[GIBSON, DUNN & CRUTCHER LETTERHEAD]
January 26, 1998
(303) 298-5775 C 88610-00003
VIA EDGAR
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: Saba Petroleum Company. - Registration Statement on Form S-1
Ladies and Gentlemen:
On behalf of Saba Petroleum Company Group, Ltd., a Delaware corporation
(the "Company"), and in connection with the Registration Statement on Form S-1
(the "Registration Statement") under the Securities Act of 1933, as amended (the
"Securities Act"), covering the proposed offering of the Company's common stock,
par value $.001 per share (the "Common Stock"), please find enclosed the
Registration Statement, including exhibits thereto, which is being filed via
EDGAR. The amount of $4,347 was paid on January 20, 1998, by wire
transfer of which $4.288 should be applied as the fee for this Registration
Statement.
Any comments or questions concerning the Registration Statement should
be directed to the undersigned at (303) 298-5775 or, in my absence, to Richard
M. Russo at (303) 298-5715. Thank you in advance for your assistance in
processing the Registration Statement.
Very truly yours,
/s/ STEVE K. TALLEY
Steven K. Talley
for GIBSON, DUNN & CRUTCHER LLP
Enclosures
cc: Richard M. Russo, Esq.
Rodney C. Hill, Esq.
As filed with the Securities and Exchange Commission on January 26, 1998
Registration No. 333-
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
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SABA PETROLEUM COMPANY
(Name of registrant in its charter)
Delaware 1311 47-0617589
(State or Other Jurisdiction of (Primary Standard Industrial (I.R.S. Employer
Incorporation or Organization) Classification Code Number) Identification No.)
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3201 Airpark Drive, Suite 201
Santa Maria, California 93455
(805) 347-8700
(Address and Telephone Number of
Principal Executive Offices and Principal Place of Business)
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Rodney C. Hill, Esq.
Saba Petroleum Company
3201 Airpark Drive, Suite 201
Santa Maria, California 93455
(805) 347-8700
(Name, Address and Telephone Number of Agent for Service)
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With copies to:
RICHARD M. RUSSO, ESQ.
Gibson, Dunn & Crutcher LLP
1801 California Street, Suite 4100
Denver, Colorado 80202
(303) 298-5700
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Approximate date of
commencement of proposed sale to the public:
As soon as practicable after
this Registration Statement becomes effective.
If any of the securities being registered on this form are to be
offered on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933, check the following box. |X|
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. |_|
If this Form is a post-effective amendment filed pursuant to Rule
462(c) under the Securities Act, check the following box and list the Securities
Act registration statement number of the earlier effective registration
statement for the same offering. |_|
If delivery of the prospectus is expected to be made pursuant to Rule
434, please check the following box. |_|
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CALCULATION OF REGISTRATION FEE
Proposed Proposed Maximum
Maximum Offering Aggregate
Title of Each Class of Securities Amount to be Price Offering Price (2) Amount of
to be Registered Registered (1) Per Share (2) Registration Fee
Common Stock.............................. 2,153,344 $6.75 $14,535,072 $4,288
(1) Shares of Common Stock which may be offered pursuant to this
Registration Statement consists of shares issuable upon conversion of
10,000 shares of Series A Convertible Preferred Stock and exercise of
the Warrants and the Redemption Warrants as defined herein. The Company
is registering approximately 150% of the number of shares of Common
Stock issuable in
connection with the conversion of the Company's Series A Convertible
Preferred Stock (based on a conversion price of $6 3/4 which is the
average of the closing bid prices of the Common Stock reported on the
American Stock Exchange for the 3 trading days ending January 23, 1998)
and exercise of the Warrants. In addition to the shares set forth in
the table, the amount to be registered includes an indeterminate number
of shares issuable upon conversion of or in respect of the Series A
Convertible Preferred Stock and the Warrants, as such number may be
adjusted as a result of stock splits, stock dividends and antidilution
provisions (including floating rate conversion prices) in accordance
with Rule 416.
(2) Estimated solely for the purpose of calculating the registration fee
based on the average of the high and low reported sales prices per
share of the Company's Common Stock on the American Stock Exchange on
January 23, 1998.
------------------------------
The Registrant hereby amends this Registration Statement on such date or dates
as may be necessary to delay its effective date until the Registrant shall file
a further amendment which specifically states that this Registration Statement
shall thereafter become effective in accordance with Section 8(a) of the
Securities Act of 1933, as amended, or until the Registration Statement shall
become effective on such date as the Securities and Exchange Commission, acting
pursuant to Section 8(a), may determine.
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Information contained herein is subject to completion or amendment. A
registration statement relating to these securities has been filed with the
Securities and Exchange Commission. These securities may not be sold nor may
offers to buy be accepted prior to the time the registration statement becomes
effective. This Prospectus shall not constitute an offer to sell or the
solicitation of an offer to buy nor shall there be any sale of these securities
in any State in which such offer, solicitation or sale would be unlawful prior
to registration or qualification under the securities laws of any such State.
================================================================================
SUBJECT TO COMPLETION - DATED JANUARY 26, 1998
================================================================================
2,153,344 Shares
[Graphic omitted]
SABA PETROLEUM COMPANY
Common Stock
All
of the shares of Common Stock offered hereby (the "Offering") are being sold by
the selling stockholders identified herein (the "Selling Stockholders") of Saba
Petroleum Company ("Saba" or the "Company"). The Company's Common Stock (the
"Common Stock") is listed on the American Stock Exchange under the symbol "SAB."
On January 23, 1998, the last reported sale price of the Common Stock on the
American Stock Exchange was $6 7/8 per share. See "Price Range of Common Stock
and Dividend Policy. "The registration of the Shares of Common Stock
hereunder does not necessarily mean that any of the Shares will be offered and
sold by the holder thereof. See "Use of Proceeds."
The Selling Stockholders or their respective pledgees, donees, transferees,
or other successors in interest from time to time may offer and sell the
Shares held by them directly or through agents or broker-dealers on terms to be
determined at the time of sale. To the extent required, the names of any
agent or broker-dealer and applicable commissions or discounts and any other
required information with respect to any particular offer will be set forth
in an accompanying Prospectus Supplement. See "Plan of Distribution". The
Selling Stockholders reserve the right to accept or reject, in whole or in
part, any proposed purchase of the Shares to be made directly or through
agents.
The Selling Stockholders and any agents or broker-dealers that participate
with the Selling Stockholders in the distribution of Shares may be deemed to be
"underwriters" within the meaning of the Securities Act of 1933, as amended
(the "Securities Act"), and any commissions recieved by them and any profit on
the resale of the Shares may be deemed to be underwriting commissions or
discounts under the Securities Act.
The Company will not receive any of the proceeds from the sale of Shares
by the Selling Stockholders, but has agreed to bear certain expenses of
registration of the Shares under federal and state securities laws.
The Common Stock offered hereby involves a high degree of risk. See "Risk
Factors" beginning on page 9.
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THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES
AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION, NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
It is anticipated that the stock will sell for, at or near the prevailing market
rate. As of January 23, 1998, the market price on The American Stock Exchange
was $6 7/8. The Company will not receive any of the proceeds of the Offering.
The Company will bear all of the expenses of the Offering, which are expected to
be approximately $140,000.
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The date of this Prospectus is January , 1998.
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. The Registration
Statement, of which this Prospectus is a part, as well as 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 Commission
also maintains a worldwide web site (address: http://www.sec.gov) that contains
reports, proxy and information statements and other information regarding
registrants that file electronically with the Commission. The Common Stock is
listed on the American Stock Exchange and such reports and other information
concerning the Company also can be obtained at the offices of the American Stock
Exchange at 86 Trinity Place, New York, New York 10006-1881.
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements, including notes thereto, appearing
elsewhere in this Prospectus. References to "Saba" or the "Company" are to Saba
Petroleum Company and its subsidiaries unless the context otherwise requires.
All share information included herein has been adjusted to reflect a two-for-one
stock split in the form of a stock dividend paid in December 1996. Certain
terms, including several technical terms commonly used in the oil and gas
industry, are defined in the "Glossary" included as Appendix A to this
Prospectus. Investors should carefully consider the information set forth under
"Risk Factors." The principal executive offices of the Company are located at
3201 Airpark Drive, Suite 201, Santa Maria, California 93455, and the Company's
telephone number at this location is (805) 347-8700.
The Company
Saba Petroleum Company is an independent energy company engaged in the
acquisition, development and exploration of oil and gas properties in the United
States and internationally. The Company has grown primarily through the
acquisition and exploitation of producing properties in California and Colombia.
The Company has also recently initiated exploration projects which the Company
believes have high potential in California, Indonesia and Great Britain. The
Company has assembled a portfolio of over 200 potential development drilling
locations. Based on current drilling forecasts, the Company estimates that such
locations represent a five-year drilling inventory. The preponderance of those
drilling locations are in Colombia's Middle Magdalena Basin. The Company also
has drilling locations in California, New Mexico and Louisiana. The Company uses
advanced drilling and production technologies to enhance the returns from its
drilling programs. On its California properties, the Company has successfully
used horizontal drilling and high-efficiency cavitation pumps, and has recently
drilled its first steam assisted gravity drainage ("SAGD") pair of wells in
California, which is expected to commence operations in the first quarter of
1998.
At December 31, 1996, the Company had estimated proved reserves of 30.6
MMBOE, consisting of 26.7 MMBbls of oil and 23.6 Bcf of gas (3.9 MMBOE), with a
PV-10 Value of $155.9 million. Since quantities of oil and gas recoverable from
a property are price sensitive, the recent decline in oil prices may be expected
to result in a reduction of the quantities of oil and gas included in the
Company's proved reserves and the PV-10 value of such reserves. See "Properties
- - Reserve Estimates."
Principal Property Areas
The Company owned interests in approximately 1,800 wells at December 31,
1997. The majority of these wells are concentrated along the central coast of
California and in the Middle Magdalena Basin of Colombia. These regions, which
primarily produce a low gravity/high viscosity or "heavy" oil, will be the focus
of the Company's near-term development drilling activities. The Company also
operates wells and has exploration and development activities in several states
outside of California and, through a majority-owned subsidiary, in western
Canada. The Company regularly evaluates international projects and has recently
negotiated the acquisition of exploration projects in Indonesia and Great
Britain.
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United States
California
Approximately 41.2% of the Company's proved reserves at December 31, 1996
(12.6 MMBOE) were located in five onshore fields in California's central coast
region (collectively, the "Central Coast Fields"). Included in the reserve
estimates are approximately 5 MMBOE (90% undeveloped) which are attributable to
the Oxnard Field, an area in which the Company's interests are subject to
forfeiture if the Company does not pursue developmental operations during 1999.
Since the date of the reserve report, the Company has reduced its interest in
the Oxnard Field by 50%, which would result in a reduction of approximately 2.5
MMBOE. Daily production from the Central Coast fields averaged 1,771 BOE for the
nine months ended September 30, 1997, representing 25.8% of the Company's total
production. The Company operates all of its wells in the Central Coast (other
than Oxnard) Fields and maintains an average net revenue interest of 89.4% in
these wells. In late 1996, the Company began a multi-year drilling program to
complete development of the Central Coast Fields. At December 31, 1997, the
Company had drilled 15 and had completed 14 horizontal wells and a pair of SAGD
wells as part of this program. The Company also holds interests in other
California areas, including several high risk exploratory projects.
Other United States
In addition to its California properties, the Company owns producing
properties in a number of states, primarily Louisiana, New Mexico, Michigan,
Texas and Wyoming, which collectively represented approximately 16.1% of the
Company's PV-10 Value at December 31, 1996. At such date, these properties had
proved reserves of 2.9 MMBOE. Daily production from these properties averaged
1,318 BOE for the nine months ended September 30, 1997, representing 19.2% of
the Company's total production.
International
Colombia
Approximately 31.4% of the Company's proved reserves at December 31, 1996
(9.6 MMBOE) were located in several fields in Colombia's Middle Magdalena Basin.
Daily production from these fields averaged 2,438 BOE for the nine months ended
September 30, 1997, representing 35.5% of the Company's total production. The
Company also holds a 50% interest in the 118-mile Velasquez-Galan Pipeline,
which connects the fields to a 180,000 bopd government-owned refinery at
Barrancabermeja. The Company and Omimex, the operator of the fields, a private
company based in Forth Worth, Texas, have formulated a plan for drilling
approximately 200 development wells.
During 1997, the Company and the operator participated in the drilling or
recompletion of thirteen wells in the Teca (eight) and South Nare (five) Fields.
All of the wells drilled were productive and the operator is installing steaming
equipment. The Company and the operator have recently reentered a
suspended Texaco drilled well to an area under the Magdalena River and have
recompleted the well as productive of approximately 30 bopd without artificial
stimulation. Both the Company and the operator believe that another two wells
should be drilled into the area in an effort to establish an additional
commercial area. The Company expects to spend approximately $3 million in 1998
on drilling and related activities on its Colombia properties.
Canada
Approximately 8.8% of the Company's proved reserves at December 31, 1996
(2.7 MMBOE) were located in Canada. Daily production from these properties,
which are owned through an approximately 74%-owned subsidiary of the Company,
averaged 615 BOE for the nine months ended September 30, 1997, representing 9.0%
of the Company's total production.
Other International
In September 1997, the Company and Pertamina, the Indonesian state-owned oil
company, signed a production sharing contract covering 1.7 million unexplored
acres on the Island of Java near a number of producing oil and gas fields. This
agreement will require the Company to spend approximately $17 million over the
next three years on this project. The Company intends to seek a joint venture
partner to share the costs of this project during 1998.
In July 1997, the Company entered into an agreement to become the operator
and a 75% working interest holder of two exploration licenses which cover a
123,000 acre exploration area in southern Great Britain. The Company expects to
spend approximately $800,000 in 1998 to drill its first exploratory well in
Great Britain, but is seeking a partner to reduce its exposure to that project.
Summary Financial Data
The following tables, parts of which have been derived from the Company's
audited financial statements, set forth historical financial information for the
Company 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 financial data for the nine month periods ended
September 30, 1996 and 1997 was derived from the unaudited financial statements
of the Company and, in management's opinion, includes all adjustments
(consisting only of normal recurring adjustments except as set forth below)
necessary to present fairly the results for such periods. The results of
operations for such periods are not necessarily indicative of those that may be
expected for a full year, and none of the data presented below is necessarily
indicative of future results.
Nine Months Ended
Years Ended December 31, September 30,
1994 1995 1996 1996 1997
- ---------------------------------------------
(In thousands, except per share
amounts)
- --------------------------------------------
Statement of Operations Data
Total revenues.......................... $ 12,954 $ 17,694 $ 33,202 $ 23,153 $ 26,778
Expenses:
Production costs (1).................. 7,547 10,561 14,604 10,955 12,250
General and administrative............ 1,882 2,005 3,920 2,660 3,468
Depletion, depreciation and amortization 2,041 2,827 5,527 3,616 5,012
Operating income........................ 1,484 2,301 9,151 5,922 6,048
Other income (expense):
Interest expense...................... (634) (1,364) (2,402) (1,795) (1,421)
Gain on issuance of shares of subsidiary --- 125 8 6 6
Other................................. 43 (10) 207 229 (196)
Income before income taxes.............. 893 1,052 6,964 4,362 4,437
Provision for taxes on income........... 384 450 2,958 1,963 1,800
Minority interest in earnings of
consolidated subsidiary............... --- 55 241 178 90
Net income ............................. $ 509 $ 547 $ 3,765 $ 2,221 $ 2,547
Net earnings per share (2).............. $ 0.06 $ 0.06 $ 0.37 $ 0.24 $ 0.23
Weighted average common and common
equivalent shares outstanding (primary) 7,996 8,743 9,416 9,224 11,192
(2).......................................
Other Financial Data
EBITDA (3).............................. $ 3,568 $ 5,188 $ 14,652 $ 9,595 $ 10,780
Operating cash flow (4)................. 2,805 3,335 9659 - -
Capital expenditures.................... 6,573 17,015 12,776 5,408 29,080
=============================================
December 31, September 30,
1995 1996 1997
(In thousands)
Balance Sheet Data
Working capital (deficit).............. $ 2,471 $ 2,418 $ (17,266)
Total assets............................... 39,751 49,117 77,472
Current portion of long-term debt........... 505 1,806 18,088
Long-term debt, net (5)..................... 23,543 20,812 20,259
Stockholders' equity........................ 7,848 17,715 22,657
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(1) Production costs include production taxes.
(2) As adjusted for a two-for-one stock split in the form of a stock dividend
paid in December 1996.
(3) EBITDA represents earnings before interest expense, provision (benefit) for
taxes on income, depletion, depreciation and amortization. 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 and the
Notes thereto included elsewhere in this Prospectus.
(4) Operating cash flow represents net income plus deferred income tax expense
and depletion, depreciation and amortization. The Company does not
calculate operating cash flow for interim financial periods.
(5) For information on terms and interest, see Note 8 of Notes to Consolidated
Financial Statements of the Company.
Summary Oil and Gas Reserve Data
The following table sets forth certain summary information as of December
31, 1994, 1995 and 1996 regarding the Company's interests in estimated proved
oil and gas reserves, the Company's estimated future net revenues therefrom
(before income taxes), the PV-10 Value thereof and other data concerning the
reserves of the Company for those years. Estimates are based upon average
year-end prices of $11.60, $11.30 and $17.05 per BOE on December 31, 1994, 1995
and 1996, respectively, at each date holding prices constant throughout the life
of the properties in accordance with regulations of the Securities and Exchange
Commission (the "Commission"). This information is based upon numerous
assumptions and is subject to various uncertainties. See "Risk Factors -Factors
Relating to the Oil and Gas Industry and the Environment -- Uncertainty of
Estimates of Reserves and Future Net Revenues," "Business -- Oil and Gas
Reserves" and "Supplemental Information About Oil and Gas Producing Activities
(Unaudited)" following the Notes to the Consolidated Financial Statements of the
Company. This summary oil and gas reserve information is based on the reserve
reports of Netherland, Sewell & Associates, Inc. and Sproule Associates Limited,
independent petroleum engineers. There can be no assurance that volumes,
prices and costs
employed by the independent petroleum engineers will prove accurate. Since
December 31, 1996, oil and gas prices have generally declined. At such date the
price of West Texas Intermediate ("WTI") crude oil as quoted on the New York
Mercantile Exchange was $25.12 per Bbl and the comparable price at December 31,
1997 was $18.30. Quotations for the comparable periods for natural gas were
$4.22 per Mcf and $ 2.55 per Mcf, respectively. A decline in prices will result
in a reduction in volumes of oil or gas which are ultimately recoverable, since
remaining reserves will become marginal earlier.
December 31,
1994 1995 1996
Estimated Net Proved Reserves:
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Oil (MBbls)...................................... 7,136 12,531 26,679
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Gas (MMcf)....................................... 9,792 19,479 23,665
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Total (MBOE).................................. 8,768 15,778 30,623
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Estimated future net revenues (before income
taxes) $ 40,167 $ 73,525 $ 253,902
(in thousands)................................
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PV-10 Value (before income taxes) (in thousands). $ 26,014 $ 48,155 $ 155,939
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Reserve Replacement Data:
- ------------------------------------------------------
Production replacement ratio (2)................. 5.8x 5.9x 7.7x
All-in finding costs per BOE..................... $ 1.64 $ 2.02 $ 3.15
(1) Present value of estimated future net revenues before income taxes,
discounted at 10% per annum.
(2) Calculated by dividing (i) reserve additions through acquisitions of
reserves, extensions and discoveries and revisions during the year by
(ii) production for such year.
Summary Operating Data
The following table sets forth certain summary operating data with respect
to the Company's oil and gas operations for the periods indicated.
Nine Months Ended
Year Ended December 31, September 30,
1994 1995 1996 1996 1997
- ----------------------------------------------
Production Data:
- ----------------------------------------------
Oil (MBbls)............................... 738 1,227 1,968 1,455 1,581
- ----------------------------------------------
Gas (MMcf)................................ 1,453 1,337 1,651 1,184 1,767
Total (MBOE)......................... 980 1,450 2,243 1,652 1,875
Average Sales Price Data (Per Unit):
Oil (Bbls)...............................$ 13.08 $ 12.22 $ 14.45 $ $
13.77 13.81
Gas (Mcf)................................. 1.73 1.45 1.88 1.72 1.95
BOE....................................... 12.42 11.69 14.05 13.36 13.48
Selected Data per BOE:
Production costs (1).....................$ 7.70 $ 7.29 $ 6.51 $ 6.63 $ 6.53
General and administrative................ 1.91 1.38 1.75 1.60 1.77
Depletion, depreciation and amortization.. 2.08 1.94 2.46 2.19 2.67
(1) Production costs include production taxes.
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CAUTIONARY STATEMENT REGARDING FORWARD LOOKING INFORMATION
Certain statements contained in this Prospectus, such as those concerning
the Company's business strategy, governmental regulation, drilling programs,
potential acquisitions, future production amounts, values and revenues, capital
requirements and other statements regarding matters that are not historical
facts are "forward-looking" statements (as such term is defined in Section 27A
of the Securities Act of 1933, as amended (the "Securities Act") and Section 21E
of the Securities Exchange Act of 1934, as amended (the "Exchange Act")).
Statements that the Company or management "believes", "anticipates", "intends",
"plans", or that refer to future events are intended to identify the statements
which follow as "forward looking" statements. Because such forward looking
statements include risks and uncertainties, actual results may differ materially
from those expressed in or implied by such forward looking statements. Factors
that could cause actual results to differ materially include, but are not
limited to, those discussed herein under "Risk Factors," "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business." The Company undertakes no obligation to release publicly the results
of any revisions to those forward looking statements that may be made to reflect
events or circumstances after the date hereof or to reflect the occurrence of
unanticipated events.
RISK FACTORS
Prospective investors should read the entire Prospectus carefully and should
consider, among other things, the risk factors set forth below.
Factors Relating to the Company
Effect of Price Declines
Most of the oil produced by the Company is of low gravity. Production
costs of such oil are generally much higher than production costs of higher
gravity oil or gas. Consequently, heavy oil properties, such as those owned by
the Company, tend to become marginally economic in periods of declining oil
prices, such as that presently existing. This is true of the Company's
California heavy oil properties, which, at present prices remain economic to
produce; should prices continue to decline, much of the Company's California
production will become marginally economic.
During 1997, the Company embarked upon an aggressive development
program of its Cat Canyon and Gato Ridge heavy oil properties. This program
included the installation of surface facilities for handling much more oil than
the Company presently produces from such properties. The recent decline in
prices and the results of the 1997 drilling program render it doubtful that the
Company will recognize the value of these installations within the foreseeable
future.
Alteration of Business Strategy
During January 1998, the Company engaged CIBC-Oppenheimer, Inc. to
advise the Company with respect to strategies and procedures to adopt in an
effort to maximize shareholder values. One of the strategies which may be
adopted by the Company will be to sell or otherwise dispose of certain domestic
properties and to concentrate its domestic efforts on its California properties
and the acquisition of lighter oil and gas properties. In addition, it is
expected that the Company will devote a larger portion of its capital budget to
exploratory activities, both in California and internationally, than it has done
in the past. Whether the Company will be successful in pursuing such a strategy
is not known.
Near Term Cash Requirements
The Company is in a capital intensive industry. Its immediate needs for
capital will intensify should the Company be successful in one or more of the
exploratory projects it is undertaking, since some of those projects are in
areas where the oil and gas transportation and marketing infrastructure is not
well developed. Consequently, should one or more exploratory wells be
successful, it is likely that the Company will be required to drill several more
wells on the apposite property to demonstrate the existence of commercial
reserves before a transportation infrastructure will be justified. Major
exploratory projects often require substantial capital investments and a
significant amount of time before generating revenues.
The Company's principal credit facility requires that it make a payment
of $3 million in April 1998 and a minimum payment of $3 million in June 1998 in
addition to its scheduled monthly payments of principal and interest. The
Company's bank will prepare its own estimate of remaining reserves and cash
flow therefrom. Should that report not show estimated proven reserves in
quantities and estimated income levels acceptable to the Company's bank, it is
likely that the bank will require that the Company make additional payments in
reduction of its indebtedness. It is unlikely that the additions to reserves
made by the Company during 1997 will be sufficient to completely offset the
reductive effect of recent price declines and production through 1997.
Continuation of the Company's exploratory and development programs will
require more cash than the Company's properties will generate at present price
levels. The sale or disposition of non-California domestic oil and gas
properties should result in the receipt of significant amounts of cash by the
Company during 1998, a major portion of which may be applied to the Company's
bank indebtedness. However, the timing of any sale and the amounts realized
therefrom nevertheless may not be sufficient or early enough to permit the
Company to make its bank payments and fund its committed exploration activities,
in which cases the Company would be required to seek other financing or attempt
to reduce its exploratory commitments. There is no assurance that the Company
will be able to do either or that the terms of any new financing or reduction in
commitments will be favorable to the Company.
The Company's newly issued Series A Preferred Stock contains provisions
which under certain circumstances not now existing, would require the Company to
redeem that series. In addition, because of the potentially dilutive effect of
the conversion of the series into common stock, it may be desirable for the
Company to redeem that series as a matter of business practice. The Company does
not presently have the funds with which to redeem the Series A Preferred Stock.
Dependence on Key Personnel
The Company depends upon the efforts and skills of its key executives, most
importantly Ilyas Chaudhary, the Chairman of the Board and Chief Executive
Officer of the Company. The Company has an employment agreement with Mr.
Chaudhary, which will expire in January 2000, and is the beneficiary of a $5
million policy insuring Mr. Chaudhary's life. The Company also has employment
agreements with other key employees which will expire in 1998 and 1999. See
"Management Benefit Plans and Employment Agreements -- Employment Agreements."
The success of the Company will depend, in part, on its ability to manage its
assets and attract and retain qualified management and field personnel. There
can be no assurance that the Company will be able to hire or retain such
personnel. In addition, the loss of Mr. Chaudhary or other key personnel could
have a material adverse effect on the Company.
Volatility of Common Stock
The market price for the Common Stock has been extremely volatile in the
past and could continue to fluctuate significantly in response to the results of
drilling one or more wells, variations in quarterly operating results and
changes in recommendations by securities analysts, as well as factors affecting
the securities markets or the oil and gas industry in general. See " Factors
Relating to the Oil And Gas Industry and the Environment." Further, the trading
volume of the Common Stock is relatively small, and the market for the Common
Stock may not be able to efficiently accommodate significant trades on any given
day. Consequently, sizable trades of the Common Stock have in the past, and may
in the future, cause volatility in the market price of the Common Stock to a
greater extent than in more actively traded securities. These broad fluctuations
may adversely affect the market price of the Common Stock. See "Price Range of
Common Stock and Dividend Policy."
Shares Eligible for Future Sale; Control by Significant Stockholder
On December 31, 1997, the Company had outstanding 10,883,908 shares of
Common Stock. Of these shares, 4,963,438 shares of Common Stock were freely
transferable and tradable without restriction or further registration under the
Securities Act. In addition, approximately 822,600 shares of Common Stock may
currently be issued upon the conversion of the outstanding Debentures of the
Company. Mr. Chaudhary, members of his family and companies controlled by Mr.
Chaudhary beneficially own 5,858,010 shares of Common Stock (53.82% of the
outstanding Common Stock). Other officers and directors of the Company
beneficially own an additional 62,460 shares (0.57% of the outstanding Common
Stock). See "Shares Eligible For Future Sale." Mr. Chaudhary, as the indirect
controlling stockholder of the Company, can exercise significant, if not
controlling, influence over all matters requiring stockholder approval,
including the election of directors and approval of significant corporate
transactions. This concentration of ownership may also accelerate, delay or
prevent a change in control of the Company. See "Principal Stockholders" and
"Description of Capital Stock."
Outstanding Preferred Stock
As of December 31, 1997, 10,000 shares of the Company's Series A Convertible
Preferred Stock (the "Series A Preferred Stock") were issued and outstanding.
Each of the Series A Preferred Stock is convertible into such number of shares
of Common Stock as is determined by dividing the stated value ($1,000) of the
shares of Series A Preferred Stock (as such value may be increased due to
accrued but unpaid interest) by the then current Conversion Price (which is
determined by reference to the then current market price, but in no event will
the Conversion Price be greater than $9.345). If converted based on a Conversion
Price equal to the closing bid price of the Common Stock on December 31, 1997,
the Series A Preferred Stock would have been convertible into approximately
1,176,500 shares of Common Stock, but this number of shares could prove to be
significantly greater in the event of a decrease in the trading price of the
Common Stock. If converted based on a Conversion Price equal to the closing bid
price of the Common Stock on January 15, 1998, the Series A Preferred Stock
would have been converted into approximately 1,454,500 shares of Common Stock.
Purchasers of Common Stock could therefore experience substantial dilution of
their investment upon conversion of the Series A Preferred Stock. The shares of
Series A Preferred Stock are not registered and may be sold only if registered
under the Securities Act or sold in accordance with an applicable exemption from
registration, such as Rule 144 or Rule 701. The shares of Common Stock into
which the Series A Preferred Stock may be converted are being registered
pursuant to the Registration Statement of which this Prospectus forms a part.
On December 31, 1997, warrants to purchase 224,719 shares of Common Stock
were issued to the purchasers of the Series A Preferred Stock and warrants to
purchase 44,944 shares of Common Stock were issued to Aberfoyle Capital Ltd. as
a fee in connection with the placement of the Series A Preferred Stock
(collectively, the "Warrants"). The Warrants are exercisable over the next three
years at a price of $10.68 (as may be adjusted from time to time under certain
antidilution provisions). The shares of Common Stock issuable upon exercise of
the Warrants are being registered pursuant to the Registration Statement of
which this Prospectus forms a part.
The Series A Preferred Stock contains terms that impose restrictions on the
Company and may hinder the Company's ability to raise additional capital. Under
certain circumstances the Company will be required to redeem the Series A
Preferred Stock at a price equal to 115% of its stated value. There can be no
assurance that the Company will have the resources to complete such redemption.
In addition, because the conversion price of the Series A Preferred Stock is
determined based on the market price of the Common Stock, the conversion of the
Series A Preferred Stock could be extremely dilutive to the holders of Common
Stock.
Authorization of Preferred Stock
The Company's Board of Directors has the authority to issue up to 49,990,000
additional shares of Preferred Stock and to determine the price, rights,
preferences and privileges of those shares without any further vote or action by
the stockholders. The rights of the holders of Common Stock will be subject to,
and may be adversely affected by, the rights of the holders of any Preferred
Stock that may be issued. The issuance of Preferred Stock could have the effect
of making it more difficult for a third party to acquire a majority of the
outstanding voting stock of the Company. The Company has no present plans to
issue additional shares of Preferred Stock. See "Description of Capital Stock."
Substantial Options and Debentures Outstanding
At December 31, 1997, the Company had outstanding options to purchase up to
1.17 million shares of Common Stock at exercise prices ranging from $1.25 to
$15.50 with a weighted average exercise price of $8.95 per share. Additionally,
as of December 31, 1997, the Company had outstanding Debentures in the aggregate
principal amount of $3,599,000, which may convert into Common Stock at a price
of $4.375 per share. If Common Stock prices continue at current levels or
improve, the Company anticipates calling for the redemption of the Debentures in
the next year, which will likely result in a substantial number of the holders
converting the Debentures prior to the redemption date. In addition, on December
31, 1997, the Company issued the Warrants to purchase 289,663 shares of Common
Stock at an exercise price of $10.68. In addition, if the Company redeems the
Series A Preferred Stock it will be obligated to issue warrants (the "Redemption
Warrants") to purchase 200,000 shares of Common Stock at an exercise price
determined based on the price of the Common Stock at the time of such
redemption. The existence of these options, warrants and Debentures may hinder
future financings by the Company and the exercise of such options and warrants
and conversion of such Debentures will dilute the interests of all other
stockholders. The possible future resale of Common Stock issuable on the
exercise or conversion of these options and Debentures could adversely affect
the prevailing market price of the Common Stock. Further, the holders of options
may exercise them and adversely affect the market price of Common Stock at a
time when the Company would otherwise be able to obtain additional equity
capital on terms more favorable to the Company. See "Description of Capital
Stock Common Stock" and "Principal Stockholders."
Dependence on Key Customers
Empresa Colombiana de Petroles ("Ecopetrol"), which also owns a 50% working
interest in the Company's Colombian Nare Association properties, is the only
viable purchaser of the Company's oil production in Colombia, which accounted
for 31.5% of the Company's total oil and gas revenues in the nine months ended
September 30, 1997. Prices received from the sale of oil produced at the
Company's Nare and Cocorna Colombian properties are determined by formulas set
by Ecopetrol. The formula for determining the price paid for crude oil produced
at the Company's Colombian properties is based upon the average of specified
fuel oil and international crude oil prices, which average is then discounted
relative to the price of West Texas Intermediate crude oil. The formula is
expected to be adjusted again by Ecopetrol in February 1999. There can be no
assurance that Ecopetrol will not decrease the prices it pays for the Company's
oil in the future. A material decrease in the price paid by Ecopetrol would have
a material adverse effect on the Company's financial condition and future
operations. Also, the loss of Ecopetrol as a purchaser could have a material
adverse effect on the Company. See "Business Marketing of Production." Further,
much of the Company's domestic production is heavy, low gravity, viscous crude
oil from the Central Coast Fields. Often these crudes contain significant
amounts of sulfur and metals, which make it undesirable feedstock for most
refineries. In times of excess supply of competitive crudes and low producer
prices, these crudes are often the first crudes rejected by California crude
purchasers. This means that the demand and price paid for much of the Company's
production from the Central Coast Fields can vary significantly. Substantially
all of the Company's production from the Central Coast Fields is sold to
PetroSource, which in turn, has such oil processed at the Company's asphalt
refinery in Santa Maria, California (the "Santa Maria Refinery"). The operation
and ownership of the Santa Maria Refinery is important to the Company because it
creates additional demand for the Company's heavy gravity crudes.
Dependence on Operator
As of September 30, 1997, all of the Company's Colombian, and approximately
13.6% of the Company's North American, oil and gas production was derived from
properties operated by the Omimex Group, a privately held Fort Worth, Texas
company (together with Ecopetrol and the Colombian governmental authorities
necessary to operate the properties). The speed and success of the Company's
Colombian development and exploration efforts depend on the competence and
proficiency of Omimex. Further, because of its minority ownership in the oil and
gas interests in this jointly owned property, the Company does not have the
ability to materially influence the development and exploration plans for such
properties or, without the cooperation of Ecopetrol, remove Omimex as operator.
The costs and results of operations conducted by Omimex are not within the
control of the Company. See "- Factors Relating to the Oil and Gas Industry and
the Environment - Colombian Operations."
Risks Relating to Certain Corporate Matters
Under previous management and prior to its recent reincorporation as a
Delaware corporation, the Company did not make various required filings with the
Commission, may not have complied with requisite corporate formalities, may have
failed to accord stockholders the right to exercise preemptive rights (the right
of an existing stockholder to purchase additional shares to prevent dilution of
its ownership percentage) and 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 for meetings of the Board of
Directors and stockholders and stock records for much of its early history.
Further, until the Company's 1997 Annual Meeting of Stockholders, the Company
had not notified stockholders of their right to cumulative voting (the right of
a stockholder to accumulate his votes and cast all of them for less than all of
the nominees for director). When these matters were discovered, the Company took
corrective, ratifying and other actions designed to mitigate the effect of these
matters, including obtaining waivers from over ninety percent of the shares
entitled to exercise preemptive rights and securing an indemnity from Capco
Resources Ltd., a company which is the owner of approximately 50.3% of the
Company and controlled by Mr. Chaudhary. Additionally, since Mr. Chaudhary would
have been entitled to elect a majority of the Board of Directors of the Company,
the Company believes that the failure to inform stockholders of the existence of
cumulative voting did not have a material effect upon the election of previous
Boards. For further information regarding these matters and the risks related
thereto, see the discussion contained under the caption "Risk Factors Factors
Relating to the Company -- Risks Relating to Certain Corporate Matters" in the
Company's Form S-3 Registration Statement (File No. 33-94678) dated December 20,
1995, filed with the Commission pursuant to Rule 424(b) under the Securities Act
of 1933, and under the caption "Description of Business - General -- Development
of the Business of Saba" in the Report on Form 10-KSB for the year ended
December 31, 1996, filed with the Commission (File No. 1-12322) under the
Securities Exchange Act of 1934, as amended, which can be obtained from the
Commission. See "Available Information".
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. If the
Company is the operator, it has the risk that one of the joint owners may not
pay the owner's share of costs. If the Company is not the operator, it has risks
because it must reimburse the operator for the Company's share of costs incurred
by the operator, and the Company does not have control over operating procedures
and expenditures of the operator.
Risks Relating to the Oil and Gas Industry and the Environment
Volatility of Commodity Prices and Markets
Oil and gas prices have been and are likely to continue to be volatile and
subject to wide fluctuations in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty, political conditions
in international oil producing regions, the extent of domestic production and
importation of oil and gas in certain relevant markets, the level of consumer
demand, weather conditions, the competitive position of oil or gas as a source
of energy as compared with other energy sources, the refining capacity of oil
purchasers, the effect of federal, state and local regulation on the production,
transportation and sale of oil and political decisions such as trade
restrictions or the sale of strategic energy reserves. Adverse changes in the
market for oil and gas or the related regulatory environment would likely have
an adverse effect on the price of the Company's Common Stock and the Company's
ability to obtain capital or partners for its projects. See "- Factors Relating
to the Company - Dependence on Key Customers."
Uncertainty of Estimates of Reserves and Future Net Revenues; Decline in Oil
and Gas Prices
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 at a particular point in time and based on
specific pricing assumptions which may no longer be valid. Changes in pricing
assumptions can have a material effect on the estimated reserves. Since December
31, 1996, oil and gas prices have generally declined. At December 31, 1996, the
price of WTI crude oil as quoted on the New York Mercantile Exchange was $25.12
per Bbl and the comparable price at December 31, 1997, was $18.30. Quotations
for natural gas at such dates were $4.22 per Mcf and $2.55 per Mcf,
respectively. Estimating 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. There can be no assurance that the pricing and production
assumptions will be realized. Estimates of proved undeveloped reserves, which
comprise a substantial portion of the Company's reserves, are, by their nature,
much less certain than proved developed reserves. Consequently, the accuracy of
engineering estimates is not assured. See "Business - Oil and Gas Reserves."
Replacement of Reserves; Exploration, Exploitation and Development Risks
The Company's success will largely depend on its ability to replace and
expand its oil and gas reserves through the development of its existing property
base, the acquisition of other properties and its exploration activities, all of
which involve substantial risks. There can be no assurance that these activities
will result in the successful replacement of, or additions to, the Company's
reserves. Successful acquisitions of producing properties generally require
accurate assessments of recoverable reserves, future oil and gas prices,
drilling, completion and operating costs, potential environmental and other
liabilities and other factors. After acquisition of a property, the Company may
begin a drilling program designed to enhance the value of the prospect. The
Company's drilling operations may be curtailed, delayed or canceled as a result
of numerous factors, including title problems, weather conditions, compliance
with governmental requirements and shortages or delays in the delivery of
equipment, including drilling rigs. Furthermore, even if a well is drilled and
completed as capable of production, it does not ensure a profit on the
investment or a recovery of drilling, completion and operating costs.
Substantially all of the Company's oil and gas leases require that the working
interest owner continuously drill wells on the lands covered by the leases until
such lands are fully developed. Failure to comply with such obligations could
result in the loss of a lease. In addition, foreign concessions (such as the
Company's Indonesian Concession) impose substantial work obligations upon the
concession holder. See "Business - Exploration and Development Drilling
Activities."
Writedowns of Carrying Values
The Company periodically reviews the carrying value of its oil and gas
properties under the full cost accounting rules of the Commission. Under these
rules, capitalized costs of oil and natural gas properties may not exceed the
present value of estimated future net revenues from proved reserves, discounted
at 10%, plus the lower of cost or fair market value of unproved properties.
Application of this "ceiling" test generally requires pricing future revenue at
the unescalated prices in effect as of the end of each fiscal quarter and
requires a writedown for accounting purposes if the ceiling is exceeded, even if
prices declined for only a short period of time, and even if prices increase in
subsequent periods. The risk that the Company will be required to write down the
carrying value of its oil and natural gas properties increases when oil and
natural gas prices are depressed or decline substantially. If a writedown is
required, it would result in a one-time charge to earnings, but would not impact
cash flow from operating activities.
As of September 30, 1997, the Company reported approximately $51.9 million
of net capitalized oil and gas property costs and estimated the cost ceiling
exceeded the net capitalized costs by approximately $15.0 million.
Competition in the Oil and Gas Industry
The oil and gas industry is highly competitive. Many of the Company's
current and potential competitors have significantly greater financial resources
and a greater number of experienced and trained managerial and technical
personnel than the Company. There can be no assurance that the Company will be
able to compete effectively with these firms.
Environmental Obligations
In connection with the acquisitions of most of its properties, including
those in Colombia and in California, the Company has agreed to indemnify the
sellers from various environmental liabilities, including those that are
associated with the seller's prior obligations. Many of these properties were in
production during years in which environmental controls were significantly more
lax than they are presently. The Company does not conduct a detailed
investigation and, accordingly, the Company may be subject to requirements for
remediation of environmental damage caused by its predecessors. At the time of
an acquisition, there may be unknown conditions which subsequently may give rise
to an environmental liability. Consequently, it is difficult to assess the
extent of the Company's obligation under these indemnities. Further, 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 for remediation costs, environmental
damages and claims by third parties for personal injury and property damage.
From time to time in the course of operations, the Company has violated
various administrative environmental rules. The Company rectifies the violations
after the same are called to its attention. In many cases, the Company has been
required to pay fines, some of which have been material in amount, as a result
of these violations. Because of the nature of oil and gas producing operations,
it is unlikely that operations will be totally violation-free. However, the
Company continuously seeks to comply with environmental laws.
Governmental Regulations and Environmental Risks
The production and refining of oil and natural gas is subject to regulation
under a wide range of federal, state and local statutes, rules, orders and
regulations. These requirements specify that the Company must file reports
concerning drilling and operations and must obtain permits and bonds for
drilling, reworking and recompletion operations. Most areas in which the Company
owns and operates properties have regulations governing conservation matters,
including provisions for the unitization or pooling of oil and natural gas
properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of spacing. Many jurisdictions also
restrict production to the market demand for oil and natural gas and several
states have indicated interest in revising applicable regulations. These
regulations may limit the rate at which oil and natural gas can be produced from
the Company's properties. Some jurisdictions have also enacted statutes
prescribing maximum prices for natural gas sold from such jurisdictions.
Various federal, state and local laws and regulations relating to the
protection of the environment affect the Company's operations and costs. In
particular, the Company's production operations and its use of facilities for
treating, processing or otherwise handling hydrocarbons and related wastes are
subject to stringent environmental regulation. Compliance with these regulations
increases the cost of Company operations. Environmental regulations have
historically been subject to frequent change and reinterpretation by regulatory
authorities and the Company is unable to predict the ongoing cost of complying
with new and existing laws and regulations or the future impact of such laws and
regulations on its operations. The Company has not obtained environmental
surveys, such as Phase I reports, which would disclose matters of public record
and could disclose evidence of environmental contamination requiring
remediation, on all of the properties that it has purchased. The Company has,
however, completed limited environmental assessments for substantially all of
its California and Michigan oil and gas properties and the Santa Maria Refinery.
These assessments are generally the result of limited investigations performed
at governmental environmental offices and cursory site investigations and are
not expected to reveal matters which would be disclosed by more costly and
time-consuming physical investigations. Generally, such reports are employed to
determine if there is obvious contamination and to attempt to obtain
indemnification from the seller of the property. Most of the properties that
have been purchased by the Company have been in production for a number of years
and should be expected to have environmental problems typical of oil field
operations generally, and may contain other areas of greater environmental
concern. The Company has identified a limited number of areas in which
contamination exists on properties acquired by it.
Refinery Matters
The party who sold the asphalt refinery in Santa Maria, California, to the
Company agreed to remediate portions of the refinery property by June 1999.
Prior to the acquisition of the refinery, the Company had an independent
consultant 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. The Company, however, believes that either all required remediation will
be completed by the seller within the five-year period or the Company will
provide the seller with additional time to complete the remediation. Should the
seller not complete the work during the five year period, because of
uncertainties in the language of the agreement, there is some risk that a court
could interpret the agreement to shift the burden of remediation to the Company.
Property Matters
In 1993, the Company acquired a producing mineral interest from a major oil
company. At the time of acquisition, the Company's investigation revealed that a
discharge of diluent (a light, oil-based fluid which is often mixed with heavier
grade crudes) had occurred on the acquired property. The purchase agreement
required the seller to remediate the area of the diluent spill. After the
Company assumed operation of the property, the Company became aware of the fact
that diluent was seeping into a drainage area which traverses the property. The
Company took action to contain the contamination and requested that the seller
bear the cost of remediation. The seller has taken the position that its
obligation is limited to the specified contaminated area and that the source of
the contamination is not within the area that the seller has agreed to
remediate. The Company has commenced an investigation into the source of the
contamination to ascertain whether it is physically part of the area which the
major oil company agreed to remediate or is a separate spill area. The Company
also found a second area of diluent contamination and is investigating to
determine the source of that contamination. Investigation and discussions with
the seller are ongoing. Should the Company be required to remediate the area
itself, the cost to the Company could be significant. The Company has spent
approximately $240,000 to date on remediation activities, and present estimates
are that the cost of complete remediation could approach $800,000. Since the
investigation is not complete, the Company is unable to accurately estimate the
cost to be borne by the Company.
In 1995, the Company agreed to acquire, for less than $50,000, an oil and
gas interest on which a number of oil wells had been drilled by the seller. None
of the wells were in production at the time of acquisition. The acquisition
agreement required that the Company assume the obligation to abandon any wells
that the Company did not return to production, irrespective of whether certain
consents of third parties necessary to transfer the property to the Company were
obtained. The Company has been unable to secure all of the requisite consents to
transfer the property but nevertheless may have the obligation to abandon the
wells. The Company is evaluating its drilling options and is considering whether
to continue to attempt to secure the transfer consents. A preliminary estimate
of the cost of abandoning the wells and restoring the well sites is
approximately $800,000. The Company has been unable to determine its exposure to
third parties if the Company elects to plug such wells without first obtaining
necessary consents. 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. These environmental compliance costs could materially
and adversely affect the Company. In addition, the Company is generally required
to plug and abandon well sites on its properties after production operations are
completed. No assurance can be given that the costs of closure of any of the
Company's other oil and gas properties would not have a material adverse effect
on the Company.
Through a subsidiary, the Company discharges water from its operations in
Louisiana pursuant to a compliance order issued by the Department of
Environmental Quality ("DEQ"). The matter of overboard discharge is controlled
by the Environmental Protection Agency, but regulated by the State of Louisiana
through its DEQ. Since the initial termination date of December 31, 1991, the
DEQ has consistently granted extensions regarding the matter of overboard
discharge. The DEQ has granted the Company an extension of its discharge permit
through January 31, 1998. In or about September 1997, the Company had been
notified by the DEQ, however, of its assertion that the Company's permit had
expired in September or October, 1997. A determination that the permit had
expired would subject the Company to a statutory fine if the DEQ determined to
levy a fine. The Company has been conducting its operations in compliance with
the permit as it has customarily done in the past. With an expected
implementation in January 1998, the Company has been making preparations to
convert a well to inject the water as an alternative means of disposal.
Colombian Operations
In February 1997, the Company's rights to the Cocorna area expired in
accordance with the terms of the governing agreement, and this property reverted
to Ecopetrol. The Company and Omimex were required to perform various
environmental remedial operations, which Omimex advises have been substantially,
if not wholly, completed. The Company and Omimex are waiting for an inspection
of the Cocorna area by Colombian officials to determine whether the government
will require any further remedial work. Based upon the advice of Omimex, the
Company does not anticipate any significant future expenditures associated with
the environmental requirements for the Cocorna area.
Operational Hazards and Uninsured Risks
Oil and gas exploration, drilling, production and refining involves hazards
such as fire, explosions, blow-outs, pipe failures, casing collapses, unusual or
unexpected formations and pressures and environmental hazards such as oil
spills, gas leaks, ruptures and discharges of toxic gases, any one of which may
result in environmental damage, personal injury and other harm that could result
in substantial liabilities to third parties and losses to the Company. The
Company maintains insurance against certain risks which it believes are
customarily insured against in the oil and gas industry by companies of
comparable size and scope of operations. The insurance that the Company
maintains does not cover all of the risks involved in oil exploration, drilling
and production and refining; and if coverage does exist, it may not be
sufficient to pay the full amount of these liabilities. The Company may not be
insured against all losses or liabilities which may arise from all hazards
because insurance is unavailable at economic rates, because of limitations in
the Company's insurance policies or because of other factors. Any uninsured loss
could have a material and adverse effect on 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 Regulations
and Environmental Risks."
Risks Relating to Operations in Colombia and Other Countries
International Operations
The Company has producing properties in Colombia and Canada, is undertaking
exploration operations in Indonesia and Great Britain and is exploring
opportunities in other countries, including Pakistan, the Peoples Republic of
China and members of the Commonwealth of Independent States (formerly part of
the Soviet Union). Risks inherent in international operations generally include
local currency instability, inflation, 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. Changes in domestic and foreign import and export laws and tariffs
can also materially impact international operations. In addition, foreign
operations involve political, as well as economic, risks such as
nationalization, expropriation, contract renegotiation and changes in laws
resulting from governmental changes. In addition, many licenses and agreements
with foreign governments are for a fixed term and may not be held by production.
In the event of a dispute, the Company may be subject to the exclusive
jurisdiction of foreign courts or may not be successful in subjecting foreign
persons to the jurisdiction of courts in the United States. The Company may also
be hindered or prevented from enforcing its rights with respect to a
governmental instrumentality because of the doctrine of sovereign immunity. In
addition, Colombia, which has a history of political instability, is currently
experiencing such instability due to, among other factors: insurgent guerrilla
activity, which has affected other oil production and pipeline operations;
drug-related violence and actual and alleged drug-related political payments;
kidnapping of political and business personnel; the potential change of the
national government by means other than a recognized democratic election; labor
unrest, including strikes and civil disobedience; and a substantial downturn in
the overall rate of economic growth. There can be no assurance that these
matters, individually or cumulatively, will not materially affect the Company's
Colombian properties and operations or by affecting Colombian governmental
policy, have an adverse impact on the Company's Colombian properties and
operations.
Uncertainties in the United States , Colombia Bilateral Political, Trade and
Investment Relations
Pursuant to the International Narcotics Control Act of 1990, the President
of the United States is required to determine whether to certify that Colombia
has cooperated with the United States, or taken adequate steps on its own, to
achieve the goals of the United Nations Convention Against Illicit Traffic in
Narcotic Drugs and Psychotropic Substances. In 1995, 1996 and 1997, the
President de-certified Colombia. The 1995 de-certification was later subject to
a so-called "national interest" waiver, effectively nullifying its statutory
effects. Based on the 1996 Presidential de-certification, the United States
imposed substantial economic sanctions on Colombia, including the withholding of
bilateral economic assistance, the blocking of Export-Import Bank and Overseas
Private Investment Corporation loans and political risk insurance and votes
against multilateral assistance to Colombia in the World Bank and the
Inter-American Development Bank. The consequences of continued and successive
United States de-certifications of Colombian activities are not fully known, but
may include the imposition of additional economic sanctions on Colombia in 1998
and succeeding years. The President also has authority to impose far-reaching
economic, trade and investment sanctions on Colombia pursuant to the
International Emergency Economic Powers Act of 1978, which powers were exercised
against Panama in a dispute over narcotics trafficking activities by the
Panamanian government in 1987. The Colombian government's reaction to United
States' sanctions could potentially include, among other things, restrictions on
the repatriation of profits and the nationalization of Colombian assets owned by
United States' entities. Accordingly, imposition of the foregoing economic and
trade sanctions on Colombia could materially and adversely affect the
performance of the Common Stock and the Company's long-term financial results.
Colombian Labor Disturbances
All of the workers employed at the Company's Colombian fields belong to one
of two unions. Omimex is currently in contract negotiations with one of these
unions. While the Company has experienced organized work disruptions, including
intermittent disruption of production during the course of such discussions,
there have been no major union disturbances. There can be no assurance, however,
that the Company will not experience such disturbances, including significant
production interruption due to sabotage, work slowdowns or work stoppages.
USE OF PROCEEDS
The Company will not receive any proceeds from the sale of the Common Stock
in this offering.
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Common Stock trades on the American Stock Exchange under the symbol
"SAB." The following table sets forth the high and low quarterly closing sales
prices of the Common Stock as reported on the American Stock Exchange for the
periods indicated. The sales prices set forth below have been adjusted to
reflect a two-for-one stock split in the form of a stock dividend paid in
December 1996. Prior to May 22, 1995, the Common Stock was traded on the
Emerging Company Marketplace of the American Stock Exchange.
Low High
1998
First Quarter (through January 23)............................................. $ 6 1/16 $ 8 1/2
1997
Fourth Quarter $ 8 $ 14 7/8
Third Quarter ................................................................. 12 13/16 20 1/8
Second Quarter................................................................. 10 3/4 17 3/4
First Quarter.................................................................. 12 3/4 25 1/4
1996
Fourth Quarter................................................................. $ 9 1/4 $ 27 1/8
Third Quarter ................................................................. 6 3/16 9 15/16
Second Quarter................................................................. 3 7/8 8
First Quarter.................................................................. 3 9/16 4 3/4
On January 23, 1998, the last reported sales price of the Common Stock on
the American Stock Exchange was $6 7/8. The Company has never paid cash
dividends on its Common Stock and does not anticipate doing so in the
foreseeable future. The Series A Preferred Stock, the Company's Debentures and
the Company's principal revolving credit agreement restrict the payment of
dividends by the Company. See Note 8 of Notes to Consolidated Financial
Statements of the Company. At December 31, 1997, the Company had approximately
2,810 stockholders of record.
SELECTED FINANCIAL DATA
The following tables, parts of which have been derived from the Company's
audited financial statements, set forth historical financial information for the
Company 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 financial data for the nine month periods ended
September 30, 1996 and 1997 was derived from the unaudited financial statements
of the Company and, in management's opinion, includes all adjustments
(consisting only of normal recurring adjustments except as set forth below)
necessary to present fairly the results for such periods. The results of
operations for such periods are not necessarily indicative of those that may be
expected for a full year, and none of the data presented below is necessarily
indicative of future results.
Nine Months Ended
Year Ended December 31, September 30,
1992 1993 1994 1995 1996 1996 1997
(In thousands, except per share amounts)
Statement of Operations
Data
Revenues:
Oil and gas sales..... $ 6,021 $ 10,130 $ 12,170 $ 16,941 $ 31,521 $ 22,076 $ 25,282
Other ................ 484 400 784 753 1,681 1,077 1,496
Total revenues .... 6,505 10,530 12,954 17,694 33,202 23,153 26,778
Expenses:
Production costs(1) .. 3,370 5,857 7,547 10,561 14,604 10,955 12,250
General and
administrative .... 1,242 2,503 1,882 2,005 3,920 2,660 3,468
Depletion,
depreciation and
amortization ...... 1,102 1,853 2,041 2,827 5,527 3,616 5,012
Total expenses .... 5,714 10,213 11,470 15,393 24,051 17,231 20,730
Operating income ........ 791 317 1,484 2,301 9,151 5,922 6,048
Other income
(expense):
Interest expense ..... (316) (443) (634) (1,364) (2,402) (1,795) (1,421)
Gain on issuance of
shares of
subsidiary ........ -- -- -- 125 8 6 6
Other ................ 15 1 43 (10) 207 229 (196)
Total other income
(expense) ........ (301) (442) (591) (1,249) (2,187) (1,560) (1,611)
Income (loss) before
income taxes ......... 490 (125) 893 1,052 6,964 4,362 4,437
Provision (benefit) for
taxes on income ...... 125 (37) 384 450 2,958 1,963 1,800
Minority interest in
earnings of
consolidated
subsidiary ........... -- -- -- 55 241 178 90
Net income (loss) ....... $ $ $ $ $ $ $
365 (88) 509 547 3,765 2,221 2,547
Net earnings (loss) per
share(2) ............. $ $ $ $ $ $ $
0.06 (0.01) 0.06 0.06 0.37 0.24 0.23
Weighted average
common and
common equivalent
shares outstanding
(primary)(2) ......... 5,813 7,065 7,996 8,743 9,416 9,224 11,192
Other Financial Data
EBITDA(3) ............... $ $ $ $ $ $ $
1,908 2,171 3,568 5,188 14,652 9,595 10,780
Operating cash flow(4) .. 1,504 1,728 2,805 3,335 9,659
Capital expenditures .... 7,166 2,372 6,573 17,015 12,776 5,408 29,080
==============================
December 31, September 30,
1992 1993 1994 1995 1996 1997
- ------------------------------
(In thousands, except per share amounts)
- ------------------------------
Balance Sheet Data
Working capital
(deficit) ............ $ (1,096) $ (860) $ (2,422) $ 2,471 $ 2,418 $ (17,266)
Total assets ............ 12,214 13,261 18,108 39,751 49,117 77,472
Current portion of
long-term debt ....... 27 1,440 2,357 505 1,806 18,088
Long-term debt, net(5) .. 3,613 4,875 5,323 23,543 20,812 20,259
Stockholders' equity .... 4,010 4,407 6,283 7,848 17,715 22,657
(1) Production costs include production taxes.
(2) As adjusted for a two-for-one stock split in the form of a stock dividend
paid in December 1996.
(3) EBITDA represents earnings before interest expense, provision (benefit) for
taxes on income, depletion, depreciation and amortization. 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 and the
Notes thereto included elsewhere in this Prospectus.
(4) Operating cash flow represents net income plus deferred income tax expense
and depletion, depreciation and amortization. The Company does not
calculate operating cash flow for interim periods.
(5) For information on terms and interest, see Note 8 of Notes to Consolidated
Financial Statements of the Company.
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 Notes thereto and the
"Selected Financial Data" included elsewhere in this Statement.
General
The Company is an independent energy company engaged in the acquisition,
exploration and development of oil and gas properties. To date, the Company has
grown primarily through the acquisition of producing properties with significant
exploration and development potential in the United States, Colombia and Canada.
This strategy has enabled the Company to assemble a significant inventory of
properties over the past five years. From January 1, 1992 through September 30,
1997, the Company completed 25 property acquisitions. Between 1992 and 1996, the
Company's proved reserve base, production and operating cash flow have increased
at compound annual growth rates of 65.8%, 54.8% and 59.2%, respectively. The
Company's strategy has expanded to emphasize growth through exploration and
development drilling.
In 1996, the Company implemented a program to increase reserves through
exploration and development drilling. The current focus of this program is on
the drilling of approximately 170 principally horizontal wells in the Central
California Coast Fields and approximately 200 wells in Colombia's Middle
Magdalena Basin. A total of thirteen gross (13.0 net) oil wells were drilled in
California as part of the Company's 1997 drilling program. Eight of the wells
are currently in production, two wells have encountered formation problems which
the Company is seeking to remediate, one well was determined to be noncommercial
and two wells (one pair) are Steam Assisted Gravity Drainage horizontal wells
that are shut-in awaiting completion of the permitting process with regulatory
authorities. Four horizontal wells were drilled in a previous waterflood area
and high water cuts are inhibiting oil production rates. Although this situation
was not unexpected, the dewatering process is occurring at lower rates than
anticipated. Based on the results obtained to date, the Company limited its 1997
horizontal drilling program to the wells already drilled. Combined
geologic-reservoir engineering and production engineering studies are currently
underway to determine the nature and extent of the 1998 horizontal drilling
program. In Colombia, a total of thirteen gross (3.25 net) wells have been
drilled to date on the Teca/Nare property, and one well abandoned by the
previous operator was re-entered and completed for production. The operator has
made an application to obtain a global environmental permit in order to more
rapidly develop the entire field. At the Velasquez field, five gross (1.25 net)
wells were recompleted in a different formation to establish additional reserves
and increase production. In the fourth quarter of 1997, the operator received
regulatory approval to conduct operations on six additional locations.
The Company's revenues are primarily comprised of oil and gas sales
attributable to properties in which the Company owns a majority or substantial
interest. The Company accounts for its oil and gas producing activities under
the full cost method of accounting. Accordingly, the Company capitalizes, in
separate cost centers, all costs incurred in connection with the acquisition of
oil and gas properties and the exploration for and development of oil and gas
reserves. 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. The Company's
financial statements have been consolidated to reflect the operations of its
subsidiaries, including the Company's approximate 74% ownership interest in
Beaver Lake Resources Corporation, a Canadian public company ("Beaver Lake").
Crude Oil Prices
The price received by the Company for its oil produced in North America is
influenced by the world price for crude oil, as adjusted for the particular
grade of oil. The oil produced from the Company's California properties is
predominantly a heavy grade of oil, which is typically sold at a discount to
lighter oil. The oil produced from the Company's Colombian properties is also
predominantly a heavy grade of oil. The prices received by the Company for its
Colombian produced oil are determined based on formulas set by Ecopetrol. See
"Risk Factors - Factors Relating to Operations in Colombia and Other Foreign
Countries" and "Business - Marketing of Production."
The weighted average sales price of the Company's crude oil was $14.45 per
Bbl in 1996 and $13.81 per Bbl for the first nine months of 1997, representing
approximately 66.8% and 66.3%, respectively, of the average posted price per Bbl
for WTI crude oil during those periods. Since January 1, 1992, the weighted
average quarterly sales price received by the Company for its crude oil ranged
from a low of $10.69 for the quarter ended March 31, 1994 to a high of $17.37
for the quarter ended December 31, 1996.
Results of Operations
Comparison of Nine Months Ended September 30, 1997 and 1996
Oil and Gas Sales
Oil and gas sales increased approximately 14.5% to $25.3 million during the
nine months ended September 30, 1997 from $22.1 million for the same period of
1996. Average sales price per BOE for the nine months ended September 30, 1997
increased 0.9% to $13.48 from $13.36 per BOE for the same period of 1996.
Total production increased 11.8% to 1.9 MMBOE in the nine months ended
September 30, 1997 as compared to 1.7 MMBOE for the same period of 1996. The
increase in oil and gas production was primarily attributable to the Company's
property acquisitions in Louisiana in November 1996 and September 1997 and the
horizontal drilling program that began in California in June 1996. The
production increases were partially offset by a decline in production in
Colombia of 117,000 BOE for the nine month period ended September 30, 1997 from
the same period of 1996. The decline resulted from the reversion of the Cocorna
concession in February 1997 and normal production declines.
Other Revenues
Other revenues increased 36.4% to $1.5 million for the nine months ended
September 30, 1997, as compared to $1.1 million for the same period of 1996. The
increase was due primarily to additional processing fee income of $723,000
realized from the Company's asphalt refinery and additional operator's overhead
recoveries of $96,000 on operated oil and gas properties, reduced by excess
Velasquez-Galan Pipeline operating expenses in the amount of $414,000 which were
invoiced to the Company by the facility's operator in the first quarter of the
year.
Production Costs
Production costs increased 10.9% to $12.2 million for the nine months ended
September 30, 1997, as compared to $11.0 million for the same period in 1996.
Average production costs per BOE decreased $0.10 for the nine months ended
September 30, 1997 from $6.63 for the same period in 1996, resulting in
decreased production costs of $186,000.
A production increase of 223,000 BOE for the nine months ended September 30,
1997, from 1.7 MMBOE for the same period of 1996, resulted in increased
production costs of $1.5 million. In comparison with the nine month period of
the prior year, production volume changes for the same period in 1997 were an
increase of 347,000 BOE in the United States and a decrease of 117,000 BOE in
Colombia. The increase in the United States was primarily attributable to the
Company's property acquisitions in Louisiana in November 1996 and September
1997, and the horizontal drilling program that began in California in June 1996.
Approximately one-half of the production declines in Colombia resulted from the
reversion of the Cocorna Concession property interest in February 1997; the
balance of the decrease was due to normal production declines. The results of
the drilling program in Colombia, which began in the second quarter of 1997,
partially offset normal production declines.
General and Administrative Expenses
General and administrative expenses increased 29.6% to $3.5 million for the
nine months ended September 30, 1997, from $2.7 million for the same period of
1996. The overall increase in general and administrative expenses was due
principally to the increase in employment in the Company's domestic offices to
support its oil and gas property development programs in California, New Mexico
and Louisiana.
Depletion, Depreciation and Amortization
Depletion, depreciation and amortization expenses increased 38.9% to $5.0
million for the nine months ended September 30, 1997, from $3.6 million for the
same period of 1996. Depletion expense increased 40.6% to $4.5 million for the
nine months ended September 30, 1997, from $3.2 million for the same period of
1996. The increase was primarily attributable to domestic production volume
increases for the nine months ended September 30, 1997, of 347,000 BOE in
comparison with the same period of 1996, and capital costs recorded by the
Company in its full cost pools beginning in the second quarter of 1996, and the
anticipated future development and abandonment costs to be incurred in
connection with the management of its oil and gas properties. Depreciation and
amortization expenses increased $62,000 for the nine months ended September 30,
1997, from $408,000 for the same period of 1996.
Other Income (Expense)
Other income (expense) decreased to expense of $190,000 for the nine months
ended September 30, 1997, from income of $235,000 for the same period of 1996.
The change was primarily due to foreign currency translation losses of $354,000
realized by the Company's Colombia operations for the nine months ended
September 30, 1997.
Interest Expense
Interest expense decreased 22.2% to $1.4 million for the nine months ended
September 30, 1997, from $1.8 million for the same period of 1996. The decrease
was due primarily to the conversion of $8.6 million of Debentures to Common
Stock occurring since April 1, 1996. Interest expense attributable to the
Company's revolving line of credit increased $262,000 for the nine months ended
September 30, 1997, from the same period of 1996. The average debt balance
outstanding under this credit facility increased 66.7% to $14.5 million for the
nine months ended September 30, 1997, from $8.7 million for the same period of
1996, due principally to the use of loan proceeds to fund property acquisitions
and development drilling activities. The weighted average interest rate for the
revolving line of credit decreased 6% to 8.72% for the nine months ended
September 30, 1997, from 9.28% for the same period of 1996.
Provision for Taxes on Income
Provision for taxes on income decreased $163,000 (8.3%) for the nine months
ended September 30, 1997, from the same period of 1996. The Company's estimated
effective tax rates were 43.0% in 1997 and 46.0% in 1996.
Net Income
Net income increased $327,000 (14.7%) for the nine months ended September
30, 1997, from the same period of 1996. This increase reflected the effects of
changes in oil and gas sales, other revenues, production costs, general and
administrative expenses, depletion, depreciation and amortization expenses,
interest expense, other income (expense) and provision for taxes on income as
discussed above.
Comparison of Years Ended December 31, 1996 and 1995
Oil and Gas Sales
The Company's total oil and gas sales increased 86.4% to $31.5 million for
the year ended December 31, 1996, from $16.9 million for 1995. The average sales
price per BOE increased 20.2% to $14.05 in 1996 from $11.69 in 1995. The
increase was primarily attributable to the full year results in 1996 of the
property acquisitions in Colombia during 1995. Excluding the financial impact of
the Colombian properties, which were principally acquired in September 1995, oil
and gas sales increased 44.2% during 1996, to $18.6 million from $12.9 million
for 1995. The average sales price per BOE for United States and Canadian
operations was $15.87 and $13.26, respectively, in 1996, representing increases
of 21.7% and 28.5%, respectively, from the comparable 1995 averages.
Oil and gas production increased 46.7% to 2.2 MMBOE for the year ended
December 31, 1996, from 1.5 MMBOE for 1995. The increase in oil and gas
production was primarily attributable to the acquisitions of the Company's
Colombian properties, which were completed in the second half of 1995, and the
Company's drilling and rework activities performed in 1996.
Other Revenues
Other revenues increased 125.8% to $1.7 million for the year ended December
31, 1996, from $753,000 in 1995. This increase was due primarily to net tariffs
of $717,000 for use of the Velasquez-Galan Pipeline in Colombia, in which the
Company acquired a 50% interest in September 1995. In addition, the Company's
asphalt refining operation reported processing fee income of $514,000 for 1996,
as compared to no processing fee income in 1995.
Production Costs
Production costs increased 37.7% to $14.6 million in 1996 from $10.6 million
in 1995. The Company's production costs per BOE decreased 10.7% to $6.51 in 1996
from $7.29 in 1995. This increase in total production costs was due primarily to
increased production volumes. Excluding the financial impact of the Colombian
properties, the Company's average production costs per BOE decreased 5.9% to
$7.70 for 1996 from $8.18 for 1995. For 1996, production costs for the Colombian
properties were $5.3 million, or $5.11 per BOE.
General and Administrative Expenses
General and administrative expenses increased 95.0% to $3.9 million in 1996
from $2.0 million in 1995. The Company's general and administrative expenses per
BOE increased 26.8% to $1.75 in 1996 from $1.38 in 1995. The increase was due
principally to expenses incurred in connection with the Company's expanded
international operations in Canada and Colombia in the third and fourth quarters
of 1995, and an increase in employment in its domestic offices to support
anticipated future growth.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased 96.4% to $5.5
million in 1996 as compared to $2.8 million in 1995. Depletion, depreciation and
amortization expenses per BOE increased 26.8% to $2.46 per BOE for the year
ended December 31, 1996 from $1.94 per BOE for 1995. This increase was primarily
attributable to the capital costs recorded by the Company in its full cost pools
during 1996 and the anticipated future development and abandonment costs to be
incurred in connection with the management of its oil and gas properties.
Other Income (Expense)
Other income increased 87.0% to $215,000 for the year ended December 31,
1996 from $115,000 in 1995. The change was due primarily to foreign currency
transaction gains of $41,000 and additional interest income of $97,000 realized
in 1996.
Interest Expense
Interest expense increased 71.4% to $2.4 million in 1996 from $1.4 million
in 1995, due principally to interest expense totaling $998,000 attributable to
the Debentures, which were issued in December 1995. The average debt balance
outstanding under the Company's revolving credit facility for the year ended
December 31, 1996 increased 7.0% to $9.2 million as compared to an average debt
balance of $8.6 million in 1995. This increase was due principally to loan
proceeds used to fund the Company's acquisition and development program during
1996. The weighted average interest rate for the Company's revolving credit
facility decreased to 9.0% in 1996 from 9.8% in 1995.
Provision for Taxes on Income
Provision for taxes on income increased 557.3% in 1996 to $3.0 million
compared to $450,000 in 1995. The Company's effective tax rate for 1996 was
44.0%, a decrease from 45.1% in 1995 due to the impact of foreign tax credits.
Net Income
Net income increased 594.7% to $3.8 million in 1996 from $547,000 in 1995.
This increase reflected the effects of changes in oil and gas sales, other
revenues, production costs, general and administrative expenses, depletion,
depreciation and amortization expenses, other income (expense), interest expense
and provision for taxes on income as discussed above.
Comparison of Years Ended December 31, 1995 and 1994
Oil and Gas Sales
The Company's total oil and gas sales increased 38.5% to $16.9 million for
the year ended December 31, 1995 from $12.2 million for 1994. The increase was
primarily attributable to property acquisitions in Colombia during 1995. The
average sales price per BOE decreased 5.9% to $11.69 in 1995 from $12.42 in
1994, due primarily to lower sales prices for oil produced from the Colombian
properties, which were acquired in 1995. The average sales price per BOE in 1995
for United States and Canadian operations was $13.04 and $10.32, respectively,
an increase of 2.9% and a decrease of 7.2%, respectively, from the comparable
1994 averages. The average sales price per BOE in Colombia was $9.44 in 1995.
Oil and gas production increased 53.1% to 1.5 MMBOE for the year ended December
31, 1995 from 980 MBOE for 1994. This increase was due primarily to production
from properties acquired during 1995.
Other Revenues
Other revenues decreased 4.0% to $753,000 for the year ended December 31,
1995 from $784,000 in 1994. This decrease was primarily attributable to a
decline in operator fee income of 35.6% to $219,000 in 1995 as compared to
$340,000 in 1994, as a result of property dispositions and reduced expenditures
on Company-operated properties. Pipeline tariffs received by the Company as a
result of its 50% ownership of the Velasquez-Galan Pipeline, which was acquired
in September 1995, generated revenue of $439,000 in 1995. A gain on sale of real
estate in 1994 provided revenue of $428,000. Rental of facilities and
agricultural land at the Company's asphalt refinery produced revenue of $74,000
in 1995 as compared to no revenue in 1994.
Production Costs
Production costs increased 39.5% to $10.6 million in 1995 from $7.6 million
in 1994. The Company's production costs per BOE decreased 5.3% to $7.29 in 1995
from $7.70 in 1994. The increase in total production costs was due primarily to
increased production volume resulting primarily from the Company's acquisition
of its Colombian properties in 1995. From the acquisition dates of the Velasquez
Field (January 1995) and the Teca-Nare Fields (September 1995), the Company
incurred production costs of $2.2 million in 1995 in such fields.
General and Administrative Expenses
General and administrative expenses increased 5.3% to $2.0 million in 1995
from $1.9 million in 1994. The Company's general and administrative expenses per
BOE decreased 27.7% to $1.38 in 1995 from $1.91 in 1994. The increase in total
general and administrative expenses was due principally to expenses incurred in
connection with the Company's refinery operations, which began in the second
quarter of 1995, the Company's Colombian operations, which began in the first
quarter of 1995, and hiring of additional personnel in the fourth quarter of
1995 for the Company's Canadian operations.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased 40.0% to $2.8
million in 1995 as compared to $2.0 million in 1994. Depletion, depreciation and
amortization expenses per BOE decreased 6.7% to $1.94 per BOE for the year ended
December 31, 1995 from $2.08 per BOE for 1994. The increase in depletion,
depreciation and amortization expenses was primarily attributable to producing
property acquisitions in Colombia in 1995.
Other Income (Expense)
Other income increased $72,000 to $115,000 for the year ended December 31,
1995 from income of $43,000 in 1994. In 1995, the Company realized a gain of
$125,000 as a result of the issuance of common stock by a subsidiary. In 1994,
the Company realized $198,000 in the settlement of litigation, while
non-recurring expenses declined to $23,000 in 1995 from $199,000 in 1994.
Interest Expense
Interest expense increased 120.8% to $1.4 million in 1995 from $634,000 in
1994, due principally to the Company's increased bank borrowings under its
revolving credit facility. The average debt balance outstanding under the
Company's revolving credit facility for the year ended December 31, 1995
increased 50.9% to $8.6 million as compared to an average debt balance of $5.7
million in 1994. This increase was due principally to loan proceeds used to fund
producing oil and gas property acquisitions which closed during 1995. The
weighted average interest rate for the Company's revolving credit facility
increased to 9.8% in 1995 from 8.1% in 1994.
Provision for Taxes on Income
Provision for taxes on income increased 17.2% in 1995 to $450,000, compared
to $384,000 in 1994. The Company's effective tax rate for 1995 was 45.1%, up
from 43.0% in 1994, due to higher tax rates applicable to the Company's foreign
operations.
Net Income
Net income increased 7.5% to $547,000 in 1995 from $509,000 in 1994. This
increase reflected the effects of changes in oil and gas sales, other revenues,
production costs, general and administrative expenses, depletion, depreciation
and amortization expenses, other income (expense), interest expense and
provision for taxes on income as discussed above.
Comparison of Years Ended December 31, 1994 and 1993.
Oil and Gas Sales
The Company's total oil and gas sales increased 20.1% to $12.2 million
for the year ended December 31, 1994, from $10.1 million in 1993. An increase of
$2.7 million was the result of an increase of 225 MBOE in the Company's oil and
gas production, of which 87.3% was attributable to acquisitions completed during
1994. The average sales per BOE for the year ended December 31, 1994 was $12.42.
This average price per BOE was 7.4% less than the $13.41 per BOE average in
1993. This decrease was primarily due to additional production from the
Company's heavy crude oil properties, including those located in Santa Maria,
California, which generally sells at a discount to the average sales price of
lighter crude oil produced from the Company's other properties.
Other Revenues
Other revenues increased 96.0% to $784,000 in 1994, from $400,000 in
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 1993 and the first
quarter of 1994 resulted in a decrease in revenues in 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 28.8% to $7.6 million ($7.70 per BOE) in
1994, from $5.9 million ($7.75 per BOE) in 1993. The overall increase was due to
higher production levels in 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 1994.
General and Administrative Expenses
General and administrative expenses decreased 24.0% to $1.9 million in
1994, from $2.5 million in 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 the first quarter of 1994, including the disposition of
non-profitable business operations, also contributed to the decrease. General
and administrative expenses attributable to the Company's Canadian subsidiary
were $176,000 for 1994. General and administrative expenses per produced BOE
decreased to $1.91 in 1994 from $3.31 in 1993.
Depletion, Depreciation and Amortization Expenses
Depletion, depreciation and amortization expenses increased
approximately 9.9% to $2.0 million in 1994, from $1.9 million in 1993. Oil and
gas depletion expense increased $141,000, or 7.8%, to $1.9 million in 1994, from
$1.8 million in 1993. In the United States, proved reserves increased 3.7 MMBOE
to 7.9 MMBOE at December 31, 1994, from 4.2 MMBOE at December 31, 1993, which
resulted in depletion expense in the United States decreasing $314,000 to $1.5
million, or $1.77 per BOE, in 1994, from $1.8 million, or $2.34 per BOE, in
1993. Depletion expense in Canada was $455,000, or $2.86 per BOE, in 1994.
Depreciation and amortization expense increased $47,000, or 53.4%, to $135,000
in 1994 from $88,000 in 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.
Other Income (Expense)
Other income (expense) increased 368.8% to income of $43,000 in 1994
from net expense of $16,000 in 1993. Included for 1994 were 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.
Interest Expense
Interest expense increased 43.1% to $634,000 in 1994, from $443,000 in
1993. The average amount of applicable interest-bearing debt in the United
States in years 1994 and 1993 was $5.7 million and $5.3 million, respectively.
The higher amounts outstanding under the Company's principal credit agreement in
1994 compared to 1993, partially offset by a 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 the Company's Canadian subsidiary was $172,000 in
1994.
Provision for Taxes on Income
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.
Net Income
Net income of $509,000 for 1994 was 678.4% higher than the net loss of
$88,000 for 1993. This increase reflected the effects of changes in oil and gas
sales, other revenues, production costs, general and administrative expenses,
depletion, depreciation and amortization expenses, other income (expense),
interest expense and provision for taxes on income as discussed above.
Liquidity and Capital Resources
Since 1991, the Company's strategy has emphasized growth through the
acquisition of producing properties with significant exploration and development
potential. The Company recently expanded its focus to emphasize drilling,
enhanced recovery methods and increased production efficiencies. During the past
five years, the Company financed its acquisitions and other capital expenditures
primarily though secured bank financing, the creation of joint interest
operations and production payment obligations and sales of Common Stock and the
Debentures. Supplemental cash and working capital are provided through
internally generated cash flows, secured bank financing and debt and equity
financing. Additionally, the sale of preferred convertible stock completed
December 31, 1997, provided approximately $2.4 million in working capital.
From January 1, 1995 through September 30, 1997, the Company used a
combination of secured bank financing, the proceeds from the sale of the
Debentures and internally generated cash flow to fund its acquisitions and other
capital expenditures, which included $23.9 million for acquisitions of producing
properties located principally in California, Colombia, Canada, New Mexico and
Texas.
Working Capital
The Company's working capital decreased in 1997 from $2.4 million at
December 31, 1996 to a deficit of $17.2 million at September 30, 1997. This
decrease was primarily due to the classification as a current liability of $8.3
million of borrowing base indebtedness that may become payable during the next
twelve months, depending on the Company's future capital requirements and
available funding sources. In addition, the Company borrowed $9.7 million in
September to fund the acquisition of a producing property under a term loan due
December 31, 1997, which was classified as a current liability. A net increase
of $3.7 million in accounts payable in excess of a corresponding increase in
accounts receivable due to the Company's drilling expenditures during the third
quarter also contributed to the decrease in working capital. At December 31,
1997, term loans in the amount of $5.7 million that matured on that date were
renewed and extended to April 30, 1998.
Operating Activities
The Company's operating activities during the nine month period ended
September 30, 1997, provided net cash flow of $12.0 million. Changes in the
non-cash components of working capital were responsible for $3.7 million of this
amount. Cash flows from operating activities provided net cash flow of $6.9
million in 1996.
Investing Activities
Investing activities during the nine month period ended September 30, 1997,
resulted in a net cash outflow of $29.1 million, which consisted of expenditures
for oil and gas property acquisition, development and exploration. Investing
activities during the year ended December 31, 1996 resulted in a net cash
outflow of $10.8 million, which consisted primarily of oil and gas property
acquisition, development and exploration expenditures in the amount of $12.2
million, reduced by the receipt of a refund of $1.8 million on a certificate of
deposit.
Financing Activities
Financing activities during the nine months ended September 30, 1997, which
provided net cash flow of $16.6 million, consisted principally of activity on
the Company's revolving credit facility.
Financing activities during the year ended December 31, 1996, which provided
net cash flow of $3.9 million, consisted principally of activity on the
Company's revolving line of credit and proceeds from the sale of the Debentures,
net of related costs, in the amount of $1.4 million.
Credit Facilities
In September 1993, the Company established a reducing, revolving line of
credit with Bank One, Texas, N.A. to provide funds for the retirement of a
production note payable, the retirement of other short-term fixed rate
indebtedness and for working capital. At September 30, 1997, the borrowing base
under the revolving loan was $18.7 million, subject to a monthly reduction of
$400,000, of which $18.7 million was outstanding.
The Company has a second borrowing base credit facility in the face amount
of $3.4 million to fund development projects in California. The borrowing base
for this facility reduces at the rate of $142,000 per month, beginning November
1, 1997. At September 30, 1997, $2.8 million was outstanding.
In November 1997, the Company secured a short term loan in the face amount
of $3.0 million with Bank One, Texas, N.A. to be advanced in a series of
tranches as needed to fund working capital requirements. Amounts outstanding
under the loan bear interest at the rate of prime plus 2%, and mature for
payment on April 30, 1998.
Pursuant to an amendment dated December 31, 1997 to the loan with Bank
One, Texas, N.A., the Company is required to make a payment of $3 million in
April 1998 and a minimum payment of $3 million in June 1998 in addition
to its scheduled monthly payments of principal and interest.
The Company's Canadian subsidiary has available a demand revolving reducing
loan in the face amount of $2.8 million. The maximum principal amount available
under the loan reduces at the rate of $58,000 per month. At September 30, 1997,
the loan was fully advanced with an outstanding balance of $2.6 million.
Capital Budget
The Company's budget for capital expenditures for the last quarter of 1997
was estimated at $6.0 million. The expenditures will be made primarily to
complete development projects on existing properties, including recompletions.
Additional capital expenditures may be made for acquisitions of producing
properties, both domestically and internationally. The amount of capital
expenditures will change during future periods depending on market conditions,
results of the Company's development drilling program and other related economic
factors, including the price of oil and natural gas. The funds available
(including those from credit lines) for anticipated capital expenditures will be
affected by prices for oil and natural gas, results of the Company's development
drilling program and other factors beyond the control of the Company.
The Company expended approximately $26.7 million for its acquisition and
drilling activities during the nine month period ended September 30, 1997. The
expenditures were funded principally by cash flow from operations and borrowings
under bank credit facilities. The producing property acquisition in September
1997 was funded in total by short-term mezzanine financing. Under the terms of
its bank credit agreements, $18.0 million has been classified as currently
payable at September 30, 1997, as this amount may become payable over the next
twelve month period. Management is in discussion with several banking groups in
an attempt to secure either replacement long-term financing or equity. Although
no definitive agreement has been secured at this time it is expected that such
arrangements will be finalized either in the fourth quarter of 1997 or first
quarter of 1998.
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.
Quarterly Results of Operations
The following table sets forth certain unaudited quarterly financial
information for each of the Company's last eleven quarters. The data has been
prepared on a basis consistent with the Company's Consolidated Financial
Statements included elsewhere in this Prospectus and includes all necessary
adjustments, consisting only of normal recurring accruals that management
considers necessary for a fair presentation. The operating results for any
quarter are not necessarily indicative of results for any future period.
Quarters Ended
-----------------------------------------------------------------------------------------------------------------
March June September December March June 30, September 30December March June 30, September
31, 30, 30, 31, 31, 31, 31, 30,
1995 1995 1995 1995 1996 1996 1996 1996 1997 1997 1997
Revenues
- -----
Oil
and $3,186,31$3,831,179$3,959,082 $5,964,676 $6,962,886$7,640,802$7,471,924 $9,445,145 $9,668,592$7,695,072$7,918,697
gas
sales
Other $32,298 $82,040 $302,948 $335,722 $424,404 $362,026 $290,998 $604,159 ($105,118$576,881 $1,024,076
Total
revenu$3,218,60$3,913,219$4,262,030 $6,300,398 $7,387,290$8,002,828$7,762,922 $10,049,304$9,563,474$8,271,953$8,942,773
Depletion
depreciation
and
amortization
$503,687 $715,321 $712,023 $895,653 $1,140,500$1,227,905$1,247,226 $1,911,787 $1,586,96$1,646,327$1,778,275
Net
income$12,132 $98,173 $119,576 $316,651 $755,488 $734,375 $730,869 $1,543,984 $1,441,58$507,300 $598,618
Net
earnings
per $0.00 $0.01 $0.01 $0.04 $0.08 $0.08 $0.08 $0.16 $0.13 $0.05 $0.05
share
New Accounting Standards
In February 1997, the Financial Accounting Standard Board issued SFAS No.
128, "Earnings Per Share." SFAS No. 128 specifies the computation, presentation
and disclosure requirements for earnings per share and is effective for
financial statements issued for periods ending after December 15, 1997.
Management has not yet determined the impact that adoption of SFAS No. 128 is
expected to have on the financial statements of the Company.
In June 1997, the Financial Accounting Standards Board issued SFAS No. 130,
"Reporting Comprehensive Income" and SFAS No. 131, "Disclosure About Segments of
an Enterprise and Related Information." Both Statements are effective for fiscal
years beginning after December 14, 1997. Management has not yet determined the
impact that adoption of SFAS No. 130 and SFAS No. 131 is expected to have on the
financial statements of 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.
BUSINESS OF THE COMPANY
Saba Petroleum Company is an independent energy company engaged in the
acquisition, development and exploration of oil and gas properties in the United
States and internationally. The Company has grown primarily through the
acquisition and exploitation of producing properties in California and Colombia.
The Company has also recently initiated exploration projects which the Company
believes have high potential in California, Indonesia and Great Britain. The
Company has assembled a portfolio of over 200 potential development drilling
locations. Based on current drilling forecasts, the Company estimates that these
locations represent a five-year drilling inventory. The preponderance of those
drilling locations are in Colombia's Middle Magdalena Basin. The Company also
has drilling locations in California, New Mexico and Louisiana. The Company
intends to continue using advanced drilling and production technologies in an
effort to enhance the returns from its drilling programs. On its California
properties, the Company has successfully used horizontal drilling and
high-efficiency cavitation pumps, and has recently drilled its first steam
assisted gravity drainage ("SAGD") pair of wells in California, the preliminary
results of which are expected during the first part of 1998.
At December 31, 1996, the Company had estimated proved reserves of 30.6
MMBOE, consisting of 26.7 MMBbls of oil and 23.6 Bcf of gas (3.9 MMBOE), with a
PV-10 Value of $155.9 million. Since quantities of oil and gas recoverable from
a property are price sensitive, the recent decline in oil prices may be expected
to result in a reduction of the quantities of oil and gas included in the
Company's proved reserves and the PV-10 value of such reserves. See "Properties
- - Reserve Estimates."
Business Strategy
The Company intends to continue to increase its proved reserves, production
rates and operating cash flow through a program which includes the following key
elements:
Development of existing hydrocarbon base. The Company has an extensive
inventory of drilling locations, which the Company intends to exploit
over the next five years. The Company's program includes exploration of
existing producing properties located in Colombia, New Mexico and
Louisiana. The Company believes that this program will provide it with
a cost-effective means to significantly increase proved reserves,
production rates and operating cash flow.
Acquisition of producing properties with significant development
potential. The Company seeks to acquire domestic and international
producing properties where it can significantly increase reserves
through development or exploitation activities and control costs by
serving as operator. Subject to receipt of an analysis presently
underway by the Company's investment banker, the Company intends to
concentrate these domestic activities in California where the Company
believes that its substantial experience and established relationships
in the oil and gas industry enable it to identify, evaluate and acquire
high potential properties on favorable terms.
Selective pursuit of exploration prospects. The Company plans to expand
its reserve base by acquiring or participating in exploration prospects
in California, New Mexico, Louisiana and internationally. The Company
believes these activities complement its traditional development and
exploitation activities. In pursuing these exploration opportunities,
the Company plans to use advanced technologies, including 3-D seismic
and satellite imaging, where appropriate. The Company intends to
increase its exposure to natural gas and lighter oil prospects. In
addition, the Company may seek to limit its direct financial exposure
in exploration projects by entering into strategic partnerships.
During early 1998, the Company's Board of Directors directed management of
the Company to formulate and implement a plan to explore alternatives for
maximizing shareholder values. The mandate includes engaging an investment
banking firm to assist the Company in developing alternatives. While a
definitive decision has not been made, it is likely that the Company will
initiate a strategy which involves the sale or other disposition of at least a
substantial portion of its non-California domestic properties and the
concentration of the Company's efforts in the California and international
arenas. In addition, it is possible that this strategy will also involve placing
a greater emphasis on exploration activities than was previously the case. To
this end, the Company has initiated three exploration projects in California,
one of which is a joint venture with a large oil company to drill a relatively
high risk, high potential gas prospect in California. See "Properties - Current
Exploration Projects."
History of the Company
The Company's initial efforts focused on the acquisition of producing
properties with positive cash flow, development potential and an opportunity to
improve cash flow through more efficient operations. The Company has acquired
several properties that met these criteria, including the 1993 acquisition of
Cat Canyon and the other properties that comprise the California Central Coast
Fields. These heavy oil properties were attractive acquisitions because the
Company believed it could acquire the properties on the low end of a market
cycle, reduce the relatively high operating cost on the fields, and
significantly develop their proven reserve base through low risk drilling and
workover activities. As the Company grew through such acquisitions, it developed
expertise in heavy oil projects, drilling and enhanced recovery techniques,
field management and cost controls. In 1995, the Company expanded its operations
internationally by acquiring an interest in heavy oil production in the Middle
Magdalena Basin of Colombia, and oil and gas properties in Canada.
Having established a core of producing properties with a predictable and
improving cash flow and development potential, the Company has begun to focus on
larger high potential exploration and development projects.
Exploration and Development Drilling Activities
The Company has identified over 200 potential drilling locations on its
properties in Colombia, which represent an estimated five year inventory at
planned drilling rates. In addition, the Company has identified a number of
drilling locations on its properties located in the United States, primarily in
California, Louisiana and New Mexico. The Company is also pursuing the
acquisition of high potential exploration prospects to enhance its inventory of
drilling opportunities. In particular, the Company has initiated high potential
exploration activities in Indonesia and Great Britain; is completing the
analysis of a 3-D seismic survey covering some 10,500 acres of land in which it
has interests in the area of the Coalinga oil field in Kern County, California;
has entered into an agreement with a subsidiary of Chevron Corp. pursuant to
which the Company will analyze Chevron 3-D seismic data covering lands in Kern
County, California, and if warranted, will drill exploratory wells on Chevron
fee lands; and, has entered into a joint venture with a large independent for
the exploration of a multi-thousand acre lease block in northern California, on
which the Company expects that a high risk, high potential exploratory well will
be commenced during the first half of 1998.
The Company's capital expenditure budget for 1998 is highly dependent upon
the price for which its oil is sold and upon the ability of the Company to
obtain external financing. Subject to these variables, the Company has budgeted
a minimum of $7.2 million and a maximum of $23.0 million for capital
expenditures during 1998.
The Company's exploration and development drilling programs are conducted by
its in-house technical staff of petroleum engineers and geologists. In addition,
the Company retains the services of several consulting geologists and engineers
to evaluate and develop exploration projects in California and internationally.
These consultants report to the Company's professional staff, which analyzes and
vets the consultants recommendations before acting upon them.
The Company's professional staff oversees the Company's development strategy
which is designed to maximize the value and productivity of its existing
property base through development drilling and enhanced recovery methods. One of
the most important components of the Company's development program is its use of
horizontal drilling technology. In general, a horizontal well is able to
encounter a greater volume of hydrocarbons through its exposure to a longer
lateral portion of a producing formation than a comparable vertical well. As a
result, in appropriate formations, a horizontal well may generate both higher
initial production and greater ultimate recovery of oil and gas than a vertical
well. In addition, because a horizontal well can be extended laterally into a
formation, it can significantly reduce the number of wells required to drain a
given reservoir. The Company believes that its application of measurement while
drilling ("MWD") tools is essential to the success of its horizontal drilling
program. The use of MWD technology enables the Company to continuously monitor
the location of a drillbit during drilling and guide it into a tightly defined
target zone in a particular formation. The Company believes that its MWD
enhanced horizontal drilling program will increase reserve recovery and decrease
drilling and operating costs. Another important component of the Company's
horizontal well program is the use of high efficiency cavitation pumps. These
pumps, which are particularly effective for heavy oil, reduce maintenance,
increase production and permit the production of oil mixed with high quantities
of sand and other formation materials.
Beginning in June 1997, the Company initiated use of another enhanced
production technique known as SAGD. This technique involves drilling two
horizontal wells in a parallel configuration, one above, and within a short
distance of, the other. After drilling is complete, steam is injected into the
upper wellbore, which creates a steam chamber and heats the oil so that it may
flow by gravity to the lower producing wellbore for extraction. The SAGD process
has been successfully employed by other companies in Canada in thick reservoirs
containing viscous oils, similar to those found in areas of the Central Coast
Fields. Although this technique is initially more costly than employing a single
horizontal well, the Company anticipates that it will result in increased rates
of production and recovery and lower per-unit production costs. The Company has
drilled one pair of SAGD wells on its Gato Ridge Field and is awaiting local
permits before initiating steaming operations. The Company expects to obtain
preliminary results from these wells during 1998. If the initial SAGD wells are
successful, the Company intends to expand the use of this technology on its
California heavy oil properties.
California
The Company's drilling operations in California are focused on the Central
Coast Fields, which consist of six onshore fields that collectively comprise
approximately 4,405 gross (4,367 net) developed acres and 2,974 gross (1,915
net) undeveloped acres. The Company intends to capitalize on the potential of
these properties through a five year multiwell drilling program. The Central
Coast Fields consist of the Cat Canyon, Gato Ridge, Santa Maria Valley,
Casmalia, and Oxnard fields. The Company also has producing properties in
Solano, Kern and Orange Counties, California. Of these properties, the Company
regards the Cat Canyon and Gato Ridge fields as the most significant and upon
which it intends to focus its near term development drilling efforts. In
addition to the producing properties, the Company has several exploratory
projects in California which it plans to drill during 1998.
Between June 20, 1996 and October 31, 1997, the Company drilled and
completed twelve horizontal wells in the Sisquoc sands of the Cat Canyon Field.
Eleven of these wells are currently producing at rates from 40 to 140 bopd; the
twelfth well has encountered a sand intrusion problem which the Company is
attempting to rectify. The Company also drilled one pair of SAGD wells in the
Gato Ridge Field, which is awaiting local permits before production may be
attempted, and two horizontal wells that have encountered severe sand production
and are presently planned to undergo recompletion operations during 1998. During
1997, the Company drilled one dry horizontal well in the Casmalia field.
Depending upon oil prices and other relevant factors, the Company intends to
drill up to six horizontal wells and recomplete up to 32 existing vertical
wells, primarily in the Cat Canyon and Gato Ridge fields in the year 1998. In
addition, the Company may attempt to reactivate as many as fifteen existing,
shut-in vertical wells. The horizontal wells will be drilled to known producing
formations and the Company believes that such wells will exhibit similar
production characteristics as the horizontal wells it recently drilled in the
Cat Canyon Field. These relatively shallow wells are anticipated to cost an
average of $500,000 per well and reach an average depth of 2,700 feet with a
lateral extension ranging from 1,500 to 2,000 feet. See "Property-California"
for additional information concerning the results of drilling activities on
these properties.
The Company believes that horizontal drilling will be particularly effective
in producing the heavy oil contained in these fields because of the
significantly greater exposure of the wellbore to the productive section. The
Company has identified several distinct horizons in the Sisquoc sands of the Cat
Canyon and Gato Ridge fields, but has not determined how many of these horizons
are productive. To date, the Company has tested only a shallow horizon to an
approximate depth of 2,500 feet. The Company intends to begin selectively
exploring additional horizons, the deepest of which is believed to be at
approximately 3,500 feet. A deeper zone, the Monterey, which is a prolific
producing zone offshore and onshore California, lies below the Sisquoc at
approximately 5,500 feet. The Company drilled a horizontal well into this
formation during 1995 and developed mechanical problems, which the Company is
seeking to rectify. The Central Coast Fields contain a number of wells drilled
by previous owners which have been suspended for various reasons. The Company is
studying the feasibility of attempting to place some of the suspended wells back
into production. As indicated, the Company intends to perform workover and
remedial operations on a number of vertical wells that exist in the Central
Coast Fields, including some of the suspended wells.
Colombia
The Company owns interests in two Association Areas (Cocorna and Nare) and
one fee property (Velasquez) all of which are located in the Middle Magdalena
Basin, some 130 miles northwest of Bogota, Colombia. The Association Areas
encompass several fields, some of which are partially developed and some of
which await development. The Teca, Nare and Velasquez fields are presently under
development. The Association Areas, Nare and Cocorna, are held under Articles of
Association between Empresa Petroleos Colombiana ("Ecopetrol") and the Company's
predecessor in interest, a subsidiary of Texaco, Inc. ("Texaco"). Each
Association Area is large enough to encompass more than one commercial area or
field.
The Company and Omimex, the operator of the fields, have formulated a
development program which includes, pending regulatory approval, the drilling of
approximately 200 development wells through the year 2001 at an average depth of
2,900 feet. During 1997, the Company and its operator successfully completed or
reworked fourteen wells of the development program, which wells have met or
exceeded initial production expectations. The 200 well program is a refinement
of an approximate 600 well program originally designed by Texaco. The Texaco
program was not implemented due to what the Company believes was Ecopetrol's
concern with refinery capacity and oil prices. The ability of Omimex, as
operator of the fields, to implement the development program is dependent on the
approval of Ecopetrol and the Colombian Ministry of the Environment. The Company
and Omimex have submitted an application for an omnibus approval of the drilling
of the remainder of the 200 well program; failing receipt of the omnibus
approval, the companies would continue to seek approval for drilling such wells
in segments. In 1997, approval was obtained for the drilling of 21 development
wells (including the completed or recompleted fourteen wells. The Company and
Omimex also have recompleted a well under the Magdalena River and plan to drill
two additional wells which, if commercial, should establish a new commercial
area for development. The Company is also pursuing selected exploration
opportunities in Colombia including acquiring third party 3-D seismic data on
the currently producing Velasquez Field to determine its exploration potential.
Canada
The Company's Canadian properties, which are owned through Beaver Lake,
represented approximately 10.3% of the Company's PV-10 Value at December 31,
1996. The Canadian properties produced an average of 622 BOEPD for the year
ended December 31, 1996, and 615 BOEPD for the nine months ended September 30,
1997, from 147 wells covering 57,436 gross (12,943.0 net) developed acres, most
of which are located in the province of Alberta. These wells had proved reserves
of 2.7 MMBOE at December 31, 1996. The Company's stated proved reserves include
100% of the reserves of Beaver Lake. See "Business -- Exploration and
Development Drilling Activities -- Other United States and Canadian Properties."
Other International Properties
In September 1997, the Company and Pertamina, the Indonesian state-owned oil
company, signed a production sharing contract covering 1.7 million unexplored
acres on the Island of Java near a number of producing oil and gas fields. The
Company is required to spend approximately $17 million over the next three years
on this project, and has invested approximately $1.5 million in 1997. The
Company expects to identify drilling locations based on geologic trends
identified through its review of existing seismic data, satellite images and the
results of its own seismic program to be performed in 1998 or 1999. The Company
is in the negotiation stage with several potential joint venture partners and is
expecting to sign a joint venture agreement during 1998.
The Company has entered into an agreement to become the operator and a 75%
working interest holder of two exploration licenses which cover in the aggregate
a 123,000 acre area in southern Great Britain. The Company expects to drill its
first exploratory well on this concession during the second or third quarter of
1998 at an estimated cost of approximately $800,000 to the Company's interest.
The Company is currently discussing joint venture opportunities with respect to
this property with other companies.
Other United States and Canadian Properties
On its non-California domestic properties, the Company has working interests
in over 400 oil and gas wells located principally in Texas, Louisiana, Michigan,
New Mexico and Oklahoma, with additional interests located in Utah, Wyoming, and
Alabama. The Company has successfully completed three of six exploratory wells
and ten of eleven development wells it has drilled on these properties since
1995. The Company believes that many of these properties may be enhanced by
performing multiple workovers, 3-D seismic surveys, recompletions and
development drilling. For example, in November 1996, the Company acquired for
approximately $3 million an interest in a field in Jefferson Parish, Louisiana
and has recently completed work-overs on two of its wells in this area, which
increased production to 1,600 BOEPD from 850 BOEPD and at December 31, 1997, the
field was producing 1,200 BOEPD. In Lea County, New Mexico, the Company used a
3-D seismic survey to delineate a prospect and establish a location for a well
which it drilled in March 1997. The well established a new oil pool discovery.
Although the initial zone is not now producing, the Company is testing one of
two additional uphole zones in an attempt to establish an additional field
productive zone, with encouraging preliminary production indications. See
"Properties -Other U.S. and Canadian Properties -Southwest Tatum Field."
The Company's operations in Canada have been conducted exclusively through
its 74% owned subsidiary, Beaver Lake, which is traded on the Alberta Stock
Exchange. The Company is presently seeking to sell all or part of its interest
in Beaver Lake. The Company has focused its exploration and development
operations in Canada on low risk oil and gas projects which are near existing
processing and transportation facilities. During 1997, Beaver Lake drilled an
exploratory well on a 3-D seismically defined prospect in the Eaglesham area of
northwestern Alberta. While the well encountered the objective formation as
anticipated and produced oil, the well ran seriously over budget, encountered
formation difficulties and was abandoned. The Company believes that the prospect
remains viable, but the Company's strategic plan does not encompass investing
further funds in Beaver Lake. As at December 31, 1997, Beaver Lake had current
liabilities in excess of its cash and accounts receivable. The Company is also
evaluating the construction of a sour gas plant which could provide a market for
the approximately 11 Bcf of Company-owned gas which is currently shut-in. See "
- -- Property -- Canadian Properties."
Since January 1, 1992, the Company has acquired in some 27 separate
transactions, approximately $53 million aggregate purchase price of properties.
The properties acquired through 1996, as improved through the Company's
development efforts and including associated drilling activities, represented
approximately 30.6 MBOE of proved reserves as of December 31, 1996. The
Company's all-in-finding costs for these acquisitions and related activities
have averaged $2.53 per BOE.
Currently, the Company seeks to acquire domestic (almost exclusively
California located) and international producing properties where it can
significantly increase reserves through development or exploitation activities
and control costs by serving as operator. The Company believes that its
substantial experience and established relationships in the oil and gas industry
enable it to identify, evaluate and acquire high potential properties on
favorable terms. As the market for acquisitions has become more competitive in
recent years, the Company has taken the initiative in creating acquisition
opportunities, particularly with respect to adjacent properties, by directly
soliciting fee owners, as well as working and royalty interest holders, who have
not placed their properties on the market. The Company also plans to expand its
existing reserve base by acquiring or participating in high potential
exploration prospects in known productive regions. The Company believes these
activities complement its traditional development and exploitation activities.
In pursuing these exploration opportunities, the Company may use advanced
technologies, including 3-D seismic and satellite imaging. In addition, the
Company may seek to limit its direct financial exposure in exploration projects
by entering into strategic partnerships.
Property
At December 31, 1996, on a PV-10 Value basis, approximately 44.9% of the
Company's proved reserves were in California, primarily in the Central Coast
Fields and approximately 28.7% were attributable to the Company's Colombian
properties.
The following table summarizes the Company's estimated proved oil and gas
reserves by geographic area as of December 31, 1996. The following table
includes both proved developed (producing and non-producing) and undeveloped
reserves. The reliability of estimates of undeveloped reserves is significantly
less than that of proved developed producing reserves. Approximately 48.5% of
the total reserves reflected in the following table are undeveloped. See "Risk
Factors - Factors Relating to the Oil and Gas Industry and the Environment
Uncertainty of Estimates of Reserves and Future Net Revenues." There can be no
assurance that the timing of drilling, reworking and other operations, volumes,
prices and costs employed by the independent petroleum engineers will prove
accurate. Since December 31, 1996, oil and gas prices have generally declined.
At such date, the price of WTI crude oil as quoted on the New York Mercantile
Exchange was $25.12 per Bbl and the comparable price at December 31, 1997 was
$18.30. Quotations for the comparable periods for natural gas were $4.22 per Mcf
and $2.55 per Mcf, respectively.
December 31, 1996
Proved Reserves, net PV-10
Value
---------------------------------
Property Gross Oil Gas
------------- (Mbbls) (Mmcf) MBOE ------------------ -------------
Wells Dollar Value Percentage
(In thousands)
California
Cat Canyon ................ 95 5,664 3,133 6,186 $40,740 26.1
Oxnard (1)................. 75 5,039 -- 5,039 8,235 5.3
Casmalia................... 62 1,205 52 1,214 4,735 3.0
Santa Maria................ 50 618 146 642 2,962 1.9
Gato Ridge................. 35 64 240 104 312 0.2
Other...................... 229 1,913 2,151 2,271 13,002 8.4
Total California..... 546 14,503 5,722 15,456 69,986 44.9
Other United States
Louisiana.................. 18 260 118 280 3,385 2.2
Michigan................... 296 665 3,597 1,264 9,928 6.3
Texas...................... 78 391 1,410 626 5,097 3.3
New Mexico................. 18 236 702 353 3,616 2.3
Other ..................... 93 96 1,565 358 3,140 2.0
Total Other United States 503 1,648 7,392 2,881 25,166 16.1
Total United States 1,049 16,151 13,114 18,337 95,152 61.0
Colombia................... 615 9,607 -- 9,607 44,709 28.7
Canada..................... 422 921 10,551 2,679 16,078 10.3
Total International 1,037 10,528 10,551 12,286 60,787 39.0
Total ..................... 2,086 26,679 23,665 30,623 $155,939 100.0
(1) See discussion under "California - Producing Properties - Oxnard Field"
================================================================================
California
PRODUCING PROPERTIES
The Company operates all of its wells in the Central Coast Fields, except
Oxnard Field in which it has no producing interest, and maintains an average
working interest in these wells of 98.8% and an average net revenue interest of
89.4%. These fields produced 1,827 net BOEPD for the three months ended
September 30, 1997, and had proved reserves (primarily undeveloped) at December
31, 1996 of 13.2 MMBOE. Included in the reserve estimates are approximately 5
MMBOE (90% undeveloped) which are attributable to the Oxnard Field, an area in
which the Company's interests are subject to forfeiture if the Company does not
initiate and pursue developmental operations during 1998. In addition, since the
date of the reserve report, the Company has reduced its interest in the Oxnard
Field by 50%, which would result in a reduction of approximately 2.5 MMBOE.
However, the Company has also acquired several producing properties and has
drilled a number of wells on its properties, neither of which events are
reflected in the 1996 engineering report.
Cat Canyon Field. The Cat Canyon Field is the Company's principal California
producing property, representing approximately 26% of the Company's PV-10 Value
at December 31, 1996. This field, which covers approximately 1,775 acres of land
is located in northern Santa Barbara County and was acquired by the Company in
1993. At the time of acquisition, there were 89 producing wells and 74 suspended
wells, all of which were vertically drilled to either the Sisquoc or Monterey
Formations (lying between approximately 2,400 feet and 3,400 feet and 4,000 feet
and 6,600 feet, respectively). At the time of acquisition, average production
was 425 bopd and during the month of October 1997, average gross production was
approximately 1,206 bopd. Daily production varies depending upon various
factors, including normal decline in production levels, the production of newly
drilled wells and whether remedial work is being done on wells in the field. The
field produces a heavy grade of viscous oil, which is in demand at the Company's
Santa Maria Refinery. The property is considered (as are many heavy oil
properties) a high production cost field and reductions in prices paid for crude
generally affect such properties more dramatically than higher gravity lower
production cost fields.
The Company owns a 100% working interest and a 99.7% net revenue interest in
approximately 45 producing wells and a number of non-producing wells located in
this field. The producing reservoir, which consists of a number of separate
zones, is divided by two major north-south trending faults into three separate
and distinct areas. The area between the faults contains the bulk of the
productive reservoir volume and has the highest cumulative production. A portion
of that area was the subject of a waterflood instituted in 1962 by a previous
operator. The waterflood was not economically successful. The Company believes
that the two faults are sealing faults, thus preventing communication with the
portions of the field lying outside of the fault block, which areas were not the
subject of waterflooding operations.
In 1995, Saba drilled its first horizontal well into the Monterey Formation;
this well has experienced formation difficulties and has not been placed on
production by the Company pending completion of a study designed to remedy the
problem. In 1996, Saba initiated its present horizontal well drilling program in
the Cat Canyon Field by drilling five horizontal wells into the Sisquoc
formation's S1b sand (which is one of the multiple separate sand bodies
comprising the Sisquoc formation) Of the five wells, three were drilled in the
previously waterflooded central fault block and one in each of the eastern and
western portions of the field. The well in the western portion of the field
initially produced at rates approaching 400 bopd and, as expected has declined
to a present rate of approximately 140 bopd. Wells drilled into the Sisquoc
formation may be expected to produce varying amounts of formation water as part
of the production process. The well drilled in the eastern portion of the field
has suffered mechanical problems and plans are to rework the well during 1998.
The three wells drilled in the central portion, or waterflood area of the field,
developed initial production rates of approximately 150 bopd per well and have
declined to approximately 40 bopd per well. One of the wells has been drilled
and completed, with initial production rates of approximately 185 bopd declining
to its present rate of approximately 160 bopd. The three wells drilled into the
central waterflood area, as expected, are producing oil with high volumes of
residual water from the prior waterflood operations, Saba believes that by using
high volume pumps and lifting large volumes of fluid, the ratio of oil to total
fluids produced will gradually increase. This is supported by the results of one
of the wells which initially produced approximately 95% water until the pump
capacity was increased resulting in a decrease of water to 88% and a gross oil
volume of approximately 140 bopd. Saba expects continued improvement in the
ratio of oil to total fluid in each of the five wells. Production declines have
been in line with the Company's expectations of roughly a forty to fifty percent
decline in production during the first twelve months of a well's operation,
followed by a more moderate ten percent annual decline in production.
Results from the horizontal well drilling program have not met Saba's
expectations and continuing study is being given to the field to determine how
to maximize production. In addition, the Company has implemented measures
designed to ensure that operations are conducted with greater efficiency than
was the case during 1997. The Company plans to drill two horizontal wells in
this field during 1998, the locations for which will probably be outside of the
waterflooded portion of the central fault block. Horizontal wells in the field
generally have a horizontal extension of approximately 1,600 feet and cost
approximately $500,000 as a completed well. In addition to its horizontal well
drilling program, Saba periodically reworks and performs remedial operations on
its wells, including existing vertically drilled wells, to maintain or increase
levels of production.
In addition to the Cat Canyon Field, the Company has interests in a number
of fields in California, none of which had a PV-10 Value equal to five percent
or more (other than Oxnard Field) of the PV-10 Value of the Company's proven
reserves at December 31, 1996. Among such fields are the following:
Oxnard Field. The Oxnard Field, which represented approximately 5.3% of the
Company's PV-10 Value at December 31, 1996, is located near Oxnard, California,
and covers approximately 633 acres. In December 1996, the Company entered into
an agreement granting it up to a 66.7% working interest in production from this
field. Partially in response to declining crude oil prices and Saba's desire to
study the characteristics of the field more extensively, in November 1997, the
Company and its joint venture partner entered into a modification of the initial
agreement, reducing the interest of Saba to a 33.3% working interest (27.78% net
revenue interest) in the field and restoring the other company as operator of
the field. Maintenance of the Company's full interest is dependent upon the
expenditure of $5 million during a two-year period ending in 1999. This field,
which first began production in the early part of this century, produces a
highly viscous oil from the Vaca Tar Sands, a formation over two hundred feet
thick and located at depths of between 1,950 and 2,400 feet. The reservoir is
highly porous (35%) and permeable (1,800 md). The oil is heavy, approximately
6(Degree) to 8(Degree) API, and is highly viscous. Consequently, steam injection
is necessary resulting in expensive operations relative to the price of the oil
produced. Produced water is disposed of in wells located on-site that are owned
and operated by a third party. The field is equipped with two steam generators,
a large capacity (9,300 Bbls) tank farm, disposal wells, fresh water source
wells and all other equipment needed for steam operations on this lease. The
Company acquired its interests in this field at a time when oil prices were
substantially higher than prevailing prices. Although the Company believes that
substantial amounts of hydrocarbons are recoverable from this field and has been
developing a comprehensive horizontal drilling program to expand the current
production base, the present low price of crude produced from this field renders
it unlikely that drilling operations will be commenced in the immediate future.
Gato Ridge Field. The Gato Ridge Field, which represented approximately
0.2% of the Company's PV-10 Value at December 31, 1996, is located in the Santa
Maria Basin adjacent to the Cat Canyon Field and covers approximately 405 acres.
The Company owns a 100% working interest and net revenue interests ranging from
83% to 100% in seven producing wells in the Gato Ridge Field. The existing
vertical wells primarily produce a heavy oil (11(Degree)) from the same
formations as those underlying the Cat Canyon Field. The Company drilled two
horizontal wells and a pair of SAGD wells, to the Sisquoc formation in 1997 at
an average cost of $500,000 ($350,000 as a dry hole) per horizontal well and
$1.7 million for the pair of SAGD wells, including related surface equipment.
The two horizontal wells have both experienced sand intrusion problems. One well
initially produced at a rate of 300 bopd before sand infiltrated the well bore
necessitating a reduction in production levels to approximately 20 bopd with
approximately 55 barrels of water per day. The other well has also experienced
sand intrusion problems and is producing at non-commercial rates. The Company is
of the view that it will be able to rectify the sand intrusion in these wells
and establish the wells as commercial producers. The pair of SAGD wells drilled
on this property during 1997 have been completed and the initiation of steaming
operations is awaiting the issuance of county permits, which while not assured,
are expected to be issued during the first quarter of 1998. At such time steam
will be injected into the upper well and thereafter production will commence
from the lower well. Should this procedure prove successful, the Company plans
to initiate other SAGD projects on its Santa Maria properties.
North Orcutt. During December 1997, the Company acquired this property
which covers approximately 120 acres of land in a residential area approximately
two miles from the Santa Maria field. Four wells are located on the property,
three of which are presently producing approximately 50 bopd and 250 mcf per day
of high sulfur content gas; the oil ranges in gravity from 8(Degree) to
32(Degree) gravity and is produced from three separate benches of the Monterey
Formation. The oil is commingled for sale which results in an approximate
22(Degree) sales crude. The Company believes that it may reestablish production
in the suspended well and increase production from the remaining three wells
because the previous owner was unable to market the produced gas and was
permitted to flare only a limited quantity. That condition limited the amount of
oil which could be produced, since gas is produced in association with the oil.
The Company plans to construct a gas pipeline connecting this property with the
Company's existing pipeline, where the gas can be transported to the Company's
refinery and burned in operations, permitting oil production to be increased.
The permitting process for the pipeline has been commenced and it is expected
that approvals will be obtained during 1998. Quantities of oil and gas from this
property are not included in the Company's 1996 engineering report.
Richfield East Dome Unit (REDU). The REDU unit, which represented
approximately 3.4% of the Company's PV-10 Value at December 31, 1996, is located
in Orange County, California and covers approximately 420 acres. The Company is
the operator of this unit and owns a working interest of 50.6% and a net revenue
interest of 40.8%. The unit is under waterflood in the Kraemer and Chapman
formations and contains approximately 68 producing wells, 39 shut-in wells and
54 water injection wells. The Company conducted remedial operations on this
property during 1997 which resulted in increasing production approximately 100
bopd. The Company plans to conduct remedial operations in 1998 on this property
at an estimated cost to the Company's interest of approximately $600,000. The
Company owns fee interests in lands in this unit which it believes will be
developable for real estate purposes as oil operations are curtailed.
Other. The Company also owns other producing properties located in Santa
Barbara, Solano, Kern and Orange counties, California, which in the aggregate
represented approximately 9.9% of the Company's PV-10 Value at December 31,
1996.
CALIFORNIA EXPLORATION VENTURES
Coalinga Exploratory Prospect, Kern County, California. The Company has
acquired leases covering approximately 3,600 acres of land and contractual
rights covering an additional approximate 7,000 acres of land in the region of
the prolific Coalinga oil field in the San Joaquin Valley of California. The
Company has participated in a 16 square mile 3-D seismic survey covering this
area and has partially interpreted the survey. 19 anomalies have been identified
in the prospect area, covering five potentially productive zones, ranging in
depth from 6,500 to 12,000 feet. The Company plans to drill three exploratory
wells during 1998 to test anomalies appearing on the 3-D seismic data. Under the
agreement, the Company will bear 100% of the cost of the wells, which is
estimated at approximately $2.5 million in the aggregate as dry holes and $3
million as completed wells. The Company would have a 85% working (68% net
revenue) interest in the wells.
Northern California Exploratory Project. In late 1997, the Company entered
into a joint venture with a large independent company and a company in which
Rodney C. Hill, a
director, has a financial interest, to acquire a multi-thousand acre block of
oil and gas leases and drill an exploratory well for gas on such block. The
Company has a 30% initial interest in the exploratory well to earn a 20%
interest in the well and in the block and any additional wells that may be
drilled by the venture thereon. The Company regards the project as a high risk
venture with possible commensurate returns should the well prove productive. The
initial objective will be the sands of the Cretaceous Age at a depth of
approximately 8,500 feet. Lease acquisition costs are estimated at approximately
$300,000 to the venture and the cost of the well is estimated at approximately
$1,250,000 as a dry hole and $1,700,000 as a completed well. Should the well be
completed, the large independent company, with a 60% interest in the well to
earn a 40% interest in the block, will be the operator of the venture. Leasing
efforts are near completion and it is expected that the exploratory well will be
commenced during the first half of 1998.
Chevron Seismic Venture. In January 1998, Saba and Nahama Natural Gas Co.
entered into an agreement with a subsidiary of Chevron Corp. under which Chevron
made available to Saba and its partner, on a non-exclusive basis, the right to
process Chevron proprietary 3-D survey data covering approximately 42 square
miles of land in Kern County, California. Included in the 42 square miles are
approximately 14 square miles of land owned in fee by Chevron. Saba and Nahama
will reprocess the seismic data employing modern techniques at a cost estimated
at $300,000 and will have the ability to select and drill upon the Chevron owned
lands as well as the other lands should it and Chevron be able to acquire leases
covering such other lands. Under the terms of the agreement, Saba will have the
right to obtain oil and gas leases covering the Chevron lands by drilling one or
more exploratory wells on such lands. Should Saba and Nahama acquire a lease on
Chevron owned lands, the sharing of costs will be 85% and 15% to Saba and
Nahama, respectively, and revenues will be shared 68% to Saba (63.7% after
payout) and 12% (11.24% after payout) to Nahama.
Other United States Properties
In addition to its California properties, the Company owns producing
properties in a number of states, primarily Louisiana, New Mexico, Michigan,
Texas and Wyoming, which collectively represented approximately 16.1% of the
Company's PV-10 Value at December 31, 1996. At such date, these properties had
proved reserves of 2.9 MMBOE and produced approximately 1,376 BOEPD for the
three months ended September 30, 1997. In September 1997, the Company acquired
its Potash Field properties which are described elsewhere in this Prospectus.
The principal producing properties are:
Manila Village is located in Jefferson Parish, Louisiana. The Company
operates this field and owns a working interest of 40.5% (28% net revenue
interest) in the wells in the field. The field represented approximately 2.2% of
the Company's PV-10 Value at December 31, 1996. The field covers approximately
450 gross acres of land covered by shallow waters, and is located approximately
forty miles south of New Orleans. After acquiring this property in November
1996, the Company successfully reworked two wells increasing production from 850
BOEPD to 1,650 BOEPD. There are six producing wells in the field that produced
approximately 1,190 BOEPD in the month of October 1997. The Company is
participating in a 3-D seismic program which includes the field and expects that
the results of the survey will provide a basis for additional enhancements to
the value of the property, including recompletions, reworks and equipment
installations.
Potash Field, which is located in Plaquemines Parish, Louisiana, was
acquired by the Company in September 1997. The Company operates all of the wells
in the field. The field is a salt dome feature originally discovered by Humble
Oil and Refining Company and covers approximately 3,600 acres. The field is
located in a shallow marine environment southeast of New Orleans. The Company
owns an 80% working interest and a 67% net revenue interest in this property, on
which are located ten active wells and a number of shut-in or suspended wells.
Current production from the field is approximately 375 BOPD and 4,000 MCFD of
high BTU content gas. The Company believes that remedial work on several of the
wells will result in increased production levels. The salt dome feature in the
field has not been fully explored. The Company plans on conducting a 3-D seismic
survey to delineate the field. Production in this field is from multipay zones;
the deepest of which is 15,000 feet.
San Simon Ranch Field, is located in Lea County, New Mexico. The Company
owns interests in several wells in this field and operates three wells. The
Company has a 50% working (42%) net revenue interest in approximately 1,122
gross (742 net) acres in the field. The Company is participating in a 3-D
seismic survey to evaluate the development of the field.
Southwest Tatum Field, which is located in Lea County, New Mexico was
acquired by the Company as an exploratory project in late 1996. The Company
holds leases covering approximately 2,000 gross acres of land, in which the
Company has a working interest of 50% and a net revenue interest of 38.75%.
During the last part of 1996, the Company, as operator, commenced the drilling
of a 14,000 foot exploratory Devonian test well. In addition to the deepest
zone, the Devonian (which has been abandoned after having produced in excess of
20,000 barrels of high gravity oil), the well has three other potential oil
producing zones. The Company has recompleted the well in the shallower Cisco
zone with initial flow rates of 400-350 bopd of clean 45(Degree) oil, 800 mcfpd
of gas and no water. The Company will be production testing this zone over the
new few weeks, which will include the installation of a gas flare stack, since a
connection to a gas pipeline has not yet been made. A potential sales line
exists approximately two miles from the well. A second reentry well to test the
shallower zones was completed in September as a Canyon producer and is currently
flowing approximately 200 bopd, with a small amount of water. Two additional
wells are planned to be drilled on this property in 1998 at an approximate cost
of $350,000 each to the Company's interest.
Colombian Properties
General
The Company's Colombian operations are conducted on two Association Areas
and one mineral fee property. These properties are located in the Middle
Magdalena Basin of Colombia, some 130 miles northwest of Bogota. The Company and
its partner, Omimex, acquired their interests in the Middle Magdalena Basin
properties from Texaco in 1995, and each has a 25% working (20% net revenue)
interest in Nare and Cocorna Association properties, while Ecopetrol, the
Colombian state oil company owns the remaining 50% working interest. The mineral
fee property, Velasquez, is owned 75% by Omimex and 25% by the Company. The
three areas cover 56,508 gross acres of land. The Nare Association is the
northernmost area in which the Company has an interest and covers approximately
37,164 gross (approximately 9,200 net) acres of land. The exploitation and
development of the Teca and Nare Fields, and the adjacent Nare North, Chicala
and Morichi Fields are governed by the association contract originally entered
into between Ecopetrol and Texaco in 1980. Under these contracts, the cost of
exploratory wells is borne solely by the Company and its partner, who are
entitled to all revenues from such wells. Once an area within an Association is
declared to be a commercial area by Ecopetrol, the Company and its partner each
receives 20% of the crude oil produced at these fields, while Ecopetrol receives
40% of production and the Colombian government receives the remaining 20% of
production in the form of royalties. A commercial area is roughly equivalent to
a field. Each of the Company and its partner bears 25% of the production costs
of commercial areas and Ecopetrol is responsible for the remaining 50%. The
exploitation rights under these contracts expire in September 2008 and are not
renewable by the Company under their current terms. The Company understands that
legislation is being considered by the Colombian government which would permit
such extensions to be obtained. The Company intends to seek an extension of
these contracts, however, no assurance can be given that any extension will be
granted or that the terms on which any extension may be obtained will be
acceptable to the Company. See "Risk Factors - Factors Relating to Operations in
Colombia and Other Foreign Countries - Foreign Operations" and "- Exploration
and Development Drilling Activities - Colombia."
Generally, as in the case of the Company's interests under the Nare and
Cocorna Associations, the Articles require that the contracting oil company
perform various work obligations (including the drilling of any exploratory
wells) at its cost on the lands covered by the Articles, and allow production of
hydrocarbons for a stated terms of years. Upon discovery of a field capable of
commercial production and upon commencement of production from that field,
Ecopetrol reimburses the contracting party out of Ecopetrol's share of
production for 50% of the allowable costs. Thereafter, costs of operations and
working interest revenues are shared 50% by Ecopetrol and 50% by the contracting
oil company, which in this case is Omimex and the Company, as successors to
Texaco, the original contracting party. The working interest is subject to a
royalty of 20% which is paid to Ecopetrol on behalf of the Colombian government.
Several of the fields in the contract area owned by the Company and Omimex have
been declared to be commercial areas, but a number of other areas have not yet
been so designated. One field located within the Cocorna Concession area, which
was acquired by the Company from Texaco, has reverted to Ecopetrol because of
the expiration of the term of the Articles governing that field. Approval of
both Ecopetrol and the Ministry of the Environment is required to implement a
development program.
Description of the Properties
Both the Nare and Cocorna Associations will expire in September 2008. At
the date hereof, three fields within the Cocorna Association have been declared
commercial by Ecopetrol: Teca (approximately 1938 acres), Toche (approximately
150 acres), and South Cocorna (approximately 700 acres) and four fields within
the Nare Association have been declared commercial: South Nare (approximately
660 acres), North Nare (approximately 1,700 acres), Chicala (approximately 830
acres) and Moriche (approximately 1085 acres). The Company's Teca and Nare
Fields, which represented approximately 27.2% of the Company's PV-10 Value at
December 31, 1996, produced an average of 1.95 Mbopd for the quarter ended
December 31, 1996 and 1.86 Mbopd during the nine months ended September 30,
1997, from 309 wells covering 2,598 gross (649.0 net) developed acres and is the
primary producing area. The Company owns a 25% mineral fee interest in the
Velasquez Field which covers approximately 3,800 gross (950 net) acres of land.
The Company's Colombian properties in the aggregate represented 9.6 MMBOE at
December 31, 1996 or approximately 31.4% of the Company's total proved reserves
and approximately 28.7% of the Company's PV-10 Value at that date. The following
table provides information concerning the Company's interest in the commercial
areas and fee minerals in Colombia.
Average Daily
Barrels of Oil Produced
Proven Reserves at 4th Quarter 1996 and 1997
Field Name Dec. 31, 1996 Number of Wells
Velasquez 857,938 69 426/403
- ---------------------------
North Nare.... 2,898,455 78 --
- ---------------------------
Chicala....... 1,448,759 104 --
- ---------------------------
Teca & South Nare 4,382,930 328 1,947/1,905
- ---------------------------
So. Cocorna 18,985 36 330 / - (1)
(1) Property interest reverted to Ecopetrol in February 1997.
Production from all of the fields comes from relatively shallow reservoirs
lying at approximate depths of from 1,200 to 3,000 feet. All of the production
(save that produced from the Velazquez field) is of a relatively heavy grade of
crude oil, generally in the area of 10(Degree) to 13(Degree) gravity API. Wells
generally produce small amounts of formation water in conjunction with oil.
Because of the viscosity of the oil, wells are initially produced without
artificial stimulation and thereafter stimulated by cyclic steam injection.
Wells cost approximately $250,000 to $300,000 to the total working interest,
depending upon depth.
During 1997, the Company and the operator participated in the drilling or
recompletion of thirteen wells in the Teca (eight) and South Nare (five) Fields.
All of the wells drilled were productive and the operator is in the process of
installing steaming equipment. While the Company has not yet received its
independent engineering report, it is believed that the drilling of such wells
has added significantly to the Company's Colombian reserves.
The Company and Omimex have recently reentered a suspended Texaco drilled
well to an area under the Magdalena River and recompleted the well as productive
of approximately 30 bopd without artificial stimulation. Both the Company and
the operator believe that another two wells should be drilled into the area in
an effort to establish an additional commercial area. Should those efforts be
successful, it is believed that from 15 to 20 additional drilling locations
would be established.
During 1997, the operator in conjunction with the Company formulated a plan
for the drilling of approximately 200 development wells in the Nare North,
Chicala and Moriche fields. This program, subject to regulatory approval, would
be implemented through the year 2001. The Company is also considering joining in
a development program at the Velazquez property. The Company has budgeted
approximately $2.5 million for its Colombian operations capital expenditures,
but the expenditure will depend upon the price of oil and other economic
factors.
Crude Sales and Pipeline Ownership
All of the Company's crude oil produced at the Company's properties in
Colombia has been sold exclusively to Ecopetrol at negotiated prices. See
"Business - Marketing of Production." In conjunction with its purchase of
interests in the Nare Association, the Company also purchased a 50% interest in
the 118 mile Velasquez-Galan Pipeline, which connects the Fields to the 180
Mbopd Colombian government-owned refinery at Barrancabermeja. See "Exploration
and Development Drilling Activities - Colombia." The pipeline transports oil
from the Company's fields, together with a lighter crude oil supplied by
Ecopetrol which acts as a diluent to the Company's heavier crude, and crude oil
from other adjacent fields. The pipeline generates revenues through collection
of tariffs for the use of the pipeline. Throughput on this pipeline in December
1996 averaged 31,816 bopd of which the Company's share was approximately 2,500
bopd; comparative numbers for the month of December 1997 are 30,500 and 2,300
bopd, respectively. In addition to the operator and the Company, three other
companies transport their crude oil through the pipeline at tariff rates
established by Colombian authorities. The Company and the operator have
considered expansion of the pipeline system if additional production is
developed by operators in the area.
Canadian Properties
The Company's Canadian properties, which are owned through Beaver Lake,
represented approximately 10.3% of the Company's PV-10 Value at December 31,
1996. The Canadian properties produced an average of 622 BOEPD for the year
ended December 31, 1996, and 615 BOEPD for the nine months ended September 30,
1997, from 147 wells covering 57,436 gross (12,943 net) developed acres, most of
which are located in the province of Alberta. These wells had proved reserves of
2.7 MMBOE at December 31, 1996. The Company's proved reserves included 100% of
the reserves of Beaver Lake. See "Business -- Exploration and Development
Drilling Activities -- Other United States and Canadian Properties."
FOREIGN EXPLORATORY PROJECTS
Indonesian Exploratory Project
In September 1997, the Company and Pertamina, the Indonesian state-owned oil
company, signed a production sharing contract covering 1.7 million unexplored
acres on the Island of Java near a number of producing oil and gas fields. The
Company is required to spend approximately $17 million over the next three years
on this project, of which approximately $1.5 million was spent in 1997 on bonus
payments, data acquisition and geophysical investigation. The Company expects to
identify drilling locations based on geologic trends identified through its
review of existing seismic data, satellite images and the results of its own 3-D
seismic program to be performed in 1997 and 1998. The Company is in the
negotiation stage with several potential joint venture partners and is expecting
to sign a joint venture agreement during 1998.
Great Britain Project
The Company has entered into agreements with Yates Petroleum (U.K.) Ltd.
pursuant to which the Company will become the operator and 75% interest holder
of a 133,000 acre exploration area covered by two exploration licenses, in
southern Great Britain. The Company expects to drill its first exploratory well
on this concession during the second or third quarter of 1998 at an estimated
cost of approximately $800,000 to the Company's interest. The Company believes
that any oil and gas eventually produced from this concession would benefit from
the fiscal regime in Great Britain, which is based on income taxes instead of a
cost-free royalty or revenue sharing regime commonly used in other countries.
Oil and Gas Reserves
The Company's proved reserves and PV-10 Value from proved developed and
undeveloped oil and gas properties in this Statement have been estimated by the
following independent petroleum engineers. In 1996, 1995 and 1994, Netherland,
Sewell & Associates, Inc. ("NSA") prepared reports on the Company's reserves in
the United States and Colombia and Sproule Associates Limited ("Sproule")
prepared a report on the Company's Canadian reserves. The estimates of these
independent petroleum engineers were based upon review of production histories
and other geological, economic, ownership and engineering data provided by the
Company. In accordance with the Commission's guidelines, the Company's estimates
of future net revenues from the Company's proved reserves and the present value
thereof are made using oil and gas sales prices in effect as of the dates of
such estimates and are held constant throughout the life of the properties,
except where such guidelines permit alternate treatment, including, in the case
of gas contracts, the use of fixed and determinable contractual price
escalation. Future net revenues at December 31, 1996, reflect weighted average
prices of $17.05 per BOE compared to $11.30 per BOE and $11.60 per BOE as of
December 31, 1995 and 1994, respectively. See "Risk Factors - Factors Relating
to the Oil and Gas Industry and the Environment - Uncertainty of Estimates of
Reserves and Future Net Revenues." There have been no reserve estimates filed
with any other United States federal authority or agency, except that the
Company participates in a Department of Energy annual survey, which includes
furnishing reserve estimates of certain of the Company's properties. The
estimates furnished are identical to those included herein with respect to the
properties covered by the survey.
The following tables present total estimated proved developed producing,
proved developed non-producing and proved undeveloped reserve volumes as of
December 31, 1994, 1995 and 1996, and calculation of the PV-10 Value thereof.
There can be no assurance that these estimates are accurate predictions of
reserves or of future net revenues from oil and gas reserves or their present
value. As indicated elsewhere, the prices received for oil and gas have declined
substantially since the preparation of the 1996 year end engineering estimates.
Were reserves and present worth thereof calculated employing current prices, the
quantities and present worth would be materially less than those shown in the
following tables.
Estimated Proved Oil and Gas Reserves
At December 31,
1994 -------------------- ---------------------
1995 1996
- ------------------------------------------------
- -----------------------------------------------
Net oil reserves (MBbl)
- ------------------------------------------------
Proved developed producing............... 4,668 10,278 12,029
- ------------------------------------------------
Proved developed non-producing........... 327 590 1,367
- ------------------------------------------------
Proved undeveloped....................... 2,141 1,664 13,283
- ------------------------------------------------
Total proved oil reserves (MBbl)....... 7,136 12,532 26,679
- ------------------------------------------------
- ------------------------------------------------
Net natural gas reserves (MMcf)
- ------------------------------------------------
Proved developed producing............... 7,655 9,371 12,659
- ------------------------------------------------
1,516
Proved developed non-producing........... 848 871
- ------------------------------------------------
Proved undeveloped....................... 1,289 9,237 9,490
- ------------------------------------------------
Total proved natural gas reserves (MMcf) 9,792 19,479 23,665
- ------------------------------------------------
Total proved reserves (MBOE)................ 8,768 15,778 30,623
Estimated Present Value of Proved Reserves
At December 31,
1994 -------------------- --------------------
1995 1996
- -------------------------------------------------
PV-10 Value (In thousands)
- -------------------------------------------------
Proved developed producing............... $ 18,267 $ 38,618 $ 84,916
9,227
Proved developed non-producing........... 1,768 3,044
Proved undeveloped....................... 5,979 6,493 61,796
Total................................. $ 26,014 $ 48,155 $ 155,939
Proved reserves are estimates of hydrocarbons to be recovered in the future.
Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserve estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserve reports of other engineers might differ from the reports contained
herein. Results of drilling, testing and production subsequent to the date of
the estimate may justify revision of such estimate. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserve estimates are often different
from the quantities of oil and gas that are ultimately recovered. See "Risk
Factors - Factors Relating to the Oil and Gas Industry and the Environment
Uncertainty of Estimates of Reserves and Future Net Revenues."
Marketing of Production
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 gas, market demand and the effect of governmental regulations and
incentives. Substantially all of the Company's North American crude oil
production is sold at the wellhead at posted prices under short term contracts,
as is customary in the industry. No one customer accounted for more than ten
percent of the sales of the Company's North American production during 1996. The
Company's Colombian oil production, which is, and as a practical matter can only
be, sold to Ecopetrol, accounted for 40.9% of total oil and gas revenues in 1996
and 31.5% of total oil and gas revenues for the nine months ended September 30,
1997. See "Risk Factors - Factors Relating to Operations in Columbia and Other
Foreign Countries - Foreign Operations."
The market for heavy crude oil produced by the Company from its Central
Coast Fields differs substantially from the remainder of the domestic crude oil
market, due principally to the transportation and refining requirements
associated with California heavy crude oil. The prices realized for heavy crude
oil are generally lower than those realized from the sale of light crude oil.
The Company's Santa Maria refinery uses essentially all of the Company's Central
Coast Fields' crude oil, in addition to third party crude oil, to produce
asphalt, among other products. Ownership of the refinery gives the Company a
steady market for its local crude oil which is not enjoyed by producers
generally. See "Property- Asphalt Refinery".
Colombia
Oil produced from the Company's Middle Magdelena Basin Fields, after being
sold to Ecopetrol, is processed in a 180 Mbopd government owned refinery in
Barrancabermeja, Colombia. The Company believes that the refinery has sufficient
unused throughput capacity to satisfy any reasonably foreseeable increase in
production that might be achieved from the Company's Colombian exploration and
development program. The refinery is connected to the Company's Colombian fields
through the 118 mile Velasquez-Galan Pipeline owned by the Company and its
partner. The pipeline is currently operating at approximately 12,000 bopd
(together with 18,000 Bbls of diluent per day) and has the capacity to carry
approximately 20,000 bopd (together with 30,000 Bbls of diluent per day).
Accordingly, significant capacity exists for additional throughput. The Company
owns a 50% interest in the Velasquez-Galan Pipeline and is working with Omimex,
the owner of the remaining 50% interest, to explore the feasibility of extending
it to an export terminal on the Colombian coast. The pipeline currently
generates approximately $65,000 in monthly net revenues to the Company. See
"Risk Factors - Factors Relating to Operations in Columbia and Other Foreign
Countries - Foreign Operations."
The formula for determining the price paid for oil produced at the Teca-Nare
Fields is based upon the average of two price baskets of fuel: (a) a crude fuel
oil basket (1% sulphur United States Gulf Coast and Ecopetrol fuel oil for
exportation) ("Basket A") and (b) an international crude basket (Maya, Mandji
and Isthmus) adjusted for gravity API and sulphur content ("Basket B"). The
average of Baskets A and B is then discounted based on the price of West Texas
Intermediate ("WTI") crude oil, an industry posted price generally indicative of
prices for sweeter, lighter crude oil. If WTI is less than $16.00 per Bbl, the
average of Baskets A and B is discounted by $1.65 per Bbl; if WTI is between
$16.00 and $20.00 per Bbl, the average of Baskets A and B is discounted by $2.05
per Bbl; and if WTI is greater than $20.00 per Bbl, the average of Baskets A and
B is discounted by $2.45 per Bbl. The formula may be adjusted by Ecopetrol in
February 1999. Ecopetrol is required to pay for oil produced at the Teca-Nare
Field in the following denominations: 75% in United States dollars paid in the
United States and 25% in Colombian pesos paid in Colombia.
For production from its Velasquez Field, the Company receives a contracted
price of between $6.00 and $7.00 per Bbl for basic production of up to 34 MBOE
per month. For incremental production above such amount, the Company receives a
price equal to the average of (a) the prior quarter average of the prices of
Baskets A and B and (b) the average international price of crude oil from the
Velasquez and Tisquirama Fields in Colombia, which average is then discounted by
approximately 47%. The average sales price of the Company's production,
expressed in terms of BOE, was $12.49 per BOE in 1996 and $11.96 per BOE for the
first nine months of 1997, representing approximately 61.1% and 63.2%,
respectively, of the average posted price per Bbl for WTI crude oil during those
periods.
The following table summarizes sales volume, sales price and production cost
information for the Company's net oil and gas production for each of the years
in the three-year period ended December 31, 1996 and for the nine months ended
September 30, 1996 and 1997:
Nine Months Ended
Year Ended December 31, September 30,
1994 1995 1996 1996 1997
- ----------------------------------------------
Production Data:
Oil (MBbls)............................... 738 1,227 1,968 1,455 1,581
Gas (MMcf)................................ 1,453 1,337 1,651 1,184 1,767
Total (MBOE)......................... 980 1,450 2,243 1,652 1,875
Average Sales Price Data (Per Unit):
Oil (Bbls)............................ $ 13.08 $ 12.22 $14.45 $ 13.77 $ 13.81
Gas (Mcf)................................. 1.73 1.45 1.88 1.72 1.95
BOE....................................... 12.42 11.69 14.05 13.36 13.48
Selected Data per BOE:
Production costs (1)................ $ 7.70 $ 7.29 $ 6.51 $ 6.63 $ 6.53
General and administrative................ 1.91 1.38 1.75 1.60 1.77
Depletion, depreciation and amortization.. 2.08 1.94 2.46 2.19 2.67
(1) Production costs include production taxes.
Drilling Activity
The following tables sets forth certain information for each of the years in
the three-year period ended December 31, 1996 and for the nine months ended
September 30, 1997, relating to the Company's participation in the drilling of
exploratory and development wells in:
United States
Year Ended December 31, Nine Months Ended
1994 1995 1996 September 30, 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
Exploratory Wells
Oil..................... - - - - - - 2 1.00
Gas..................... 1 0.07 - - 3 1.35 - -
Dry (3)................. 3 0.19 3 .46 3 1.28 - -
Development Wells
Oil..................... 2 0.65 4 1.51 10 6.59 10 10.00
Gas..................... 2 0.29 1 .10 3 .64 - -
Dry (3)................. 1 0.25 1 .04 1 .35 1 1.00
Total Wells
Oil..................... 2 0.65 4 1.51 10 6.59 12 11.00
Gas..................... 3 0.36 1 .10 6 1.99 - -
Dry (3)................. 4 0.44 4 .50 4 1.63 1 1.00
(1) A gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest
is owned.
(2) A net well is deemed to exist when the sum of fractional ownership
working interest in gross wells equals one. The number of net wells is
the sum of fractional working interests owned in gross wells expressed
as whole numbers and fractions thereof.
(3) A dry hole is an exploratory or development well that is not a
producing well.
Colombia
Year Ended December 31, Nine Months Ended
1994 1995 1996 September 30, 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
Exploratory Wells
Oil..................... - - - - - - 1 .50
Gas..................... - - - - - - - -
Dry (3)................. - - - - - - - -
- -
Development Wells
Oil..................... - - - - - - 6 1.50
Gas..................... - - - - - - - -
Dry (3)................. - - - - - - - -
Total Wells
Oil..................... - - - - - - 7 2.00
Gas..................... - - - - - - - -
Dry (3)................. - - - - - - - -
(1) A gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest
is owned.
(2) A net well is deemed to exist when the sum of fractional ownership
working interest in gross wells equals one. The number of net wells is
the sum of fractional working interests owned in gross wells expressed
as whole numbers and fractions thereof.
(3) A dry hole is an exploratory or development well that is not a
producing well.
Canada
Year Ended December 31, Nine Months Ended
1994 1995 1996 September 30, 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
Exploratory Wells
Oil..................... - - - - - - - -
Gas..................... - - - - - - 1 .29
Dry (3)................. - - - - 1 .01 2 1.87
Development Wells
Oil..................... - - - - - - - -
Gas..................... - - 1 .09 - - - -
Dry (3)................. - - - - - - - -
Total Wells
Oil..................... - - - - - - - -
Gas..................... - - 1 .09 - - 1 .29
Dry (3)................. - - - - 1 .01 2 1.87
(1) A gross well is a well in which a working interest is owned. The number
of gross wells is the total number of wells in which a working interest
is owned.
(2) A net well is deemed to exist when the sum of fractional ownership
working interest in gross wells equals one. The number of net wells is
the sum of fractional working interests owned in gross wells expressed
as whole numbers and fractions thereof. No reduction is made for the
minority interest in Beaver Lake.
(3) A dry hole is an exploratory or development well that is not a
producing well.
Productive Oil and Gas Wells
The following table sets forth certain information at September 30, 1997
relating to the number of productive oil and gas wells (producing wells and
wells capable of production, including wells that are shut in) in which the
Company owned a working interest:
Oil Gas Total
Gross Net Gross Net Gross Net
United States......................... 527 208.7 108 57.3 635 266.0
Colombia.............................. 384 96.3 - - 384 96.3
Canada (1)............................ 85 22.6 41 9.9 126 32.5
(1) No reduction is made for the minority interest in Beaver Lake.
In addition to its working interests, the Company held royalty interests in
approximately 157 productive wells in the United States and Canada at September
30, 1997.
Oil and Gas Acreage
The following table sets forth certain information at September 30, 1997
relating to oil and gas acreage in which the Company owned a working interest:
Developed(1) Undeveloped
Gross Net Gross Net
United States (nine states)............. 52,647 15,469 21,754 14,169
Colombia................................ 6,398 1,600 5,719 1,430
Canada.................................. 58,076 13,303 48,724 18,935
(1) Developed acreage is acreage assigned to productive wells.
Title to Properties
Many of the Company's oil and gas properties are held 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 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.
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:
Nine
Year Ended December 31,
Months Ended
September 30,
1994 1995 1996 1997
Average sales price per BOE
California............................... $ 11.98 $ 12.55 $ 15.10 $ 13.62
Colombia................................. - 9.44 12.49 11.96
Canada................................... 11.12 10.32 13.26 10.35
Other.................................... 13.90 13.97 17.39 17.49
Combined................................. 12.42 11.69 14.05 13.48
Average production cost per BOE
California............................... $ 8.52 $ 9.15 $ 8.50 $ 7.55
Colombia................................. - 5.17 5.11 5.64
Canada................................... 5.19 5.92 5.15 4.72
Other.................................... 7.59 7.49 7.88 7.10
Combined................................. 7.70 7.29 6.51 6.53
- ---------------------------------------------
Asphalt Refinery
In June 1994, in an effort to increase margins on the heavy crude oil
produced from the Company's oil and gas properties in Santa Barbara County,
California, the Company, through a wholly owned subsidiary, acquired from Conoco
Inc. ("Conoco") and Douglas Oil Company of California an asphalt refinery in
Santa Maria, California, which had been inoperative since 1992. The Company
refurbished the refinery and, in May 1995, completed a re-permitting
environmental impact review process with Santa Barbara County, receiving a
Conditional Use Permit to operate the refinery. Pursuant to the refinery
purchase agreement, Conoco is required to perform certain remediation and other
environmental activities on the refinery property until June 1999, at which
point the Company will be responsible for any additional remediation, if any.
See "Risk Factors - Factors Relating to the Oil and Gas Industry and the
Environment Environmental Obligations."
The Company entered into a processing agreement with PetroSource in May
1995, and recommenced operations of the refinery in June 1995. Under the
processing agreement, PetroSource purchases crude oil (including crude oil
produced by the Company), delivers it to the refinery, reimburses the Company's
out-of-pocket refining costs, markets the asphalt and other products and
generally shares any profits equally with the Company. The arrangement with
PetroSource ends on December 31, 1998 and the Company does not intend to renew
the arrangement on its present terms. From that time forward, the Company may
negotiate an alternative arrangement with PetroSource and may assume the
marketing responsibilities presently held by PetroSource and may carry the cost
of inventorying crude oil and asphalt.
The refinery is a fully self-contained plant with steam generation,
mechanical shops, control rooms, office, laboratory, emulsion plant and related
facilities, and is staffed with a total of 20 operating, maintenance, laboratory
and administrative personnel. Crude oil is delivered to the refinery by trucks
to current crude oil storage of 40,000 barrels of processing. An additional
60,000 barrels of crude oil storage is also available for future demands. Crude
processing equipment consists of a conventional pre-flash tower, an atmospheric
distillation tower, strippers and a vacuum fractionation tower. The refinery has
truck and rail loading facilities, including some capability of tank car
unloading. Throughput at the refinery has ranged between 2,000 to 4,000 bopd,
while production capacity is approximately 8,000 bopd.
Refinery products include light feedstock (naphtha), kerosene distillate,
gas oils and numerous cut-back, paving and emulsion asphalt products, with the
primary product produced at the refinery being asphalt, with some liquids, such
as propane. Historically, marketing efforts have been focused on the asphalt
products which are sold to various users, primarily in the Southern California
area. Liquids are readily marketed to wholesale purchasers.
The Company regards the refinery as a valuable adjunct to its production of
crude oil in the Santa Maria Basin and surrounding areas. Generally, the crude
oil produced in these areas is of low gravity and makes an excellent asphalt.
Recent prices for asphalt exceed market prices for crude and costs of operating
the refinery. The Company believes that as road building and repair increase in
California, the market for asphalt will expand significantly.
Real Estate Activities
The Company from time to time has purchased real estate in conjunction with
its acquisition of oil and gas and refining properties in California and plans
to continue this practice. In connection with the acquisition of oil and gas
producing properties in Santa Maria, California in June 1993, the Company
purchased 1,707 acres in Santa Barbara County for an aggregate purchase price of
$465,000. In addition, the Company entered into an agreement to acquire 385
acres in Santa Barbara County 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. In addition, the Company acquired approximately
370 acres in Santa Maria, California in June 1994 in connection with the
acquisition of its Santa Maria refinery. The Company has used a portion of its
real estate holdings for agricultural purposes. The Company plans to retain
these real estate holdings for asset appreciation which may include
developmental activities at a future date.
Office Facilities
The Company's executive offices are located in Santa Maria, California, and
its accounting offices are located in Irvine, California. The Company maintains
regional offices in Edmond, Oklahoma, Calgary, Alberta, Canada and Bogota,
Colombia. These offices, consisting of approximately 21,300 square feet, are
leased with varying expiration dates to March 2002, at an aggregate rate of
$18,000 per month. The Company owns its office facilities at the asphalt
refinery in Santa Maria, which occupy approximately 1,500 square feet of space.
Employees
As of December 31, 1997, the Company employed 109 persons in the operation
of its business, 54 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 good. Omimex, the operator of
the Company's Colombian fields, has experienced minor organized work disruptions
from its union employees. See "Risk Factors - Factors Relating to Operations in
Colombia and Other Foreign Countries - Colombia Labor Disturbances."
Insurance
The Company maintains customary and usual insurance for companies in its
industry.
Legal Proceedings
The Company is a party to certain litigation that has arisen in the normal
course of its business and that of its subsidiaries. In the opinion of
management, none of this litigation is likely to have a material adverse effect
on the Company's financial condition or results of operations.
Competition
The oil and gas industry is highly competitive in all its phases. The
Company encounters competition from a substantial number of companies, many of
which have greater financial and other resources than the Company in acquiring
economically desirable producing properties and drilling prospects, in obtaining
equipment and labor to operate and maintain its properties and in the sale of
oil and gas. See "Risk Factors - Factors Relating to the Oil and Gas Industry
and the Environment - Replacement of Reserves; - Exploration and Development
Risks; - Competition in the Oil and Gas Industry."
MANAGEMENT
Directors, Executive Officers, Control Persons and Key Employees
The following table sets forth the name, age and position of each director,
executive officer, control person and significant employee of the Company and
significant subsidiaries (references are to offices or directorships held in the
Company unless otherwise indicated):
Name Age Position
Ilyas Chaudhary................ 49 Chairman of the Board and Chief Executive Officer
Walton C. Vance................ 50 Vice President, Treasurer, Secretary, Chief Financial Officer and
Director
Alex S. Cathcart............... 62 President, Chief Operating Officer and Director
Rodney C. Hill................. 60 Director
William N. Hagler.............. 64 Director
Ronald D. Ormand............... 38 Director
Faysal Sohail.................. 33 Director
Bradley T. Katzung............. 44 Vice President-Mid-continent Operations of the Company,
and President and Chief Operating Officer of Saba Energy of Texas,
Incorporated and Saba Petroleum of Michigan, Inc.
Burt M. Cormany................ 67 President and Chief Operating Officer of Santa Maria Refining
Company
Herb Miller.................... 62 Vice President-Exploration and Drilling-International of the
Company, and President and Chief Operating Officer of Saba
Imran Jattala.................. 39 Exploration Company
President and Chief Operating Officer of Saba Petroleum, Inc.
Executive Officers and Directors
Ilyas Chaudhary has been a director of the Company since 1985 and has served
as Chairman of the Board and Chief Executive Officer since 1993. Mr. Chaudhary
has served as President of the Company during parts of 1991, 1992 and 1993, and
in 1994 through December 1997. Mr. Chaudhary also serves as Chairman of the
Board and Chief Executive Officer of all subsidiaries of the Company other than
Beaver Lake Resources Corporation, Saba Petroleum (U.K.) Limited, Saba Cayman
Limited and Saba Jatiluhur Limited, and serves as Chairman of the Board of these
latter three subsidiaries. Mr. Chaudhary is a director and controlling
stockholder of Capco Resources Ltd. ("Capco"), the Company's majority
stockholder whose common stock is traded on the Alberta Stock Exchange and as of
December 31, 1997, owned 50.27% of the outstanding Common Stock of the Company,
and the controlling stockholder of SEDCO Inc. ("SEDCO"), which as of December
31, 1997, owned 3.54% of the outstanding Common Stock of the Company. Mr.
Chaudhary is also a director of Meteor Industries, Inc. Mr. Chaudhary has 25
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 Factors Relating to
the Company Dependence on Key Personnel."
Walton C. Vance has been the Vice President and Chief Financial Officer of
the Company since 1993 and became Secretary of the Company in 1994. Mr. Vance
has been a director of the Company since September 1996. From 1990 to 1993, he
was an independent consultant and 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 the Chief Financial Officer of Natural Resource Management Corporation
(now Edisto Resources) from 1981 to 1983 and Treasurer of such company in 1984.
Alex S. Cathcart has been a director of the Company since January 1997 and
has served as Executive Vice President of the Company since March 1997 until his
appointment as President in December 1997. Mr. Cathcart has served as President
and Chief Executive Officer of Beaver Lake Resources Corporation since 1993 and
previously as President and Chief Operating Officer of Saba Exploration Company
from May through December 1997. He has also served as President and Chief
Operating Officer of Saba Offshore, Inc. and Sabacol, Inc., subsidiaries of the
Company, from December 1996 to August 1997. From 1987 to 1993 he was the
Chairman and principal owner of Barshaw Enterprises Ltd., a family-owned
consulting and investment company operating primarily in the oil industry. Mr.
Cathcart has over 39 years experience in the oil industry. His exploration
experience was gained with Texaco Exploration Company, Francana Oil & Gas and
LL&E Canada. Since 1971 he has been involved in the management of exploration
programs with Banner Petroleum, Voyager Petroleum, Natomas Exploration of
Canada, Page Petroleum and Prime Energy.
Rodney C. Hill has been a director of the Company since February 1997 and
was Vice President - Legal Affairs from October through December of 1997. Since
1993 Mr. Hill has served as President of Rodney C. Hill, a (California)
Professional Corporation. From 1981 until 1993 Mr. Hill was a senior partner of
Hill & Weiss, where he was in charge of that firm's natural resources and
corporate securities departments. Prior to 1981 Mr. Hill served as both a senior
partner at several major Southern California law firms and as an officer of
certain natural resources companies where he directed their oil and gas property
acquisitions.
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. In addition, he is President of
Hagler Oil and Gas Company. Prior to 1979, Mr. Hagler was Vice President of
Plateau, Inc., a Rocky Mountain oil refiner and marketer. Mr. Hagler has served
for approximately 10 years on 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. Mr. Hagler currently serves as
a director of Consolidated Oil & Transportation, a privately held company in the
business of asphalt transportation.
Ronald D. Ormand has been a director since May 1997 and currently serves
as a Managing Director of CIBC-Oppenheimer & Co., Inc., an international
investment banking firm, where he has been employed since 1988. Mr. Ormand is
the head of CIBC-Oppenheimer's Energy Investment Banking Group, which is
responsible for financing and advising energy companies on a worldwide basis.
Prior to 1988, Mr. Ormand was employed by L.F. Rothschild & Co., Inc., Bateman
Eichler Hill Richards, Inc. and Rauscher Pierce Refsnes, Inc. in their
investment banking departments.
Faysal Sohail has been a director since May 1997 and currently serves as
Vice President and General Manager for Synopsys, Inc., a leading Silicon Valley
provider of electronic design automation tools for complex integrated circuits,
where he has been employed since 1996. He is responsible at Synopsys for
corporate strategic planning and representing this company to the investment
community. From 1990 to 1996 he worked as a senior executive and co-founder of
Silicon Architects, which is a worldwide licensor of libraries for highly
complex integrated circuits to semiconductor manufacturers.
Bradley T. Katzung has been Vice President - Mid-Continent Operations of
the Company and 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 20 years experience in the oil and gas industry, including Vice President
of Operations for Oakland Oil Company from 1987 to 1993.
Burt M. Cormany has been President of Santa Maria Refining Company since
July 1994. Mr. Cormany worked in various capacities for the previous owners of
the Company's Santa Maria Refinery from 1951 to 1990, including refinery manager
from 1974 to 1990. In 1991, Mr. Cormany was a consultant to the previous owner
of the refinery. He retired in 1991 and returned to work in 1994 as a consultant
to the Company for several months prior to becoming President of Santa Maria
Refining Company later that year.
Herb Miller had been appointed Vice President of the Company's international
exploration and drilling operations and President and Chief Operating Officer of
Saba Exploration Company in December 1997. Mr. Miller graduated from the
University of Tulsa, Oklahoma with a Bachelor of Geology degree and has 38 years
of oil industry experience. Mr. Miller's exploration experience was obtained
while employed by the Pure Oil Company and Unocal Canada Explorations. For the
period 1976-1980, he was involved in managing exploration projects with Unocal
in the position of District Geologist, Division Geologist and Exploration
Co-ordinator. In 1980 he joined Westar Petroleum serving as general manager of
exploration/land and general manager exploration/engineering. Mr. Miller's
experience has been primarily in Western Canada and also includes the Northwest
Territories, Beaufort Sea, east and west coast offshore, the United States and
the North Sea. From 1991 to 1993 when he joined Beaver Lake as Vice President
Exploration and Land, he was a private consultant to the energy industry. In
February 1997, he was transferred to Saba Petroleum Company's Corporate office
as Manager of the Technical and Drilling Departments and in August 1997 he was
appointed President and Chief Operating Officer of Saba Petroleum, Inc. in which
positions he served through December 1997.
Imran Jattala had been appointed President and Chief Operating Officer of
Saba Petroleum, Inc., which operates the Company's California properties, in
December 1997. Mr. Jattala joined the Company in 1992 as Assistant Controller
for the Company and its subsidiaries. Since that time, Mr. Jattala had worked in
various capacities for the Company, including Administrative Manager. In
addition to Mr. Jattala's educational background in international business and
banking, he has over 4 years experience in revnue auditing.
Director Compensation
The Company does not pay any additional remuneration to executive officers
for serving as directors. As of May 1997 and for each term thereafter,
non-employee directors will receive a retainer of $12,000 for the first four
Board meetings and $1,000 per meeting for the fifth and any additional meetings,
including committee meetings attended. 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. The Board of Directors received a total of $47,900 in cash
compensation in 1996 and $39,700 in 1997. Pursuant to the 1997 Stock Option Plan
for Non-Employee Directors, each non-employee director shall be granted, as of
the date such person first becomes a director and automatically on the first day
of each year thereafter for so long as he continues to serve as a non-employee
director, an option to acquire 3,000 shares of the Company's Common Stock at
fair market value at the date of grant. For as long as the director continues to
serve, the option shall vest over five years at the rate of 20% per year on the
first anniversary of the date of grant. Subject to shareholder approval, the
Board of Directors increased the number of shares of the Company's Common Stock
subject to option from 3,000 to 15,000,vesting 20% per year. To date, each
qualified non-employee director has been granted 15,000 options, subject to
shareholder approval, at an exercise price of $15.50 per share. See "Benefit
Plans and Employment Agreements -- Stock Option Plans."
No family relationships exist between or among any of the directors or
executive officers.
Executive Compensation
The following table sets forth certain information as to compensation of the
Chief Executive Officer of the Company and the three other most highly
compensated executive officers of the Company who received salary and bonuses of
over $100,000 in any of the years 1994, 1995, 1996 or 1997.
Long Term
Compensation
Securities
Annual Compensation Other Annual Underlying All Other
Name and Principal Position Year Salary Bonus Compensation Options Compensation (3)
Ilyas Chaudhary............... 1997 $ 183,500 $ 2,885 (2) 500,000 (4) $ 4,420
Chairman of the Board, 1996 153,000 20,000 (2) --- 4,750
Chief Executive Officer 1995 150,000 (1) 1,731 (2) 200,000 ---
1994 120,786 (1) --- (2) --- ---
Walton C. Vance............... 1997 $ 120,700 $ 2,254 (2) --- $ 4,009
Vice President, 1996 101,633 20,000 (2) --- 2,259
Chief Financial Officer, and 1995 --- --- --- --- ---
Secretary 1994 --- --- --- --- ---
Burt Cormany.................. 1997 $ 110,040 $ 9,170 (2) 20,000 $ 1,351
President and 1996 113,386 8,330 (2) --- 5,549
Chief Operating Officer 1995 --- --- --- --- ---
of Santa Maria Refining 1994 --- --- --- --- ---
Company
Bradley T. Katzung 1997 $ 77,655 $ 70,200 (2) --- $ 1,097
Executive Vice President & 1996 --- --- --- --- ---
General
Manager -- USA 1995 --- --- --- --- ---
1994 --- --- --- --- ---
(1) Includes amounts reimbursed by the Company in 1994 and 1995 to SEDCO,
a corporation wholly owned by Ilyas Chaudhary, of $120,786 and $75,000,
respectively, for management services performed by Mr. Chaudhary. (2)
"Other Annual Compensation" was less than the lesser of $50,000 or 10% of such
officer's annual salary and bonus for such year. (3) Represents the
contributions made by the Company on behalf of these individuals to the
Company's 401(k) Plan. (4) Consists of options covering 200,000 shares granted
pursuant to the Company's 1996 Incentive Equity Plan; 200,000 shares of deferred
Common Stock; and 100,000 performance shares issuable if the Company meets 1998
earnings test.
Option Grants
There were no stock options granted to the named executive officers in the
fiscal year ended December 31, 1996. During 1997, the following stock options
were granted by the Company to the named executive officers:
Options
Executive Officers:
Ilyas Chaudhary.......................... 200,000
Alex S. Cathcart......................... 75,000
Burt Cormany............................. 20,000
Herb Miller.............................. 15,000
Imran Jattala............................ 25,000
Option Exercises and Fiscal Year-End Values
The following table provides certain information with respect to options
exercised in 1997 and unexercised options to purchase Common Stock of the
Company at December 31 1997:
Securities Underlying
--------------- --------------------------- ------------------------------
Number of Unexercised Value of Unexercised,
Shares Acquired on Options SARs at In-the-Money Options at
Name --------------------- Value Fiscal Year-End (#) Fiscal Year-End ($)
Exercise (#) Realized ($) Exercisable/Unexercisable Exercisable/Unexercisable
Ilyas Chaudhary....... 20,000 $50,000 60,000/120,000 $420,000/$840,000
Walton C. Vance....... - - 150,000/40,000 $1,087,500/$290,000
Bradley T. Katzung.... - - 80,000/20,000 $570,000/$142,500
Benefit Plans and Employment Agreements
Employment Agreements
Ilyas Chaudhary Employment Agreement. 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 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 provided 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 200,000 shares of
the Company's Common Stock, for $1.50 per share, 40,000 of which vest each year
of the agreement beginning in 1996. Of the total shares vested at December 31,
1997, 60,000 were unexercised and 20,000 have been exercised. 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. In May 1997, the Company authorized
the issuance to Mr. Chaudhary 200,000 shares of Deferred Common Stock, the
issuance of such deferred shares being contingent upon Mr. Chaudhary remaining
in the employ of the Company for a period of two years succeeding the expiration
of his existing employment contract and such shares being issuable 100,000
shares at the end of each such succeeding year. In addition, at that time the
Company authorized the issuance to Mr. Chaudhary of 100,000 shares of the Common
Stock should the Company meet certain earnings benchmarks during 1997, which
benchmarks have not been achieved.
Walton C. Vance Employment Agreement. The Company has entered into an
employment agreement with Walton C. Vance for a five-year term expiring June 30,
1998, pursuant to which Mr. Vance will serve as Vice President and Chief
Financial Officer of the Company. The employment agreement provides for a base
salary of $117,200 from July 1, 1997 through the end of the agreement. Under the
agreement, Mr. Vance is eligible to participate in the stock option plans of the
Company, and is also granted additional options to purchase 200,000 shares of
the Company's Common Stock at a strike price of $1.25 per share, of which
150,000 are currently vested and unexercised, 10,000 have been exercised and
40,000 will vest on June 30, 1998. Upon termination of Mr. Vance's employment
during the term of the employment agreement for any reason other than for
"cause," Mr. Vance's death or permanent incapacitation or voluntary termination,
the Company will be obligated to pay Mr. Vance a lump sum severance payment in
the amount equal to Mr. Vance's then current annual base salary.
Alex S. Cathcart Employment Agreement. The Company has entered into an
employment agreement with Alex S. Cathcart, dated March 1, 1997, for a two-year
term expiring on February 28, 1999, which can be extended for an additional two
years at the sole discretion of the Company. The employment agreement provides
for a base salary of $115,000, increasing to $123,000 in the following years.
Mr. Cathcart is granted options to purchase 50,000 shares at fair market value
as of May 31, 1997, which vest pro rata at the completion of the year of service
under the agreement to which they relate (with the first 25,000 options vesting
on March 1, 1998). In May 1997, the Company granted to Mr. Cathcart options to
purchase 25,000 shares at fair market value as of May 31, 1997, the grant of
such options being contingent upon Mr. Cathcart remaining in the employ of the
Company for an additional year succeeding the expiration of his existing
employment contract and such options vesting at the completion of the additional
year of service to which they relate.
Burt Cormany Employment Agreement. Santa Maria Refining Company, a wholly
owned subsidiary of the Company, and Burt Cormany have entered into an
employment agreement for a two-year term expiring on December 31, 1998, pursuant
to which Mr. Cormany will serve as President and Chief Operating Officer of that
subsidiary. Under the agreement, Mr. Cormany is eligible to participate in the
stock option plans of the Company and will receive a base salary of $110,000 in
the first year of the agreement and $120,000 in the second year.
Bradley Katzung Employment Agreement. The Company has entered into an
employment agreement with Bradley Katzung for a five-year term expiring on
November 8, 1998, pursuant to which Mr. Katzung will serve as an executive
officer of the Company. The employment provides for an initial annual salary of
$75,000 subject to annual reviews and which was increased to $125,000 in January
1998. Under the agreement Mr. Katzung is eligible to participate in the stock
option plans of the Company, and is also granted options to purchase 100,000
shares of the Company's Common Stock at a strike price of $1.375 per share, of
which 80,000 shares are vested and unexercised as of December 31, 1997.
Benefit Plans
Stock Option Plans. In June 1996, the Company's stockholders approved the
Company's 1996 Incentive Equity Plan (the "Incentive Plan"). The purpose of the
Incentive Plan is to enable the Company to provide officers, other key employees
and consultants with appropriate incentives and rewards for superior
performance. Subject to certain adjustments, the maximum aggregate number of
shares of the Company's Common Stock that may be issued pursuant to the
Incentive Plan, and the maximum number of shares of Common Stock granted to any
individual in any calendar year, shall not in the aggregate exceed 1,000,000 and
200,000 shares, respectively. Options granted under the Incentive Plan have an
exercise price equal to the market value of the Common Stock on the date of
grant, and become exercisable over periods ranging from two to five years from
the date of grant. At December 31, 1997, options to purchase 580,000 shares of
Common Stock had been awarded under the Incentive Plan.
In May 1997, the Company's stockholders approved the Company's 1997 Stock
Option Plan for Non-Employee Directors (the "Directors Plan"), which provided
that each non-employee director shall be granted, as of the date such person
first becomes a director and automatically on the first day of each year
thereafter for so long as he continues to serve as a non-employee director, an
option to acquire 3,000 shares of the Company's Common Stock at fair market
value at the date of grant. For as long as the director continues to serve, the
option shall vest over five years at the rate of 20% per year on the first
anniversary of the date of grant. Subject to shareholder approval, the Board of
Directors increased the number of shares of the Company's Common Stock subject
to option from 3,000 to 15,000 vesting 20% per year. Subject to certain
adjustments, a maximum of 250,000 options to purchase shares (or shares
transferred upon exercise of options received) may be outstanding under the
Directors Plan. At December 31, 1997, a total of 45,000 options had been granted
under the Directors Plan.
In fiscal years 1993 through 1996, the Company issued options for 560,000
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
$1.25 to $4.38, with a weighted exercise price of $1.47. Options to acquire a
total 284,000 shares were exercisable as of December 31, 1997.
Retirement Plan. The Company sponsors a defined contribution retirement
savings plan (the "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 to the 401(k) Plan were
$25,745 in 1995, $44,014 in 1996, and $42,016 in 1997.
Certain Relationships and Related Transactions
SEDCO and Capco owned 385,580 shares (3.54%) and 5,471,300 shares (50.27%),
respectively, of the Company's Common Stock outstanding as of December 31,
1997.
Certain officers, directors and key employees of the Company 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.
In 1997, the Company adopted a policy whereby all transactions by and
between the Company and any affiliate of the Company shall be conducted on an
arm's-length basis, and all substantial transactions shall be approved by a
majority of the Company's directors without an interest in such transactions.
In 1995, the Company borrowed $350,000 from Unico, Inc., a company
controlled by William N. Hagler, a director. The loan bore interest at 10% per
annum and was repaid in December 1995.
The Company has, from time to time, outstanding balances due to, or
receivables due from, Capco and SEDCO (or subsidiaries of such companies).
Except as indicated to the contrary, balances from and to the Company are open
accounts and are unsecured. The transactions giving rise to such matters are as
follows:
In 1995, Capco loaned $2,221,900 to the Company at 9% per annum; the
proceeds were used to acquire certain of the Company's Colombian properties. The
loans were evidenced by unsecured promissory notes. $600,000 of the initial loan
proceeds was exchanged for 150,000 shares of Common Stock at a price of $4 per
share (which exceeded market price at the time). The notes were paid in full in
1997.
In 1995, the Company borrowed $10,500 from SEDCO on a short-term basis and
repaid such amount during 1996.
In 1995, the Company paid SEDCO $10,700 for reimbursement of prior year
charges to the Company.
In 1995, the Company received $210,100 from Capco for reimbursement of prior
year charges and advances and was charged $22,700 for interest on advances.
In 1995, the Company remitted $92,100 to Capco and affiliates in settlement
of prior year charges.
During 1995, the Company loaned $101,700 to SEDCO, evidenced by a secured
promissory note bearing interest at 9% per annum, collateralized by Mr.
Chaudhary's vested, but unexercised, options to purchase the Common Stock of the
Company. The note is payable December 31, 1997. At year-end the note was
current.
In 1996, the Company received $29,300 from Capco and certain affiliates of
Mr. Chaudhary for reimbursement of prior year advances and charged Capco $9,600
for interest on such advances.
In 1996, the Company charged SEDCO $9,800 for interest on the outstanding
note receivable and was charged $5,100 by Saba Energy, Ltd. for interest due to
that company.
The Company charged SEDCO, Capco and certain affiliates of Mr. Chaudhary
$92,900 and $26,300 for administrative services provided to such companies
during 1995 and 1996, respectively. Such administrative services consisted
largely of Mr. Chaudhary's time. Of such amounts, $43,100 was unpaid at December
31, 1996.
During 1996, a subsidiary of Capco participated in the drilling of one of
the Company's exploratory wells on the same basis as did the Company. The
Company has billed the subsidiary a total of $112,200, of which $64,700 was
outstanding at December 31, 1996.
During 1996, the Company provided a short-term advance to SEDCO amounting to
$10,000, all of which was repaid subsequent to year end 1996. No interest
was charged on the advance.
During 1996, the Company loaned $300,000 to Mr. Chaudhary, evidenced by a
promissory note bearing interest at the rate of prime plus 0.75%. Interest is
due in quarterly installments and principal is due April 30, 1998. At year end,
the note was current. The note is secured by Mr. Chaudhary's vested, but
unexercised, options to acquire Common Stock of the Company. In September 1997,
the Company commenced amortization of the note by applying twenty percent of Mr.
Chaudhary's salary thereto.
During 1996, the Company loaned $30,000 to William J. Hickey, a director.
Such loan is evidenced by an unsecured promissory note, with interest of 9%
payable at maturity.
The Company charged SEDCO and Capco $6,600 for administrative services
provided to such companies during the nine months ended September 30, 1997. Such
administrative services consisted largely of Mr. Chaudhary's time.
The Company charged Capco $23,335 for charges incurred in connection with
the Solv-Ex Corporation matter, and $93,198 for an advance against an
indemnification provided by Capco during the nine months ended September 30,
1997.
During the nine months ended September 30, 1997, the Company billed a
subsidiary of Capco a total of $30,800 and received payments of $92,000 which
included amounts billed in the prior year, in connection with the subsidiary's
participation in drilling and production activities in one of the Company's oil
properties.
During the nine months ended September 30, 1997, the Company charged
interest to SEDCO, Ilyas Chaudhary and William Hickey (a former director of the
Company) in the amounts of $6,500, $20,400, and $2,000, respectively, on
outstanding, interest-bearing indebtedness to the Company. The Company received
$19,300 from Mr. Chaudhary during the period in payment of interest charges.
During the nine months ended September 30, 1997, the Company incurred
interest charges in the total amount of $60,200 on the notes payable to Capco.
The Company paid Capco a total of $142,000 for such interest charges, which
included amounts charged, but unpaid, at the end of the previous year.
From time to time the Company charters from a non-affiliated airplane
leasing service, a jet airplane acquired by Mr. Chaudhary in 1997. When
chartering the airplane, the Company pays the rate charged others by the leasing
service, less a discount, so that the rate paid by the Company is less than that
paid by others. Use of the airplane indirectly benefits Mr. Chaudhary since it
reduces the amount of time he is required to engage the airplane. During 1997,
the Company incurred usage charges of $49,400.
In July 1997, the Company and Solv-Ex Corporation, which owned interests in
two tar sands licenses in the Athabasca region of Alberta, Canada, informally
agreed to terms upon which the Company would acquire a 55% interest in the
licenses, related improvements and certain related technology, subject to
various conditions, including satisfactory results of a due diligence
investigation by the Company. Solv-Ex and its principal subsidiary have filed
for reorganization pursuant to the United States Bankruptcy Code and for
protection under analogous Canadian legislation. To conclude the transaction,
the Company would be required to invest approximately $15 million, largely to
pay creditors in Canada and would then undertake project development, which
could cost as much as $1 billion. In lieu of committing to the purchase, the
Company entered into an agreement with Capco by which the Company transferred to
Capco its rights under such agreements in exchange for Capco's agreement to
convey to the Company a 2% overriding royalty on the project (commencing after
the project generated $10 million in gross revenues) and granted to the Company
the right to acquire up to 25% of the interests in the project that are acquired
by Capco for the same proportion of Capco's cost of acquisition and maintenance
of the project. The option runs for two years from the date of Capco's
acquisition of the properties or the company. Neither of these events has
occurred. In the investigation and negotiations of the acquisition of the tar
sands project, the Company and Capco had agreed that the Company would bear all
costs, internal and third party, incurred by the Company prior to August 13,
1997 and that Capco would bear the expenses incurred subsequent to said date.
Such costs include $100,000 lent to Solv-Ex as an inducement to negotiate and
execute a purchase agreement. The Company's total costs in respect of the
acquisition (excluding the loans) are approximately $60,000.
In November 1997, the Company and a large independent oil company each
entered into an agreement with Hamar II Associates, LLC, an entity in which
Rodney C. Hill, a director of the Company is a member, providing for the Company
and the large independent to acquire oil and gas leases and to participate in
the drilling of a test well in northern California, to bear a proportionate part
of the lease acquisition and maintenance payments and to pay a proportionate
share (30% in the case of the Company and 60% in the case of the large
independent) of a consideration of $100,000 to members of Hamar, including
Rodney C. Hill. The Company has orally agreed to issue 20,000 shares of its
Common Stock for no additional consideration should the test well drilled on the
Behemoth Prospect be productive in quantities deemed commercial by the Company.
Save for the issuance of the Common Stock, the terms of participation are the
same for the Company and the large independent, which would be the operator of
the project if it were successful.
Rodney C. Hill, a director of the Company, is the sole stockholder of Rodney
C. Hill, a Professional Corporation, which acts as general counsel to the
Company. In 1997, such corporation was engaged to provide legal services to the
Company pursuant to a retainer agreement, which may be canceled by the Company
at any time, and pursuant to which such corporation receives an annual retainer
of $150,000 and reimbursement of certain expenses. During 1997, Mr. Hill was
granted options to acquire 125,000 shares of the Common Stock of the Company at
a price equal to the current fair market value of the Common Stock at the time
of grant that vest over a period of five years.
Ronald D. Ormand, a director of the Company, is a Managing Director of
CIBC-Oppenheimer & Co., Inc., which has rendered investment banking services to
the Company. CIBC-Oppenheimer & Co., Inc. is expected to render additional
investment banking services to the Company in the future.
William N. Hagler, a director of the Company, is the President of Unico,
Inc. and the President and a director of Capco.
PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information with respect to
beneficial ownership of the Common Stock by (i) each person who is either the
record owner or known to the Company to be a beneficial owner of more than 5% of
the Common Stock, (ii) each director and named executive officer of the Company
and (iii) all directors and officers of the Company as a group. Shares
Beneficially Owned and as a Percent of Common Stock is given as of December 31,
1997, when there were 10,883,908 shares outstanding. Ownership as a Percent of
Common Stock Assuming Full Conversion and Exercise assumes that the 10,000
shares of Series A Convertible Preferred Stock are converted at $8.50 per share
(the closing bid for the Company's Common Stock on December 31, 1997) and that
all 269,663 Warrants issued in connection with the Series A Preferred Stock are
exercised. Such conversion and exercise would increase the outstanding shares by
1,446,134 shares to 12,330,042. Because the Series A Preferred Stock is not
required to be converted and the conversion rate varies with the current price
of the stock these numbers could vary materially.
Ownership as a Percent of
Common Stock Assuming Full
Ownership as a Percent of Conversion and Exercise
Shares Beneficially Common Stock
Owned (1)
Principal Stockholders:
Capco Resources Ltd. (2)......... 5,471,300 50.27% 44.37%
2236 S. Broadway, Suite K
Santa Maria, CA 93456
Ilyas Chaudhary (2)(3)........... 5,858,010 53.82% 47.51%
3201 Airpark Dr., Suite 201
Santa Maria, California 93456
Other Directors and Named
Executive Officers:
Walton C. Vance.................. 3,000 * *
William N. Hagler................ 14,000 * *
Ronald D. Ormand................. - * *
Rodney C. Hill................... 1,500 * *
Alex S. Cathcart................. - * *
Faysal Sohail.................... 31,600 * *
Bradley T. Katzung............... 360 * *
Herb Miller...................... - * *
All Directors and Officers as a 5,908,470 54.29% 47.92%
Group (3)..........................
SELLING STOCKHOLDERS (4)
------------------------ ------------------------
Amount and Percentage
Shares Beneficially Amount of Shares to be to be Owned After
Owned Prior to the Offered (5) Completion of the
Offering Offering (5)
RGC International Investors (6) 1,401,190 (7) 1,401,190 0
Aberfoyle Capital Limited 44,944 (8) 44,944 0
- --------------------------------------------------------------
* Less than one percent.
(1) Except as otherwise indicated, the Company believes that the beneficial
owners of the Common Stock listed above have sole investment and voting
power with respect to such shares, subject to community property laws
where applicable.
(2) Mr. Chaudhary owns of record and beneficially 1,130 shares of Common
Stock and options to acquire 380,000 shares of Common Stock of which
options to purchase 60,000 shares were exercisable as of December
31, 1997. Mr. Chaudhary owns 50% of a privately held Canadian
company, which through a subsidiary, owned 90% by it and 10% by Mr.
Chaudhary, owns 1,582,126 shares of the common stock of Capco, which
in turn owns directly and indirectly through a wholly owned subsidiary,
5,471,300 shares (50.27%) of Common Stock. Mrs. Bushra Chaudhary,
the wife of Mr. Chaudhary, owns the remaining 50% of the privately
held Canadian company. Faisal Chaudhary, the adult son of Mr. and
Mrs. Chaudhary, owns 905,961 shares of the common stock of Capco and
Aamna Chaudhary, the daughter of Mr. and Mrs. Chaudhary, owns
905,961 shares of the common stock of Capco. Mr. and Mrs. Chaudhary
each disclaim beneficial interest in the shares of Capco owned by
each other and in the shares held by Faisal Chaudhary. SEDCO, a
corporation wholly owned by Mr. Chaudhary, owns 385,580 shares of
Common Stock (3.54%) and 4,227,821 shares of the common stock of
Capco. As of December 31, 1997 there were 9,148,311 outstanding
shares of the common stock of Capco. Shares in Capco owned by members
of his family may be deemed to be owned by Mr. Chaudhary by reason of
the attribution rules of the Securities and Exchange Commission.
(3) Includes 5,471,300 and 385,580 shares of Common Stock of the Company
owned by Capco and SEDCO, respectively. Mr. Chaudhary, as the
controlling stockholder of such companies, is deemed to be the
beneficial owner of such shares.
(4) Selling Stockholders do not and have not had any material relationships
with the registrant or any of its affiliates.
(5) These numbers assume that the Selling Stockholders offer all shares
issuable upon conversion of the Series A Preferred Stock and
exercise of the
Warrants and that all Shares so issued are sold in the Offering.
(6) The number of shares set forth in the table represents an estimate
of the number of shares of Common Stock to be offered by the
Selling Stockholder. The actual number of shares of Common Stock
issuable upon conversion of Series A Preferred Stock and exercise
of the warrants is indeterminate, is subject to adjustment and could
be materially less or more than such estimated number depending
on factors which cannot be predicted by the Company at this time,
including, among other factors, the future market price of the Common
Stock. The actual number of shares of Common Stock offered hereby,
and included in the Registration Statement of which this Prospectus
is a part, includes such additional number of shares of Common Stock
as may be issued or issuable upon conversion of the Series A Preferred
Stock and exercise of the Warrants and the Redemption
Warrants by reason of the floating rate conversion price mechanism
or other adjustment mechanisms described therein, or by reason of
any stock split, stock dividend or similar transaction involving
the Common Stock, in order to prevent dilution, in accordance with
Rule 416 under the Securities Act. Pursuant to the terms of the
Series A Preferred Stock, the shares of Series A Preferred Stock are
convertible and the Warrants are exercisable by any holder only to
the extent that the number of shares of Common Stock thereby
issuable, together with the number of shares of Common Stock owned by
such holder and its affiliates (but not including shares of Common
Stock underlying unconverted shares of Series A Preferred
Stock) would not exceed 4.9% of the then outstanding Common Stock as
determined in accordance with Section 13(a) of the Exchange Act.
Accordingly, the number of shares of Common Stock set forth in the
table for this Selling Stockholder exceeds the number of shares of
Common Stock that this Selling Stockholder could own beneficially
at any given time through their ownership of the Series A Preferred
Stock. In that regard, beneficial ownership of this Selling
Stockholder set forth in the table is not determined in accordance with
Rule 13d-3 under the Exchange Act.
(7) This number is the sum of 1,176,471 (the shares issuable upon
conversion at a Conversion Price of $8.50, the closing bid price for
the Common Stock on December 31, 1997) and 224,719 (the number of
shares issuable upon exercise of the Selling Stockholder's Warrants).
(8) This number is the number of shares issuable upon exercise of the
Warrants issued to Aberfoyle as a fee in connection with the
placement of the Series A Preferred Stock.
DESCRIPTION OF CAPITAL STOCK
The authorized capital stock of the Company consists of 150,000,000 shares
of Common Stock, par value $.001 per share, and 50,000,000 shares of preferred
stock, par value $.001 per share (the "Preferred Stock").
Common Stock
As of December 31, 1997, the Company had 10,883,908 shares of Common Stock
issued and outstanding. 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 "Price Range of Common Stock 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. All
outstanding shares of Common Stock are fully paid and nonassessable.
Preferred Stock
On December 31, 1997, the Company issued 10,000 shares of Series A
Convertible Preferred Stock (the "Series A Preferred Stock") in exhange for $10
million. The Series A Preferred Stock bears a cumulative dividend of 6% per
annum and is convertible at the option of the holder into shares of Common Stock
at a price equal to the lower of $9.345 or the average closing bid price for any
three consecutive trading days during the 30 trading day period ending one
trading day prior to the date the conversion notice is sent to the Company. In
general, conversion of the Series A Preferred Stock can occur after 120 days
from its issuance, in monthly increments of 20% of the amount issued. The Series
A Preferred Stock may be converted into a maximum of approximately 2,150,000
shares of the Common Stock (subject to increase in the event of certain dilutive
events), unless either shareholder or regulatory approvals are obtained, which
the Company may be obligated to seek. The issuance was exempt from registration
under Rule 506 of Regulation D of the Securities Act.
The Series A Preferred Stock is redeemable by the Company at any time and
must be redeemed upon the occurrence of certain events. The Company may redeem
the Series A Preferred Stock until April 29, 1998 at 115% of its stated value
plus accrued dividends and the issuance of a five year warrant to purchase
200,000 shares of the Common Stock at 105% of the average closing bid price for
the five consecutive trading days preceding the date fixed for redemption. After
April 29, 1998, the Company may still redeem the Preferred Stock, but the holder
will have the ability to convert the Series A Preferred Stock into Common Stock.
The Series A Preferred Stock is senior to all other classes of the Company's
equity securities and is accorded preferential status with regard to dividend
and liquidation rights. The conversion of the Series A Preferred Stock could
have a dilutive effect on the Company's Common Stock. The Series A Preferred
Stock generally carries no voting rights other than with respect to the future
issuance of preferred stock.
The Board has the authority to issue an additional 49,990,000 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. However, approval by the holders of a majority of the Company's
Series A Preferred Stock is required to create any new class or series of
capital stock having a preference over or on par with the Series A Preferred
Stock. 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.
9% Convertible Senior Subordinated Debentures
On December 26, 1995, the Company issued $11,000,000 of 9% Convertible
Senior Subordinated Debentures ("Debentures") due December 15, 2005. The
Debentures are convertible into Common Stock, at the option of the holders of
the Debentures, at any time prior to maturity at a conversion price of $4.38 per
share, subject to adjustment in certain events. The Company has reserved
3,000,000 shares of its Common Stock for the conversion of the Debentures.
Mandatory sinking fund payments of 15% of the original principal, adjusted for
conversions prior to the date of payments, are required annually commencing
December 15, 2000. The Debentures are uncollateralized and subordinated to all
present and future senior debt, as defined, of the Company and are effectively
subordinated to all liabilities of subsidiaries of the Company.
Debentures in the amount of $6,212,000 were converted into 1,419,846 shares
of Common Stock during the year ended December 31, 1996. An additional
$2,839,000 of Debentures were converted into 648,882 shares of Common Stock
during the year ended December 31, 1997.
Certain Corporate Governance Provisions
Certain Anti-Takeover Effects of Certain Provisions of the Delaware General
Corporation Law The Delaware General Corporation Law provides that, subject to
certain exceptions, a corporation shall not engage in any business combination
with any "interested stockholder" for a three-year period following the date
that such stockholder becomes an interested stockholder unless (1) prior to such
date, the board of directors of the corporation approved either the business
combination or the transaction which resulted in the stockholder becoming an
interested stockholder, (2) upon consummation of the transaction which resulted
in the stockholder becoming an interested stockholder, the interested
stockholder owned at least 85% of the voting stock of the corporation
outstanding at the time the transaction commenced (excluding certain shares), or
(3) on or subsequent to such date, the business combination is approved by the
board of directors of the corporation and at an annual or special meeting of
stockholders by the affirmative vote of at least two-thirds of the outstanding
voting stock, which is not owned by the interested stockholder. Except as
specified in the Delaware GCL , an interested stockholder is defined to include
(x) any person that is the owner of 15% or more of the outstanding voting stock
of the corporation, or is an affiliate or associate of the corporation and was
the owner of 15% or more of the outstanding voting stock of the corporation at
any time within three years immediately prior to the relevant date, and (y) the
affiliates and associates of any such person.
Under certain circumstances, the foregoing provisions make it more difficult
for a person who would be an "interested stockholder" to effect various business
combinations with a corporation for a three-year period, although the
stockholders may elect to exclude a corporation from the restrictions imposed
thereby. The Amended and Restated Certificate of Incorporation (the "Certificate
of Incorporation") of the Company does not exclude it from the restrictions
imposed by the foregoing provisions of Delaware law. Those provisions may
encourage companies interested in acquiring the Company to negotiate in advance
with the Board of Directors of the Company, since the stockholder approval
requirement would be avoided if a majority of the directors then in office
approve, prior to the time the stockholder becomes an interested stockholder,
either the business combination or the transaction which results in the
stockholder becoming an interested stockholder.
Limitations on Directors' Liabilities and Indemnification of Officers and
Directors The Certificate of Incorporation and the Bylaws of the Company each
contain provisions that eliminate, to the extent permitted under the Delaware
GCL, the personal monetary liability of a director to the Company and its
stockholders for breach of a director's fiduciary duty of care as a director. If
a director were to breach the duty of care, neither the Company nor its
stockholders could recover monetary damages from the director and the only
course of action available to the stockholders would be equitable remedies, such
as an action to enjoin or rescind a transaction involving the breach. To the
extent certain claims against directors are limited to equitable remedies, these
provisions may reduce the likelihood of derivative litigation and may discourage
stockholders or management from initiating litigation against directors for
breach of their duty of care. Additionally, equitable remedies may not be
effective in many instances. Were a stockholder's only remedy to enjoin the
completion of the Board of Directors' action, this remedy would be ineffective
if the stockholder does not become aware of a transaction or event until after
it has been completed. In such a situation, the stockholder would have no
effective remedy against the directors. Liability for monetary damages remains
for (1) any breach of the duty of loyalty to the Company or its stockholders,
(2) acts or omissions not in good faith or which involve intentional misconduct
or a knowing violation of law, (3) payment of an improper dividend or improper
repurchase or redemption of the Company's stock, or (4) any transaction from
which the director derived an improper personal benefit. The Certificate of
Incorporation also provides that if the Delaware GCL is amended to allow the
further elimination or limitation of the liability of directors, the liability
of the Company's directors shall be limited to the fullest extent permitted by
such amendment. The Delaware GCL permits a corporation to indemnify certain
persons, including officers and directors, who are (or are threatened to be
made) parties to any threatened, pending or completed action, suit or
proceeding, whether civil, criminal, administrative or investigative (other than
derivative actions) by reason of their being officers or directors of the
corporation. The indemnity may include expenses, such as attorneys' fees,
judgments, fines and amounts paid in settlement actually and reasonably incurred
by an indemnified officer or director, provided that he acted in good faith and
in a manner he reasonably believed to be in, or not opposed to, the
corporation's best interests and, in the case of criminal proceedings, provided
he had no reasonable cause to believe that his conduct was unlawful. The Bylaws
provide indemnification to the fullest extent allowed pursuant to the foregoing
provisions of the Delaware GCL.
The Delaware GCL also permits a corporation to extend indemnification to
various persons, including officers and directors, who are, or are threatened to
be made, parties to any threatened, pending or completed action or suit by or in
the right of the corporation to procure a judgment in its favor by reason of
their being officers or directors of the corporation. This indemnity may include
the items specified in the preceding paragraph, subject to the proviso described
in that paragraph. However, no such person will be indemnified as to matters for
which he is found to be liable for negligence or misconduct in the performance
of his duty to the corporation unless, and only to the extent that,
indemnification is ordered by a court. The Certificate of Incorporation and
Bylaws of the Company provide indemnification of the Company's directors and
officers to the fullest extent allowed pursuant to the foregoing provisions.
Insofar as indemnification for liabilities arising under the Securities Act
of 1933 may be permitted to directors, officers or persons controlling the
registrant pursuant to the foregoing provisions, the registrant has been
informed that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Act and is
therefore unenforceable.
As permitted by the Delaware GCL, the Company has obtained a directors' and
officers' liability insurance policy that, subject to the terms and conditions
of the policy, insures the director and officers of the Company against losses
arising from any wrongful act (as defined by such policy) in his or her capacity
as director or officer of the Company.
Transfer Agent and Registrar
The transfer agent and registrar for the Company's Common Stock is American
Securities Transfer, Inc., Denver, Colorado.
PLAN OF DISTRIBUTION
The shares of Common Stock (the "Shares") being offered by the Selling
Stockholders or their respective pledgees, donees, transferees or other
successors in interest, will be sold in one or more transactions (which may
involve block transactions) on the American Stock Exchange or on such other
market on which the Common Stock may from time to time be trading, in
privately-negotiated transactions, through the writing of options on the Shares,
short sales or any combination thereof. The sale price to the public may be the
market price prevailing at the time of sale, a price related to such prevailing
market price or such other price as the Selling Stockholders determine from time
to time. The Shares may also be sold pursuant to Rule 144. The Selling
Stockholders shall have the sole and absolute discretion not to accept any
purchase offer or make any sale of Shares if they deem the purchase price to be
unsatisfactory at any particular time.
The Selling Stockholders or their respective pledgees, donees,
transferees or other successors in interest, may also sell the Shares directly
to market makers acting as principals and/or broker-dealers acting as agents for
themselves or their customers. Brokers acting as agents for the Selling
Stockholders will receive usual and customary commissions for brokerage
transactions, and market makers and block purchasers purchasing the Shares will
do so for their own account and at their own risk. It is possible that a Selling
Stockholder will attempt to sell the Shares of Common Stock in block
transactions to
market makers or other purchasers at a price per share which may be below the
then market price. There can be no assurance that all or any of the Shares
offered hereby will be issued to, or sold by, the Selling Stockholders. The
Selling Stockholders and any brokers, dealers or agents, upon effecting the sale
of any of the Shares offered hereby, may be deemed "underwriters" as that term
is defined under the Securities Act or the Exchange Act, or the rules and
regulations thereunder.
The Selling Stockholders and any other persons participating in the
sale or distribution of the Shares will be subject to applicable provisions of
the Exchange Act and the rules and regulations thereunder, which provisions may
limit the timing of purchases and sales of any of the Shares by the Selling
Stockholders or any other such person. The foregoing may affect the
marketability of the Shares.
The Company has agreed to indemnify the Selling Stockholders, or their
transferees or assignees, against certain liabilities, including liabilities
under the Securities Act, or to contribute to payments the Selling Stockholders
or their respective pledgees, donees, transferees or other successors in
interest, may be required to make in respect thereof.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the Offering, the Company will have outstanding
12,330,042 shares of Common Stock (including 269,663 shares issuable upon the
exercise of the Warrants and an estimated 1,176,471 shares issuable upon
conversion of the Series A Preferred Stock). Of these shares, 6,421,572 shares
will be freely tradeable without restriction or further registration under the
Securities Act. Of the remaining shares, 5,908,470 will be "restricted
securities" ("Restricted Shares") within the meaning of Rule 144 under the
Securities Act. In addition, approximately 822,629 shares of Common Stock may be
issued upon the conversion of the outstanding Debentures, the conversion price
for which is $4.38 per share. See "Notes to Consolidated Financial Statements
Note 8 Long Term Debt." Sales of any of these 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 -- Factors Relating to the Company
- -- Shares Eligible for Future Sale; Control by Significant Stockholder."
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 one year, 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 Commission with respect to such
sale. Such sales under Rule 144 are also subject to 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.
CERTAIN LEGAL MATTERS
The validity of the Common Stock will be passed upon for the Company by
Gibson, Dunn & Crutcher LLP, Denver, Colorado, as counsel to the Company.
EXPERTS
The Consolidated Financial Statements of the Company as of December 31, 1995
and 1996, and for the three years in the period ended December 31, 1996 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 information appearing in this Prospectus with respect to the Company's
proved reserves at December 31, 1994, 1995 and 1996, and to the extent stated
herein, was estimated by Netherland, Sewell & Associates, Inc. and Sproule
Associates Limited, independent petroleum engineers. Such information is
included herein on the authority of such firms as experts in petroleum
engineering.
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. The Registration
Statement, of which this Prospectus is a part, as well as 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 Commission
also maintains a worldwide web site (address: http://www.sec.gov) that contains
reports, proxy and information statements and other information regarding
registrants that file electronically with the Commission. The Common Stock is
listed on the American Stock Exchange and such reports and other information
concerning the Company also can be obtained at the offices of the American Stock
Exchange at 86 Trinity Place, New York, New York 10006-1881.
The Company has filed with the Commission a registration statement on Form
S-1 (the "Registration Statement") under the Securities Act of 1933, as amended
(the "Securities Act") with respect to the Common Stock. This Prospectus, which
constitutes part of the Registration Statement, omits certain of the information
contained in the Registration Statement and the exhibits thereto which are 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, agreement or other document
referred to are not necessarily complete and in each instance reference is made
to the copy of such contract, agreement or other documents filed as an exhibit
to the Registration Statement for a more complete description of the matter
involved, each such statement being qualified in all respects by such reference.
Appendix A
GLOSSARY
The following defined terms have the indicated meanings when used in this
Prospectus:
Bbl or barrel means 42 United States gallons liquid volume, usually used herein
in reference to crude oil or other liquid hydrocarbons. Bcf means one billion
cubic feet of gas. BOE or Barrels of oil equivalent converts gas to oil at a
ratio of 6,000 cubic feet of gas to one Bbl of oil, usually. Then oil and gas
are added together for total BOE. BOEPD means barrels of oil equivalent per day.
bopd means barrels of oil per day. BTU means British Thermal Unit, which is a
heating equivalent measure for natural gas and is an alternate measure of
natural gas reserves, as opposed to Mcf, which is strictly a measure of natural
gas volume. Typically prices quoted for natural gas are designated as price per
MMBTU, the same basis on which natural gas is contracted for sale. Completion
means the installation of permanent equipment for the production of crude oil or
gas, or in the case of a dry hole, the reporting of abandonment to the
appropriate agency. Developed acreage means the number of acres of oil and gas
leases held or owned, which are allocated or assignable to producing wells or
wells capable of production. Development well means 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. EBITDA means earnings before interest expense, provision (benefit)
for taxes on income, depletion, depreciation and amortization. Ecopetrol means
Empresa Columbiana de Perroles, the Columbian state-owned oil company.
Exploration means the search for economic deposits of minerals, petroleum and
other natural earth resources by any geological, geophysical or geochemical
technique. Exploration well means a well drilled either in search of a new,
as-yet-undiscovered oil or gas reservoir or to greatly extend the known limits
of a previously discovered reservoir, as indicated by reasonable interpretation
of available data, with the objective of completing that reservoir. Field means
a geographic area in which a number of oil or gas wells produce from a
continuous reservoir. Finding Cost is calculated, for a specified time, by
dividing the sum of acquisition, exploration and development costs by the amount
of proved reserves added as a result of acquisition, drilling and other
activities during the same period (including the amount of any proved reserves
added from properties previously acquired and including reserve revisions). GAAP
means generally accepted accounting principles, consistently applied. MBbl means
one thousand barrels of oil. MBOE means one thousand barrels of oil equivalent.
Mbopd means one thousand barrels of oil per day. Mcf means one thousand cubic
feet of natural gas. md means millidarcies , which is a unit of measurement of
the permeability of rock. A Darcy is equalivent to a rate of low of one cubic
centimeter per second through a liquid having a viscosity of one centipoise.
Mineral interest means 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. MMBbl means one
million barrels of oil. MMBOE means one million barrels of oil equivalent. MMcf
means one million cubic feet of natural gas. MWD means measurement while
drilling. Net acres or net wells means the sum of fractional ownership working
interests in gross acres or gross wells. Oil wells or gas wells means those
wells which generate revenue from oil production or gas production,
respectively. Operator means the person or company actually operating an oil or
gas well. Proved developed reserves means Proved Reserves which can be expected
to be recovered through existing wells with existing equipment and operating
methods. Proved reserves means 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 undeveloped reserves means 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. PV-10 Value means the estimated future net revenue to be
generated from the production of proved reserves discounted to present value
using an annual discount rate of 10%. These amounts are calculated net of
estimated production costs and future development costs, using prices and costs
in effect as of a certain date, without escalation and without giving effect to
non-property related expenses such as general and administrative expense, debt
service, future income tax expense or depreciation, depletion and amortization.
See "Risk Factors - Factors Relating to the Oil and Gas Industry and the
Environment -- Uncertainty of Estimates of Reserves and Future Net Revenues."
Recompletion means the completion for production of an existing well bore in
another formation from that in which the well has been previously completed.
Reserve replacement cost means, with respect to proved reserves, a three-year
average calculated by dividing total acquisition, exploration and development
costs by net reserves added during the period. Reservoir means a porous and
permeable underground formation containing a natural accumulation of producible
crude oil and/or gas that is confined by impermeable rock or water barriers and
is individual and separate from other reservoirs. SAGD wells means oil wells
drilled using technology known as "steam assisted gravity drainage," which
involves drilling two horizontal wells in a parallel configuration, one above
the other, and within a short distance of each other. Steam is injected into the
upper wellbore which creates a steam chamber and heats the oil so that it may
flow by gravity to the lower producing wellbore, where it is extracted. Tcf
means one trillion cubic feet of natural gas.
INDEX TO FINANCIAL STATEMENTS
CONSOLIDATED FINANCIAL STATEMENTS OF SABA PETROLEUM COMPANY
AND SUBSIDIARIES
Report of Independent Accountants
Consolidated Balance Sheet at December 31, 1995 and 1996 and
September 30, 1997 (unaudited) ......... F-2
Consolidated Statements of Income for the three years ended December 31, 1996
and the nine months ended
September 30, 1996 and 1997 ......... F-3
Consolidated Statements of Stockholders' Equity for the three years ended
December 31, 1996 and the nine months ended
September 30, 1997 (unaudited) ......... F-4
Consolidated Statements of Cash Flows for the three years ended December 31,
1996 and the nine months ended
September 30, 1996 and 1997 (unaudited)..... F-5
Notes to Consolidated Financial Statements for the three years ended December
31, 1996 and the nine months ended
September 30, 1997 (unaudited) ......... F-6
Supplemental Information About Oil and Gas Producing Activities (unaudited) F-29
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Saba Petroleum Company
We have audited the accompanying consolidated balance sheets of Saba
Petroleum Company and subsidiaries as of December 31, 1995 and 1996, and the
related consolidated statements of income, stockholders' equity and cash flows
for each of the three years in the period ended December 31, 1996. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audits 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 audits provide 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, 1995 and 1996, and the
consolidated results of their operations and cash flows for each of the three
years in the period ended December 31, 1996, in conformity with generally
accepted accounting principles.
Coopers & Lybrand L.L.P.
Los Angeles, California
March 26, 1997
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
December 31, September 30,
1995 1996 1997
--------------------------------- ----------------
ASSETS (unaudited)
Current assets:
Cash and cash equivalents $ 640,287 $ 734,036 $
227,396
Restricted certificate of deposit (Note 2) 1,750,000 - -
Accounts receivable, net of allowance for
doubtful
accounts of $57,000, $65,000 and
$74,000, 4,444,209 7,361,326 10,616,055
respectively
Other current assets 2,995,172 3,485,924
4,281,979
------------ ------------------
Total current assets ------------- 11,581,286 15,125,430
9,829,668
------------ ------------------
Property and equipment (Note 8):
- --------------------------------------------------
Oil and gas properties (full cost method) 32,602,571 44,494,387 71,224,084
Land 1,849,313 1,888,578
2,626,511
Plant and equipment 3,240,771 3,799,307
5,411,999
------------ ------------------
37,692,655 50,182,272 79,262,594
Less accumulated depletion and depreciation (10,108,845) (15,323,780) (20,159,770)
------------ ------------------
Total property and equipment ------------- 34,858,492 59,102,824
27,583,810
------------ ------------------
Other assets:
- --------------------------------------------------
Deposits on properties 50,000 42,529 -
- --------------------------------------------------
Notes receivable, less current portion 9,166 834,590 1,603,891
- --------------------------------------------------
Deferred financing costs 1,995,458 1,123,250 835,424
- --------------------------------------------------
Due from affiliates 183,975 205,226 235,936
- --------------------------------------------------
Deposits and other 99,020 471,513 568,661
- --------------------------------------------------
------------ ------------------
Total other assets ------------- 2,677,108 3,243,912
2,337,619
------------ ------------------
============ ==================
$ 39,751,097 $ 49,116,886 $ 77,472,166
- -------------------------------------------------- ============ ==================
==================================================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities $ 5,619,163 $ 5,377,137 $ 13,586,724
Oil imbalance obligation (Note 2) 692,384 - -
Income taxes payable 541,651 1,981,064 716,232
Current portion of long-term debt 504,985 1,805,556 18,087,907
------------ -----------------
Total current liabilities 7,358,183 9,163,757 32,390,863
- --------------------------------------------------
Long-term debt, net of current portion 23,543,307 20,811,980 20,258,983
Other liabilities 194,836 108,295 106,678
Deferred taxes 321,237 590,285 1,244,285
Minority interest in consolidated subsidiary 485,285 727,359 814,404
------------ -----------------
Total liabilities ------------- 31,401,676 54,815,213
31,902,848
------------ -----------------
- --------------------------------------------------
Commitments and contingencies (Note 12)
- --------------------------------------------------
- --------------------------------------------------
Stockholders' equity:
- --------------------------------------------------
Preferred stock - $.001 par value, authorized
- --------------------------------------------------
50,000,000 shares; none issued - - -
- --------------------------------------------------
Common stock - $.001 par value, authorized
- --------------------------------------------------
150,000,000 shares; issued and
outstanding
- --------------------------------------------------
8,529,180 (1995), 10,081,026 (1996) and
- --------------------------------------------------
10,775,115 (1997) shares 8,529 10,081 10,775
- --------------------------------------------------
Capital in excess of par value 6,787,611 12,891,002 15,301,686
- --------------------------------------------------
Retained earnings 1,038,129 4,802,845 7,350,345
- --------------------------------------------------
Cumulative translation adjustment 22,480 11,282 (5,853)
- --------------------------------------------------
Unearned compensation (8,500) - -
- --------------------------------------------------
------------ -----------------
Total stockholders' equity ------------- 17,715,210 22,656,953
7,848,249
------------ -----------------
============ =================
$ 39,751,097 $ 49,116,886 $ 77,472,166
- -------------------------------------------------- ============ =================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Year Ended December 31, Nine Months Ended September 30,
1994 1995 1996 1996 1997
-------------------------------------------- ---------------------------------
Revenues: (unaudited)
Oil and gas sales $ 12,170,203 $ 16,941,247 $ 31,520,757 $ 22,075,612 $ 25,282,361
Other 783,688 753,008 1,681,587 1,077,428 1,495,839
------------- ------------ ------------- -------------
Total revenues 12,953,891 ------------- 33,202,344 23,153,040 26,778,200
17,694,255
------------- ------------ ------------- -------------
- -------------------------------
Expenses:
- -------------------------------
Production costs 7,547,479 10,561,552 14,604,291 10,955,455 12,249,901
- -------------------------------
General and administrative 1,881,852 2,005,192 3,919,435 2,659,998 3,467,984
- -------------------------------
Depletion, depreciation and
amortization 2,041,032 2,826,684 5,527,418 3,615,631 5,011,562
- -------------------------------
------------- ------------ ------------- -------------
Total expenses 11,470,363 ------------- 24,051,144 17,231,084 20,729,447
15,393,428
------------- ------------ ------------- -------------
- -------------------------------
Operating income 1,483,528 2,300,827 9,151,200 5,921,956 6,048,753
------------- ------------ ------------- -------------
- -------------------------------
Other income (expense):
- -------------------------------
Interest income 25,481 16,924 114,302 82,520 99,008
- -------------------------------
Other 18,397 (26,614) 92,149 152,290 (289,316)
- -------------------------------
Interest expense, net of
interest capitalized
- -------------------------------
of $58,085 (1994) and
$27,369 (1995) (634,292) (1,364,110) (2,401,856) (1,795,113) (1,421,144)
- -------------------------------
Gain on issuance of shares
of - 124,773 8,305 - -
subsidiary
- -------------------------------
------------ ------------- -------------
Total other ------------ ------------- (2,187,100) (1,560,303) (1,611,452)
income (590,414) (1,249,027)
(expense)
------------ ------------- -------------
- -------------------------------
Income before 893,114 1,051,800 6,964,100 4,361,653 4,437,301
income
taxes
- -------------------------------
- -------------------------------
Provision for taxes on income (383,800) (449,636) (2,957,983) (1,962,900) (1,799,807)
- -------------------------------
Minority interest in earnings
of - (55,632) (241,401) (178,021) (89,994)
consolidated subsidiary
------------- -------------- ------------ ------------- -------------
Net income $ 509,314 $ 546,532 $ 3,764,716 $ 2,220,732 $ 2,547,500
============ ============= =============
===============================
Net earnings per common share:
===============================
Primary $ 0.06 $ 0.06 $ 0.40 $ 0.24 $ 0.23
============ ============= =============
Fully-diluted $ 0.06 $ 0.06 $ 0.37 $ 0.24 $ 0.22
============ ============= =============
===============================
Weighted average common and
===============================
common equivalent shares
outstanding:
===============================
Primary 7,995,574 8,742,768 9,416,033 9,223,994 11,192,408
===============================
Fully-diluted 7,995,574 8,784,099 12,066,256 11,971,802 12,229,478
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY The
accompanying notes are an integral part of these financial statements.
Common Stock Capital In Cumulative
Shares Amount Excess Translation
Of Par Value Adjustment
------------ ------------ -------------- --------------
Balance at December 31,1993 .............................. 7,194,074 $ 7,194 $ 4,398,141 $ --
Exercise of options .................................. 400,000 400 625,356 --
Issuance of Common Stock for interest in oil and gas . 44,440 44 66,616 --
property
Issuance of Common Stock for acquisition of subsidiary 600,000 600 -- --
Contributed surplus .................................. -- -- 674,106 --
Net Income ........................................... -- -- -- --
----------- ----------- ----------- -----------
Balance at December 31, 1994 ............................. 8,238,514 8,238 5,764,219 --
Minority interest in subsidiary ...................... -- -- -- --
Exercise of options .................................. 116,666 117 189,466 --
Issuance of Common Stock for compensation ............ 24,000 24 25,476 --
Issuance of Common Stock ............................. 150,000 150 599,850 --
Cumulative translation adjustment .................... -- -- -- 22,480
Unearned compensation ................................ -- -- -- --
Contributed surplus .................................. -- -- 208,600 --
Net income ........................................... -- -- -- --
----------- ----------- ----------- -----------
Balance at December 31, 1995 ............................. 8,529,180 8,529 6,787,611 22,480
Exercise of options .................................. 118,000 118 646,982 --
Issuance of Common Stock ............................. 14,000 14 41,986 --
Cumulative translation adjustment .................... -- -- -- (11,198)
Unearned compensation ................................ -- -- -- --
Debenture conversions ................................ 1,419,846 1,420 5,414,423 --
Net income ........................................... -- -- -- --
----------- ----------- ----------- -----------
Balance at December 31, 1996 ............................. 10,081,026 10,081 12,891,002 11,282
Exercise of options .................................. 154,000 154 227,346 --
Cumulative translation adjustment .................... -- -- -- (17,135)
Debenture conversions ................................ 540,089 540 2,183,338 --
Net income ........................................... -- -- -- --
=========== =========== =========== ===========
Balance at September 30, 1997 (unaudited) ................ 10,775,115 $ 10,775 $15,301,686 $ (5,853)
=========== =========== =========== ===========
Unearned Retained Total
Compensation Earnings Shareholders'
Equity
-------------- ----------- ----------------
Balance at December 31,1993 .............................. $ -- $ 1,556 $ 4,406,891
Exercise of options .................................. -- -- 625,756
Issuance of Common Stock for interest in oil and gas .
property -- -- 66,660
Issuance of Common Stock for acquisition of subsidiary -- -- 600
Contributed surplus .................................. -- -- 674,106
Net Income ........................................... -- 509,314 509,314
----------- ----------- -----------
Balance at December 31, 1994 ............................. -- 510,870 6,283,327
Minority interest in subsidiary ...................... -- (19,273) (19,273)
Exercise of options .................................. -- -- 189,583
Issuance of Common Stock for compensation ............ -- -- 25,500
Issuance of Common Stock ............................. -- -- 600,000
Cumulative translation adjustment .................... -- -- 22,480
Unearned compensation ................................ (8,500) -- (8,500)
Contributed surplus .................................. -- -- 208,600
Net income ........................................... -- 546,532 546,532
----------- ----------- -----------
Balance at December 31, 1995 ............................. (8,500) 1,038,129 7,848,249
Exercise of options .................................. -- -- 647,100
Issuance of Common Stock ............................. -- -- 42,000
Cumulative translation adjustment .................... -- -- (11,198)
Unearned compensation ................................ 8,500 -- 8,500
Debenture conversions ................................ -- -- 5,415,843
Net income ........................................... -- 3,764,716 3,764,716
----------- ----------- -----------
Balance at December 31, 1996 ............................. -- 4,802,845 17,715,210
Exercise of options .................................. -- -- 227,500
Cumulative translation adjustment .................... -- -- (17,135)
Debenture conversions ................................ -- -- 2,183,878
Net income ........................................... -- 2,547,500 2,547,500
----------- ----------- -----------
Balance at September 30, 1997 (unaudited) ................ $ -- $ 7,350,345 $22,656,953
=========== =========== ===========
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Year Ended December 31, Nine Months Ended
1994 1995 1996 September 30,
1996 1997
(unaudited)
---------------------------------------------- -----------------------------
Cash flows from operating activities:
Net income $ 509,314 $ 546,532 $ 3,764,716 $ 2,220,732 $ 2,547,500
Adjustments to reconcile net income to net
cash
provided by operations:
Depletion, depreciation and 2,041,032 2,826,684 5,527,418 3,615,631 5,011,562
amortization
Amortization of unearned compensation - 17,000 8,500 8,500 -
Deferred tax provision (benefit) 254,800 (39,000) 366,389 - 654,000
Compensation expense attributable to
non-employee option 115,756 - 91,600 91,600 -
Minority interest in earnings of
consolidated
subsidiary - 55,632 241,403 178,021 89,994
Gain on issuance of shares of - (124,773) (8,305) (6,336) (5,533)
subsidiary
Changes in:
Accounts receivable (1,999,984) (2,919,287) (1,821,046) (3,260,779)
100,820
Other assets (299,830) (2,452,503) (572,233) 371,576 35,929
Accounts payable and accrued 2,396,976 (237,328) (1,426,031) 8,199,407
liabilities 588,135
Income taxes payable and other 509,343 650,644 968,349 (1,264,832)
liabilities 36,449
------------ ------------ ------------ ----------- -----------
Net cash provided by operating 1,735,907 6,913,517 4,200,996 12,007,248
activities 3,346,476
------------ ------------ ------------ ----------- -----------
------------ ------------ ------------ ----------- -----------
Cash flows from investing activities:
Deposit (purchase) of restricted - (1,750,000) 1,750,000 875,000 -
certificate of deposit
Expenditures for oil and gas properties (3,661,844) (12,807,412) (12,171,392) (4,921,582) (26,765,927)
Expenditures for equipment, net (797,690) (2,660,120) (585,893) (709,115) (2,308,096)
Proceeds from sale of oil and gas 529,611 157,933 256,646 - -
properties
------------ ------------ ------------ ----------- -----------
Net cash used in investing (3,929,923) (17,059,599) (10,750,639) (4,755,697) (29,074,023)
activities
------------ ------------ ------------ ----------- -----------
------------ ------------ ------------ ----------- -----------
Cash flows from financing activities:
Proceeds from notes payable and long-term 5,986,266 34,814,900 17,085,315 9,700,712 28,649,983
debt
Principal payments on notes payable and
long-term (5,822,026) (19,136,299) (12,296,839) (9,589,794) (10,546,557)
debt
Increase in notes receivable (445,073) - (1,172,639) (300,000) (2,141,992)
Proceeds from notes receivable 74,848 302,968 67,384 27,960 403,479
Increase in deferred financing costs (11,972) (1,854,421) (165,777) (165,777) -
Net change in accounts with affiliated (107,066) (47,120) (21,251) (12,250) (30,725)
companies
Net proceeds from exercise of options and
issuance of
common stock 510,000 789,583 422,500 422,375 227,500
Increase in contributed surplus 674,706 208,600 - - -
Capital subscription of minority interest - 74,778 12,805 10,963 -
------------ ------------ ------------ ----------- -----------
Net cash provided by financing 859,683 15,152,989 3,931,498 94,189 16,561,688
activities
------------ ------------ ------------ ----------- -----------
------------ ------------ ------------ ----------- -----------
Effect of exchange rate changes on cash
and cash equivalents - 12,006 (627) 241 (1,553)
------------ ------------ ------------ ----------- -----------
Net increase (decrease) in cash and cash 276,236 (158,697) 93,749 (460,271) (506,640)
equivalents
Cash and cash equivalents at beginning of year 522,748 798,984 640,287 640,287 734,036
------------ ------------ ------------ ----------- -----------
Cash and cash equivalents at end of year $ 798,984 $ 640,287 $ 734,036 $ 180,016 $ 227,396
============ ============ ============ =========== ===========
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Description of Business and Summary of Significant Accounting Policies
General
Saba Petroleum Company ("Saba" or the "Company") is a Delaware corporation
formed in 1979 as a natural resources company. Saba is an international oil
and gas producer with principal producing properties located in the
continental United States, Canada and Colombia. Until 1994, all of the
Company's principal assets were located in the United States. In 1994 and
1995, the Company acquired interests in producing properties in Canada and
Colombia. For the years ended December 31, 1995 and 1996, approximately
33.3% and 50.4% of the Company's gross revenues from oil and gas production
were derived from its international operations. Saba's principal United
States oil and gas producing properties are located in California,
Louisiana, Michigan, New Mexico and Wyoming. As of December 31, 1996, 55.1%
of the Company's outstanding Common Stock is owned directly, or indirectly,
by the Company's Chief Executive Officer.
In February 1997, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 128, "Earnings Per Share." Statement
of Financial Accounting Standard No. 128 specifies the computation,
presentation, and disclosure requirements for earnings per share and is
effective for financial statements issued for periods ending after December
15, 1997. Management has not yet determined the impact that adoption of
Statement of Financial Accounting Standard No. 128 is expected to have on
the financial statements of the Company.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those
estimates.
Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly and majority-owned subsidiaries. All significant
intercompany balances and transactions have been eliminated.
Interim Financial Information
The consolidated financial statements at September 30, 1996 and 1997, and
for the nine month periods ended September 30, 1996 and 1997, are unaudited
but have been prepared on a basis consistent with the accounting principles
and policies reflected in the financial statements for the year ended
December 31, 1996. In the opinion of management, the accompanying unaudited
consolidated financial statements contain all adjustments (consisting of
normal recurring accruals only) necessary to present fairly the Company's
consolidated financial position as of September 30, 1996 and 1997, and the
consolidated results of operations and cash flows for the nine months ended
September 30, 1996 and 1997.
Fair Value of Financial Instruments
Cash and Cash Equivalents - The Company considers all liquid investments
with an original maturity of three months or less to be cash equivalents.
The carrying amount approximates fair value because of the short maturity
of those instruments.
Other Financial Instruments - The Company does not hold or issue financial
instruments for trading purposes. The Company's financial instruments
consist of notes receivable and long-term debt. The fair value of the
Company's notes receivable and long-term debt, excluding the Debentures, is
estimated based on current rates offered to the Company for similar issues
of the same remaining maturates. The fair value of the Debentures is based
on quoted market prices.
The fair value of the Company's notes receivable and long-term debt,
excluding the Debentures, at December 31, 1995 and 1996 approximates
carrying value. The carrying value and fair value of the Debentures at
December 31, 1995 and 1996 are as follows:
December 31,
1995 1996
----------------------------- -----------------------------
Carrying Carrying
Value Fair Value Value Fair Value
9% convertible senior
subordinated
debentures-due 2005 $11,000,000 $10,945,000 $6,438,000 $36,374,700
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, site restoration, dismantlement and
abandonment costs, net of estimated salvage values, is provided using the
equivalent unit-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.
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 is 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 fifteen years.
Depreciation expense in the fiscal years ended December 31, 1994, 1995,
1996 and the nine month period ended September 30, 1996 and 1997, was
$74,600, $155,900, $293,245, $217,169 and $301,640, 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.
The implementation in 1995 of Statement of Financial Accounting ("SFAS")
No. 121, "Accounting for the Impairment of long-lived Assets and for
long-lived Assets to Be Disposed Of," has had no impact on the financial
statements.
Deferred Financing Costs
The costs related to the issuance of debt are capitalized and amortized
using the effective interest method over the original terms of the related
debt. At September 30, 1997, the Company had unamortized costs in the
amount of $57,837 and $770,261 relating to its bank credit facilities and
debentures, respectively. Amortization expense in the fiscal years ended
December 31, 1994, 1995 and 1996 and the nine month period ended September
30, 1996 and 1997 was $60,000, $63,600, $241,827, $189,696 and $116,855,
respectively.
Stock-Based Compensation
In 1996, the Company implemented the disclosure requirements of SFAS No.
123, "Accounting for Stock-Based Compensation." This statement sets
forth-alternative standards for recognition of the cost of stock-based
compensation and requires that a company's financial statements include
certain disclosures about stock-based employee compensation arrangements
regardless of the method used to account for them. As allowed in this
statement, the Company continues to apply Accounting Principles Board
Opinion (APB) No. 25, "Accounting for Stock Issued to Employees," and
related interpretations in recording compensation related to its plans.
Income Taxes
The Company accounts for income taxes pursuant to the asset and liability
method of computing deferred income taxes. Deferred tax assets and
liabilities are established 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.
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. Foreign currency transaction gains and losses are
included in net income.
Earnings per Common Share
Primary earnings per common share are based on the weighted average number
of shares outstanding during each year plus, when their effect is dilutive,
common stock equivalents consisting of certain shares subject to stock
options. The calculation of fully diluted earnings per common share
additionally assumes the conversion of the 9% convertible senior
subordinated debentures due December 15, 2005, using the conversion price
of $4.38 per common share. In each of 1994 and 1995 primary earnings per
common share equaled fully diluted earnings per share.
Sale of Subsidiary Stock
The Company accounts for a change in its proportionate share of a
subsidiary's equity resulting from the issuance by the subsidiary of its
stock in current operations in the consolidated financial statements.
Two-For-One Forward Stock Split
On November 21, 1996, The Company's Board of Directors approved a
two-for-one forward stock split effected as a stock dividend on all
outstanding shares of Common Stock. The Company's outstanding stock option
awards and Debentures were also adjusted accordingly. The record date
established for such stock split was December 9, 1996 with a payment date
of December 16, 1996. All share and per share amounts have been adjusted to
give retroactive effect to this split for all periods presented.
Reclassification
Certain previously reported financial information has been reclassified to
conform to the current year's presentation.
2. Acquisitions
In September 1995, the Company acquired a 25% interest in the Teca and Nare
oil fields ("Teca/Nare Fields") and a 50% interest in the Velasquez-Galan
pipeline, all of which are located in Colombia, South America. The
Company's gross acquisition cost for the acquired interests was $12.25
million, which was reduced by the Company's share of net revenue credits
from the properties from the effective date of January 1, 1995 to the
closing date ($3.95 million), leaving a net purchase price of $8.3 million.
In addition, the Company assumed an oil imbalance obligation of
approximately $1.25 million at the closing date. In December 1995, the
Company acquired a 50% interest in the Cocorna oil field in Colombia at a
net acquisition cost of $533,000.
In connection with the acquisition of the Teca/Nare Fields, the Colombia
government owned oil company (Ecopetrol) required that Omimex, the operator
of the properties, 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. In
connection with the issuance of the letter of credit, Omimex required that
the Company pledge collateral consisting of a $1.75 million certificate of
deposit. The letter of credit expired by its own terms in 1996 and the
collateral was returned to the Company.
The acquisition cost of the properties has been assigned to various
accounts in the accompanying balance sheet (primarily oil and gas
properties), and the results of operations of the properties are included
in the accompanying financial statements from the respective dates of
acquisition of each property.
The following unaudited proforma financial information presents the results
of operations of the Company as if the acquisitions had occurred as of the
beginning of the respective periods. The proforma financial information
does not necessarily reflect the results of operations that would have
occurred had the properties been acquired at the beginning of the
respective periods.
(Dollars in thousands except Year Ended December 31,
per share amounts) 1994 1995
(unaudited)
Total revenues $ 24,470 $ 27,678
Total operating expenses, including general and
administrative and depletion, depreciation and
amortization (18,320) (20,036)
Interest expense (1,447) (1,985)
Other income (expense) 43 (10)
----------- ----------
Income before income taxes 4,746 5,647
Provision for taxes on income 2,326 2,767
----------- ----------
Net income $ 2,420 $ 2,880
=========== ==========
Net earnings per common share $ 0.30 $ 0.33
=========== ==========
In October 1995, all of the issued shares of Capco Resource Properties Ltd.
("CRPL"), the Company's 100% owned subsidiary, were exchanged for
13,437,322 voting common shares of Beaver Lake Resources Corporation
("BLRC"), a publicly traded corporation located in Alberta, Canada.
The net assets of BLRC were deemed to be acquired at their net book value
(which approximated fair market value) at the date of acquisition.
Net assets acquired were as follows:
Working capital deficiency $ (105,981)
Oil and gas properties 316,420
---------------
$ 210,439
===============
On December 30, 1994, the Company acquired CRPL, a Canadian oil and gas
company, from its parent company, Capco Resources, Ltd., in exchange for
600,000 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.
On the same date as the share exchange with the Company, BLRC acquired
interests in certain oil and gas properties in exchange for 1,443,204
shares of its common stock. Property interests of $399,527 were acquired
and production notes receivable in the amount of $157,311 were deemed to be
paid.
In addition, as part of a private placement of 1,200,000 shares in 1995,
the Company purchased 1,000,000 common shares of BLRC at a cost of
approximately $370,000. In 1996, BLRC issued a total of 35,000 shares of
common stock to minority shareholders. As a result of these transactions,
the Company owned 74.3% of the outstanding common stock of BLRC at December
31, 1996.
The sales of shares of common stock by the subsidiary resulted in net gains
in 1995 and 1996 of $124,773 and $8,305, respectively, which the Company
has reported in current operations. Deferred income taxes have not been
recorded in conjunction with these transactions as the Company plans to
maintain a majority ownership position in the subsidiary.
3. Notes Receivable
Notes receivable are comprised of the following at December 31, 1995 and
1996:
1995 1996
---- ----
Canadian prime plus 1% (5.75% at December 31, 1996) production notes
receivable, with interest paid currently, collateralized by
producing oil and gas properties $ 121,126 $ 120,385
Prime plus 0.75% (9% at December 31, 1996) promissory note from an officer
of the Company with quarterly interest only installments, due April 30,
1998, collateralized by vested stock options
- 300,000
9% note receivable from a director of the Company, due June 30,
1997, uncollateralized - 30,000
Prime plus 0.75% (9% at December 31, 1996) note receivable from joint
venture partner with principal payments through October 2000 and interest
payments at the end of twenty-four and forty-eight
months, collateralized by producing oil and gas properties - 739,206
9.25% note receivable from an employee of the Company, with
principal and interest due in full on September 30, 1997,
collateralized by vested stock options - 45,000
Other 17,526 4,917
----------- -----------
138,652 1,239,508
Less current portion (included in other current assets) 129,486 404,918
=========== ===========
$ 9,166 $ 834,590
=========== ===========
4. Oil and gas properties, land, plant and equipment
Oil and gas properties, land, plant and equipment at December 31, 1995 and
1996 are as follows:
United
States Canada Colombia Total
December 31, 1995
Oil and gas properties
Unevaluated oil and gas
properties $ 305,974 $ - $ - $ 305,974
Proved oil and gas
properties 20,195,774 3,857,561 8,243,262 32,296,597
------------- ------------- ------------- -------------
Total capitalized 20,501,748 3,857,561 8,243,262
costs 32,602,571
Less accumulated
depletion
and depreciation 8,538,599 518,304 780,675 9,837,578
------------- ------------- ------------- -------------
Capitalized costs, $ 11,963,149 $ 3,339,257 $ 7,462,587 $ 22,764,993
net
============= ============= ============= =============
Other property and
equipment
Land $ 1,548,938 $ - $ 300,375 $
1,849,313
Plant and equipment 1,754,329 62,894 1,423,548
3,240,771
------------- ------------- ------------- -------------
62,894 1,723,923
3,303,267 5,090,084
Less accumulated
depreciation 217,270 12,601 41,396 271,267
============= ============= ============= =============
$ 3,085,997 $ 50,293 $ 1,682,527 $
4,818,817
============= ============= ============= =============
December 31, 1996
Oil and gas properties
Unevaluated oil and gas
properties $ 843,351 $ - $ - $ 843,351
Proved oil and gas
properties 29,933,734 4,999,809 8,717,493 43,651,036
------------- ------------- ------------- -------------
Total capitalized 30,777,085 4,999,809 8,717,493 44,494,387
costs
Less accumulated
depletion
and depreciation 11,038,022 824,752 2,921,559 14,784,333
------------- -------------
============= =============
Capitalized costs, $ 19,739,063 $ 4,175,057 $ 5,795,934 $ 29,710,054
net
============= ============= ============= =============
Other property and
equipment
Land $ 1,583,344 $ - $ 305,234 $ 1,888,578
Plant and equipment 2,222,464 69,081 1,507,762 3,799,307
------------- ------------- ------------- -------------
3,805,808 69,081 1,812,996 5,687,885
Less accumulated
depreciation 337,816 26,874 174,757 539,447
============= ============= ============= =============
$ 3,467,992 $ 42,207 $ 1,638,239 $ 5,148,438
============= ============= ============= =============
Costs incurred in oil and gas property acquisition, exploration, and
development activities are as follows:
United
States Canada Colombia Total
December 31, 1995
Exploration $ 328,322 $ 31,718 $ - $ 360,040
Development 1,453,593 134,883 - 1,588,476
Acquisition of proved
properties 3,349,594 802,804 8,243,262 12,395,660
============= ============= ============= =============
Total cost incurred $ 5,131,509 $ 969,405 $ 8,243,262 $ 14,344,176
============= ============= ============= =============
December 31, 1996
Exploration $ 1,832,579 $ 150,262 $ - $ 1,982,841
Development 5,572,690 734,269 - 6,306,959
Acquisition of proved
properties 3,149,644 257,717 474,231 3,881,592
============= ============= ============= =============
Total costs $ 10,554,913 $ 1,142,248 $ 474,231 $ 12,171,392
incurred
============= ============= ============= =============
Oil and gas depletion expense in the years ended December 31, 1994, 1995
and 1996 and the nine month period ended September 30, 1996
and 1997, was $1,906,203, $2,605,419, $4,979,361, $3,207,500 and
$4,541,631, or $1.94, $1.80, $2.22, $1.94 and $2.42 per produced
barrel of oil equivalent, respectively.
5. Statement of Cash Flows
Following is certain supplemental information regarding cash flows for the
years ended December 31, 1994, 1995 and 1996, and for the nine month
periods ended September 30, 1996 and 1997:
December 31 September 30,
---------------------------------------------- --------------------------------
(unaudited)
1994 1995 1996 1996 1997
---- ---- ---- ---- ----
Interest paid $ 462,639 $ 1,388,369 $ 2,309,475 $ 1,517,532 $ 1,428,974
Income taxes paid $ - $ - $ 1,150,029 $ 998,978 $ 2,479,832
Non-cash investing and financing transactions:
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 44,440 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 during the year ended December
31, 1994.
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.
In January 1995, the Company awarded 24,000 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
$1,248,866 which was assumed by the Company.
In October 1995, the Company's Canadian subsidiary issued common stock to
acquire a corporation at a recorded net cost of $210,439.
In October 1995, interests in oil and gas properties with a cost of
$399,527 were acquired by the issuance of 1,443,204 shares of common stock
of the Company's Canadian subsidiary and cancellation of notes receivable
in the amount of $157,311.
In February 1996, the company issued 14,000 shares of Common Stock to a
director of the Company in settlement of an obligation in the amount of $42,000.
Debentures in the principal amount of $6,212,000, less related costs of
$796,157, were converted into 1,419,846 shares of Common Stock during the
year ended December 31, 1996.
The Company incurred a credit to Stockholders' Equity in the amount of
$91,600 resulting from the issuance of stock options to a consultant during
the year ended December 31, 1996.
The Company incurred a credit to Stockholders' Equity in the amount of
$133,000 attributable to the income tax effect of stock options exercised
during the year ended December 31, 1996.
Cumulative foreign currency translation gains (losses) of $18,216 and
($15,655) were recorded during the years ended December 31, 1995 and 1996,
respectively.
The Company realized gains in 1995 and 1996 of $124,773 and $8,305,
respectively, as a result of the issuance of common stock by a subsidiary.
Debentures in the principal amount of $2,363,000 were converted into
540,087 shares of Common Stock during the nine months ended September 30, 1997.
A cumulative foreign currency translation loss in the amount of $17,620 was
recorded during the nine months ended September 30, 1997.
6. Accounts Payable and Accrued Liabilities.
Accounts payable and accrued liabilities at December 31, 1995 and 1996 are
as follows:
1995 1996
---- ----
Trade accounts payable $ 3,568,400 $ 3,545,599
Undistributed revenue payable 398,519 341,614
Insurance and tax assessments payable 716,597 684,758
Other accrued expenses 935,647 805,166
============= ============
Total $ 5,619,163 $ 5,377,137
============= ============
7. Income Taxes.
The components of income (loss) before income taxes and after minority
interest in earnings of consolidated subsidiary for the years ended
December 31, 1994, 1995 and 1996 are as follows:
1994 1995 1996
---- ---- ----
United States $ 734,396 $ (523,572) $ 383,453
Canada 158,718 134,138 693,439
Colombia - 1,385,602 5,645,807
------------- ------------- -------------
$ 893,114 $ 996,168 $ 6,722,699
============= ============= =============
Components of income tax expense (benefit) for the years ended December 31,
1994, 1995 and 1996 are as follows:
1994 1995 1996
---- ---- ----
Current:
Federal $ 19,300 $ (112,364) $ 149,600
State 25,700 45,000 259,994
Foreign 84,000 556,000 2,182,000
------------- ------------- -------------
129,000 488,636 2,591,594
------------- ------------- -------------
Deferred:
Federal 164,400 (44,350) 207,787
State 90,400 5,350 158,602
-------------
------------- -------------
254,800 (39,000) 366,389
------------- ------------- -------------
$ 383,800 $ 449,63 $ 2,957,983
============= ============= =============
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, 1994, 1995 and 1996 as follows:
1994 1995 1996
---- ---- ----
Expected tax provision (benefit) 34.0% 34.0% 34.0%
State income taxes, net of
Federal benefit 5.9 3.3 4.1
Effect of foreign earnings 3.4 (13.0) (0.9)
Change in valuation allowance (2.2) 15.6 4.4
Other 1.9 5.2 2.4
============ ============ ===========
43.0% 45.1% 44.0%
============ ============ ===========
The tax effected temporary differences which give rise to the deferred tax
provision consist of the following:
1994 1995 1996
---- ---- ----
Property and equipment $ 569,600 $ 337,900 $ 1,084,200
Effect of state taxes (39,500) (12,300) (120,000)
Net operating losses (212,400) 209,500 (2,200)
Foreign tax credits -- (640,000) (845,811)
Alternative minimum tax credits (42,600) (38,100) (61,200)
Change in valuation allowance (19,700) 155,000 295,000
Other (600) (51,000) 16,400
-------------- ------------- --------------
$ 254,800 $ (39,000) $ 366,389
============== ============= ==============
The components of the tax effected deferred income tax asset (liability) as
of December 31 are as follows:
1995 1996
Property and equipment $ (976,600) $ (2,060,800)
State taxes 51,800 171,800
Net operating losses 37,200 39,400
Foreign tax credits 640,000 1,600,800
Alternative minimum tax credits 135,200 196,400
Other 51,600 35,200
------------ ------------
(60,800) (17,200)
Valuation allowance (155,000) (450,000)
------------ ------------
Net deferred income tax liability (215,800) $ (467,200)
============ ============
At December 31, 1995 and 1996, $105,400 and $123,000 of current deferred
taxes are included in other current assets, respectively.
At December 31, 1996, the Company had approximately $650,000 of California
net operating loss carryovers that begin to expire in 1998.
At December 31, 1996, the Company had approximately $1,600,000 of foreign
tax credit carryovers, which expire in the year 2001. A $450,000 valuation
allowance has been provided for a portion of the foreign tax credits which
are not likely to be realized during the carryforward period. The Company
also has alternative minimum tax credit carryforwards for federal and state
purposes of approximately $156,700 and $39,700, 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, 1996, management is not aware of such a change for purposes of
section 382.
8. Long-Term Debt
Long-term debt at December 31, 1995 and 1996 and September 30, 1997
consists of the following:
December 31, September 30,
1995 1996 1997
---------------------------------- ------------------------
9% convertible senior subordinated (unaudited)
debentures - due 2005 $ 11,000,000 $ 6,438,000 $ 4,075,000
----------------------------------------------
Revolving loan agreement with a bank 9,500,000 12,100,000 18,700,000
----------------------------------------------
Term loan agreements with a bank - 450,000 12,477,769
----------------------------------------------
Demand loan agreement with a bank 1,026,392 1,605,136 2,642,821
----------------------------------------------
Capital lease obligations - - 451,300
----------------------------------------------
Promissory note 900,000 450,000 -
----------------------------------------------
Promissory notes - Capco 1,621,900 1,574,400 -
--------------
-------------- -- ----------------
24,048,292 22,617,536 38,346,890
Less current portion 504,985 1,805,556 18,087,907
============== ============== == ================
$ 23,543,307 $ 20,811,980 $ 20,258,983
============== ============== == ================
On December 26, 1995, the Company issued $11,000,000 of 9% convertible
senior subordinated debentures ("Debentures") due December 15, 2005. The
Debentures are convertible into Common Stock of the Company, at the option
of the holders of the Debentures, at any time prior to maturity at a
conversion price of $4.38 per share, subject to adjustment in certain
events. The Company has reserved 3,000,000 shares of its Common Stock for
the conversion of the Debentures. The Debentures are not redeemable by the
Company prior to December 15, 1997. Mandatory sinking fund payments of 15%
of the original principal, adjusted for conversions prior to the date of
payments, are required annually commencing December 15, 2000. The
Debentures are uncollateralized and subordinated to all present and future
senior debt, as defined, of the Company and are effectively subordinated to
all liabilities of subsidiaries of the Company. The principal use of
proceeds from the sale of the Debentures was to retire short-term
indebtedness incurred by the Company in connection with its acquisitions of
producing oil and gas properties in Colombia. A portion of the proceeds was
used to reduce the balance outstanding under the Company's revolving credit
agreement. On February 7, 1996, the Company issued an additional $1,650,000
of Debentures pursuant to the exercise of an over-allotment option by the
underwriting group. Net proceeds to the Company were approximately $1.5
million and a portion was utilized to reduce the outstanding balance under
the Company's revolving line of credit.
Certain terms of the Debentures contain requirements and restrictions on
the Company with regard to the following limitations on Restricted Payments
(as defined in the Indenture), on transactions with affiliates, and on oil
and gas property divestitures; Change of Control (as defined), which will
require immediate redemption; maintenance of life insurance coverage of
$5,000,000 on the life of the Company's Chief Executive Officer; and
limitations on fundamental changes and certain trading activities, on
Mergers and Consolidations (as defined) of the Company, and on ranking of
future indebtedness. Debentures in the amount of $6,212,000 were converted
into 1,419,846 shares of Common Stock during the year ended December 31,
1996. An additional $2,363,000 of Debentures were converted into 540,089
shares of Common Stock during the nine month period ended September 30,
1997.
The revolving loan ("Agreement") is subject to semi-annual redeterminations
and will be converted to a three-year term loan on July 1, 1999. 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
principal subsidiaries. The Agreement also provides for a second borrowing
basse term loan of as much as $3.4 million which may be borrowed for the
purpose of development of oil and gas properties in California. Funds
advanced under this credit facility are to be repaid no later than April
30, 1998. At September 30, 1997, the borrowing bases for the two loans were
$18.7 million and $3.4 million respectively. Interest on the two loans is
payable at the prime rate plus 0.25%, or LIBOR rate pricing options plus
2.25%. The weighted average interest rate for borrowings outstanding under
the loans at September 30, 1997 was 8.3%. In accordance with the terms of
the Agreement, and after giving effect to the Company's anticipated capital
requirements, $7.6 million of the loan balance is classified as currently
payable at September 30, 1997. The Agreement, at September 30, 1997,
requires, among other things, that the Company maintain at least a 1 to 1
working capital ratio, stockholders' equity of $18.0 million, 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 limits to
affiliates. The Company was in compliance with the terms of the Agreement
at September 30, 1997.
In September 1997, the Company borrowed $9,687,769 from its principal
commercial lender to finance the acquisition cost of a producing oil and
gas property. Interest is payable at the prime rate (8.5% at September 30,
1997) plus 1.0% until December 1, 1997, and the prime rate plus 2.0%
thereafter. The loan is due to be repaid no later than December 31, 1997,
and, accordingly, is classified as currently payable at September 30, 1997.
The Company's Canadian subsidiary has available a demand revolving reducing
loan in the face amount of $2.8 million. Interest is payable at a variable
rate equal to the Canadian prime rate plus 0.75% per annum (5.5% at
September 30, 1997). The loan is collateralized by the subsidiary's oil and
gas producing properties, and a first and fixed floating charge debenture
in the principal amount of $3.6 million over all assets of the company. The
borrowing base reduces at the rate of $58,000 per month. In accordance with
the terms of the loan agreement, $695,000 of the loan balance is classified
as currently payable at September 30, 1997. Although the bank can demand
payment in full of the loan at any time, it has provided a written
commitment not to do so except in the event of default.
The Company leases certain equipment under agreements which are classified
as capital leases. Lease payments vary from three to four years. The
effective interest rate on the total amount of capitalized leases at
September 30, 1997 was 8.8%.
The promissory note is due to the seller of an oil refining facility, which
was acquired by the Company in June 1994. Final payment of the note, which
bears interest at the prime rate in effect on the note anniversary date,
plus two percent (10.25% at December 31, 1996), is due on June 24, 1997.
The note is collateralized by a deed of trust on the acquired assets.
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 rate of 9% per annum, is due April 1,
2006. The loan proceeds were utilized by the Company principally in
connection with the acquisition of producing oil and gas properties in
Colombia. The notes are subordinated to the same extent the Debentures are
subordinated.
Maturities of long term debt at December 31, 1996 are as follows:
1997 $ 1,805,556
1998 5,091,247
1999 3,083,333
2000 4,067,493
2001 2,525,827
Thereafter 6,044,080
---------
$22,617,536
9. Related Party Transactions
Related party transactions are described as follows:
In 1994, 1995 and 1996, the Company charged its affiliates $105,300,
$92,900 and $26,300, respectively, for reimbursement of certain general and
administrative expenses.
In 1994, the Company sold certain oil and gas producing properties to an
affiliated company for total consideration of $20,630.
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.
In 1995, the Company charged an affiliate $7,600 and was charged $30,000 by
affiliates for interest on short-term advances.
In 1995, the Company received remittances from affiliates totaling $107,300
in payment of prior and current period charges for general and
administrative expenses and cash advances.
In 1995, the Company received a short-term advance in the amount of $10,500
from an affiliate.
In 1995, the Company loaned $101,700 to a company controlled by the
Company's Chief Executive Officer at an interest rate of 9% per annum. The
loan is collateralized by the officer's vested, but unexercised, Common
Stock options.
In 1995, the Company borrowed $350,000 from a company controlled by a
director of the Company. The entire amount, plus interest at the rate of
10% per annum, was repaid in December 1995.
In 1995, affiliated companies loaned a total of $2,221,900 to the Company,
at an interest rate of 9% per annum, in connection with the acquisition of
producing oil and gas properties in Colombia. Of this amount, $600,000 was
converted to equity by the issuance of 150,000 shares of Common Stock of
the Company. The balance of the borrowings is due April 1, 2006 and is
subordinated to the same extent as the Debentures are subordinated. The
Company incurred interest expense in the amount of $67,600 in 1995 as a
result of this indebtedness.
In 1996, the Company provided a short-term advance to an affiliate in the
amount of $10,000.
In 1996, the Company received remittances in the amount of $120,200 and
made payments in the amount of $90,900 for reimbursement of prior period account
balances.
In 1996, the Company charged affiliates $19,400 and was charged $152,300 by
affiliates for interest on promissory notes.
In 1996, the Company loaned $30,000 to a director of the Company, on an
unsecured basis, at an interest rate of 9% per annum.
In 1996, the Company loaned $300,000 to the Chief Executive Officer of the
Company at an interest rate of prime plus 0.75% due in quarterly
installments. The loan is collateralized by the officer's vested, but
unexercised, Common Stock options.
In 1996, an affiliate of the Company participated, on a joint interest
basis, in one of the Company's exploratory drilling prospects. At December
31, 1996, the affiliate had been assessed a total of $112,150 for costs
associated with the drilling prospect. Of such amount, $64,650 was unpaid
at December 31, 1996.
10. Common Stock and Stock Options
In January 1995, the Company awarded 24,000 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 was amortized against earnings over the
contract term.
In July 1995, the Company cancelled its Incentive and Nonqualified Stock
Option Plans. No options were granted under either plan prior to cancellation.
During the year 1995, the Company issued options to acquire 200,000 shares
of the Company's Common Stock to a consultant. The options had an exercise
price of $1.63 and were exercisable for a period of one year, beginning
January 2, 1995. Options to acquire 116,666 shares of Common Stock were
exercised during the year ended December 31, 1995. In July 1995, the
consulting arrangement was terminated and the balance of the options was
cancelled. The Company also issued options to acquire 200,000 shares of the
Company's Common Stock to an employee under the terms of an employment
agreement.
In April 1996 and June 1996, the Company's Board of Directors and
shareholders, respectively, approved the Company's 1996 Incentive Equity
Plan ("Plan"). The purpose of the Plan is to enable the Company to provide
officers, other key employees and consultants with appropriate incentives
and rewards for superior performance. Subject to certain adjustments, the
maximum aggregate number of shares of the Company's Common Stock that may
be issued pursuant to the Plan, and the maximum number of shares of Common
Stock granted to any individual in any calendar year, shall not in the
aggregate exceed 1,000,000 and 200,000, respectively. At December 31, 1996,
no awards had been made under the Plan.
During the year 1996, the Company's issued options to acquire 100,000
shares of the Company's Common Stock to a consultant. The options had an
exercise price of $4.00 and were exercisable over a period of 180 days,
beginning May 21, 1996. The options were fully exercised during the year
1996. The Company also issued options to acquire 20,000 shares of the
Company's Common Stock to an employee under the terms of an employment
agreement.
As of December 31, 1996, the Company had outstanding options for 742,000
shares of Common Stock to certain employees of the Company. These options,
which are not covered by the Incentive Equity Plan, become exercisable
ratably over a period of five years from the date of issue. The exercise
price of the options, which ranges from $1.25 to $4.38, is the fair market
value of the Common Stock at the date of grant. There is no contractual
expiration date for exercise of these options.
The Company accounts for stock based compensation to employees under the
rules of Accounting Principles Board Opinion No 25. The compensation cost
for options granted in 1995 and 1996 was $115,880 and $139,962,
respectively.
Information regarding the shares under option and weighted average exercise
price for the years ended December 31, 1995 and 1996 is as follows:
1995 1996
--------------- -- --------------- --------------- -- -------------
Wt. Avg. Wt. Avg.
Shares Ex. Pr. Shares Ex. Pr.
--------------- --------------- --------------- -------------
--------------- --------------- --------------- -------------
Beginning of year 890,000 $1.42 740,000 $1.40
Granted 400,000 $1.56 120,000 $4.06
Exercised (116,666) $1.63 (118,000) $3.58
Cancelled (433,334) $1.52 - -
--------------- ---------------
=============== ===============
End Of Year 740,000 $1.40 742,000 $1.49
=============== ===============
=============== ===============
Options exercisable
at end of year 176,000 $1.34 306,000 $1.37
=============== =============== =============== =============
=============== =============== =============== =============
Weighted average fair value of
options granted during the year $0.29 $1.17
=============== ===============
The fair value of each option granted during 1995 and 1996 is estimated on
the date of grant using the Black-Scholes option-pricing model with the
following assumptions: (a) risk-free interest rates ranging from 4.9% to
7.9%, (b) expected volatility of 58.4%, (c) average time to exercise
ranging from six month to five years, and (d) expected dividend yield of
0.0%. If the compensation cost for the Company's 1995 and 1996 grants to
employees had been determined consistent with SFAS No. 123, the Company's
net income and net earnings per common share (primary) for 1995 and 1996
would approximate the proforma amounts set forth below:
1995 1996
---- ----
As Reported Proforma As Reported Proforma
Net income $546,532 $457,189 $3,764,716 $3,733,426
============ ============ =========== ============
Net earnings per common share
(primary) $0.06 $0.05 $0.40 $0.40
============ ============ =========== ============
=========== ============
On May 30, 1997, the Company issued options to acquire 595,000 shares of
Common Stock to certain officers and employees in accordance with the
provisions of the 1996 Incentive Equity Plan. The options have an exercise
price equal to of the market value at date of grant and become exercisable
over various periods ranging from two to five years from the date of grant.
No options were exercised during the period ended September 30, 1997.
On May 30, 1997, the Company's Board of Directors authorized, on a deferred
basis, the issuance of 200,000 shares of Common Stock to the Company's
President, the issuance of such shares being contingent upon the officer
remaining in the employ of the Company for a period of two years succeeding
the expiration of his existing employment contract at December 31, 1999,
with such shares to be issued in two equal installments of 100,000 shares
each at the end of each of the two succeeding years.
Additionally, the Board of Directors authorized the issuance of 100,000
shares of performance shares to the Company's President, issuable at the
end of calendar year 1997 provided that certain operating results are
reported by the Company at the end of the year.
As of September 30, 1997, the Company had outstanding options to certain
employees of the Company for the purchase of 588,000 shares of Common
Stock. These options become exercisable over a period of five years from
the date of issue. The exercise price of the options is the fair market
value of the Common Stock at the date of grant. Options to acquire 154,000
shares of Common Stock were exercised during the nine month period ended
September 30, 1997. Options to acquire 284,000 shares of Common Stock were
exercisable at September 30, 1997.
11. Retirement Plan
The Company sponsors a defined contribution retirement savings plan
("401(k) Plan") to assist all eligible U.S. employees in providing for
retirement or other future financial needs. 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 $3,245, $25,745 and $44,014 in 1994,
1995 and 1996, respectively.
12. Commitments and Contingencies
The Company is a defendant in various legal proceedings, 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.
Leases
The Company leases office space, vehicles and office equipment under
non-cancelable operating leases expiring in the years 1997 through 2001.
Future minimum lease payments under all leases are as follows:
Year Ending December 31,
1997 $218,767
1998 176,285
1999 120,151
2000 100,413
2001 96,292
-----------
===========
$711,908
===========
Rent expense amounted to $92,349, $129,470 and $246,013 for the years ended
December 31, 1994, 1995 and 1996, respectively.
Concentration of Credit Risk and Major Customers
The Company invests its cash primarily in deposits with major banks.
Certain deposits may, at times, be in excess of federally insured limits
($2,740,655 and $2,461,583 at December 31, 1995 and December 31, 1996,
respectively, according to bank records). 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, 1995 and 1996 are the
following amounts due from unaffiliated parties (each accounting for 10% or
more of accounts receivable):
1995 1996
---- ----
Customer A $ 1,986,000 $ 2,566,700
================== ===============
Customer B $ 817,900 $ 1,267,100
================== ===============
Customer C $ - $ 899,600
================== ===============
Sales to major unaffiliated customers (customers accounting for 10 percent
or more of gross revenue), all representing purchasers of oil and gas and
related transportation tariffs and the applicable geographic area for each
customer, for each of the years ended December 31, 1994, 1995 and 1996 are
as follows:
Geographic Area 1994 1995 1996
--------------- ---- ---- ---------------
Customer A Colombia $ - $ 4,505,000 $ 13,594,000
=============== =============== ==============
Customer B United States $ 3,713,000 $ 2,926,000 $ 4,117,000
=============== =============== ==============
Customer C United States $ 2,198,000 $ 2,150,000 $ -
=============== =============== ==============
All sales to the geographic area of Colombia are to the government owned
oil company.
Contingencies
The Company is subject to extensive Federal, state, and local environmental
laws and regulations. These requirements, which change frequently, regulate
the discharge of materials into the environment. The Company believes that
it is in compliance with existing laws and regulations.
Environmental Contingencies
Pursuant to the purchase and sale agreement of an asphalt refinery in Santa
Maria, California, the sellers agreed to perform certain remediation and
other environmental activities on portions of the refinery property through
June 1999. Because the purchase and sale agreement contemplates that the
Company might also incur remediation obligations with respect to the
refinery, the Company 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.
The Company, however, believes that all required remediation will be
completed by the seller within 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.
In accordance with the Articles of Association for the Cocorna Concession,
the Concession expired in February 1997 and the property interest reverted
to Ecopetrol. The property is presently under operation by Ecopetrol. Under
the terms of the acquisition of the Concession, the Company and the
operator were required to perform various environmental remedial
operations, which the operator advises have been substantially, if not
wholly, completed. The Company and the operator are awaiting an inspection
of the Concession area by Colombian officials to determine whether the
government concurs in the operator's conclusions. Based upon the advice of
the operator, the Company does not anticipate any significant future
expenditures associated with the environmental requirements for the Cocorna
Concession.
In 1993, the Company acquired a producing mineral interest from a major oil
company ("Seller"). At the time of acquisition, the Company's investigation
revealed that the Seller had suffered a discharge of diluent (a light oil
based fluid which is often mixed with heavier grade crudes). The purchase
agreement required the Seller to remediate the area of the diluent spill.
After the Company assumed operation of the property, the Company became
aware of the fact that diluent was seeping into a drainage area, which
traverses the property. The Company took action to eliminate the fluvial
contamination and requested that the Seller bears the cost of remediation.
The Seller has taken the position that its obligation is limited to the
specified contaminated area and that the source of the contamination is not
within the area that the Seller has agreed to remediate. The Company has
commenced an investigation into the source of the contamination to
ascertain whether it is physically part of the area which the Seller agreed
to remediate or is a separate spill area. Investigation and discussions
with the Seller are ongoing. Should the Company be required to remediate
the area itself, the cost to the Company could be significant. The Company
has spent approximately $240,000 to date in remediation activities, and
present estimates are that the cost of completes remediation could approach
$1 million. Since the investigation is not complete, an accurate estimate
of cost cannot be made.
In 1995, the Company agreed to acquire, for less than $50,000, an oil and
gas interest on which a number of oil wells had been drilled by the seller.
None of the wells were in production at the time of acquisition. The
acquisition agreement required that the Company assume the obligation to
abandon any wells that the Company did not return to production,
irrespective of whether certain consents of third parties necessary to
transfer the property to the Company would be obtained. The Company has
been unable to secure all of the requisite consents to transfer the
property but nevertheless may have the obligation to abandon the wells. The
Company is evaluating its drilling options and is considering whether to
continue to attempt to secure the transfer consents. A preliminary estimate
of the cost of abandoning the wells and restoring the well sites is
approximately $800,000. The Company is currently unable to assess its
exposure to third parties if the Company elects to plug such wells without
first obtaining necessary consent.
The Company, as is customary in the industry, is required to plug and
abandon wells and remediate facility sites on its properties after
production operations are completed. The cost of such operation will be
significant and will occur, from time to time, as properties are abandoned.
There can be no assurance that material costs for remediation or other
environmental compliance will not be incurred in the future. The incurrence
of such environmental compliance costs could be materially adverse to the
Company. No assurance can be given that the costs of closure of any of the
Company's other oil and gas properties would not have a material adverse
effect on the Company.
14. Business Segments
The Company considers that its operations are principally in one industry
segment that of acquisition, exploration, development and production of oil
and gas reserves. A summary of the Company's operations by geographic area
for the years ended December 31, 1994, 1995 and 1996 is as follows:
(Dollars in thousands) Corporate
United and
States Canada Colombia Other Total
Year ended December 31, 1994
Total reveenues $ 10,752 $ 1,766 $ - $ 436 $ 12,954
Production costs 6,722 825 - - 7,547
Other operating expenses 481 176 - - 657
Depreciation, depletion and
amortization 1,510 460 - 71 2,041
Income tax expense (benefit) 693 135 - (444) 384
----------- ---------- ------------
----------- ---------- ------------
Results of operations from oil
and gas producing activities $ 1,346 $ 170 $ -
=========== ========== ============
Interest and other expenses (net) 1,816 1,816
---------- -----------
Net income (loss) $ (1,007) $ 509
========== ===========
Identifiable assets at
December 31, 1994 $ 14,428 $ 3,889 $ - $ (209) $ 18,108
=========== ========== ============ ========== ===========
Year ended December 31, 1995
Total revenues $ 11,538 $ 1,577 $ 4,505 $ 74 $ 17,694
Production costs 7,431 901 2,229 - 10,561
Other operating expenses 398 243 51 - 692
Depreciation, depletion and
amortization 1,735 156 823 113 2,827
Income tax expense (benefit) 849 147 645 (1,191) 450
----------- ---------- ------------
Results of operations from oil
and gas producing activities $ 1,125 $ 130 $ 757
=========== ========== ============
Interest and other expenses (net) 2,617 2,617
---------- -----------
Net income (loss) (1,465) $ 547
========== ===========
Identifiable assets at
December 31, 1995 $ 19,525 $ 3,963 $ 13,514 $ 2,749 $ 39,751
=========== ========== ============ ========== ===========
Year ended December 31, 1996
Total revenues $ 15,907 $ 3,105 $ 13,594 $ 596 $ 33,202
Production costs 8,160 1,172 5,272 - 14,604
Other operating expenses 759 536 213 - 1,508
Depreciation, depletion and
amortization 2,565 353 2,275 334 5,527
Income tax expense (benefit) 1,561 - 2,917 (1,520) 2,958
Results of operations from oil
and gas producing activities $ 2,862 $ 1,044 $ 2,917
=========== ========== ============
Interest and other expenses (net) 4,840 4,840
========== ===========
Net income (loss) $ (3,058) $ 3,765
========== ===========
Identifiable assets at
December 31, 1996 $ 28,730 $ 5,346 $ 12,473 $ 2,568 $ 49,117
=========== ========== ============ ========== ===========
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:
United
Year ended December 31, 1995 States Canada(1) Colombia Total
Oil (Barrels)
Proved reserves:
Beginning of year 6,671,341 464,390 - 7,135,731
Acquisition, exploration and
development of minerals in place 1,295,876 289,113 5,473,310 7,058,299
Revisions of previous estimates (691,553) 264,497 - (427,056)
Production (710,271) (85,800) (430,808) (1,226,879)
Sales of minerals in place (2,798) (6,000) - (8,798)
(2,798)
------------- --------------- ============== ==================
End of year 6,562,595 926,200 5,042,502 12,531,297
============= =============== ============== ==================
Proved developed reserves, end of year 5,385,856 750,500 4,731,369 10,867,725
============= =============== ============== ==================
Gas(Thousands of cubic feet) Proved reserves:
Beginning of year 7,225,973 2,565,800 - 9,791,773
Acquisition, exploration and
development of minerals in place 1,333,669 464,028 - 1,797,697
Revisions of previous estimates 1,519,718 7,832,888 - 9,352,606
Production (938,577) (398,616) - (1,337,193)
Sales of minerals in place (37,734) (88,100) - (125,834)
------------- --------------- -------------- ---------------
End of year 9,103,049 10,376,000 - 19,479,049
============= =============== ============== ==================
Proved developed reserves, end of year 8,190,986 2,051,000 - 10,241,986
============= =============== ============== ==================
(1) See reference (1) on page F-29
United
Year ended December 31, 1996 States Canada (1) Colombia Total
Oil (Barrels)
Proved reserves:
Beginning of year 6,562,595 926,200 5,042,502 12,531,297
Acquisition, exploration and
development of minerals in place 4,501,828 103,837 - 4,605,665
Revisions of previous estimates 5,950,525 24,771 5,595,772 11,571,068
Production (803,070) (134,008) (1,031,207) (1,968,285)
Sales of minerals in place (60,820) - - (60,820)
-------------- ------------------ -------------- -------------
End of year 16,151,058 920,800 9,607,0 26,678,925
============== ================ ================= ============
Proved developed reserves, end of year 7,993,854 710,000 4,692,140 13,395,994
============== ================ =============== ==============
Gas (Thousands of cubic feet) Proved reserves:
Beginning of year 9,103,049 10,376,000 - 19,479,049
Acquisition, exploration and
development of minerals in place 4,186,184 924,033 - 5,110,217
Revisions of previous estimates 1,046,326 48,213 - 1,094,539
Production (1,089,576) (561,042) - (1,650,618)
Sales of minerals in place (132,018) (236,204) - (368,222)
-------------- ---------------- --------------- --------------
End of year 13,113,965 10,551,000 - 23,664,965
============== ================ =============== ==============
Proved developed reserves, end of year 11,520,707 2,654,000 - 14,174,707
============== ================ =============== ==============
(1) The proved reserve information at December 31, 1995 and 1996 includes
the following proved reserve amounts attributable to the approximately
26% minority interest resulting from the CRPL business combination with
BLRC in October 1995. See Note 2 of Notes to Consolidated Financial
Statements.
1995 1996
Oil (Bbls) 237,237 236,911
Gas (Mcf) 2,657,709 2,714,646
Barrels of oil equivalent(BOE) 680,188 689,352
Standardized measure of discounted future net
cash flows $1,893,643 $2,840,628
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.
(Dollars in thousands) 1995
-------------------------------------------------------------------
United
States Canada(1) Colombia Total
Future cash inflows $ 100,559 $ 25,411 $ 52,335 $ 178,305
Future production costs (56,871) (8,979) (30,193) (96,043)
Future development costs (3,997) (3,064) (1,675) (8,736)
Future income tax expenses (10,872) (3,204) (5,623) (19,699)
-------------- -------------- -------------- --------------
Future net cash flows 28,819 10,164 14,844 53,827
10 percent annual discount for
estimated timing of cash flows (9,585) (2,771) (2,406) (14,762)
============== ============== =============== =============
Standardized measure of discounted
future net cash flows $ 19,234 $ 7,393 $ 12,438 $ 39,065
============= ============== ============== ==============
(Dollars in thousands) 1996
---------------------------------------------------------------------
United Canada (1) Colombia Total
States
---------- ---------- --------- --------
Future cash inflows 324,206 39,985 157,552 521,743
Future production costs (143,964) (13,247) (63,458) (220,669)
Future development costs (24,432) (587) (22,153) (47,172)
Future income tax expenses (36,539) (9,529) (22,172) (68,240)
-------------- -------------- -------------- --------------
Future net cash flows 119,271 16,622 49,769 185,662
10 percent annual discount for
estimated timing of cash flows (45,942) (5,581) (17,650) (69,173)
-------------- -------------- -------------- --------------
Standardized measure of discounted
future net cash flows 73,329 11,041 32,119 116,489
============== ============== ============== ===============
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows during 1995 and 1996.
(Dollars in thousands) 1995
-----------------------------------------------------------------
United
States Canada(1) Colombia Total
Balance at beginning of year $ 18,779 $ 2,348 $ - 21,127
Acquisitions, discoveries and extensions 6,561 2,123 17,848 26,532
Sales and transfers of oil and gas
produced, net of production costs (3,873) (670) (1,837) (6,380)
Changes in estimated future
development costs 2,329 (2,716) - (387)
Net changes in prices, net of
production costs (1,682) 1,614 - (68)
Sales of reserves in place (11) (115) - (126)
Development costs incurred
during the period 126 - - 126
Changes in production rates and other (3,358) (2,757) - (6,115)
Revisions of previous quantity estimates (1,452) 7,313 - 5,861
Accretion of discount 2,367 332 - 2,699
Net change in income taxes (552) (79) (3,573) (4,204)
=========== ============= ============= ================
Balance at end of year 19,234 $ 7,393 $ 12,438 39,065
=========== ============= ============= ================
(1) See reference (1) on page F-29
1996
----------------------------------------------------------------
(Dollars in thousands) United
States Canada (1) Colombia Total
------ ---------- - -------- - -----
Balance at beginning of year $ 19,234 $ 7,393 $ 12,438 $ 39,065
Acquisitions, discoveries and extensions 43,988 1,604 - 45,592
Sales and transfers of oil and gas
produced, net of production costs (7,590) (7,605) (17,040) (1,845)
Changes in estimated future
development costs (15,038) (16,233) 2,430
(28,841)
Net changes in prices, net of
production costs 14,951 20,390 41,021 5,680
Sales of reserves in place (667) (77) -
(744)
Development costs incurred
during the period 330 120 - 450
Changes in production rates and other 16 (490) (2,236)
(2,710)
Revisions of previous quantity estimates 32,023 436 32,781 65,240
Accretion of discount 2,467 748 1,601
4,816
Net change in income taxes (16,385) (9,017) (30,360) (4,958)
============== ============= ============= ============
Balance at end of year $ 73,329 $ $ 32,119 $ 11,041
116,489
============== ============= ============= ============
(1) See reference (1) on page F-29
No dealer, salesperson or other person has been
authorized to give any information or to make any
representation 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 of the securities offered hereby
in any jurisdiction to any person to whom it is
unlawful to make such an offer in such jurisdiction.
Neither the delivery of this Prospectus nor any sale made hereunder shall, under
any circumstances, create any implication that the information contained herein
is correct as of any time subsequent to the date hereof or that there has been
no change in the affairs of the Company since such date.
2,153,344 Shares
[Graphic omitted]
SABA PETROLEUM COMPANY
Common Stock
----------------------------------------
PROSPECTUS
----------------------------------------
- ----------------------------------------
January , 1998
TABLE OF CONTENTS
Page
Prospectus Summary............................
Cautionary Statement Regarding Forward
Looking Statements..........................
Risk Factors..................................
The Company...................................
Use of Proceeds...............................
Capitalization................................
Price Range of Common Stock and
Dividend Policy.............................
Selected Financial Data.......................
Management's Discussion and Analysis
of Financial Condition and Results
of Operations...............................
Business......................................
Management....................................
Principal Stockholders........................
Description of Capital Stock..................
Shares Eligible for Future Sale...............
Underwriting..................................
Certain Legal Matters.........................
Incorporation by Reference....................
Experts.......................................
Available Information.........................
Index to Financial Statements.................F-1
Report of Netherland, Sewell & Associates.....A-1
Report of Sproule Associates Limited..........B-1
Glossary...................................... C-1
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
Estimated expenses in connection with the issuance and distribution of the
Common Stock other than underwriting discounts and commissions, all of
which will be borne by the
Company.
Commission registration fee.................................. $4,288
NASD filing fee..............................................
American Stock Exchange listing fee.......................... 10,000
Blue Sky fees and expenses...................................
Printing and engraving expenses.............................. 15,000
Legal fees and expenses...................................... 70,000
Accounting fees and expenses................................. 5,000
Transfer agent and registrar fees............................ 40,000
Other........................................................ 3,000
TOTAL................................................... $ 138,288
Item 14. Indemnification of Directors and Officers.
Section 145 of the Delaware GCL permits a corporation to indemnify its
directors and officers against expenses (including attorney's fees), judgments,
fines and amounts paid in settlements actually and reasonably incurred by them
in connection with any action, suit or proceeding brought by third parties, if
such directors or officers acted in good faith and in a manner they reasonably
believed to be in or not opposed to the best interests of the corporation and,
with respect to any criminal action or proceeding, had no reason to believe
their conduct was unlawful. In a derivative action, i.e., one by or in the right
of the corporation, indemnification may be made only for expenses actually and
reasonably incurred by directors and officers in connection with the defense or
settlement of an action or suit, and only with respect to a matter as to which
they shall have acted in good faith and in a manner they reasonably believed to
be in or not opposed to the best interests of the corporation, except that no
indemnification shall be made if such person shall have been adjudged liable to
the corporation, unless and only to the extent that the court in which the
action or suit was brought shall determine upon application that the defendant
officers or directors are reasonably entitled to indemnity for such expenses
despite such adjudication of liability. The Company's Bylaws provide that it
shall indemnify its directors, officers, employees and agents to the fullest
extent permitted by the Delaware GCL.
In addition, the Company's Certificate of Incorporation provides that to the
fullest extent permitted by the Delaware GCL, a director of the Company shall
not be liable to the Company or its stockholders for monetary damages for breach
of fiduciary duty as a director. Under the Delaware GCL, liability of a director
may not be limited (i) for any breach of the director's duty of loyalty to the
Company or its stockholders, (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 derives an
improper personal benefit. The effect of this provision in the Company's
Certificate of Incorporation is to eliminate the rights of the Company and its
stockholders (through stockholders' derivative suits on behalf of the Company)
to recover monetary damages against a director for breach of the fiduciary duty
of care as a director (including breaches resulting from negligent or grossly
negligent behavior), except in the situation described in clauses (i) through
(iv) above. The provision does not limit or eliminate the rights of the Company
or any stockholders to seek non-monetary relief such as an injunction or
rescission in the event of a breach of a director's duty of care.
Pursuant to Section 145 of the Delaware GCL, the Company maintains
directors' and officers' liability insurance coverage.
Item 15. Recent Sales of Unregistered Securities.
On September 15, 1994, the Company issued 44,440 unregistered shares of
Common Stock to Magnum Petroleum, Inc. in exchange for interests in oil and gas
properties valued at approximately $66,660. The Common Stock was exempt from
registration pursuant to Regulation D of the Securities Act and Section
4(2) of the Securities Act. On
December 30, 1994, the Company issued 300,000 unregistered shares to Capco in
connection with the acquisition of Capco Resource Properties Ltd. The Common
Stock was exempt from registration pursuant to Section 4(2) of the Securities
Act.
In January 1995, the Company issued 24,000 unregistered shares of Common
Stock, pursuant to a consulting agreement with Burt Cormany. The Common Stock
was exempt from registration pursuant to Section 4(2) of Regulation D under the
Securities Act.
On December 31, 1997, the Company issued 10,000 shares of Series A
Convertible Preferred Stock (the "Series A Preferred Stock") in exchange for $10
million. The Series A Preferred Stock bears a cumulative dividend of 6% per
annum and is convertible at the option of the holder into shares of Common Stock
at a price equal to the lower of $9.345 or the average closing bid price for any
three consecutive trading days during the 30 trading day period ending one
trading day prior to the date the conversion notice is sent to the Company. In
general, conversion of the Series A Preferred Stock can occur after 120 days
from its issuance, in monthly increments of 20% of the amount issued. The Series
A Preferred Stock may be converted into a maximum of approximately 2,150,000
shares of the Common Stock (subject to increase in the event of certain dilutive
events), unless either shareholder or regulatory approvals are obtained, which
the Company may be obligated to seek. The issuance was exempt from registration
under Rule 506 of Regulation D of the Securities Act.
The Series A Preferred Stock is redeemable by the Company at any time and
must be redeemed upon the occurrence of certain events. The Company may redeem
the Series A Preferred Stock until April 29, 1998 at 115% of its stated value
plus accrued dividends and the issuance of a five year warrant to purchase
200,000 shares of the Common Stock at 105% of the average closing bid price for
the five consecutive trading days preceding the date fixed for redemption. After
April 29, 1998, the Company may still redeem the Preferred Stock, but the holder
will have the ability to convert the Series A Preferred Stock into Common Stock.
The Series A Preferred Stock is senior to all other classes of the Company's
equity securities and is accorded preferential status with regard to dividend
and liquidation rights. The conversion of the Series A Preferred Stock could
have a dilutive effect on the Company's Common Stock. The Series A Preferred
Stock generally carries no voting rights other than with respect to the future
issuance of preferred stock.
Item 16. Exhibits.
3(i).1 Amended and Restated Certificate of Incorporation of the
Company (filed as Exhibit 4.1 to the Company's Registration
Statement on Form S-8, dated August 21, 1997 and
incorporated herein by reference)
3(i).1(a) Certificate of Designations, Preferences, and Rights of
Series A Convertible Preferred
Stock dated December 31, 1997*
3(ii).1 ByLaws of the Company (filed as Exhibit 4.2 to the Company's
Registration Statement on Form S-8, dated August 21, 1997
and incorporated herein by reference)
4.1 Form of Indenture (including form of Debenture) (filed as
Exhibit 4.1 to the Company's Registration Statement on
Form SB-2 (File No. 33-94678) and incorporated herein by
reference)
5.1 Opinion of Gibson, Dunn & Crutcher LLP regarding legality+
10.1 Form of Indemnification Agreement to be entered into with
officers and directors of the Company (filed as Exhibit 10.1
to the Company's Registration Statement on Form SB-2 (File
No. 33-94678) and incorporated herein by reference)
10.2 Saba Petroleum Company 1996 Equity Incentive Plan (filed as
Exhibit 4.4 to the Company's Registration Statement on Form
S-8, dated August 21, 1997 and incorporated herein by
reference)
10.3 Saba Petroleum Company 1997 Stock Option Plan for
Non-Employee Directors (filed as Exhibit 4.5 to the
Company's Registration Statement on Form S-8, dated August
21, 1997 and incorporated herein by reference)
10.4 Employment Agreement with Ilyas Chaudhary (filed as
Exhibit 10.3 to the Company's Registration Statement
on From SB-2(File No. 33-94678) and incorporated
herein by reference)
10.5 Employment Agreement with Alex Cathcart, dated March 1,
1997, (filed as Exhibit 10.38 to the Company's Quarterly
Report Form 10-Q for the quarter ended June 30, 1997 and
incorporated herein by reference)
10.6 Retainer Agreement with Rodney C. Hill, A Professional
Corporation, dated March 16, 1997 (filed as Exhibit 10.39 to
the Company's Quarterly Report Form 10-Q for the quarter
ended June 30, 1997)
10.7 First Amended and Restated Loan Agreement between the
Company and Bank One, Texas, N.A. (filed as Exhibit 10.1
to the Company's Quarterly Report Form 10-QSB for the
quarter ended September 30, 1996 and incorporated herein by
reference)
10.8 Stock Purchase Agreement (filed as an exhibit to the
Company's Current Report on Form 8-K dated January 10, 1995
and incorporated herein by reference)
10.9 Processing Agreement between Santa Maria Refining Company
and PetroSource Refining Corporation (filed as Exhibit
10.6 to the Company's Registration Statement on Form
SB-2 (File No. 33-94678) and incorporated herein by
reference)
10.10 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire
Teca-Nare Fields (filed as Exhibit 10.7 to the
Company's Registration Statement on Form SB-2 (File No.
33-94678) and incorporated herein by reference)
10.11 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire
Cocorna Field (filed as Exhibit 10.8 to the Company's
Registration Statement on Form SB-2 (File No. 33-94678)
and incorporated herein by reference)
10.12 Agreement among Saba Petroleum Company and Cabot Oil and
Gas Corporation to acquire Cabot Properties (filed as
Exhibit 10.9 to the Company's Registration Statement on
Form SB-2 (File No. 33-94678) and incorporated herein by
reference)
10.13 Agreement among Saba Petroleum Company, Beaver Lake
Resource Corporation and Capco Resource Properties Ltd.
(filed as Exhibit 10.10 to the Company's Registration
Statement on Form SB-2 (File No. 33-94678) and incorporated
herein by reference)
10.14 Amendment to Agreement among the Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire the
Teca-Nare Fields (filed as Exhibit 2.2 to the Company's
Current Report on Form 8-K dated September 14, 1995 and
incorporated herein by reference)
10.15 Promissory Notes of the Company (filed as Exhibit 10.13 to
the Company's Registration Statement on Form SB-2 (file
No. 33-94678) and incorporated herein by reference)
10.16 CRI Stock Purchase Termination Agreement (filed as Exhibit
10.14 to the Company's Registration Statement on Form SB-2
(file No. 33-94678) and incorporated herein by reference)
10.17 Form of Common Stock Conversion Agreement between
Capco and the Company (filed as Exhibit 10.15 to the
Company's Registration Statement on Form SB-2 (file No.
33-94678) and incorporated herein by reference)
10.18 Form of Agreement regarding exercise of preemptive rights
between Capco and the Company (filed as Exhibit 10.16 to the
Company's Registration Statement on Form SB-2 (File No.
33-94678) and incorporated herein by reference)
10.19 Letter Agreement, as amended, between Omimex de Colombia,
Ltd. and the Company (filed as Exhibit 10.17 to the
Company's Registration Statement on Form SB-2 (File No.
33-94678) and incorporated herein by reference)
10.20 Promissory Note of Mr. Chaudhary (filed as Exhibit 10.2
to the Company's quarterly report on Form 10-QSB for the
quarter ended June 30, 1996 and incorporated herein by
reference)
10.21 Form of Stock Option Agreements between Mr. Chaudhary and
Messrs. Hickey and Barker (filed as Exhibit 10.3 to the
Company's quarterly report on Form 10-QSB for the
quarter ended June 30, 1996 and incorporated herein by
reference)
10.22 Form of Stock Option Termination Agreements between the
Company and Messrs. Hagler and Richards (filed as Exhibit
10.4 to the Company's quarterly report on Form 10-QSB for
the quarter ended June 30, 1996 and incorporated herein by
reference)
10.24 Amendment Number Two to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10.1 to the Company's quarterly report on
Form 10-Q for the quarter ended September 30, 1997 and
incorporated herein by reference)
10.25 Amendment Number Three to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10.2 to the Company's Quarterly Report
Form 10-Q for quarter ended September 30, 1997 and
incorporated herein by reference)
10.26 Amendment Number Four to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10 to Saba's Report Form 8-K filed
September 24, 1997 and incorporated herein by reference)
10.27 Corrections relating to Second Amendment dated August 28,
1997, and Fourth Amendment dated September 9, 1997 to the
First Amended and Restated Loan Agreement between Saba
Petroleum Company and Bank One, Texas, N.A. (filed as
Exhibit 10.4 to the Company's Quarterly Report Form 10-Q for
quarter ended September 30, 1997 and incorporated herein by
reference)
10.28 Amendment Number Five to First Amended and Restated Loan
Agreement between the Company
and Bank One, Texas, N.A. (filed as Exhibit 10.4 to
Saba's Report Form 8-K filed
January 15, 1998 and incorporated herein by reference)
10.29 Amendment of the First Amended and Restated Loan Agreement
between the Company and Bank One, Texas, N.A., dated
December 31, 1997 (filed as Exhibit 10.3 to Saba's Report
Form 8-K filed January 15, 1998 and incorporated herein by
reference)
10.30 Securities Purchase Agreement dated December 31, 1997 (filed
as Exhibit 10.1 to Saba's Report Form 8-K filed January 15,
1998 and incorporated herein by reference)
10.31 Registration Rights Agreement dated as of December 31, 1997*
10.32 Stock Purchase Warrant (Closing Warrant) dated December 31,
1997*
10.33 Stock Purchase Warrant (Redemption Warrant) dated December
31, 1997*
10.34 Finders Warrant+
10.35 Agreements among the Company, Amerada Hess Corporation and
Hamar II Associates, LLC dated November 1, 1997+
10.36 Agreements among the Company, Chevron U.S.A. Production
Company and Nahama Natural
Gas.+
16.1 Letter from Jackson & Rhodes P.C. to the Company (filed as
an exhibit to the Company's
Annual Report on Form 10-KSB for the year ended December
31, 1994 and incorporated
herein by reference)
21.1 Subsidiaries of the Company*
23.1 Consent of Gibson, Dunn & Crutcher LLP ( included in Exhibit
5.1)+
23.2 Consent of Coopers & Lybrand L.L.P. (Los Angeles,
California)*
23.3 Consent of Netherland, Sewell & Associates, Inc.*
23.4 Consent of Sproule Associates Limited*
24.1 Powers of Attorney , see p. II-5*
* Filed herewith
+ To be filed by Amendment
Item 17. Undertakings.
The undersigned registrant hereby undertakes that:
(1) For determining any liability under the Securities Act, treat the
information omitted from the form of prospectus filed as part of this
Registration Statement in reliance upon Rule 430A and contained in a
form of prospectus filed by the registrant pursuant to Rule 424(b)(1)
or (4) or 497(h) under the Securities Act as part of this Registration
Statement as of the time The Commission declared it effective.
(2) For determining any liability under the Securities Act, treat each
post-effective amendment that contains a form of prospectus as a new
registration statement for the securities offered therein, and that,
the offering of the securities at that time as the initial bona fide
offering thereof of those securities.
Insofar as indemnification for liabilities arising under the Securities Act
may be permitted for directors, officers and controlling persons of the
registrant pursuant to the foregoing provisions, or otherwise, the registrant
has been advised that in the opinion of the Commission such indemnification is
against public policy as expressed in the Act and is, therefore, unenforceable.
In the event that a claim for indemnification against such liabilities (other
than the payment by the registrant of expenses incurred or paid by a director,
officer or controlling person of the registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the
Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes to supplement the prospectus,
after the expiration of the subscription period, to set forth the results of the
subscription offer, the transactions by the underwriters during the subscription
period, the amount of unsubscribed securities to be purchased by the
underwriters, and the terms of any subsequent reoffering thereof. If any public
offering by the underwriters is to be made on terms differing from those set
forth on the cover page of the prospectus, a post-effective amendment will be
filed to set forth the terms of such offering.
The undersigned registrant hereby undertakes:
(1) To file, during any period in which offers or sales are being made, a
post-effective amendment to this registration statement:
(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933; (ii) To reflect in the prospectus any facts or
events arising after the effective date of the registration statement
(or the most recent post-effective amendment thereof) which,
individually or in the aggregate, represent a fundamental change in the
information set forth in the registration statement. Notwithstanding
the foregoing, any increase or decrease in volume of securities offered
(if the total dollar value of securities offered would not exceed that
which was registered) and any deviation from the low or high and of the
estimated maximum offering range may be reflected in the form of
prospectus filed with the Commission pursuant to Rule 424(b) if, in the
aggregate, the changes in volume and price represent no more than 20
percent change in the maximum aggregate offering price set forth in the
"Calculation of Registration Fee" table in the effective registration
statement. (iii) To include any material information with respect to
the plan of distribution not previously disclosed in the registration
statement or any material change to such information in the
registration statement;
provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) do not apply if
the registration statement is on Form S-3, Form S-8 or Form F-3, and the
information required to be included in a post-effective amendment by those
paragraphs is contained in periodic reports filed with or furnished to the
Commission by the registrant pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 that are incorporated by reference in the registration
statement.
(2) That, for the purpose of determining any liability under the Securities
Act of 1933, each such post-effective amendment shall be deemed to be a new
registration statement relating to the securities offered therein, and the
offering of such securities at that time shall be deemed to be the initial bona
fide offering thereof.
(3) To remove from registration by means of a post-effective amendment any
of the securities being registered which remain unsold at the termination of the
offering.
(4) If the registrant is a foreign private issuer, to file a post-effective
amendment to the registration statement to include any financial statements
required by Rule 3-19 of this chapter at the start of any delayed offering or
throughout a continuous offering. Financial statements and information otherwise
required by Section 10(a)(3) of the Act need not be furnished, provided, that
the registrant includes in the prospectus, by means of a post-effective
amendment, financial statements required pursuant to this paragraph (a)(4) and
other information necessary to ensure that all other information in the
prospectus is at least as current as the date of those financial statements.
Notwithstanding the foregoing, with respect to registration statements on Form
F-3, a post-effective amendment need not be filed to include financial
statements and information required by Section 10(a)(3) of the Act or Rule 3-19
of this chapter if such financial statements and information are contained in
periodic reports filed with or furnished to the Commission by the registrant
pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934
that are incorporated by reference in the Form F-3.
POWER OF ATTORNEY
Saba Petroleum Company, a Delaware corporation, and each person whose
signature appears below, constitute and appoint Ilyas Chaudhary, Rodney C. Hill
and Walton C. Vance, and each of them, with full power to act without the other,
such person's true and lawful attorneys-in-fact, with full power of substitution
and resubstitution, for him and in his name, place and stead, in any and all
capacities, to sign this Registration Statement, and any and all amendments
thereto (including post-effective amendments), and to file the same, with
exhibits and schedules thereto, and other documents in connection therewith,
with the Securities and Exchange Commission, granting unto said
attorneys-in-fact, and each of them, full power and authority to do and perform
each and every act and thing necessary or desirable to be done in and about the
premises, as fully to all intents and purposes as he might or could do in
person, thereby ratifying and confirming all that said attorneys-in-fact, or any
of them, or their or his substitute or substitutes, may lawfully do or cause to
be done by virtue hereof.
SIGNATURE
In accordance with the requirements of the Securities Act of 1933, the
registrant certifies that it has reasonable grounds to believe that it meets all
of the requirements of filing on Form S-1 and authorized this Registration
Statement to be signed on its behalf by the undersigned in the City of Santa
Maria, State of California on January 26, 1998.
SABA PETROLEUM COMPANY
By: /s/ILYAS CHAUDHARY___________________________
Ilyas Chaudhary
Chairman of the Board and
Chief Executive Officer
In accordance with the requirements of the Securities Act of 1933, this
registration statement was signed by the following persons in the capacities and
on the dates stated.
Signatures Title Date
/S/ILYAS CHAUDHARY Chairman of the Board and January 26, 1998
- ---------------------------------------------------- Chief Executive Officer
Ilyas Chaudhary (Principal Executive
Officer)
/s/WALTON C. VANCE Vice President, Chief January 26, 1998
- ---------------------------------------------------- Financial Officer and
Walton C. Vance Secretary and Director
(Principal Financial and
Accounting Officer)
/s/ALEX S. CATHCART President, Chief January 26, 1998
- ---------------------------------------------------- Operating Officer and
Alex S. Cathcart Director
/s/WILLIAM N. HAGLER Director January 26, 1998
- ----------------------------------------------------
William N. Hagler
/s/RONALD D. ORMAND Director January 26, 1998
- ----------------------------------------------------
Ronald D. Ormand
/s/RODNEY C. HILL Director January 26, 1998
- ----------------------------------------------------
Rodney C. Hill
/s/FAYSAL SOHAIL Director January 26, 1998
- ----------------------------------------------------
Faysal Sohail
SABA PETROLEUM COMPANY
EXHIBIT INDEX
3(i).1 Amended and Restated Certificate of Incorporation of the
Company (filed as Exhibit 4.1 to the Company's Registration
Statement on Form S-8, dated August 21, 1997 and
incorporated herein by reference)
3(i).1(a) Certificate of Designations, Preferences, and Rights of
Series A Convertible Preferred
Stock dated December 31, 1997*
3(ii).1 ByLaws of the Company (filed as Exhibit 4.2 to the Company's
Registration Statement on Form S-8, dated August 21, 1997
and incorporated herein by reference)
4.1 Form of Indenture (including form of Debenture) (filed as
Exhibit 4.1 to the Company's
Registration Statement on Form SB-2 (File No. 33-94678)
and incorporated herein by
reference)
5.1 Opinion of Gibson, Dunn & Crutcher LLP regarding legality+
10.1 Form of Indemnification Agreement to be entered into with
officers and directors of the Company (filed as Exhibit 10.1
to the Company's Registration Statement on Form SB-2 (File
No. 33-94678) and incorporated herein by reference)
10.2 Saba Petroleum Company 1996 Equity Incentive Plan (filed as
Exhibit 4.4 to the Company's Registration Statement on Form
S-8, dated August 21, 1997 and incorporated herein by
reference)
10.3 Saba Petroleum Company 1997 Stock Option Plan for
Non-Employee Directors (filed as
Exhibit 4.5 to the Company's Registration Statement on
Form S-8, dated August 21,
1997 and incorporated herein by reference)
10.4 Employment Agreement with Ilyas Chaudhary
(filed as Exhibit 10.3 to the Company's
Registration Statement on Form SB-2 (File No. 33-94678)
and incorporated herein by
reference)
10.5 Employment Agreement with Alex Cathcart, dated March 1,
1997, (filed as Exhibit 10.38 to the Company's Quarterly
Report Form 10-Q for the quarter ended June 30, 1997 and
incorporated herein by reference)
10.6 Retainer Agreement with Rodney C. Hill, A Professional
Corporation, dated March 16, 1997 (filed as Exhibit 10.39 to
the Company's Quarterly Report Form 10-Q for the quarter
ended June 30, 1997)
10.7 First Amended and Restated Loan Agreement between the
Company and Bank One, Texas,
N.A. (filed as Exhibit 10.1 to the Company's Quarterly
Report Form 10-QSB for the
quarter ended September 30, 1996 and incorporated herein by
reference)
10.8 Stock Purchase Agreement (filed as an exhibit to the
Company's Current Report on Form 8-K dated January 10, 1995
and incorporated herein by reference)
10.9 Processing Agreement between Santa Maria Refining Company
and PetroSource Refining
Corporation (filed as Exhibit 10.6 to the Company's
Registration Statement on Form
SB-2 (File No. 33-94678) and incorporated herein by
reference)
10.10 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum
Company to acquire Teca-Nare Fields (filed as
Exhibit 10.7 to the Company's
Registration Statement on Form SB-2 (File No. 33-94678)
and incorporated herein by
reference)
10.11 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum
Company to acquire Cocorna Field (filed as Exhibit 10.8 to
the Company's Registration
Statement on Form SB-2 (File No. 33-94678) and incorporated
herein by reference)
10.12 Agreement among Saba Petroleum Company and Cabot Oil and
Gas Corporation to acquire
Cabot Properties (filed as Exhibit 10.9 to the Company's
Registration Statement on
Form SB-2 (File No. 33-94678) and incorporated herein by
reference)
10.13 Agreement among Saba Petroleum Company, Beaver Lake
Resource Corporation and Capco
Resource Properties Ltd. (filed as Exhibit 10.10 to
the Company's Registration
Statement on Form SB-2 (File No. 33-94678) and incorporated
herein by reference)
10.14 Amendment to Agreement among the Company, Omimex de
Colombia, Ltd. and Texas Petroleum
Company to acquire the Teca-Nare Fields (filed as Exhibit
2.2 to the Company's Current
Report on Form 8-K dated September 14, 1995 and incorporated
herein by reference)
10.15 Promissory Notes of the Company (filed as Exhibit 10.13 to
the Company's Registration
Statement on Form SB-2 (file No. 33-94678) and incorporated
herein by reference)
10.16 CRI Stock Purchase Termination Agreement (filed as Exhibit
10.14 to the Company's Registration Statement on Form SB-2
(file No. 33-94678) and incorporated herein by reference)
10.17 Form of Common Stock Conversion Agreement between Capc
and the Company (filed as
Exhibit 10.15 to the Company's Registration Statement on
Form SB-2 (file No. 33-94678)
and incorporated herein by reference)
10.18 Form of Agreement regarding exercise of preemptive rights
between Capco and the Company (filed as Exhibit 10.16 to the
Company's Registration Statement on Form SB-2 (File No.
33-94678) and incorporated herein by reference)
10.19 Letter Agreement, as amended, between Omimex de Colombia,
Ltd. and the Company (filed
as Exhibit 10.17 to the Company's Registration
Statement on Form SB-2 (File No.
33-94678) and incorporated herein by reference)
10.20 Promissory Note of Mr. Chaudhary (filed as Exhibit 10.2
to the Company's quarterly
report on Form 10-QSB for the quarter ended June 30, 1996
and incorporated herein by
reference)
10.21 Form of Stock Option Agreements between Mr. Chaudhary an
Messrs. Hickey and Barker
(filed as Exhibit 10.3 to the Company's quarterly
report on Form 10-QSB for the
quarter ended June 30, 1996 and incorporated herein by
reference)
10.22 Form of Stock Option Termination Agreements between the
Company and Messrs. Hagler and
Richards (filed as Exhibit 10.4 to the Company's quarterly
report on Form 10-QSB for
the quarter ended June 30, 1996 and incorporated herein by
reference)
10.23 Amendment Number One to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10.20 to the Company's annual report on
Form 10-KSB for the year ended December 31, 1996 and
incorporated herein by reference)
10.24 Amendment Number Two to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10.1 to the Company's quarterly report on
Form 10-Q for the quarter ended September 30, 1997 and
incorporated herein by reference)
10.25 Amendment Number Three to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10.2 to the Company's Quarterly Report
Form 10-Q for quarter ended September 30, 1997 and
incorporated herein by reference)
10.26 Amendment Number Four to First Amended and Restated Loan
Agreement between the Company
and Bank One, Texas, N.A. (filed as Exhibit 10 to
Saba's Report Form 8-K filed
September 24, 1997 and incorporated herein by reference)
10.27 Corrections relating to Second Amendment dated August 28,
1997, and Fourth Amendment dated September 9, 1997 to the
First Amended and Restated Loan Agreement between Saba
Petroleum Company and Bank One, Texas, N.A. (filed as
Exhibit 10.4 to the Company's Quarterly Report Form 10-Q for
quarter ended September 30, 1997 and incorporated herein by
reference)
10.28 Amendment Number Five to First Amended and Restated Loan
Agreement between the Company
and Bank One, Texas, N.A. (filed as Exhibit 10.4 to
Saba's Report Form 8-K filed
January 15, 1998 and incorporated herein by reference)
10.29 Amendment of the First Amended and Restated Loan Agreement
between the Company and Bank One, Texas, N.A., dated
December 31, 1997 (filed as Exhibit 10.3 to Saba's Report
Form 8-K filed January 15, 1998 and incorporated herein by
reference)
10.30 Securities Purchase Agreement dated December 31, 1997 (filed
as Exhibit 10.1 to Saba's Report Form 8-K filed January 15,
1998 and incorporated herein by reference)
10.31 Registration Rights Agreement dated as of December 31, 1997*
10.32 Stock Purchase Warrant (Closing Warrant) dated December 31,
1997*
10.33 Stock Purchase Warrant (Redemption Warrant) dated December
31, 1997*
10.34 Finders Warrant+
Agreements among the Company, Amerada Hess Corporation and
Hamar Associates II, LLC dated November 1, 1997+
10.35
Agreements among the Company, Chevron U.S.A. Production
Company and Nahama Natural Gas+
10.36
Letter from Jackson & Rhodes P.C. to the Company (filed as
an exhibit to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1994 and incorporated herein by
reference)
16.1 Letter from Jackson & Rhodes P.C. to the Company (filed as
an exhibit to the Company's Annual Report on Form 10-KSB for
the year ended December 31, 1994 and incorporated herein by
reference
21.1 Subsidiaries of the Company*
23.1 Consent of Gibson, Dunn & Crutcher LLP ( included in Exhibit
5.1)+
23.2 Consent of Coopers & Lybrand L.L.P. (Los Angeles,
California)*
23.3 Consent of Netherland, Sewell & Associates, Inc.*
23.4 Consent of Sproule Associates Limited*
24.1 Powers of Attorney , see p. II-5*
* Filed herewith
+ To be filed by Amendment.