required. The Company maintains reserves for potential credit losses and such
losses have not exceeded management's expectations. Included in accounts
receivable at December 31, 1993 and 1994 is $829,198 and $727,461, respectively,
which is due from an unaffiliated third party, who is both an operator of
property in which the Company is a joint owner and a joint owner of property
operated by the Company.
September 30, 1995 (Unaudited)
The Colombian Ministry of the Environment issued a resolution dated June 7,
1995 that set forth a number of measures aimed at correcting certain
deficiencies that the Ministry has allegedly found in environmental aspects of
the Teca and Nare fields. Among such measures, the Ministry ordered the
temporary closing of one of five production modules and of any wells processed
in that module until Texas Petroleum Company, the former owner and operator of
the properties, provided a document detailing the timetable to implement some of
the measures described above. This temporary closing of the module has not had a
substantial effect on total production because substantially all of the crude
oil which would otherwise have been processed in the closed module has been
directed to other production modules. The resolution also ordered the opening of
an environmental investigation of Texas Petroleum Company's operation of the
Teca and Nare fields. The document containing the requested timetable was
presented to the Ministry of the Environment on July 6, 1995. On August 8, 1995
the Ministry of the Environment requested certain revisions to the timetable.
Texas Petroleum Company, the previous owner of the property, estimated that
the cost of compliance with the resolution would not exceed $250,000. Texas
Petroleum Company formally appealed the resolution and the Company is currently
awaiting a response from the Ministry of the Environment.
F-20
<PAGE> 85
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
In connection with the acquisition of the Teca and Nare fields, the Company
is required to pledge collateral consisting of either a $1.75 million
certificate of deposit or a commitment of $1.75 million against the Company's
borrowing base under its bank credit facility to the operator of the fields to
secure payments due third party vendors at the Teca and Nare fields.
14. BUSINESS SEGMENTS AND MAJOR CUSTOMERS
The Company considers that its operations are principally in one industry
segment, that of acquisition, exploration, development and production of oil and
gas reserves. For a summary of the Company's operations by geographic area, see
Note 2.
Sales to major unaffiliated customers (customers accounting for 10 percent
or more of gross revenue), all representing purchasers of oil and gas, for each
of the years ended December 31, 1993 and 1994, are as follows:
<TABLE>
<CAPTION>
1993 1994
---------- ----------
<S> <C> <C>
Customer A.......................................... $2,107,000 $3,713,000
========== ==========
Customer B.......................................... $1,641,000 $2,198,000
========== ==========
</TABLE>
15. SUBSEQUENT EVENTS (UNAUDITED)
In January 1995, the Company acquired certain oil and gas interests in
Colombia, South America, at a cost of $1,250,000. The purchase price was funded
from proceeds available under the Company's revolving line of credit. The
acquisition represents a 25% interest in an area encompassing 3,800 gross (950.0
net) acres, and includes 82 active wells, 61 of which are oil producers. Proved
reserves, net to the Company's interest and estimated by the property's operator
at the time of acquisition, are approximately 2,971,000 barrels of oil.
In October 1995, the Company consummated a reverse merger transaction,
effective April 1, 1995, with an unaffiliated third party, by which CRPL was
merged with the third party. All of the outstanding shares of CRPL were
exchanged for 13,437,322 shares of common stock of the third party. In addition,
the Company will subscribe for 1,000,000 shares of the common stock of the third
party at an approximate cost of $350,000, which subscription is expected to
close in the first quarter of 1996. As a result of these transactions, the
Company will own approximately 70% of the issued and outstanding shares of
common stock of the third party. The merger was effected to expand the funding
alternatives available to CRPL for future acquisition and development
activities.
In October 1995, the Company borrowed $250,000 from Unico, Inc., a company
controlled by a director of the Company, which indebtedness bears interest at
10% per annum and matures April 15, 1996.
F-21
<PAGE> 86
SABA PETROLEUM COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Estimated Proved Reserves
Estimates of the Company's proved developed and undeveloped oil and gas
reserves for its working and royalty interest wells were prepared by independent
engineers. The estimates are based upon engineering principles generally
accepted in the petroleum industry and take into account the effect of past
performance and existing economic conditions. Reserve estimates vary from year
to year because they are based upon judgmental factors involved in interpreting
and analyzing production performance, geological and engineering data and
changes in prices, operating costs and other economic, regulatory, and operating
conditions. Changes in such factors can have a significant impact on the
estimated future recoverable reserves and estimated future net revenue by
changing the economic lives of the properties. Proved undeveloped oil and gas
reserves include only those reserves which are expected to be recovered on
undrilled acreage from new wells which are reasonably certain of production when
drilled, or from presently existing wells which could require relatively major
expenditures to effect recompletion.
Presented below is a summary of proved reserves of the Company's oil and
gas properties:
YEAR ENDED DECEMBER 31, 1993 (United States only)
<TABLE>
<CAPTION>
OIL GAS
(BBLS) (MCF)
--------- ----------
<S> <C> <C>
Proved reserves:
Beginning of year.......................................... 2,708,473 8,044,348
Acquisition, exploration and development of minerals in
place................................................... 1,504,430 1,749,969
Revisions of previous estimates............................ (310,405) (695,728)
Production................................................. (572,783) (1,096,294)
Sales of minerals in place................................. (277,696) (989,633)
--------- ----------
End of year................................................ 3,052,019 7,012,662
========= ==========
Proved developed reserves, end of year....................... 2,998,618 6,982,419
========= ==========
</TABLE>
YEAR ENDED DECEMBER 31, 1994
<TABLE>
<CAPTION>
UNITED
STATES CANADA TOTAL
--------- -------- ---------
<S> <C> <C> <C>
Oil (Barrels)
Proved reserves:
Beginning of year.............................. 3,052,019 -- 3,052,019
Acquisition, exploration and development of
minerals in place........................... 1,095,717 544,337 1,640,054
Revisions of previous estimates................ 3,307,387 -- 3,307,387
Production..................................... (658,016) (79,947) (737,963)
Sales of minerals in place..................... (125,766) -- (125,766)
--------- ------- ---------
End of year.................................... 6,671,341 464,390 7,135,731
========= ======= =========
Proved developed reserves, end of year........... 4,530,148 464,390 4,994,538
========= ======= =========
</TABLE>
F-22
<PAGE> 87
SABA PETROLEUM COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
<TABLE>
<CAPTION>
UNITED
STATES CANADA TOTAL
--------- --------- ----------
<S> <C> <C> <C>
Gas (Thousands of cubic feet)
Proved reserves:
Beginning of year.............................. 7,012,662 -- 7,012,662
Acquisition, exploration and development of
minerals in place........................... 497,684 3,038,952 3,536,636
Revisions of previous estimates................ 765,069 -- 765,069
Production..................................... (979,893) (473,152) (1,453,045)
Sales of minerals in place..................... (69,549) -- (69,549)
--------- --------- ----------
End of year.................................... 7,225,973 2,565,800 9,791,773
========= ========= ==========
Proved developed reserves, end of year........... 6,582,511 1,920,800 8,503,311
========= ========= ==========
</TABLE>
Standardized Measure of Discounted Future Net Cash Flows and
Changes Therein Relating to Proved Oil and Gas Reserves
The following information has been prepared in accordance with Statement of
Financial Accounting Standards No. 69, which requires the standardized measure
of discounted future net cash flows to be based on sales prices, costs and
statutory income tax rates in effect at the time the projections are made and a
10 percent per year discount rate. The projections should not be viewed as
estimates of future cash flows nor should the "standardized measure" be
interpreted as representing current value to the Company.
<TABLE>
<CAPTION>
1993 1994
------------ ---------------------------------
(UNITED UNITED
STATES ONLY) STATES CANADA TOTAL
------------ -------- ------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Future cash inflows..................... $ 44,384 $ 92,859 $ 8,821 $101,680
Future production costs................. (25,532) (49,915) (5,657) (55,572)
Future development costs................ (1,081) (5,757) (185) (5,942)
Future income tax expenses.............. (3,638) (8,455) -- (8,455)
-------- -------- ------- --------
Future net cash flows................... 14,133 28,732 2,979 31,711
10 percent annual discount for estimated
timing of cash flows.................. (3,288) (9,953) (631) (10,584)
-------- -------- ------- --------
Standardized measure of discounted
future net cash flows................. $ 10,845 $ 18,779 $ 2,348 $ 21,127
======== ======== ======= ========
</TABLE>
F-23
<PAGE> 88
SABA PETROLEUM COMPANY AND SUBSIDIARIES
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED) (CONTINUED)
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows during 1993 and 1994.
<TABLE>
<CAPTION>
1993 1994
------------ --------------------------------
(UNITED UNITED
STATES ONLY) STATES CANADA TOTAL
------------ ------- ------ -------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Balance at beginning of year............ $14,110 $10,845 $ -- $10,845
Acquisitions, discoveries and
extensions............................ 3,283 4,066 3,290 7,356
Sales and transfers of oil and gas
produced, net of production costs..... (4,273) (3,681) (942) (4,623)
Changes in estimated future development
costs................................. 63 (3,393) -- (3,393)
Net changes in prices, net of production
costs................................. (4,636) 1,908 -- 1,908
Sales of reserves in place.............. (1,101) (363) -- (363)
Development costs incurred during the
period................................ -- -- -- --
Changes in production rates and other... (172) (191) -- (191)
Revisions of previous quantity
estimates............................. (1,607) 12,235 -- 12,235
Accretion of discount................... 1,849 1,190 -- 1,190
Net change in income taxes.............. 3,329 (3,837) -- (3,837)
------- ------- ------ -------
Balance at end of year.................. $10,845 $18,779 $2,348 $21,127
======= ======= ====== =======
</TABLE>
F-24
<PAGE> 89
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Saba Petroleum Company
We have audited the accompanying historical summaries of gross revenues and
direct operating expenses of the TNC Fields for each of the two years in the
period ended December 31, 1994. These historical summaries are the
responsibility of the management of Texas Petroleum Company. Our responsibility
is to express an opinion on the historical summaries based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the historical summaries
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the historical summaries. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of
the historical summaries. We believe that our audits provide a reasonable basis
for our opinion.
The accompanying historical summaries were prepared for the purpose of
complying with the rules and regulations of the U.S. Securities and Exchange
Commission (for inclusion in Saba Petroleum Company's registration statement on
Form SB-2) and are not intended to be a complete presentation of the revenues
and expenses of the TNC Fields. They exclude certain material expenses,
described in Note 1, that were incurred in connection with the operations of the
properties.
In our opinion, the historical summaries referred to in the first paragraph
(prepared on the basis described in Note 1) present fairly, in all material
respects, the gross revenues and direct operating expenses of the TNC Fields for
each of the two years in the period ended December 31, 1994 in conformity with
generally accepted accounting principles.
COOPERS & LYBRAND
Santafe de Bogota, Colombia
July 7, 1995
F-25
<PAGE> 90
THE TNC FIELDS
HISTORICAL SUMMARIES OF GROSS REVENUES
AND DIRECT OPERATING EXPENSES
(EXPRESSED IN US DOLLARS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS
--------------------------- ENDED
1993 1994 SEPTEMBER 30, 1995
----------- ----------- ------------------
(UNAUDITED)
<S> <C> <C> <C>
Gross revenues:
Sales of oil.................................. $11,487,853 $ 9,935,207 $ 8,871,288
Pipeline revenues............................. 2,004,916 1,580,448 1,516,876
----------- ----------- ----------
Total gross revenues.................. 13,492,769 11,515,655 10,388,164
----------- ----------- ----------
Direct operating expenses:
Operating expenses(1)......................... 2,779,143 3,138,646 2,537,423
Pipeline operating expenses(1)................ 1,353,710 1,480,534 990,054
Production and other taxes(2)................. 539,139 627,835 474,211
Loss on sale of fixed assets.................. 58,553 -- --
----------- ----------- ----------
Total direct operating expenses....... 4,730,545 5,247,015 4,001,688
----------- ----------- ----------
Excess of gross revenues over direct
operating expenses.................. $ 8,762,224 $ 6,268,640 $ 6,386,476
=========== =========== ==========
</TABLE>
- ---------------
(1) Excludes depreciation, depletion and amortization expenses.
(2) Includes war and pipeline transportation taxes; does not include provision
for income taxes.
The accompanying notes are an integral part of these historical summaries.
F-26
<PAGE> 91
THE TNC FIELDS
NOTES TO HISTORICAL SUMMARIES OF GROSS REVENUES
AND DIRECT OPERATING EXPENSES
1. BASIS OF PRESENTATION
Sabacol, Inc., a wholly-owned subsidiary of Saba Petroleum Company, has
entered into an agreement with Texas Petroleum Company, a subsidiary of Texaco
Inc. ("Texaco"), to acquire a 25% interest in the Teca and Nare oil fields and a
50% interest in the Cocorna oil field and the Velasquez-Galan pipeline. All of
these properties are located in Colombia, South America and are collectively
referred to as "the TNC Fields." The pipeline transports crude oil from these
fields to a refinery at Barrancabermeja, Colombia, owned by Empresa Colombiana
de Petroleos ("Ecopetrol"), which is owned by the Colombian government. Prior to
the acquisitions, the TNC Fields have been included in the consolidated
financial statements of Texaco Inc. and were not accounted for as a separate
entity. The Cocorna Concession expires in 1997 and the Teca and Nare Association
contracts expire in the year 2008, at which time they revert to Ecopetrol.
The accompanying historical summaries include only the gross revenues and
direct operating expenses attributable to the production, sale and
transportation of hydrocarbons from the acquired interests in the TNC Fields.
The historical summaries do not include certain material expenses that were
incurred in connection with the operations of the properties and that were
recorded in the Texaco financial statements. Those expenses were not included
because the information was not obtainable as Texaco did not allocate such
expenses to individual properties. Items excluded are depreciation, depletion
and amortization, provisions for dismantlement, abandonment and restoration of
wells, interest expense which may have been incurred for any debt directly or
indirectly associated with the TNC Fields, provision for pensions, allocated
income taxes, exploration and technical support, engineering, land, materials
support, accounting, legal, marketing and other general and administrative
costs.
The 1994 historical summary of gross revenues and direct operating expenses
does not include 186,092 barrels of crude oil valued at US $1,994,868 invoiced
by Texas Petroleum Company during 1994, but related to an imbalance obligation
to Ecopetrol (see Note 4).
Revenue Recognition
Sales of oil are recorded when oil is delivered to the refinery and
invoiced to Ecopetrol. Pipeline revenues are recognized when oil is received at
the pump station. Of the sales 75% are invoiced in US dollars and the remaining
25% in Colombian pesos, which is determined based on the market representative
exchange rate in effect at the date of each delivery.
Foreign Currency Translation
Expenses originated in Colombian pesos are translated into US dollars at
the average market representative exchange rate of Col. Ps. 788.87 per US $1 for
1993 and Col. Ps. 827.24 per US $1 for 1994. Unaudited: The exchange rate for
the nine months ended September 30, 1995 was Col. Ps. 871.29 per US $1.
Interim Financial Information (Unaudited)
The historical summary of gross revenues and direct operating expenses for
the nine months ended September 30, 1995 is unaudited but includes all
adjustments (consisting of normal recurring accruals only) which management
considers necessary to present fairly the gross revenues and direct operating
expenses of the TNC Fields for the nine months ended September 30, 1995.
F-27
<PAGE> 92
THE TNC FIELDS
NOTES TO HISTORICAL SUMMARIES OF GROSS REVENUES
AND DIRECT OPERATING EXPENSES (CONTINUED)
2. SALES PRICE CALCULATION
Sale of Oil
The price of crude oil is determined based on Platt's Oilgram Price Report,
considering the price basket of fuels -- Fuel Oil Gulf Coast 3% and Ecopetrol
Fuel Oil for Exportation -- (Basket A), and the price basket for international
crude oil -- Maya, Mandji and Isthmus crudes -- (Basket B).
For the Teca and Nare Association contracts the price is calculated by
taking the prior monthly average of Basket A and B prices, after adjusting the
Basket B price for API grades and sulfur content. The resulting price is reduced
by US $1.45 per barrel. This procedure has been agreed to up to December 31,
1995.
For the Cocorna Concession contract the price is the weighted average of
the prices obtained from the following procedures:
- A fixed price for the basic production, as agreed to between the
Ministry of Mines and Energy, Ecopetrol and Texas Petroleum
Company.
- For incremental production (barrels produced in excess of the basic
production agreed to), the average price from the following: a) The
prior quarter average of Basket A and B prices, after adjusting the
Basket B price for API grades and sulfur content, and b) the
average adjusted international price of the crude oil from the
Velasquez and Tisquirama (Distrito Magdalena) fields.
The above mentioned adjustment reduces the price of Cocorna Concession
crude oil to approximately 50% of market price.
Crude Oil Transportation
For crude oil transportation of others, the price set forth by the
Colombian Ministry of Mines and Energy was US $0.77 per barrel. By agreement
with Ecopetrol dated August 14, 1993, the transportation fee was negotiated at
US $0.50 per barrel (for Ecopetrol's oil from the Teca, Nare and Cocorna
fields).
Beginning February 10, 1995, the price for the transportation of crude oil
of others through pipelines was increased to US $0.82 per barrel. The price for
the transportation of Ecopetrol's crude oil has not changed.
3. ROYALTIES
Royalties on the sale of crude oil from the Teca and Nare fields are 20% of
the production. The Cocorna Concession is subject to a royalty interest of
7.59%.
4. IMBALANCE OBLIGATION TO ECOPETROL
During 1994, 253,650 barrels valued at US $2,814,572 were invoiced by Texas
Petroleum Company in connection with an imbalance obligation to Ecopetrol. As of
December 31, 1994, 67,558 barrels valued at US $819,704 had been returned.
September 30, 1995 (Unaudited)
During the nine months ended September 30, 1995, 93,836 barrels valued at
US $1,261,686 were returned to Ecopetrol in connection with the imbalance
obligation. As of September 30, 1995, the imbalance obligation to Ecopetrol had
been reduced to 92,256 barrels.
F-28
<PAGE> 93
THE TNC FIELDS
NOTES TO HISTORICAL SUMMARIES OF GROSS REVENUES
AND DIRECT OPERATING EXPENSES (CONTINUED)
5. TRANSPORTATION TAX
In the third quarter of 1994, a new transportation tax of 6% of the tariff
invoiced for barrels transported through the pipeline was enacted. The amount of
transportation tax incurred in 1994 was US $49,067.
6. SUBSEQUENT EVENTS (UNAUDITED)
War Tax
As of July 1, 1995, the war tax applied to produced barrels was increased
from Col. Ps. 500 (approximately US $0.60) to Col. Ps. 700 (approximately
US $0.80).
Environmental Compliance
The Colombian Ministry of the Environment issued a resolution dated June 7,
1995 that set forth a number of measures aimed at correcting certain
deficiencies that the Ministry has allegedly found in environmental aspects of
the TNC Fields. Among such measures, the Ministry ordered the temporary closing
of one of five production modules and of any wells processed in that module
until Texas Petroleum Company provided a document detailing the timetable to
implement some of the measures described above. This temporary closing of the
module has not had a substantial effect on total production because
substantially all of the crude oil which would otherwise have been processed in
the closed module has been directed to other production modules. The resolution
also ordered the opening of an environmental investigation of Texas Petroleum
Company's operation of the TNC Fields. The document containing the requested
timetable was presented to the Ministry of the Environment on July 6, 1995. On
August 8, 1995, Texas Petroleum Company received a communication from the
Ministry of the Environment requesting certain revisions to the timetable.
Texas Petroleum Company estimated that the cost of compliance with the
resolution will not exceed US $250,000. Texas Petroleum Company has formally
appealed the resolution and is currently awaiting a response from the Ministry
of the Environment.
September 30, 1995
Sabacol, Inc. completed the acquisition of a 25% interest in the Teca and
Nare oil fields and a 50% interest in the Velasquez-Galan pipeline on September
12, 1995, and expects to complete the acquisition of the 50% interest in the
Cocorna oil field prior to the end of 1995. Texas Petroleum Company continued as
the operator of the Teca and Nare oil fields and the Velasquez-Galan pipeline
through October 4, 1995 and will continue as the operator of the Cocorna oil
field through the completion of the acquisition of that property. Omimex de
Colombia, Ltd., a joint-interest owner in the TNC Fields, will succeed Texas
Petroleum Company as the operator of the TNC Fields.
F-29
<PAGE> 94
THE TNC FIELDS
SUPPLEMENTAL INFORMATION ABOUT OIL AND GAS
PRODUCING ACTIVITIES (UNAUDITED)
Information with respect to oil and gas producing activities is presented
in the following tables. Reserve information is based on reserve reports and
other information prepared by independent petroleum engineers. The information
presented for the years 1993 and 1994 is based on a January 1, 1995 reserve
report, which has been adjusted for production in the years 1993 and 1994.
The following table sets forth the TNC Fields' proved oil reserves (all
located in Colombia, South America) at December 31, 1993 and 1994 and the
related changes in such reserves for each of the two years in the period ended
December 31, 1994.
<TABLE>
<CAPTION>
CRUDE OIL (MBBLS)
-----------------
1993 1994
------ ------
<S> <C> <C>
Proved reserves at beginning of year....................... 7,443 6,335
Decreases due to production................................ (1,108) (1,033)
------ ------
Proved reserves at end of year............................. 6,335 5,302
====== ======
Proved developed reserves at end of year................... 6,335 5,302
====== ======
</TABLE>
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS (DOLLARS IN THOUSANDS)
The following information has been prepared in accordance with Statement of
Financial Accounting Standards No. 69, which requires the standardized measure
of discounted future net cash flows to be based on sales prices, costs and
statutory income tax rates in effect at the time the projections are made and a
10 percent per year discount rate. The projections should not be viewed as
estimates of future cash flows nor should the "standardized measure" be
interpreted as representing current value of the TNC Fields.
<TABLE>
<CAPTION>
1993 1994
-------- --------
<S> <C> <C>
Future cash inflows.................................... $ 75,138 $ 65,203
Future production and development costs................ (40,418) (36,652)
Future income tax expenses............................. (9,951) (8,071)
-------- --------
Future net cash flows................................ 24,769 20,480
Discount at 10% for timing of cash flows............... (5,998) (4,363)
-------- --------
Standardized measure of discounted future net cash
flows................................................ $ 18,771 $ 16,117
======== ========
</TABLE>
The following table sets forth the changes in the standardized measure of
discounted future net cash flows for each of the two years in the period ended
December 31, 1994:
<TABLE>
<CAPTION>
1993 1994
------- -------
<S> <C> <C>
Balance at beginning of year............................. $22,297 $18,771
Increase (decrease) due to:
Sales and transfers of oil and gas produced,
net of production costs............................. (8,170) (6,169)
Accretion of discount.................................. 2,723 2,278
Net change in income taxes............................. 1,921 1,237
------- -------
Balance at end of year................................... $18,771 $16,117
======= =======
</TABLE>
F-30
<PAGE> 95
[ARTWORK]
<PAGE> 96
- ------------------------------------------------------
- ------------------------------------------------------
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS IN CONNECTION WITH THIS OFFERING
OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR MADE, SUCH
INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN AUTHORIZED
BY THE COMPANY OR ANY UNDERWRITER. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER
TO SELL, OR A SOLICITATION OF ANY OFFER TO BUY, ANY SECURITIES OTHER THAN THE
REGISTERED SECURITIES TO WHICH IT RELATES OR AN OFFER TO, OR A SOLICITATION OF,
ANY PERSON IN ANY JURISDICTION WHERE SUCH AN OFFER OR SOLICITATION WOULD BE
UNLAWFUL. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER
SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO
CHANGE IN THE AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE
INFORMATION CONTAINED HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE
HEREOF.
UNTIL JANUARY 14, 1996 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS), ALL
DEALERS EFFECTING TRANSACTIONS IN THE REGISTERED SECURITIES, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS DELIVERY REQUIREMENT IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER
A PROSPECTUS WHEN ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD
ALLOTMENTS OR SUBSCRIPTIONS.
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
Prospectus Summary.................... 3
Risk Factors.......................... 10
Use of Proceeds....................... 19
Capitalization........................ 19
Common Stock Price Range and
Dividend Policy..................... 20
Selected Consolidated Financial
Data................................ 21
Selected Oil and Gas Data............. 22
Management's Discussion and Analysis
of Financial Condition and Results
of Operations....................... 23
Business.............................. 31
Management............................ 39
Principal Stockholders................ 43
Description of the Debentures......... 44
Description of Capital Stock.......... 59
Shares Eligible for Future Sale....... 60
Underwriting.......................... 61
Certain Legal Matters................. 62
Experts............................... 62
Available Information................. 63
Glossary.............................. 63
Index to Financial Statements......... F-1
</TABLE>
- ------------------------------------------------------
- ------------------------------------------------------
- ------------------------------------------------------
- ------------------------------------------------------
$11,000,000
SABA PETROLEUM
COMPANY
9% CONVERTIBLE SENIOR SUBORDINATED
DEBENTURES DUE 2005
LOGO
------------------------
PROSPECTUS
------------------------
VAN KASPER & COMPANY
DECEMBER 20, 1995
- ------------------------------------------------------
- ------------------------------------------------------
