As filed with the Securities and Exchange Commission on May 13, 1998
Registration No. 333-45023
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------------
Amendment No. 1
To
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------------
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.)
------------------------------
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)
------------------------------
Walton C. Vance
Saba Petroleum Company
3201 Airpark Drive, Suite 201
Santa Maria, California 93455
(805) 347-8700
(Name, Address and Telephone Number of Agent for Service)
------------------------------
With copies to:
Susan M. Knill, Esq.
Saba Petroleum Company
3201 Airpark Drive, Suite 201
Santa Maria, CA 93455
(805) 347-8700
------------------------------
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.............................. 2,165,898 $3.16 $6,844,238 $2,019
- --------------------------------------------- ------------------- -------------------- ------------------- ======================
<FN>
(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 60.8% 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 $3.08 which is the average
of the closing prices of the Common Stock reported on the American
Stock Exchange for the 3 trading days ending May 12, 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
May 12, 1998.
</FN>
------------------------------
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.
================================================================================
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 May 13, 1998
2,165,898 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 May 12, 1998, the last reported sale price of the Common Stock on the
American Stock Exchange was $3.0625 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 or 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 received 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 14.
- --------------------------------------------------------------------------------
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 May 12, 1998, the market price on the American Stock Exchange was
$3.0625. 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 $155,000.
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
The date of this Prospectus is May 13, 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.
37
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, Louisiana
and Colombia. 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, on which producing operations
have been held in abeyance awaiting a permit and oil price increases. The
Company has also recently initiated exploration projects which the Company
believes have high potential in California, Indonesia and Great Britain.
At December 31, 1997, the Company had estimated proved reserves of 29.1
MMBOE, consisting of 23.9 MMBbls of oil and 31.3 Bcf of gas (5.2 MMBOE), with a
PV-10 Value of $118.6 million. Since quantities of oil and gas recoverable from
a property are price sensitive, declines in oil and gas prices from December 31,
1997 postings 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."
The Company also owns an asphalt refinery in Santa Maria, California, where
it currently processes approximately 4,000 Bopd. See "Description of Property
- -Asphalt Refinery". Incident to its gas and oil operations, the Company has
acquired fee interests in real estate. See "Description of Property - Real
Estate Activities". In Colombia the Company holds a 50% interest in a 118-mile
pipeline. See "Description of Property-Principal Properties-Colombian
Properties".
Recent Developments
Going Concern Status
The Company's auditors have included an explanatory paragraph in their
opinion on the Company's 1997 financial statements to state that there is
substantial doubt as to the Company's ability to continue as a going concern.
The cause for inclusion of the explanatory paragraph in their opinion is the
apparent lack of the Company's current ability to service its bank debt as it
comes due (See Note 8 to Consolidated Financial Statements). While the Company
is attempting to address funding the current deficit, there is no assurance that
it will be able to do so timely. Further, while the Company is in discussion
with its primary lender to restructure its bank debt, there is no assurance that
the preconditions to the intended restructuring will be met or a satisfactory
restructuring accomplished. Finally, as discussed below, the Company has entered
into a preliminary agreement to conclude a business combination; however, a
definitive agreement has not as yet been reached and there is no assurance that
such business combination will be consummated.
Possible Business Combination
In early 1998, the Board of Directors of the Company engaged
CIBC-Oppenheimer, Inc. ("Oppenheimer"), an investment banking firm, to explore
ways to enhance shareholder values. This engagement was prompted by several
factors, predominately the declining price of Common Stock and the lack of
working capital available to the Company. In March 1998, Oppenheimer presented
the Board with its recommendations, which included exploring a possible business
combination of the Company with another oil and gas company. In March 1998, the
Company achieved a preliminary agreement with Omimex Resources, Inc., a
privately held Fort Worth, Texas oil and gas company ("Omimex") which operates a
substantial portion of the Company's producing properties, to enter into a
business combination. At the date of this Prospectus, all of the details of the
business combination have not been fully negotiated. However, it is intended
that all of the assets of the Company, except possibly for its California
operations, would be combined with the assets of Omimex, with the Company being
the surviving corporation. The economic terms of the transaction include issuing
Common Stock to the shareholders of Omimex on a basis proportionate to the
respective net asset values of the two companies, determined by replacing the
property accounts on the respective balance sheets with the present value,
calculated at a ten percent discount, of the proved reserves of the apposite
company and adjusting that number for other assets and liabilities. Credit is to
be given for oil and gas properties deemed to have exploration or development
potential. Should a definitive agreement be obtained and the combination
consummated, it is expected that the Company will issue Common Stock to the
holders of Omimex stock resulting in such holders owning in the range of sixty
percent of the then outstanding Common Stock. Management of Omimex would become
management of the Company, which would be headquartered in Fort Worth, Texas.
The Company's California operations, if excluded from the transaction, may be
sold or combined into an existing subsidiary, the shares of which would be
distributed proportionately to the Company's shareholders. While the proposed
transaction has not been fully negotiated, a definitive agreement with Omimex is
to be executed by May 15, 1998. Consummation of the transaction would require
the consent of the holders of the Company's 9% Convertible Senior Subordinate
Debentures due 2005 ("the Debentures"), the consent of the holders of the
Company's Series A Convertible Preferred Stock ("Series A Preferred Stock"),
shareholder approval, various governmental approvals and agreement on various
matters which are yet unresolved.
Status Of Bank Debt
Approximately $8.8 million in principal amount of bank debt matured for
payment on April 30, 1998. The Company and its bank were in discussions to
restructure the terms of the loan agreement and extend the maturities of the
short-term loans to a time which would accommodate the proposed business
combination with Omimex provided that a $2.0 million payment was made on April
30, 1998 and a definitive agreement with Omimex was executed. The definitive
agreement with Omimex has not as yet been concluded and the Company was unable
to make the $2.0 million payment. Therefore, no extension was secured and the
$8.8 million of principal indebtedness remains due and payable. The Company is
continuing its discussions with the bank in an attempt to restructure the
indebtedness and is continuing its negotiations with Omimex with a definitive
agreement to be executed by May 15, 1998. The bank has not declared the loan in
default by giving notice to the Company as required pursuant to the terms of the
loan agreement.
PRINCIPAL PROPERTY AREAS
The Company owned interests in approximately 1,070 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.
United States
California
Approximately 20.3% of the Company's proved reserves at December 31, 1997
(5.9 MMBOE) were located in four onshore fields in California's central coast
region (collectively, the "Central Coast Fields"). Daily production from the
Central Coast Fields averaged 1,808 BOE for the year ended December 31, 1997,
representing 26.3% of the Company's total production. The Company operates all
of its wells in the Central Coast Fields. The Company also holds interests in
other California areas, which represented 7.2% (2.1 MMBOE) of the Company's
proved reserves at December 31, 1997. Further, the Company has interests in
several high risk exploratory projects.
Louisiana
Approximately 11.0% of the Company's proved reserves at December 31, 1997
(3.2 MMBOE) were located in two fields in Louisiana. An interest in one of these
fields was first acquired during 1996, the other in 1997, with additional
interests in both fields acquired in the second quarter of 1998. Daily
production from the Louisiana fields averaged 524 BOE for the year ended
December 31, 1997, representing 7.6% of the Company's total production.
Other United States
In addition to its California and Louisiana properties, the Company owns
producing properties in a number of other states, primarily New Mexico,
Michigan, Texas and Oklahoma, which collectively represented 9.3% of the
Company's proved reserves (2.7 MMBOE). Daily production from these properties
averaged 834 BOE for the year ended December 31, 1997, representing 12.1% of the
Company's total production.
International
Colombia
Approximately 43.3% of the Company's proved reserves at December 31, 1997
(12.6 MMBOE) were located in several fields in Colombia's Middle Magdalena
Basin. Daily production from these fields averaged 2,429 BOE for the year ended
December 31, 1997, representing 35.3% 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 250,000 Bopd government-owned refinery at
Barrancabermeja. The Company and Omimex, the operator of the fields, 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 well
acquired from Texaco and drilled 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 $2.5 million in 1998
on drilling and related activities on its Colombia properties.
Canada
Approximately 8.9% of the Company's proved reserves at December 31, 1997
(2.6 MMBOE) were located in Canada. Daily production from these properties,
which are owned through an approximately 74%-owned subsidiary of the Company,
averaged 608 BOE for the year ended December 31, 1997, representing 8.9% 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 $17.0 million over the
next three years on this project, in addition to the approximate $1.4 million
expended as of December 31, 1997. The Company is seeking a joint venture partner
to share the costs of this project; however, the recent economic turmoil in
Indonesia may affect the timing and terms of such agreement.
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. On March 31, 1998, the
Company assigned a 3.75% carried working interest in the first well to be
drilled on this concession as payment of a finder's fee. By agreement dated
April 14, 1998, the Company sold one half of its net interest in this concession
to Omimex at the Company's cost. The Company expects to spend approximately
$550,000 in 1998 to drill the first exploratory well on this concession.
SUMMARY FINANCIAL DATA
The following table presents summary historical consolidated financial
data of the Company as of and for each of the five years in the period ended
December 31, 1997, which has been derived from the Company's consolidated
financial statements. The information in this table should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and the Consolidated Financial Statements and notes
thereto included elsewhere herein. (in thousands, except for per share data)
Year Ended December 31
--------------------------------------------------------------------------
1993 1994 1995 1996 1997
--------------- ------------- ------------- --------------- --------------
Statement of Income Data
Total revenues $10,530 $12,954 $17,694 $33,202 $35,996
Expenses:
Production costs (1) 5,857 7,547 10,561 14,604 16,607
General and administrative 2,503 1,882 2,005 3,920 5,125
Depletion, depreciation and
amortization 1,853 2,041 2,827 5,527 7,265
Interest expense 443 634 1,364 2,402 2,305
Net income (loss) (88) 509 547 3,765 2,397
Net earnings (loss) per
share - basic (2):
(0.01) 0.06 0.07 0.43 0.23
Weighted average common shares
outstanding - basic (2): 7,065 7,996 8,327 8,804 10,650
Statement of Cash Flow Data
Net cash provided by
operating activities $503 $3,346 $1,736 $6,914 $4,954
Net cash used in
investing activities (1,439) (3,930) (16,757) (11,856) (36,166)
Net cash provided by
financing activities 958 860 14,850 5,037 21,991
Other Data
EBITDA (3) $2,171 $3,568 $5,188 $14,652 $13,843
Capital expenditures (4)
2,372 6,573 17,015 12,776 35,270
Production (MBOE) 755 980 1,450 2,243 2,508
December 31,
--------------------------------------------------------------------------
1993 1994 1995 1996 1997
--------------- ------------- ------------- --------------- --------------
Balance Sheet Data
Working capital (deficit) $(860) $(2,422) $2,471 $2,418 $(11,724)
Total assets
13,261 18,108 39,751 49,117 77,657
Current portion of
long-term debt
1,440 2,357 505 1,806 13,442
Long-term debt, net (5)
4,875 5,323 23,543 20,812 19,610
Redeemable preferred stock 8,511
- - - -
Stockholders' equity
4,407 6,283 7,848 17,715 23,640
<FN>
(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.
(4) Capital expenditures in 1995 include $10.0 million expended in connection
with acquisitions of producing properties in Colombia. The acquisitions
were principally responsible for the significant increase in results of
operations reported by the Company in 1995 and 1996. For additional
information, see Note 2 of Notes to Consolidated Financial Statements of
the Company.
(5) For information on terms and interest, see Note 8 of Notes to Consolidated
Financial Statements of the Company.
</FN>
SUMMARY OIL AND GAS RESERVE DATA
The following table sets forth certain summary information as of December
31, 1995, 1996 and 1997 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 $11.30, $17.05 and $13.13 per BOE on December 31, 1995, 1996
and 1997, 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, 1997, 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 $18.30 per Bbl and the comparable price at March
31, 1998 was $15.60. Quotations for the comparable periods for natural gas were
$2.45 per Mcf and $2.41 per Mcf, respectively. A decline in prices will result
in a reduction in volumes of oil or gas which are ultimately recoverable, since
certain remaining reserves will become marginal earlier.
December 31,
1995 1996 1997
------------------- -------------------- -------------
- ------------------------------------------------------
Estimated Net Proved Reserves:
- ------------------------------------------------------
Oil (MBbls) 12,532 26,679 23,925
- ------------------------------------------------------
Gas (MMcf) 19,479 23,665 31,296
- ------------------------------------------------------
Total (MBOE) 15,778 30,623 29,141
- ------------------------------------------------------
Estimated future net revenues (before income taxes)
(in thousands) $ 73,525 $ 253,902 $ 183,578
- ------------------------------------------------------
PV-10 Value (before income taxes) (in thousands)(1) $ 48,155 $ 155,939 $ 118,629
- ------------------------------------------------------
Reserve Replacement Data:
- ------------------------------------------------------
Production replacement ratio (2) 5.9x 7.7x 1.4x
- ------------------------------------------------------
All-in finding costs per BOE $ 2.02 $ 3.15 $ 4.49
<FN>
(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.
</FN>
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.
- ----------------------------------------------
Year Ended December 31,
- ----------------------------------------------
- ----------------------------------------------
1995 1996 1997
- ----------------------------------------------
- ----------------------------------------------
Production Data:
- ----------------------------------------------
- ----------------------------------------------
Oil (MBbls) 1,227 1,968 2,107
- ----------------------------------------------
- ----------------------------------------------
Gas (MMcf) 1,337 1,651 2,408
- ----------------------------------------------
- ----------------------------------------------
Total (MBOE) 1,450 2,243 2,508
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
Average Sales Price Data (Per Unit):
- ----------------------------------------------
- ----------------------------------------------
Oil (Bbls) $ 12.22 $ 14.43 $ 13.73
- ----------------------------------------------
- ----------------------------------------------
Gas (Mcf) 1.45 1.88 2.09
- ----------------------------------------------
- ----------------------------------------------
BOE 11.69 14.05 13.54
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
Selected Data per BOE:
- ----------------------------------------------
- ----------------------------------------------
Production costs (1) $ 7.29 $ 6.51 $ 6.62
- ----------------------------------------------
- ----------------------------------------------
General and administrative 1.27 1.72 1.93
- ----------------------------------------------
- ----------------------------------------------
Depletion, depreciation and amortization 1.92 2.43 2.84
- ----------------------------------------------
<FN>
(1) Production costs include production taxes.
</FN>
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. 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. In March 1998, Oppenheimer presented the Board with
its recommendations, which included exploring a possible business combination of
the Company with another oil and gas company. In March 1998, the Company entered
into a preliminary agreement with Omimex with the objective being a business
combination. Should the contemplated merger be consummated, the shareholders of
Omimex will receive in the range of 60% of the then outstanding Common Stock and
management of Omimex would become management of the Company, which is to be
headquartered in Fort Worth, Texas. The Company's California operations may be
sold or combined into an existing subsidiary, the shares of which would be
distributed proportionately to the Company's shareholders. That corporation is
expected to retain some of the Company's existing management and concentrate its
efforts on its California properties and the acquisition of lighter oil and gas
properties. Whether the Company will be successful in pursuing the above
described strategies is not known.
Near Term Cash Requirements
The Company maintains a reducing revolving credit facility with a bank. As
provided for in the loan agreement, the bank, applying its internal projections
of future oil and gas prices and applying its internal discount factors to each
classification of proved reserves, prepares its own estimate of the Company's
remaining reserves and the projected cash flows from those reserves. In the
event that the bank's estimate of the loan value of the Company's reserves
("borrowing base") is less than the outstanding loan balance, the bank may
require the Company to (I) post additional collateral or (II) make additional
payments in reduction of its indebtedness. In accordance with the terms of the
reducing revolving credit facility, $3.5 million of the outstanding balance may
be payable within the next year depending upon the bank's determination of the
borrowing base. In addition to the reducing revolving credit facility, the
Company's lending bank has advanced three short-term loans with an aggregate
currently outstanding balance of $8.8 million, all of which matured on April 30,
1998. The Company's Canadian subsidiary has a fully advanced borrowing base
revolving loan of $2.4 million of which $643,000 is classified as a current
liability in that it may be payable over the next year. Further, accounts
payable and accrued liabilities increased $3.9 million over accounts receivable
and cash balances during the year ended December 31, 1997, due primarily to the
Company's year end drilling activities which contributed to the decrease in
working capital. The Company and its bank were in discussions to restructure the
terms of the loan agreement and extend the maturities of the short-term loans to
a time which would accommodate the proposed business combination with Omimex
provided that a $2.0 million payment was made on April 30, 1998 and a definitive
agreement with Omimex was executed. The definitive agreement with Omimex has not
as yet been concluded and the Company was unable to make the $2.0 million
payment. Therefore, no extension was secured and the $8.8 million of principal
indebtedness remains due and payable. The Company is continuing its discussions
with the bank in an attempt to restructure the indebtedness and is continuing
its negotiations with Omimex with a definitive agreement to be executed by May
15, 1998. The bank has not declared the loan in default by giving notice to the
Company as required pursuant to the terms of the loan agreement. Further, the
Company is in discussions with several investment banking firms to arrange for
financing should the contemplated business combination with Omimex not be
consummated. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations".
In that the current maturities of the Company's bank debt are in excess of
the Company's apparent ability to meet such obligations as they come due, the
Company's auditors have included an explanatory paragraph in their opinion on
the Company's 1997 financial statement to state that there is substantial doubt
as to the Company's ability to continue as a going concern. In the past, the
Company has demonstrated ability to secure capital through debt and equity
placements, and believes that, if given sufficient time, it will be able to
obtain the capital required to continue its operations. Further, the Company is
in negotiations to divest itself of certain of its non-core oil and gas assets
and real estate assets, with the proceeds of such divestitures to be applied to
reduction of its bank debt. There can be no assurance that the Company will be
successful in obtaining capital on favorable terms, if at all. Additionally,
there can be no assurance that the assets which are the present object of the
Company's divestiture efforts will be sold at prices sufficient to reduce the
bank debt to levels acceptable to the bank in order to allow for a restructuring
resulting in the elimination of the "Going Concern" opinion.
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, in that 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. Should a commercial discovery
exist, additional costs are likely to be incurred to create transportation and
marketing infrastructure. Major exploratory projects often require substantial
capital investments and a significant amount of time before generating revenues.
Continuation of the Company's exploratory and development programs will
require more cash than the Company's properties will generate at present price
levels. Should the Omimex business combination be concluded, it is expected that
the Company will refinance its debt, consolidating into an Omimex credit
facility. Should negotiations of the merger be unsuccessful, the Company will
attempt to sell or dispose of its non-core oil and gas properties which 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 at a price equal to 115% of its stated value. See
"Description of Capital Stock-Preferred Stock. The Company does not presently
have the funds with which to redeem the Series A Preferred Stock.
Restriction on Payment of Dividends
The Company has not paid any cash dividends on its Common Stock to date and
has no plans to pay such dividends in the foreseeable future. The payment of
cash dividends in the future will be dependent on the Company's future earnings
and financial condition. Pursuant to the terms of the Company's credit facility
and the terms of its Series A Preferred Stock and its Debentures, the Company is
prohibited from making any cash dividend payments on its Common Stock without
the specific consent from the lending bank, the holders of the Series A
Preferred Stock and the holders of the Debentures.
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 March 31, 1998, the Company had outstanding 10,947,393 shares of Common
Stock. Of these shares, 7,141,412 shares of Common Stock were freely
transferable and tradable without restriction or further registration under the
Securities Act. In addition, approximately 817,143 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 3,743,521 shares of Common Stock (34.19% 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 a major
indirect 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."
Potential Dilution-Outstanding Preferred Stock
As of December 31, 1997, 10,000 shares of the Company's Series A Preferred
Stock were issued and outstanding. Each share 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
increased by accrued but unpaid dividends as of March 31, 1998) 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 at March 31, 1998, based on a Conversion Price of $4.06 (the
closing price of the Common Stock on March 31, 1998), the Series A Preferred
Stock would have been convertible into 2,500,000 shares of Common Stock;
however, without waiver by the American Stock Exchange of its rules, the Company
would be permitted to issue only 2,165,898 shares of Common Stock without a
shareholders' vote approving the issuance of additional shares. The number of
shares of Common Stock which may be required to be issued could prove to be even
greater in the event of further decreases in the trading price of the Common
Stock assuming that the required shareholder approval is obtained. 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 maximum number of shares of
Common Stock into which the Series A Preferred Stock may be converted without
shareholder approval is 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. 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."
Potential Dilution-Substantial Options, Warrants 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 March 31, 1998, the Company had outstanding Debentures in the aggregate
principal amount of $3,575,000, which may convert into Common Stock at a price
of $4.375 per share (817,143 shares). If Common Stock prices 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 warrants to purchase 269,663 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 shares of Common Stock issuable upon exercise of the Redemption
Warrants are being registered pursuant to the Registration Statement of which
this Prospectus forms a part.
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, warrants and Debentures could adversely
affect the prevailing market price of the Common Stock. Further, the holders of
options and warrants 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 31.4% of the Company's total oil and gas revenues in the year ended December
31, 1997. Prices received from the sale of oil produced at the Company's
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."
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 December 31, 1997, approximately 13.5% of the Company's North American
oil and gas production was derived from properties operated by Omimex. All of
the Company's Colombian properties are operated by Omimex (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 at that time was 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 Relating to the Company - Risks Relating to Certain Corporate Matters"
in the Company's Form SB-2 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, 1997, oil and gas prices have generally declined. At March 31, 1998, the
price of WTI crude oil as quoted on the New York Mercantile Exchange was $15.60
per Bbl and the comparable price at December 31, 1997, was $18.30. Quotations
for natural gas at such dates were $2.41 per Mcf and $2.45 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 reserves may vary from year to
year reflecting changes in the price of oil and gas and results of drilling
activities during the intervening period. Reserves previously classified as
proved undeveloped may be completely removed from the proved reserves
classification in a subsequent year as a consequence of negative results from
additional drilling or product price declines which make such undeveloped
reserves non-economic to develop. Conversely, successful development and/or
increase s in product prices may result in additions to proved undeveloped
reserves. 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 December 31, 1997, the Company reported approximately $55.3 million
of net capitalized oil and gas property costs and estimated the cost ceiling
exceeded the net capitalized costs, less related deferred income taxes, by
approximately $40.7 million. However, cost ceilings are computed on a country by
country basis, therefore lower product prices coupled with unsuccessful capital
investment or higher operating costs may cause a writedown with respect to the
cost center for a particular country.
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 in a five-year
period ending 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
grades of crude) 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 $1.0 million. 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 was unable to secure all of the requisite consents to
transfer the property but nevertheless may have the obligation to abandon the
wells. The leases have expired and the Company is presently considering whether
to attempt to secure new leases. 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"). A determination was made by the DEQ that the
Company's permit had expired while the Company continued operations. The Company
paid a fine of approximately $30,000.
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."
Economic and Political Risks of Foreign Operations
International Operations-General
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.
Colombian Operations
Inherent Risks
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 Foreign Assistance Act of 1961, the President of the United
States is required to determine whether to certify that certain countries have
cooperated with the United States, or taken adequate steps on their own, to
achieve the goals of the United Nations Convention Against Illicit Traffic in
Narcotic Drugs and Psychotropic Substances. In 1995, 1996, 1997 and 1998, the
President did not certify Colombia. The 1995 and 1998 decertifications were
subject to a so-called "national interest" waiver, effectively nullifying its
statutory effects. Based on the 1996 and 1997 Presidential decertification, 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 the entry of the United States votes against multilateral assistance to
Colombia in the World Bank and the InterAmerican Development Bank.
The consequences of continued and successive United States decertifications
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 in 1988 and 1989
against Panama in a dispute over narcotics trafficking activities by the
Panamanian government. 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 affect 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. Contracts with both unions are scheduled for renegotiations later
in 1998 and discussions are currently being held. 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
Second Quarter (through May 12) $ 3.0625 $ 3.125
First Quarter 3 .38 8 .50
1997
Fourth Quarter $ 8 .00 $ 14 .88
Third Quarter 12 .81 20 .12
Second Quarter 10 .75 17 .75
First Quarter 12 .75 25 .25
1996
Fourth Quarter $ 9 .25 $ 27 .12
Third Quarter 6 .19 9 .94
Second Quarter 3 .88 8 .00
First Quarter 3 .56 4 .75
On May 12, 1998, the last reported sales price of the Common Stock on the
American Stock Exchange was $3.0625. 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 March 31, 1998, the Company had approximately 2,817 stockholders of
record.
SELECTED FINANCIAL DATA
The following table presents selected historical consolidated financial
data for the Company as of and for each of the five years in the period ended
December 31, 1997. The following information should be read in conjunction with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the Consolidated Financial Statements of the Company and the
related notes thereto included elsewhere herein. (in thousands, except for per
share data)
Year Ended December 31,
---------------------------------------------------------------------------
---------------------------------------------------------------------------
1993 1994 1995 1996 1997
------------- ------------- ------------- ------------- --------------
Statement of Income Data
Revenues:
Oil and gas sales $ 10,130 $ 12,170 $ 16,941 $ 31,521 $ 33,969
Other 400 784 753 1,681 2,027
------------- ------------- ------------- ------------- --------------
Total revenues 10,530 12,954 17,694 33,202 35,996
------------- ------------- ------------- ------------- --------------
Expenses:
Production costs (1) 5,857 7,547 10,561 14,604 16,607
General and
administrative 2,503 1,882 2,005 3,920 5,125
Depletion,
depreciation and
amortization 1,853 2,041 2,827 5,527 7,265
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Total expenses 10,213 11,470 15,393 24,051 28,997
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Operating income 317 1,484 2,301 9,151 6,999
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Other income (expense):
Interest income (443) (634) (1,364) (2,402) (2,305)
Gain on issuance
of shares of subsidiary 0 0 125 8 4
Other 1 43 (10) 207 (369)
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Total other income
(expense) (442) (591) (1,249) (2,187) (2,670)
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Income (loss) before
income taxes (125) 893 1,052 6,964 4,329
Provision (benefit) for
taxes on income (37) 384 450 2,958 1,876
Minority interest in
earnings of
consolidated subsidiary 0 0 55 241 56
------------- ------------- ------------- ------------- --------------
============= ============= ============= ============= ==============
Net income $ (88) $ 509 $ 547 $ 3,765 $ 2,397
============= ============= ============= ============= ==============
Net earnings (loss) per
share (basic)(2) $ (0.01) $ 0.06 $ 0.07 $ 0.43 $ 0.23
Weighted average
common
shares outstanding:
(basic) (2) 7,065 7,996 8,327 8,804 10,650
Statement of Cash Flow Data
Net cash provided by
operating activities 503 3,346 1,736 6,914 14,954
Net cash used in
investing activities (1,439) (3,930) (16,757) (11,856) (36,166)
Net cash provided by
financing activities 958 860 14,850 5,037 21,991
Other Financial Data
EBITDA (3) $ $ $ $ $
2,171 3,568 5,188 14,652 13,843
Capital expenditures(4) $ $ $ $ $
2,372 6,573 17,015 12,776 35,270
December 31,
-----------------------------------------------------------------------------
1993 1994 1995 1996 1997
------------- ------------- ------------- ------------- --------------
------------- ------------- ------------- ------------- --------------
Balance Sheet Data
Working capital (deficit) $ $ $ $ $
(860) (2,422) 2,471 2,418 (11,724)
Total assets 13,261 18,108 39,751 49,117 77,657
Current portion of
long-term debt 1440 2,357 505 1,806 13,442
Long-term debt, net (5) 4,875 5,323 23,543 20,812 19,610
Redeemable preferred Stock 8,511
Stockholders' equity 4,407 6,283 7,848 17,715 23,640
<FN>
(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) Capital expenditures in 1995 include $10.0 million expended in connection
with acquisitions of producing properties in Colombia. The acquisitions
were principally responsible for the significant increase in results of
operations reported by the Company in 1995 and 1996. For additional
information, see Note 2 of Notes to Consolidated Financial Statements of
the Company.
(5) For information on terms and interest, see Note 8 of Notes to Consolidated Financial Statements of the Company.
</FN>
Quarterly Results of Operations
The following table sets forth certain unaudited quarterly financial
information for each of the Company's last two fiscal years. 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
----------------------------------------------------------------------------------------------------------
------------------------------------------------- --------------------------------------------------
1996 1997
------------------------------------------------- --------------------------------------------------
------------------------------------------------- --------------------------------------------------
Mar 31, June 30, Sept 30, Dec 31, Mar 31, June 30, Sept 30, Dec 31,
------- -------- -------- ------- ------- -------- -------- -------
Revenues
Oil and
gas sales $6,962,886 $7,640,802 $7,471,924 $9,445,145 $9,668,592 $7,695,072 $7,918,697 $8,686,790
Other $424,404 $362,026 $290,998 $604,159 ($105,118) $576,881 $1,024,076 $530,772
Total
revenues $7,387,290 $8,002,828 $7,762,922 $10,049,304 $9,563,474 $8,271,953 $8,942,773 $9,217,562
Depletion
depreciation
and
amortization $1,140,500 $1,227,905 $1,247,226 $1,911,787 $1,586,960 $1,646,327 $1,778,275 $2,253,394
Net income
(loss) $755,488 $734,375 $730,869 $1,543,984 $1,441,582 $507,300 $598,618 ($150,053)
Net earnings
(loss)
per share-basic $0.09 $0.09 $0.08 $0.17 $0.14 $0.05 $0.06 ($0.01)
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 Prospectus.
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 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 six years. From January 1, 1992 through December 31,
1997, the Company completed 26 property acquisitions. During that six-year
period, the Company's proved reserve base, production and operating cash flow
have increased at compound annual growth rates of 48.4%, 45.0% and 45.8%,
respectively. In 1996, the Company broadened its strategy to include growth
through exploration and development drilling.
The current focus of the Company's activity is drilling of horizontal wells
in the Central Coast Fields and drilling 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. Seven of
the wells are currently in production, three wells have encountered formation
problems which the Company is seeking to remediate, one well was determined to
be noncommercial and two wells (one pair) of SAGD horizontal wells are shut-in
awaiting local permits and an increase in oil prices. Five of these wells were
horizontal wells 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 slower rates than anticipated. Based on
disappointing results, the Company reduced the number of wells it had originally
projected to drill in 1997 and 1998. Combined geologic, reservoir engineering
and production engineering studies are currently underway and the Company plans
to drill at least two wells in 1998. In Colombia, a total of thirteen gross
(3.25 net) wells were drilled in 1997 on the Teca/Nare property, and one well
drilled 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 Colombian properties. At the Velasquez field,
three gross (0.75 net) wells were recompleted to establish additional reserves
and increase production.
The Company's revenues are primarily comprised of oil and gas sales
attributable to properties in which the Company owns a 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 by country, 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 Beaver Lake Resources Corporation ("Beaver Lake"), its
74% owned Canadian oil and gas operation.
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 production is determined based on formulas set by Ecopetrol. See
"Description of Business-Economic and Political Factors of Foreign
Operations-Colombian Operations".
The weighted average sales price of the Company's crude oil was $13.73 per
Bbl in 1997 and $14.43 per Bbl in 1996, representing approximately 73.7% and
70.6%, 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 $16.31 for the quarter
ended December 31, 1996.
Results of Operations
Comparison of Years Ended December 31, 1997 and 1996
Oil and Gas Sales
Oil and gas sales increased 7.9% to $34.0 million during the year ended
December 31, 1997 from $31.5 million for 1996. Average sales price per BOE for
the year ended December 31, 1997 decreased 3.6% to $13.54 from $14.05 per BOE in
1996.
Total production increased 13.6% to 2.5 MMBOE in the year ended December 31,
1997 as compared to 2.2 MMBOE for 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 145,000 BOE for the year ended
December 31, 1997 as compared with 1996. The decline resulted from the reversion
of the Cocorna Concession in February 1997 and normal production declines.
Other Revenues
Other revenues increased 17.6% to $2.0 million for the year ended December
31, 1997, as compared to $1.7 million for 1996. The increase was due primarily
to additional processing fee income of $659,000 realized from the Company's
asphalt refinery and additional operator's overhead recoveries of $101,000 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 13.7% to $16.6 million for the year ended
December 31, 1997, as compared to $14.6 million in 1996. Average production
costs per BOE increased $0.11 to $6.62 for the year ended December 31, 1997 from
$6.51 in 1996, resulting in increased production costs of $279,000.
A production increase of 265,000 BOE for the year ended December 31, 1997,
from 2.2 MMBOE in 1996, resulted in increased production costs of $1.7 million.
In comparison with the prior year, production volume in 1997 increased 415,000
BOE in the United States and decreased 145,000 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
two-thirds 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 30.8% to $5.1 million for the
year ended December 31, 1997, from $3.9 million for 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 32.7% to $7.3
million for the year ended December 31, 1997, from $5.5 million in 1996.
Depletion expense increased 32.0% to $6.6 million for the year ended December
31, 1997, from $5.0 million in 1996. The increase was primarily attributable to
domestic production volume increases for the year ended December 31, 1997, of
415,000 BOE in comparison with 1996, capital costs recorded by the Company in
its full cost pools beginning in the second quarter of 1996, and 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 19.3% to $654,000 for the year ended December 31, 1997, from $548,000
in 1996.
Other Income (Expense)
Other income (expense) decreased to a net expense of $365,000 for the year
ended December 31, 1997, from income of $215,000 in 1996. The change was
primarily due to foreign currency transaction losses of $230,000 realized by the
Company's Colombia operations, costs in the amount of $321,000 attributable to
prospect screening activities and financing proposal costs in the amount of
$175,000, partially reduced by interest income of $52,000 and other income of
$67,000.
Interest Expense
Interest expense decreased 4.2% to $2.3 million for the year ended December
31, 1997, from $2.4 million in 1996. Interest expense attributable to the
Debentures decreased $636,000 due to the conversion of $9.1 million of
Debentures to Common Stock occurring since June, 1996. Interest expense
attributable to the Company's principal commercial credit facilities increased
$881,000 for the year ended December 31, 1997, from 1996. The average debt
balance outstanding under the credit facilities increased 106.5% to $19.0
million for the year ended December 31, 1997, from $9.2 million in 1996, due
principally to the use of loan proceeds to fund property acquisitions and
development drilling activities. The weighted average interest rate for the
credit facilities decreased 2.8% to 8.75% for the year ended December 31, 1997,
from 9.00% for 1996.
Provision for Taxes on Income
Provision for taxes on income decreased 36.7% to $1.9 million for the year
ended December 31, 1997, from $3.0 million in 1996. The Company's effective tax
rate was 43.9% in 1997 and 44.0% in 1996.
Net Income
Net income decreased $1.4 million (36.8%) to $2.4 million for the year ended
December 31, 1997, from $3.8 million in 1996. This decrease 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.
Liquidity and Capital Resources
The Company's auditors have included an explanatory paragraph in their
opinion on the Company's 1997 financial statements to state that there is
substantial doubt as to the Company's ability to continue as a going concern.
The cause for inclusion of the explanatory paragraph in their opinion is the
apparent lack of the Company's current ability to service its bank debt as it
comes due (See Note 8 to Consolidated Financial Statements). While the Company
is attempting to address funding the current deficit, there is no assurance that
it will be able to do so timely. Further, while the Company is in discussion
with its primary lender to restructure its bank debt, there is no assurance that
the preconditions to the intended restructuring will be met or a satisfactory
restructuring accomplished. Finally, the Company has entered into a preliminary
agreement to conclude a business combination; however, a definitive agreement
has not as yet been reached and there is no assurance that such business
combination will be consummated.
Since 1991, the Company's strategy has emphasized growth through the acquisition
of producing properties with significant development potential. The Company
recently broadened its activities to include exploration drilling, enhanced
recovery projects and programs to increase production efficiencies. During the
past five years, the Company financed its acquisitions and other capital
expenditures primarily though secured bank financing, production payment
obligations, participation arrangements with joint venture partners and through
the sale of Common Stock and Debentures. Working capital was provided by
internally generated cash flow from operations supplemented by bank debt which
was available because the Company's borrowing base was greater than loan
balances. At year end 1997, the Company sold $10.0 million of Series A Preferred
Stock which provided approximately $2.1 million working capital after repayment
of $7.0 million in short term bank debt and providing for costs associated with
the sale of the Series A Preferred Stock and attendant preparation and filing of
a registration statement. The Company has a working capital deficit due
principally to the near-term maturities of a portion of its bank debt, with $8.8
million past due as of May 1, 1998. The Company and its bank were in discussions
to restructure the terms of the loan agreement and extend the maturities of the
short-term loans to a time which would accommodate the proposed business
combination with Omimex provided that a $2.0 million payment was made on April
30, 1998 and a definitive agreement with Omimex was executed. The definitive
agreement with Omimex has not as yet been concluded and the Company was unable
to make the $2.0 million payment, therefore, no extension was obtained The
Company is continuing its discussions with the bank in an attempt to restructure
the indebtedness and is continuing its negotiations with Omimex with a
definitive agreement to be executed by May 15, 1998. It is expected that
following the merger, the bank debt of both companies will be consolidated in
one credit facility. Apart from these discussions, the Company is negotiating
the sale of certain non-core oil and gas assets and real estate assets, the
proceeds of which would be applied to reduce the bank loan and provide working
capital. Further, the Company is in discussions with several investment banking
firms to arrange for financing should the contemplated business combination with
Omimex not be consummated.
The Company's capital expenditure budget for 1998 is dependant upon the
price for which its oil and gas is sold and upon the ability of the Company to
obtain external financing. Subject to these variables, the Company has budgeted
a minimum of $12.0 million and a maximum of $18.3 million for 1998 capital
expenditures. As presently scheduled, the majority of these expenditures are to
commence during the second calendar quarter and continue throughout the
remainder of 1998. A significant portion of the capital expenditures budget is
discretionary. Due to the decline in oil prices during the first quarter of
1998, the Company deferred certain capital programs. The Company may elect to
make further deferrals of capital expenditures if oil prices remain at current
levels. Capital expenditures beyond 1998 will depend upon 1998 drilling results,
improved oil prices and the availability of external financing,.
Working Capital
The Company's working capital decreased $14.1 million in 1997 from $2.4
million at December 31, 1996 to a deficit of $11.7 million at December 31, 1997.
This decrease was primarily due to the classification as a current liability of
$12.3 million of long-term debt presently scheduled for repayment to the
Company's principal lender during the next year. During 1997, the Company's
capital expenditures did not produce expected increases in reserves, which, when
coupled with the decline in oil and gas prices, reduced the amount of reserves
against which the Company could borrow and the projected cash flow with which to
service debt. The Company's principal credit facility is a reducing, revolving
line of credit with an outstanding balance of $17.1 million at December 31,
1997. In accordance with the terms of the loan agreement, $3.5 million of this
amount may be payable within the next year depending upon the value ascribed to
the Company's proved oil and gas assets by the Company's principal lender, and
therefore has been classified as a current liability. The Company has a reducing
borrowing base term loan in the amount of $3.1 million which matured on April
30, 1998, and accordingly is classified as a current liability. On March 30,
1998, the Company and its lender amended the terms of both loans to provide for
a three-month deferral of borrowing base reductions. The effect of this
amendment is reflected in the amounts classified as currently payable at
December 31, 1997. In addition to the two borrowing base loans, the Company has
two outstanding term loans in the amounts of $3.0 million and $2.7 million that
matured on April 30, 1998, and are classified as current liabilities.
Notwithstanding the maturity date of the loans, the Company was to make a
principal reduction of $2.0 million on April 30, 1998, and another principal
reduction of not less than $3.0 million on June 1, 1998. The April 30, 1998
payment has not been made. The Company's Canadian subsidiary has a reducing
borrowing base revolving loan that was fully advanced with an outstanding
balance of $2.4 million at December 31, 1997. In accordance with the terms of
that facility, $643,000 of the outstanding balance is classified as a current
liability as it may be payable over the next year. A net increase of $3.9
million in accounts payable and accrued liabilities over accounts receivable and
cash balances for the year ended December 31, 1997, was due primarily to the
Company's year end drilling activities and contributed to the decrease in
working capital.
In that the current maturities of the Company's bank debt are in excess of
the Company's apparent ability to meet such obligations as they come due, the
Company's auditors have included an explanatory paragraph in their opinion on
the Company's 1997 financial statement to state that there is substantial doubt
as to the Company's ability to continue as a going concern. In the past, the
Company has demonstrated ability to secure capital through debt and equity
placements, and believes that, if given sufficient time, it will be able to
obtain the capital required to continue its operations. Further, the Company is
in negotiations to divest itself of certain of its non-core oil and gas assets
and possibly its real estate assets, with the proceeds of such divestitures to
be applied to reduction of its bank debt. There can be no assurance that the
Company will be successful in obtaining capital on favorable terms, if at all.
Additionally, there can be no assurance that the assets which are the present
object of the Company's divestiture efforts will be sold at prices sufficient to
reduce the bank debt to levels acceptable to the bank in order to allow for a
restructuring resulting in the elimination of the "Going Concern" opinion.
The Company is taking actions to address the working capital deficit. It is
in discussions with institutions to secure capital either by the placement of
debt or equity. Discussions have been held with the Company's principal lender
to restructure existing indebtedness to allow sufficient time for the
contemplated business combination with Omimex to be concluded.
Operating Activities
The Company's operating activities during the year ended December 31, 1997,
provided net cash flow of $15.0 million. Changes in the non-cash components of
working capital were responsible for $4.6 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 year ended December 31, 1997, resulted in a
net cash outflow of $36.2 million, which consisted principally of expenditures
in the amount of $32.9 million for oil and gas property acquisition, development
and exploration, and a net increase of $1.5 million in notes receivable.
Investing activities during the year ended December 31, 1996 resulted in a net
cash outflow of $11.9 million, which consisted primarily of oil and gas property
acquisition, development and exploration expenditures in the amount of $12.2
million and a net increase of $1.1 million in notes receivable, all reduced by
the receipt of a refund of $1.8 million on a certificate of deposit.
Financing Activities
Financing activities during the year ended December 31, 1997, which provided
net cash flow of $22.0 million, consisted principally of activity on the
Company's revolving credit facility and net proceeds of $9.1 million realized
from the sale of Preferred Stock. Financing activities during the year ended
December 31, 1996, which provided net cash flow of $5.0 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 December 31, 1997, the borrowing base
under the revolving loan was $17.5 million, subject to a monthly reduction of
$400,000, of which $17.4 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. At December 31,
1997, the borrowing base for this facility was $3.1 million, subject to a
monthly reduction of $142,000 to April 30, 1998, at which time any outstanding
balance was due and payable. The payment was not made and the note maturity was
not extended. At December 31, 1997, $3.1 million was outstanding. In September
1997, the Company borrowed $9.7 million from Bank One, Texas, N.A. to fund the
acquisition cost of the Potash Field property. On December 31, 1997, a principal
payment in the amount of $7.0 million was made, reducing the outstanding balance
to $2.7 million which matured for payment on April 30, 1998. The payment was not
made and the note maturity was not extended.
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 3%, and matured for
payment on April 30, 1998. At December 31, 1997 the loan was fully advanced. The
payment was not made and the note maturity was not extended.
Pursuant to an amendment dated December 31, 1997, to the Loan Agreement with
Bank One, Texas, N.A., the Company was required to make a payment of $3.0
million in April 1998 and a minimum payment of $3.0 million in June 1998 in
addition to its scheduled monthly payments of principal and interest. On March
30, 1998, the Loan Agreement with Bank One, Texas, N.A. was amended to provide
for a deferral of monthly reductions totaling $542,000 to the borrowing base
loans for the period February to April 1998. In addition, the previous
requirement for a $3.0 million payment due April 1, 1998, was reduced to $2.0
million and the payment date was extended to April 30, 1998. This payment, which
was to be applied to the aggregate $8.8 million in debt due on April 30, 1998,
has not been made.
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 $56,000 per month. At December 31, 1997,
the loan was fully advanced with an outstanding balance of $2.4 million.
Capital Budget
The Company expended approximately $32.6 million for its acquisition,
development and exploration activities during the year ended December 31, 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 a short-term bank loan. The Company's
capital expenditure budget for 1998 is dependant upon the price for which its
oil and gas is sold and upon the ability of the Company to obtain external
financing. Subject to these variables, the Company has budgeted a minimum of
$12.0 million and a maximum of $18.3 million for 1998 capital expenditures. As
presently scheduled, the majority of these expenditures are to commence during
the second calendar quarter and continue throughout the remainder of 1998. A
significant portion of the capital expenditures budget is discretionary. Due to
the decline in oil prices during the first quarter of 1998, the Company deferred
certain capital programs. The Company may elect to make further deferrals of
capital expenditures if oil prices remain at current levels. Capital
expenditures beyond 1998 will depend upon 1998 drilling results, improved oil
prices and the availability of external financing.
New Accounting Standards
In June 1997, the Financial Standards Accounting Board issued FAS No. 130,
"Reporting Comprehensive Income." FAS No. 130 establishes standards for the
reporting and display of comprehensive income and its components in a full set
of general-purpose financial statements. The statement is effective for fiscal
years beginning after December 15, 1997. The Company will adopt FAS No. 130 in
1998. Management does not believe that adoption of the statement will have a
material impact on the financial statements of the Company.
In June 1997, the Financial Accounting Standards Board issued FAS No. 131,
"Disclosure About Segments of an Enterprise and Related Information." FAS No.
131 establishes standards for reporting information about operating segments in
annual financial statements and requires that interim financial reports issued
to shareholders include selected information about reporting segments. The
statement is effective for fiscal years beginning after December 15, 1997. The
Company will adopt FAS No. 131 in 1998. Management does not believe that
adoption of FAS No. 131 will have a material impact 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.
Information Systems for the Year 2000
The Company has reviewed its computer systems and software and has
determined that it must replace its current integrated accounting software in
order to accurately process data beginning with the year 2000. Should it not do
so, the Company would be unable to properly process and report upon its own
operating data, as well as information provided to it by outside sources that
are "Year 2000" compliant. The Company's third-party accounting software vendor
is modifying the current operating system utilized by the Company and expects to
provide the modified system to the Company in the third quarter of 1998. The
cost of this modification will be included in the vendor's system support
contract and will not be a significant additional expense to the Company. The
Company is also reviewing its other computer applications, in addition to
interviewing outside parties that provide data base access, to determine that
they will be "Year 2000" compliant.
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 second quarter of 1998. (See Note 16 to
the Consolidated Financial Statements for a description of operating results by
geographic region)
At December 31, 1997, the Company had estimated proved reserves of 29.1
MMBOE, consisting of 23.9 MMBbls of oil and 31.3 Bcf of gas (5.2 MMBOE), with a
PV-10 Value of $118.6 million. Since quantities of oil and gas recoverable from
a property are price sensitive, declines in oil and gas 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
In March 1998, the Company entered into a preliminary agreement with Omimex
to enter a business combination. Should such merger be consummated, it is
anticipated that the combined entity will continue to develop its properties in
the U.S., Colombia and in other areas deemed appropriate by the Omimex
management. Until the merger is completed, 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 California, 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.
Should the contemplated merger be consummated, it is anticipated that the
California properties, if not sold, will be combined into an existing
subsidiary, the shares of which would be distributed proportionately to the
Company's shareholders. That corporation is expected to retain some of the
Company's existing management and concentrate its efforts on its California
properties and the acquisition of lighter oil and gas properties. Whether the
Company will be successful in pursuing such strategies is not known.
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 meet 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.
From January 1, 1992 through December 31, 1997, the Company completed 26
property acquisitions with an aggregate purchase price of approximately $43
million. These properties, as improved through the Company's development efforts
and including associated drilling activities, represented approximately 29.1
MMBOE of proved reserves as of December 31, 1997. The Company's all-in-finding
costs for these acquisitions and related activities have averaged $2.71 per BOE.
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. It has recently completed
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, resulting in defining a number of drillable prospects; 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 an exploratory well commenced drilling in 1998.
The Company's capital expenditure budget for 1998 is 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 $12.0 million and a maximum of $18.3 million for capital expenditures
during 1998; allocated $7.8 million to $13.4 million for U.S. activities,
approximately $2.5 million for Colombian activities and $1.7 million to $2.4
million for other international activities. As presently scheduled, the majority
of these expenditures are to commence during the second calendar quarter and
continue throughout the remainder of 1998. A significant portion of the capital
expenditures budget is discretionary. Due to the decline in oil prices during
the first quarter of 1998, the Company deferred certain capital programs. The
Company may elect to make further deferrals of capital expenditures if oil
prices remain at current levels. Capital expenditures beyond 1998 will depend
upon 1998 drilling results, improved oil prices and the availability of external
financing.
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 evaluates
the consultants' recommendations and determines what, if any, actions are to be
taken. 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. An 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 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, but does not anticipate
commencing such operations until oil prices improve. 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 four onshore fields that collectively comprise
approximately 4,405 gross (4,367 net) developed acres and 1,139 gross (1,138
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 and
Casmalia fields. The Company also has producing properties in Ventura, Solano,
Kern and Orange Counties, California. Of these properties, the Company regards
the Cat Canyon and Gato Ridge fields, both heavy oil properties, as the most
significant and upon which it has focused its development drilling efforts.
Aggressive development activities during 1997, in contemplation of significantly
increased production, included the installation of surface facilities for
handling much more oil than the Company presently produces from the properties.
The recent decline in oil prices coupled with the drilling results of the 1997
program render it doubtful that the Company will realize its initially projected
rates of return. In addition to the producing properties, the Company has
several exploratory projects in California which it plans to drill during 1998.
Overall, the Company during 1997 experienced a 38% increase in annual
production from its California properties (from 654 MBOE in 1996 to 904 MBOE in
1997). The development costs incurred by the Company in California during 1997
were $12.8 million. The economic benefits derived from the program were
substantially below the Company's expectations. Notwithstanding the 1997
results, the Company continues to believe that its focus on the Central Coast
Fields will ultimately be justified. This opinion is based in part on the
established synergy between the Company's production from the Central Coast
Fields and its asphalt refinery located in Santa Maria, in that the Company is
able to sell its production to the refinery at a price reflecting a premium to
market. Generally, the crude oil produced by the Company and other producers in
the Santa Maria Basin is of low gravity and makes an excellent asphalt. Recent
prices for asphalt exceed market prices for crude oil and costs of operating the
refinery. The Company believes that as road building and repair increase in
California and surrounding western states, the market for asphalt will expand
significantly.
To date, the Company has drilled and completed thirteen horizontal wells in
the Sisquoc sands of the Cat Canyon Field. Twelve of these wells are currently
producing at rates from 40 to 140 Bopd; the thirteenth 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 and oil price increases before production will be attempted. Two
horizontal wells drilled to test a different zone in this field have encountered
severe sand production and are presently planned to undergo recompletion
operations during 1998. During 1997, the Company drilled one well in the
Casmalia Field which was non-productive.
Depending upon oil prices and other relevant factors, the Company intends to
drill up to six horizontal wells and recomplete up to 10 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 at relatively shallow depths (2,700 feet). Costs are anticipated to
average approximately $550,000 per well, with a lateral extension of each well
ranging from 1,500 to 2,000 feet. See "Description of Property-Principal
Properties-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 yet 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 formation, the Monterey,
which is a prolific producing formation offshore and onshore California, lies
below the Sisquoc at approximately 5,500 feet. A horizontal well drilled into
this formation during 1995 developed mechanical problems and operations were
suspended. The Company had deferred attempts to correct the problem until such
time as oil prices increase sufficiently to justify such efforts. 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.
Louisiana
The Company acquired an 80% working interest in the Potash Field in
September 1997 and subsequent to 1997 year end acquired the remaining 20%
working interest. The total field reserves comprise approximately 13.9 Bcf and
approximately 1.3 MMBbl. Current production from the field is averaging 375 Bopd
and 4.0 MMcfd. Increases in productivity and possibly reserves are expected to
be achieved through completion of a number of potential zones presently behind
pipe in existing wells. These potential producing zones range in depth from
1,500 to 15,000 feet. Further technical programs, including a possible 3-D
seismic shoot, are planned to evaluate the exploration potential of the Company
lands associated with this field. The Company owned a 40.5% working interest in
the Manila Village field and subsequent to year end 1997 acquired an additional
10.2% working interest. The Company's net reserves, including the 1998 acquired
interest, are approximately 327 MBbl and 156 MMcf. Current gross production is
averaging 900 BOEPD. A workover of a shut-in well is scheduled for 1998 in order
to increase field production. A 3-D seismic program is being interpreted to
determine additional opportunities to further develop this field.
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, 13 of which were completed during the year. Also, a well under the
Magdalena River was recompleted and plans to drill two additional wells which,
if commercial, should establish a new commercial area for development. In the
Velasquez Field, the operator recompleted a behind pipe zone in three wells.
Initial per well production rates ranged from 142 Bopd to 223 Bopd. Studies to
date indicate up to 23 wells with behind pipe zones suitable for recompletion.
Recompletion of ten of these wells is budgeted for 1998. 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
(Alberta Stock Exchange), represented approximately 8.5% of the Company's PV-10
Value at December 31, 1997. The Canadian properties produced an average of 608
BOEPD for the year ended December 31, 1997, from 142 wells covering 56,800 gross
(14,972 net) developed acres, most of which are located in the province of
Alberta. These properties had proved reserves of 2.6 MMBOE at December 31, 1997.
The information presented has not been adjusted for the approximate 26% minority
interest in Beaver Lake held by others. 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 $17.0 million over the next three
years on this project in addition to the approximate $1.4 million expended as of
December 31, 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 expects to sign a joint venture agreement during
1998. However, the recent economic turmoil in Indonesia may affect the timing
and terms of such agreement.
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. On March 31, 1998, the
Company assigned a 3.75% carried working interest in the first well to be
drilled on this concession as payment of a finder's fee. By agreement dated
April 14, 1998, the Company sold one half of its net interest in this concession
to Omimex at the Company's cost. The Company expects to spend approximately
$550,000 in 1998 to drill the first exploratory well on this concession.
Other United States Properties
Other than its California and Louisiana properties, the Company has
interests in over 290 oil and gas wells located principally in Texas, Michigan,
New Mexico and Oklahoma, with other interests located in Utah, Wyoming, and
Alabama. 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. 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, 1997, on a PV-10 Value basis, approximately 16.9% of the
Company's proved reserves were in California, primarily in the Central Coast
Fields and approximately 48.2% 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, 1997. 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 33.0% 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, 1997, 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 $18.30 per Bbl and the comparable price at March 31, 1998 was
$15.60. Quotations for the comparable periods for natural gas were $2.45 per Mcf
and $2.41 per Mcf, respectively.
December 31, 1997
Proved Reserves, net PV-10
Value
Gross Oil Gas Dollar Value
Property Wells(1) (MBbls) (MMcf) MBOE (In thousands) Percentage
California
Cat Canyon 51 4,483 485 4,564 $10,320 8.7
Casmalia 26 259 10 260 328 0.3
Santa Maria 20 558 823 695 2,127 1.8
Gato Ridge 9 399 5 400 816 0.7
Other 77 2,034 623 2,138 6,466 5.4
Total California 183 7,733 1945 8,057 20,057 16.9
Louisiana
Potash Field 37 1,066 11,116 2,919 15,917 13.4
Manila Village 10 262 125 283 2,186 1.9
Total Louisiana 47 1,328 11,241 3,202 18,103 15.3
Other United States
Michigan 185 560 3,889 1,209 4,743 4.0
Texas 48 397 1,141 587 2,794 2.4
New Mexico 23 474 1,133 662 4,576 3.9
Other 38 58 961 218 1,172 0.8
Total Other United States 294 1,489 7,124 2,676 13,285 11.1
Total United States 524 10,550 20,310 13,935 51,445 43.3
Colombia 511 12,568 -- 12,568 57,136 48.2
Canada 168 807 10,986 2,638 10,048 8.5
Total International 679 13,375 10,986 15,206 67,184 56.7
Total 1,203 23,925 31,296 29,141 $118,629 100.0
<FN>
(1) Includes locations attributed to proved undeveloped reserves and wells in
which the Company holds royalty interests.
</FN>
================================================================================
California
Producing Properties
The Company operates all of its wells in the Central Coast Fields and
maintains an average working interest in these wells of 98.8% and an average net
revenue interest of 89.4%. These fields produced 1,808 net BOEPD for the year
ended December 31, 1997, and had proved reserves at December 31, 1997 of 5.9
MMBOE. The Company's 1998 operations may include recompletions of up to 32
existing vertical wells and reactivation of up to 15 existing shut-in vertical
wells.
Cat Canyon Field. The Cat Canyon Field is the Company's principal California
producing property, representing approximately 8.7% of the Company's PV-10 Value
at December 31, 1997. 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 for the month of December 1997, average production was
approximately 1,243 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 (99.7% net revenue interest) in
approximately 45 producing wells and a number of non-producing wells located in
this field which consists of two major producing horizons, the Sisquoc and the
Monterey. The Sisquoc formation, 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 waterflood operations.
In 1995, the Company drilled its first horizontal well into the Monterey
formation. The well developed mechanical problems and operations were suspended.
The Company has deferred attempts to correct the problem until such time as oil
prices increase sufficiently to justify further efforts. In 1996, the Company
initiated its present horizontal well drilling program in the Cat Canyon Field
by drilling five horizontal wells into the Sisquoc formation S1b sand (which is
one of the multiple separate sand bodies comprising the Sisquoc formation). Of
the five wells, three wells were drilled in the central fault block, on which a
waterflood operation was previously conducted, 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 130 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 encountered 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. In 1997, the Company continued
its horizontal drilling program in the Cat Canyon Field by drilling eight
additional wells into the Sisquoc S1b sand. Of the eight wells, five were
drilled into the waterflood area and the remaining three were drilled into other
areas. Year end average production rates for the wells in the waterflood area
were 82 Bopd and 1,100 barrels of water per day per well. Production rates for
the other wells were 88 Bopd and 13 barrels of water per day per well. The wells
drilled into the central waterflood area, as expected, are producing oil with
high volumes of residual water from the prior waterflood operations. The Company
believes that by using high volume pumps and lifting large volumes of fluid, the
ratio of oil to total fluids produced will gradually increase. Production
declines have been in line with the Company's expectations of roughly a 40-50%
decline in production during the first 12 months of the wells' operation,
followed by a more moderate 10% annual decline in production.
Results from the horizontal well drilling program have not met the Company'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
waterflood area of the central fault block. As many as four additional wells may
be drilled, depending on results from existing wells and product prices.
Horizontal wells in the field generally have a horizontal extension of 1,500 to
2,000 feet and cost approximately $550,000 as a completed well.
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 of the PV-10 Value of the Company's proven reserves at December 31,
1997. Among such fields are the following:
Gato Ridge Field. The Gato Ridge Field, which represented approximately 0.7%
of the Company's PV-10 Value at December 31, 1997, 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 86%
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. In 1997, the Company drilled a pair of
SAGD wells, to the Sisquoc formation at a total cost of $1.8 million, including
related surface equipment. In addition, two horizontal wells were drilled to a
different zone in the Sisquoc formation, at an average cost of $537,000, both of
which 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. Operations on the other well have
been suspended. 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 and a recovery in oil prices. At such time steam will be injected into
the upper well and thereafter production will commence from the lower well.
Should this procedure prove economically successful, the Company plans to
initiate other SAGD projects on its Central Coast Fields.
Richfield East Dome Unit (REDU). The REDU unit, which represented
approximately 2.4% of the Company's PV-10 Value at December 31, 1997, 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 by 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, Ventura, Solano, Kern and Orange counties, California, which in the
aggregate represented approximately 5.1% of the Company's PV-10 Value at
December 31, 1997.
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. Nineteen 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 $3.0 million as completed wells. The Company would have an 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. An exploratory well commenced drilling in March 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.
Louisiana
Manila Village is located in Jefferson Parish, Louisiana. The Company
operates this field and to year end 1997, owned a working interest of 40.5% (28%
net revenue interest) in the wells in the field. Subsequent to year end 1997,
the Company acquired an additional 10.2% working interest. The field represented
approximately 1.9% of the Company's PV-10 Value at December 31, 1997. The field
covers approximately 450 gross acres of land covered by shallow waters, and is
located approximately forty miles south of New Orleans. There are six producing
wells in the field that produced approximately 331 BOEPD for the year ended
December 31, 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 that represented approximately 13.4% of the Company's PV-10 Value
at December 31, 1997. 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. To year end
1997, the Company owned 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. Subsequent to year end 1997, the Company acquired the
remaining working interest. Current production from the field is approximately
375 Bopd and 4.0 MMcfd 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.
Other United States Properties
In addition to its California and Louisiana properties, the Company owns
producing properties in a number of states, primarily New Mexico, Michigan,
Texas and Oklahoma, which collectively represented approximately 11.1% of the
Company's PV-10 Value at December 31, 1997. At such date, these properties had
proved reserves of 2.7 MMBOE and produced approximately 833 BOEPD for the year
ended December 31, 1997 . The principal producing properties are:
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 interest (42% net revenue) 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% (38.75% net revenue interest). 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. A second reentry well to test the shallower zones was completed in
September 1997, and is currently flowing approximately 175 Bopd and 140 Mcfd of
gas, with a small amount of water. A gas sales line was completed in February
1998, allowing for gas sales from the two wells. 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
Omimex, acquired their interests in the Middle Magdalena Basin properties from
Texaco in 1994 and 1995 transactions; 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 52,894 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 9,300 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. Approval of both Ecopetrol and the Ministry of the
Environment is required to implement a development program. 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.
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 40.0% of the Company's PV-10 Value at
December 31, 1997, produced an average of 1.87 Mbopd for the year ended December
31, 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,
and produced an average of 505 Bopd for the year ended December 31, 1997.
The Company's Colombian properties in the aggregate represented 12.6 MMBOE
at December 31, 1997 or approximately 43.1% of the Company's total proved
reserves and approximately 48.2% 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.
Proved Reserves Average Daily Barrels of
at Dec. 31, 1997 Oil Produced in 1997
Field Name (MMBbls) Number of Wells
- ---------------------------- ------------------- ----------------------- --------------------------
Velasquez 2.9 102 505
North Nare 3.8 78 0
Magdalena 0.1 3 53
Teca & South Nare 5.8 328 1,871
=================== ======================= ==========================
Total 12.6 511 2,429
=================== ======================= ==========================
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 Velasquez 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. In the Velasquez field, the Company and Omimex recompleted
three wells in a behind-pipe zone. Initial per well production rates range from
142 Bopd to 223 Bopd. Studies to date indicate up to 23 additional wells with
behind pipe reserves suitable for recompletion.
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 Velasquez 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 Oil 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 250,000
Bopd 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
1997 averaged 30,500 Bopd of which the Company's share was approximately 2,300
Bopd. 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 8.5% of the Company's PV-10 Value at December 31,
1997. The Canadian properties produced an average of 608 BOEPD for the year
ended December 31, 1997, from 142 wells covering 56,800 gross (14,972 net)
developed acres, most of which are located in the province of Alberta. These
wells had proved reserves of 2.6 MMBOE at December 31, 1997. The information
presented has not been adjusted for the approximate 26% minority interest in
Beaver Lake held by others.
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 $17.0 million over the next three
years on this project, in addition to the approximate $1.4 million expended as
of December 31, 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 1998 and 1999. The Company has held discussions with several potential joint
venture partners with a view to concluding a participation agreement during
1998. However, the recent economic turmoil in Indonesia may affect the timing
and the terms of such agreement.
Great Britain Project
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. On March 31, 1998, the
Company assigned a 3.75% carried working interest in the first well to be
drilled on this concession as payment of a finder's fee. By agreement dated
April 14, 1998, the Company sold one half of its net interest in this concession
to Omimex at the Company's cost. The Company expects to spend approximately
$550,000 in 1998 to drill the first exploratory well on this concession. 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 Prospectus have been estimated by the
following independent petroleum engineers. In 1995, 1996 and 1997, 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, 1997, reflect weighted average
prices of $13.13 per BOE compared to $17.05 per BOE and $11.30 per BOE as of
December 31, 1996 and 1995, 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, 1995, 1996 and 1997, 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
since the preparation of the 1997 year end engineering estimates.
ESTIMATED PROVED OIL AND GAS RESERVES
At December 31,
1995 1996 1997
-------------------- -------------------- ---------------------
Net oil reserves (MBbl)
- ------------------------------------------------
Proved developed producing............... 10,278 12,029 13,977
- ------------------------------------------------
- ------------------------------------------------
Proved developed non-producing........... 590 1,367 2,639
- ------------------------------------------------
- ------------------------------------------------
Proved undeveloped....................... 1,664 13,283 7,309
----- ------ -----
- ------------------------------------------------
- ------------------------------------------------
Total proved oil reserves (MBbl)....... 12,532 26,679 23,925
====== ====== ======
- ------------------------------------------------
- ------------------------------------------------
Net natural gas reserves (MMcf)
- ------------------------------------------------
- ------------------------------------------------
Proved developed producing............... 9,371 12,659 11,995
- ------------------------------------------------
- ------------------------------------------------
Proved developed non-producing........... 871 1,516 5,407
- ------------------------------------------------
- ------------------------------------------------
Proved undeveloped....................... 9,237 9,490 13,894
----- ----- -------
- ------------------------------------------------
- ------------------------------------------------
Total proved natural gas reserves (MMcf) 19,479 23,665 31,296
====== ====== ======
- ------------------------------------------------
- ------------------------------------------------
Total proved reserves (MBOE)................ 15,778 30,623 29,141
====== ====== ======
- ------------------------------------------------
Estimates of proved reserves may vary from year to year reflecting changes
in the price of oil and gas and results of drilling activities during the
intervening period. Reserves previously classified as proved undeveloped may be
completely removed from the proved reserves classification in a subsequent year
as a consequence of negative results from additional drilling or product price
declines which make such undeveloped reserves non-economic to develop.
Conversely, successful development and/or increase s in product prices may
result in additions to proved undeveloped reserves. 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.
ESTIMATED PRESENT VALUE OF PROVED RESERVES
At December 31,
- ------------------------------------------------- ----------------------------------------------------------------
- ------------------------------------------------- -------------------- --------------------- ---------------------
1995 1996 1997
(In thousands)
-------------------- -------------------- --------------------
PV-10 Value
- -------------------------------------------------
- -------------------------------------------------
Proved developed producing............... $ 38,618 $ 84,916 $ 62,215
- -------------------------------------------------
- -------------------------------------------------
Proved developed non-producing........... 3,044 9,227 16,097
- -------------------------------------------------
- -------------------------------------------------
Proved undeveloped....................... 6,493 61,796 40,317
----- ------ -------
- -------------------------------------------------
- -------------------------------------------------
Total................................. $ 48,155 $ 155,939 $ 118,629
====== ======= =======
- -------------------------------------------------
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 1997
except PetroSource which accounted for 33.2% of such sales. The Company's
Colombian oil production, which is, and as a practical matter can only be, sold
to Ecopetrol, accounted for 31.4% of total oil and gas revenues in 1997.
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 250,000 Bopd 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 tariff revenue from the transportation of oil produced for Ecopetrol's
interest and by other producers in the area. The tariff revenue is sufficient to
cover the direct expenses associated with the operation of the pipeline.
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 MBbl
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 was
$12.04 per Bbl in 1997 and $12.49 per Bbl in 1996, representing approximately
64.6% and 61.1%, 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, 1997.
Year Ended December 31,
1995 1996 1997
--------------- ------------- --------------
--------------- ------------- --------------
Production Data:
- ----------------------------------------------
- ----------------------------------------------
Oil (MBbls) 1,227 1,968 2,107
- ----------------------------------------------
- ----------------------------------------------
Gas (MMcf) 1,337 1,651 2,408
- ----------------------------------------------
- ----------------------------------------------
Total (MBOE) 1,450 2,243 2,508
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
Average Sales Price Data (Per Unit):
- ----------------------------------------------
- ----------------------------------------------
Oil (Bbls) $ 12.22 $ 14.43 $ 13.73
- ----------------------------------------------
- ----------------------------------------------
Gas (Mcf) 1.45 1.88 2.09
- ----------------------------------------------
- ----------------------------------------------
BOE 11.69 14.05 13.54
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
- ----------------------------------------------
Selected Data per BOE:
- ----------------------------------------------
- ----------------------------------------------
Production costs (1) $ 7.29 $ 6.51 $ 6.62
- ----------------------------------------------
- ----------------------------------------------
General and administrative 1.27 1.72 1.93
- ----------------------------------------------
- ----------------------------------------------
Depletion, depreciation and amortization 1.92 2.43 2.84
- ----------------------------------------------
<FN>
(1) Production costs include production taxes.
</FN>
Drilling Activity
The following tables sets forth certain information for each of the years in
the three-year period ended December 31, 1997, relating to the Company's
participation in the drilling of exploratory and development wells in:
United States
Year Ended December 31,
1995 1996 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
----- --- --- --- ----- --- --- --- ----- --- --- ---
Exploratory Wells
Oil - - - - 2 1.00
Gas - - 3 1.35 - -
Dry (3) 3 0.46 3 1.28 1 0.5
Development Wells
Oil 4 1.51 11 7.59 13 13.00
Gas 1 0.10 3 0.64 - -
Dry (3) 1 0.04 1 0.35 1 1.00
Total Wells
Oil 4 1.51 11 7.59 15 14.00
Gas 1 0.10 6 1.99 - -
Dry (3) 4 0.50 4 1.63 2 1.5
<FN>
(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.
</FN>
Colombia
Year Ended December 31,
1995 1996 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
----- --- --- --- ----- --- --- --- ----- --- --- ---
Exploratory Wells
Oil - - - - - -
Gas - - - - - -
Dry (3) - - - - - -
Development Wells
Oil - - - - 13 3.25
Gas - - - - - -
Dry (3) - - - - - -
Total Wells
Oil - - - - 13 3.25
Gas - - - - - -
Dry (3) - - - - - -
<FN>
(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.
</FN>
Canada
Year Ended December 31,
1995 1996 1997
Gross (1) Net (2) Gross (1) Net (2) Gross (1) Net (2)
----- --- --- --- ----- --- --- --- ----- --- --- ---
Exploratory Wells
Oil - - - - - -
Gas - - - - - -
Dry (3) - - 1.0 0.01 1.0 1.0
Development Wells
Oil - - - - - -
Gas 1.0 0.09 - - 1.0 0.29
Dry (3) - - - - 1.0 0.87
Total Wells
Oil - - - - - -
Gas 1.0 0.09 - - 1.0 0.29
Dry (3) - - 1.0 0.01 2.0 1.87
<FN>
(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.
</FN>
Productive Oil and Gas Wells
The following table sets forth certain information at December 31, 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 378 179.3 74 23.4 452 202.7
Canada (1) 82 20.7 60 15.9 142 36.6
Colombia 390 97.4 - - 390 97.4
--------- ---------- --------- --------- ---------- --------
850 297.4 134 39.3 984 336.7
========= ========== ========= ========= ========== --------
<FN>
(1) No reduction is made for the minority interest in Beaver Lake.
</FN>
In addition to its working interests, the Company held royalty interests in
approximately 86 productive wells in the United States and Canada at December
31, 1997. The Company does not own any royalty interests in Colombia.
Oil and Gas Acreage
The following table sets forth certain information at December 31, 1997
relating to oil and gas acreage in which the Company owned a working interest:
Developed (1) Undeveloped
Gross Net Gross Net
United States 50,997 14,388 30,684 23,388
Canada (2) 56,809 13,492 39,114 12,280
Colombia 6,398 1,599 46,496 11,624
------------ ----------- ------------ -----------
============ =========== ============ ===========
Total 114,204 29,479 116,294 47,292
============ =========== ============ ===========
<FN>
(1) Developed acreage is acreage assigned to productive wells.
(2) No reduction is made for the minority interest in Beaver Lake
</FN>
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:
Year Ended December 31,
--------------------------------------------------
1995 1996 1997
---- ---- ----
Average sales price per BOE
California $ 12.55 $ 15.10 $ 13.49
Colombia 9.44 12.49 12.04
Canada 10.32 13.26 10.52
Other 13.97 17.39 17.68
Combined 11.69 14.05 13.54
Average production cost per BOE
California $ 9.15 $ 8.50 $ 7.48
Colombia 5.17 5.11 5.71
Canada 5.92 5.15 4.87
Other 7.49 7.88 7.47
Combined 7.29 6.51 6.62
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 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 a 40,000 barrel storage facility. An additional 60,000 barrels of crude oil
storage is also available for future demands. Crude oil 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 and surrounding western states, 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 18,000 square feet, are
leased with varying expiration dates to January 2002, at an aggregate rate of
$15,000 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-Economic and Political Risks of
Foreign Operations-Colombian Labor Disturbances"
Insurance
The Company maintains customary and usual insurance for companies in its
industry.
Legal Proceedings
Gitte-Ten v. Saba Petroleum Company. In December 1997, the Company
contracted with Gitte-Ten, Inc. ("GTI") to purchase from GTI all of its surface
fee and leasehold interests in certain property located in Santa Barbara County,
California. A portion of the purchase price was paid at closing on December 31,
1997, at which time GTI's interests were conveyed to the Company. The remaining
purchase price of $350,000 was to be paid through overriding royalty payments of
the Company's gross income from the leases until the balance was retired but no
later than January 1, 2003, on which date any unpaid balance was to be
immediately due and payable. To provide GTI with an assurance of the Company's
payment obligation, the Company executed a promissory note in the principal
amount of $350,000 which provided that said amount (less the total amount of
overriding royalties paid to GTI) was all due and payable on February 27, 1998,
unless the Company replaced the note by February 24, 1998, with an irrevocable
and non-cancelable surety bond or letter of credit in the then unpaid balance.
The Company was unable to procure either instrument and the note became all due
and payable on February 27, 1998. Notwithstanding attempted settlement
conferences by the Company with GTI, GTI filed a claim against the Company in
March 1998, for breach of contract and seeks damages of $350,000 plus interest
at the rate of 13.5% per annum and attorney fees. The Company intends to
interpose certain defenses.
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................ 50 Chairman of the Board and Chief Executive Officer
- ----------------------------------- ----------- ---------------------------------------------------------------------
- ----------------------------------- ----------- ---------------------------------------------------------------------
Walton C. Vance................ 50 Vice President, Treasurer, Secretary, Chief Financial Officer and
Director
- ----------------------------------- ----------- ---------------------------------------------------------------------
- ----------------------------------- ----------- ---------------------------------------------------------------------
Alex S. Cathcart............... 64 President, Chief Operating Officer and Director
- ----------------------------------- ----------- ---------------------------------------------------------------------
- ----------------------------------- ----------- ---------------------------------------------------------------------
Rodney C. Hill................. 61 Director
- ----------------------------------- ----------- ---------------------------------------------------------------------
- ----------------------------------- ----------- ---------------------------------------------------------------------
William N. Hagler.............. 65 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.................... 63 President Beaver Lake Resources Corp.
Imran Jattala.................. 39 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 to which he devotes fifty percent of
his professional time. 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 40 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 general management 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 January 1997 and was
Vice President - Legal Affairs from March 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.
Mr. Hill has informed the Company that he will not stand for re-election of the
Board of Directors.
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. Mr. Ormand has informed the Company that he will not stand for
re-election of the Board of Directors.
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 has been President of Beaver Lake since March 1998 where he had
also served as Vice President of Exploration and Land from 1993 to February
1997. At that time, Mr. Miller was transferred to the Company's corporate office
to the position of 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. In December
1997, Mr. Miller was appointed Vice President of the Company's international
exploration and drilling operations and President and Chief Operating Officer of
Saba Exploration Company. 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.
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 revenue 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 which
will be sought at the Annual Shareholders' Meeting scheduled for June 25, 1998,
the Board of Directors amended the plan to provide for a one-time grant of
15,000 shares of Common Stock, 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 four other most highly
compensated executive officers of the Company who received salary and bonuses of
over $100,000 in any of the years 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 ---
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
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
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
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
Company
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
Bradley T. Katzung 1997 $ 77,655 $ 70,200 (2) --- $ 1,097
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
Executive Vice President & 1996 --- --- --- --- ---
General
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
Manager -- USA 1995 --- --- --- --- ---
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
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- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
Rodney C. Hill 1997 $ 121,636 --- --- 125,000 ---
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
Vice President-Legal Affairs 1996 --- --- --- --- ---
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
1995 --- --- --- --- ---
- -------------------------------- --------- ---------------- ------------ ------------------ ------------------ -------------------
<FN>
(1) Includes amounts reimbursed by the Company in 1995 to SEDCO, a corporation
wholly owned by Ilyas Chaudhary, of $75,000 for management services
performed by Mr. Chaudhary.
(2) "Other Annual Compensation" was less than the lesser of $50,000 or 10% of
such officer's annual salary and bonus for such year. (3) Represents the
contributions made by the Company on behalf of these individuals to the
Company's 401(k) Plan. (4) Consists of options covering 200,000 shares
granted pursuant to the Company's 1996 Incentive Equity Plan; 200,000
shares of deferred Common Stock; and 100,000 performance shares issuable if
the Company meets 1998 earnings test.
</FN>
Option/SAR Grants In Last Fiscal Year
The following stock options were granted during 1997 by the Company to
the named executives.
Potential
Realized Value At
Assumed annual
Rates of Stock Alternative
Price to (f) and
Individual Grants Appreciation For (g); Grant
Option Term Date Value
- -------------------------------------------------------------------------- ------------------- --------------
- --------------------- ------------ ------------- ------------- ----------- --------- --------- -------------
(a) (b) (c) (d) (e) (f) (g) (h)
Number of
Securities % of Total
Underlying Options/
Options/ SARs
SARs Granted to
Granted (f) Employees Exercise or Grant Date
Name (in in Fiscal Base Expiration Present
thousands) Year Price($/Sh.) Date 5% ($) 10% ($) Value $
- --------------------- ------------ ------------- ------------- ----------- --------- --------- -------------
- --------------------- ------------ ------------- ------------- ----------- --------- --------- -------------
Ilyas Chaudhary 200 33.6 15.50 5-30-07 1,454,500
Herb Miller 15 2.5 15.50 5-30-07 109,100
Alex Cathcart 75 12.6 15.50 5-30-07 421,600
Imran Jattala 25 4.2 15.50 5-30-07 181,800
Rod Hill 125 21.0 15.50 5-30-07 909,000
Burt Cormany 20 3.4 15.50 5-30-07 89,800
Total in 1997 595
<FN>
(1) Valuation Method used: Black-Scholes option pricing model:
Expected volatility - 43.16% Risk-free rate of return -
ranging from 6.18%-6.49% Dividend yield - 0% Time of Exercise
- full vesting period of each option, ranging from 2-5 years
</FN>
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 Exercise (#) Value Fiscal Year-End (#) Fiscal Year-End ($)
Realized ($) 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
- ------------------------------------------------------------------------------------------------------------------------
Compensation and Options Committee Interlocks and Insider Participation
For the year ended December 31, 1997, the following non-executive directors
of the Company served as members of the Compensation and Options Committee of
the Board of Directors: Messrs. Sohail, Ormand and Hagler. Neither Mr. Sohail
nor Mr. Ormand were formerly, nor are they currently, officers or employees of
the Company or any of its subsidiaries. Mr. Hagler, although currently not an
officer or employee of the Company or any of its subsidiaries, was President
from July 1997 through September 1997 of Capco, an affiliate of the Company.
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 of 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 was
later extended to 1998 by the Company in December 1997.
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.
Herb Miller Employment Agreement. Beaver Lake Resources Corporation, a
74%-owned subsidiary of the Company, and Herb Miller have entered into an
employment agreement for a two-year term expiring on March 1, 2000, pursuant to
which Mr. Miller will serve as President of that subsidiary. The employment
provides for an annual salary of $85,000 (Cdn) and the grant of options to
purchase 500,000 shares of Beaver Lake Resources Corporation's common stock at a
strike price of $0.50 (Cdn) per share to be vested fifty percent a year for two
years. During the first year of Mr. Miller's employment, the agreement provides
that either party may terminate the agreement by providing three months' written
notice thereof to the other party.
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 amended the plan to provide for a one-time grant of 15,000 shares of
Common Stock 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. In March, 1998, the legal
services agreement was amended to terminate the existing fee arrangement and
limit the scope of representation of the Company to matters pertaining to the
proposed business combination with compensation set at $100,000 upon completion
of the business combination or $50,000 if such transaction is not consummated.
The agreement was further amended to provide for the cancellation of the grant
of options to acquire 125,000 shares of Common Stock and, among other
consideration, the issuance of 20,000 shares of Common Stock, fully paid, and
the grant of options to acquire 30,000 shares of Common Stock at fair market
value at the time of grant that vested immediately.
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. During January 1998, the Company engaged CIBC-Oppenheimer to advise
the Company with respect to strategies and procedures to adopt in an effort to
maximize shareholder values.
William N. Hagler, a director of the Company, is the President of Unico,
Inc. and was the President of Capco from July 1997 to September 1997.
In January 1998, the Company engaged Faysal Sohail, a director of the
Company, to render investor relations services to the Company for which Mr.
Sohail had been granted 20,000 shares of fully paid Common Stock.
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 March 31,
1998, when there were 10,947,393 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 including $150,000 dividend, are
converted at $4.06 per share (the closing price for the Company's Common Stock
on March 31, 1998), that all 269,663 Warrants issued in connection with the
Series A Preferred Stock are exercised, and that the Company obtains the
requisite approval to comply with the terms of the Series A Preferred Stock with
respect to conversion. See "Risk Factors-Potential Dilution Series A Preferred
Stock". Such conversion and exercise would increase the outstanding shares by
2,769,663 shares to 13,717,056. 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:
- --------------------------------------------------------------------------------------------------------------------
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Capco Resources Ltd. (2) 3,472,890 31.72% 25.32%
2236 S. Broadway, Suite K
Santa Maria, CA 93456
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- --------------------------------------------------------------------------------------------------------------------
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Ilyas Chaudhary (2)(3) 3,743,521 34.20% 27.29%
3201 Airpark Dr., Suite 201
Santa Maria, California 93456
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Other Directors and Named
Executive Officers:
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
Walton C. Vance 3,000 * *
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William N. Hagler 14,000 * *
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Ronald D. Ormand - * *
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Rodney C. Hill 1,500 * *
- --------------------------------------------------------------------------------------------------------------------
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Alex S. Cathcart - * *
Faysal Sohail 31,600 * *
Bradley T. Katzung 360 * *
Herb Miller - * *
Burt Cormany 12,000 * *
Imran Jattala - * *
- --------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------------------------------------------
All Directors and Officers as a 3,805,981 34.77% 27.75%
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) 2,724,719 2,724,719 0
Aberfoyle Capital Limited 44,944 (8) 44,944 0
<FN>
* 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 100,000 shares were exercisable as of March 31, 1998. 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, 3,472,890 shares (31.7%) 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 269,501 shares of Common Stock (2.5%) and 4,227,821 shares
of the common stock of Capco. As of March 31, 1998 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 3,472,890 and 269,501 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. The
Certificate of Designation governing the Series A Preferred Stock and the
Warrants each contain provisions which limit the number of shares of Common
Stock into which the shares of Series A Perferred Stock and the Warrants
are convertible. Under these provisions, the number of shares of Common
Stock into which the Series A Preferred Stock and the Warrants are
convertible (together with any additional shares of Common Stock held by
this Selling Stockholder) will not exceed 4.9% of the Company's then
outstanding Common Stock. 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 and the Warrants.
(7) This number is the sum of 2,500,000 (the shares issuable upon conversion at
a Conversion Price of $4.06, the closing price for the Common Stock on
March 31, 1998) 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.
</FN>
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 March 31, 1998, the Company had 10,947,393 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 exchange for $10
million. The Series A Preferred Stock bears a cumulative dividend of 6% per
annum payable quarterly in cash or, at the Company's option, the dividend amount
may be added to the "Conversion Amount", as defined. The Series A Preferred
Stock 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. Presently,
the Series A Preferred Stock is convertible into a maximum of 2,165,898 shares
of the Common Stock (subject to increase in the event of certain dilutive
events), until shareholder or regulatory approval is obtained, which the Company
is 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 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. However, the holder has the
ability to convert all or any shares of the Series A Preferred Stock into Common
Stock. The Series A Preferred Stock must be redeemed under certain
circumstances. Such circumstances include the failure of the Company to obtain
an effective registration statement for the Common Stock underlying the Series A
Preferred Stock prior to June 28, 1998, failure to maintain American Stock
Exchange listing or should the Series A Preferred Stock cease to become fully
convertible as a result of such conversion resulting in the issuance of more
than 19.9% of the then outstanding shares of Common Stock and the Company has
not, within certain time limitations, secured shareholder approval to allow for
full conversion.
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. On February
7, 1996 the underwriter exercised its right to overallotment and $1,650,000 of
additional Debentures were issued. 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 and additional $24,000 of Debentures
were converted into 5,485 shares of Common Stock during the first quarter of
1998.
Warrants
The purchasers of the Series A Preferred Stock received warrants to
purchase 224,719 shares of Common Stock at a price of $10.68 per share for a
period of three years from December 31, 1997. In addition, Aberfoyle Capital,
Ltd., was issued warrants to acquire 44,000 shares of Common Stock as a fee in
connection with the placement of the Series A Preferred Stock. These warrants
are exercisable at $10.68 per share for a three year period from December 31,
1997. The warrants issued to the purchasers of the Series A Preferred Stock and
to Aberfoyle Capital, LTD., may be adjusted from time to time under certain
anti-dilution provisions.
Redemption Warrants
In connection with the issuance of the Series A Preferred Stock, the
purchaser received the right to be issued warrants to acquire 200,000 shares of
Common Stock should the Company exercise its right to redeem the Series A
Preferred Stock. The warrants are exercisable over five years commencing five
days after redemption of the Series A Preferred Stock at an exercise price of
105% of the price of the Common Stock at the time of redemption. The warrants
may be adjusted from time to time under certain anti-dilution provisions.
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 Shares 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
13,113,291shares of Common Stock (including 269,663 shares issuable upon the
exercise of the Warrants and an estimated maximum of 2,165,898 to a minimum of
1,896,235 shares issuable upon conversion of the Series A Preferred Stock,
depending on exercise of the warrants; such maximum being registered pursuant to
the Registration Statement of which this Prospectus forms a part.) An additional
number of shares of Common Stock, currently undeterminable, may be issued and
may be then registered in the future to satisfy full conversion of the Series A
Preferred Stock.See "Risk Factors-Potential Dilution-Outstanding Preferred
Stock" Of these shares, 9,307,310 shares will be freely tradeable without
restriction or further registration under the Securities Act. Of the remaining
shares, 3,805,981 will be "restricted securities" ("Restricted Shares") within
the meaning of Rule 144 under the Securities Act. In addition, approximately
817,143 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,
1996 and 1997, and for the three years in the period ended December 31, 1997
included in this Prospectus, have been included herein in reliance on the
report, which includes an explanatory paragraph concerning substantial doubt
regarding the Company's ability to continue as a going concern, 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, 1995, 1996 and 1997, 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: 42 United States gallons liquid volume, usually used herein in
reference to crude oil or other liquid hydrocarbons. Bcf: One billion cubic feet
of gas.
BOE or Barrels of oil equivalent: a conversion of 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: Barrels of oil equivalent per day.
Bopd: Barrels of oil per day.
BTU: 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: 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: 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: 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: Earnings before interest expense, provision (benefit) for taxes on
income, depletion, depreciation and amortization. Ecopetrol: Empresa Columbiana
de Perroles, the Columbian state-owned oil company.
Exploration: The search for economic deposits of minerals, petroleum and other
natural earth resources by any geological, geophysical or geochemical technique.
Exploration well: 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: Ageographic area in which a number of oil or gas wells produce from
a continuous reservoir.
Finding cost: a calculation, 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: Generally accepted accounting principles, consistently applied.
MBbl: One thousand barrels of oil.
MBOE: One thousand barrels of oil equivalent.
Mbopd: One thousand barrels of oil per day.
Mcf: One thousand cubic feet of natural gas.
Mcfd: One thousand cubic feet of natural gas per day.
Mineral interest: Possessing the right to explore, right of ingress and egress,
right to lease and right to receive part or all of the income from mineral
exploitation, i.e., bonus, delay rentals and royalties.
MMBbl: One million barrels of oil.
MMBOE: One million barrels of oil equivalent.
MMcf: One million cubic feet of natural gas.
MMcfd: One million cubic feet of natural gas per day.
Net acres or net wells: The sum of fractional ownership working interests in
gross acres or gross wells.
Net revenue interest: A share of a Working Interest that does not bear any
portion of the expense of drilling and completing a well that represents the
holder's share of production after satisfaction of all royalty, overriding
royalty, oil payments and other nonoperating interests.
Oil wells or gas wells: Those wells which generate revenue from oil production
or gas production, respectively.
Operator: The person or company actually operating an oil or gas well.
Proved developed reserves: Proved Reserves which can be expected to be recovered
through existing wells with existing equipment and operating methods.
Proved reserves: The estimated quantities of crude oil, natural gas and natural
gas liquids which geological and engineering data have demonstrated with
reasonable certainty to be recoverable in future years from known oil and gas
reservoirs under existing economic and operating conditions, on the basis of
prices and costs on the date the estimate is made and any price changes provided
by existing contracts.
Proved undeveloped reserves: Proved Reserves which can be expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.
PV-10 Value: 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.
Recompletion: 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: 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: 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: 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.
Working interest: The operating interest that gives the owner the right to
drill, produce, and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
SABA PETROLEUM COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
Report of Independent Accountants F-2
Consolidated Balance Sheets as of
December 31, 1996 and 1997 F-3
Consolidated Statements of Income,
years ended December 31, 1995, 1996 and 1997 F-4
Consolidated Statements of Stockholders'
Equity, years ended December 31, 1995, 1996 and 1997 F-5
Consolidated Statements of Cash Flows,
years ended December 31, 1995, 1996 and 1997 F-6
Notes to Consolidated Financial Statements F-7
Supplemental Information About Oil and
Gas Producing Activities (unaudited) F-31
Supporting Financial Statement Schedule:
Report of Independent Accountants F-37
Schedule II - Valuation and Qualifying Accounts,
years ended December 31, 1995, 1996 and 1997 F-38
Schedules other than that listed above have been omitted since they are
either not required, are not applicable or the required information is
included in the footnotes to the financial statements.
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, 1996 and 1997, and the
related consolidated statements of income, stockholders' equity and cash flows
for each of the three years in the period ended December 31, 1997. 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, 1996 and 1997, and the consolidated
results of their operations and cash flows for each of the three years in the
period ended December 31, 1997, in conformity with generally accepted accounting
principles.
The accompanying financial statements have been prepared assuming that the
Company will continue as a going concern. As discussed in Note 1 to the
financial statements, the Company's near term liquidity may not be sufficient to
satisfy their short term obligations, which raises substantial doubt about their
ability to continue as a going concern. Management's plans in regard to these
matters are also described in Note 1. The financial statements do not include
any adjustments that might result from the outcome of this uncertainty.
COOPERS & LYBRAND L.L.P.
Los Angeles, California
May , 1998
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31, 1996 and 1997
The accompanying notes are an integral part of these consolidated financial
statements F-6
1996 1997
---- ----
ASSETS
Current assets:
Cash and cash equivalents
$ 734,036 $ 1,507,641
Accounts receivable, net of allowance for doubtful
accounts of $65,000 (1996) and $69,000 (1997). 7,361,326 6,459,074
Other current assets 3,485,924 4,589,501
------------------------ ----------------------
------------------------ ----------------------
Total current assets 11,581,286 12,556,216
------------------------ ----------------------
------------------------ ----------------------
Property and equipment (Note 8):
Oil and gas properties (full cost method) 44,494,387 76,562,279
Land 1,888,578 2,685,605
Plant and equipment 3,799,307 5,682,800
------------------------ ----------------------
------------------------ ----------------------
50,182,272 84,930,684
Less accumulated depletion and depreciation (15,323,780) (22,325,276)
------------------------ ----------------------
------------------------ ----------------------
Total property and equipment 62,605,408
34,858,492
------------------------ ----------------------
------------------------ ----------------------
Other assets:
Deposits on properties 42,529 -
Notes receivable, less current portion 936,257 1,385,092
Deferred financing costs 1,123,250 553,030
Due from affiliates 103,559 235,608
Deposits and other 471,513 321,592
------------------------ ----------------------
------------------------ ----------------------
Total other assets 2,677,108 2,495,322
------------------------ ----------------------
======================== ======================
$ 49,116,886 $ 77,656,946
======================== ======================
======================== ======================
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities
$ 5,377,137 $ 10,104,519
Income taxes payable 1,981,064 733,887
Current portion of long-term debt 1,805,556 13,441,542
------------------------ ----------------------
------------------------ ----------------------
Total current liabilities 9,163,757 24,279,948
------------------------ ----------------------
------------------------ ----------------------
Long-term debt, net of current portion 20,811,980 19,609,855
Other liabilities 108,295 78,069
Deferred taxes 590,285 784,930
Minority interest in consolidated subsidiary 727,359 752,570
Preferred stock - $.001 par value, authorized
50,000,000 shares; issued and outstanding
10,000 (1997) shares - 8,511,450
Commitments and contingencies (Note 15)
Stockholders' equity:
Common stock - $.001 par value, authorized
150,000,000 shares; issued and outstanding
10,081,026 (1996) and 10,883,908 (1997) shares 10,081 10,884
Capital in excess of par value 12,891,002 17,321,680
Retained earnings 4,802,845 7,200,292
Deferred compensation - (803,000)
Cumulative translation adjustment 11,282 (89,732)
------------------------ ----------------------
------------------------ ----------------------
Total stockholders' equity 17,715,210 23,640,124
------------------------ ----------------------
======================== ======================
$ 49,116,886 $ 77,656,946
======================== ======================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
Years ended December 31, 1995, 1996 and 1997
1995 1996 1997
---- ---- ----
Revenues:
Oil and gas sales $ 16,941,247 $ 31,520,757 $ 33,969,151
Other 753,008 1,681,587 2,026,611
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Total revenues 17,694,255 33,202,344 35,995,762
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Expenses:
Production costs 10,561,552 14,604,291 16,607,027
General and administrative 2,005,192 3,919,435 5,124,771
Depletion, depreciation and amortization 2,826,684 5,527,418 7,264,956
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Total expenses 15,393,428 24,051,144 28,996,754
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Operating income 2,300,827 9,151,200 6,999,008
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Other income (expense):
Interest income 16,924 114,302 165,949
Other (26,614) 92,149 (535,426)
Interest expense, net of interest capitalized
of $27,369 (1995) (1,364,110) (2,401,856) (2,304,517)
Gain on issuance of shares of subsidiary 124,773 8,305 4,036
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Total other income (expense) (1,249,027) (2,187,100) (2,669,958)
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Income before income taxes 1,051,800 6,964,100 4,329,050
Provision for taxes on income (449,636) (2,957,983) (1,875,720)
Minority interest in earnings
of consolidated subsidiary (55,632) (241,401) (55,883)
------------------- ------------------ -------------------
------------------- ------------------ -------------------
Net income $ 546,532 $ 3,764,716 $ 2,397,447
=================== ================== ===================
=================== ================== ===================
Net earnings per common share:
Basic $ 0.07 $ 0.43 $ 0.23
Diluted $ 0.06 $ 0.37 $ 0.22
Weighted average common shares outstanding:
Basic 8,327,495 8,803,941 10,649,766
Diluted 8,699,233 11,825,453 12,000,940
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1995, 1996 and 1997
Common Stock Capital In Cumulative Unearned Retained Total
Excess Translation Compensation Earnings Stockholders'
Shares Amount Of Par Value Adjustment Equity
------------ ---------- --------------- ------------- --------------- ------------ ----------------
------------ ---------- --------------- ------------- --------------- ------------ ----------------
Balance at
December 31, 1994 8,238,514 $ 8,238 $ 5,764,219 $ - $ - $ 510,870 $ 6,283,327
Minority
interest in
subsidiary (19,273) (19,273)
Exercise of
options 116,666 117 189,466 189,583
Issuance of
Common Stock for 24,000 24 25,476 25,500
compensation
Issuance of
Common Stock 150,000 150 599,850 600,000
Cumulative
translation 22,480 22,480
adjustment
Unearned
compensation (8,500) (8,500)
Contributed
surplus 208,600 208,600
Net income
546,532 546,532
------------ ---------- --------------- ------------- --------------- ------------ ----------------
Balance at
December 31, 1995 8,529,180 8,529 6,787,611 22,480 (8,500) 1,038,129 7,848,249
Issuance and
exercise of 118,000 118 646,982 647,100
options
Issuance of
Common Stock 14,000 14 41,986 42,000
Cumulative
translation (11,198) (11,198)
adjustment
Unearned
compensation 8,500 8,500
Debenture
conversions 1,419,846 1,420 5,414,423 5,415,843
Net income 3,764,716 3,764,716
------------ ---------- --------------- ------------- --------------- ------------ ----------------
Balance at
December 31, 1996 10,081,026 10,081 12,891,002 11,282 - 4,802,845 17,715,210
Issuance and
exercise of 154,000 154 1,409,842 (803,000) 606,996
options
Issuance of
warrants 622,000 622,000
Cumulative
translation
adjustments
Debenture
conversions 648,882 649 2,398,836 2,399,485
Net income 2,397,447 2,397,447
------------ --------------------------- ------------- --------------- ------------ ----------------
Balance at
December 31, 1997 10,883,908 $ 10,884 $17,321,680 $ (89,732) $ (803,000) $7,200,292 $ 23,640,124
============ ========== =============== ============= =============== ============ ================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended December 31, 1995, 1996 and 1997
1995 1996 1997
---- ---- ----
Cash flows from operating activities:
Net income $ 546,532 $ 3,764,716 $ 2,397,447
Adjustments to reconcile net income to net cash
provided by operations:
Depletion, depreciation and amortization 2,826,684 5,527,418 7,264,956
Write off of property screening costs - - 254,937
Amortization of unearned compensation 17,000 8,500 -
Deferred tax provision (benefit) (39,000) 366,389 248,645
Compensation expense attributable to
non-employee option - 91,600 106,000
Minority interest in earnings of 55,632 241,403 55,883
consolidated
subsidiary
Gain on issuance of shares of subsidiary (124,773) (8,305) (4,036)
Changes in:
Accounts receivable (1,999,984) (2,919,287) 859,286
Other assets (2,452,503) (572,233) (24,304)
Accounts payable and accrued liabilities 2,396,976 (237,328) 4,768,747
Income taxes payable and other liabilities 509,343 650,644 (973,681)
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Net cash provided by operating activities 1,735,907 6,913,517 14,953,880
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Cash flows from investing activities:
Deposit (purchase) of restricted certificate of deposit (1,750,000) 1,750,000 -
Expenditures for oil and gas properties (12,807,412) (12,171,392) (32,874,800)
Expenditures for equipment, net (2,660,120) (585,893) (2,039,234)
Proceeds from sale of oil and gas properties 157,933 256,646 234,141
Increase in notes receivable - (1,172,639) (2,114,953)
Proceeds from notes receivable 302,968 67,384 629,109
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Net cash used in investing activities (16,756,631) (11,855,894) (36,165,737)
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Cash flows from financing activities:
Proceeds from notes payable and long-term debt 34,814,900 17,085,315 28,725,454
Principal payments on notes payable and
long-term debt (19,136,299) (12,296,839) (15,972,780)
Increase in deferred financing costs (1,854,421) (165,777) -
Net change in accounts with affiliated companies (47,120) (21,251) (131,562)
Net proceeds from exercise of options and
issuance of common stock 789,583 422,500 227,500
Proceeds from issuance of preferred stock, net - - 8,511,450
Issuance of warrants - - 622,000
Increase in contributed surplus 208,600 - -
Capital subscription of minority interest 74,778 12,805 8,535
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Net cash provided by financing activities 14,850,021 5,036,753 21,990,597
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Effect of exchange rate changes on cash
and cash equivalents 12,006 (627) (5,135)
------------------- ------------------ -----------------
------------------- ------------------ -----------------
Net increase (decrease) in cash and cash equivalents (158,697) 93,749 773,605
Cash and cash equivalents at beginning of year 798,984 640,287 734,036
------------------- ------------------ -----------------
=================== ================== =================
Cash and cash equivalents at end of year $ 640,287 $ 734,036 $ 1,507,641
=================== ================== =================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, 1996 and 1997, approximately
50.4% and 38.3% 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, 1997, 53.8
% of the Company's outstanding Common Stock is owned directly, or
indirectly, by the Company's Chief Executive Officer.
Management's Plans
The Company's financial statements for the year ended December 31, 1997
have been prepared on a going-concern basis which contemplates the
realization of assets and the settlement of liabilities and commitments in
the normal course of business. The Company reported a working capital
deficit of $11.7 million at December 31, 1997, due principally to the
classification of $12.3 million of long-term debt presently scheduled for
repayment to the Company's principal lender during the next year. The
Company is in a capital intensive business, and during 1997, the Company's
capital expenditures for drilling activities did not produce expected
increases in proved oil and gas reserves, which, when coupled with the
decline in oil and gas prices, reduced the quantity of proved reserves
against which the Company could borrow and the projected cash flow with
which to service debt. The Company's immediate needs for capital will
intensify should the Company be successful in one or more of the
exploratory projects it is undertaking, in that the Company will incur
additional capital expenditures to drill more wells and create
transportation and marketing infrastructure. Major exploratory projects
often require substantial capital investments and a significant amount of
time before generating revenue. The Company's exploratory prospect in
Indonesia requires a three-year work commitment of $17.0 million. The
Company is in negotiation with several potential joint venture partners to
participate in this project.
The Company is taking action to satisfy its working capital requirements.
It has retained investment banking counsel to advise it on such matters as
asset divestitures and a proposed business combination (see footnote 17).
It is in discussions with institutions to secure capital either by the
placement of debt or equity. Discussions have been held with the Company's
principal lender to restructure existing indebtedness to allow sufficient
time for the contemplated business combination to be concluded. The Company
is also in negotiations for the disposition of non-core oil and gas assets
and possibly the sale of real estate assets. The proceeds of such sales,
should they be concluded, would be applied to the reduction of bank debt.
Management believes that should such asset divestitures be timely
concluded, short term obligations to the bank will be satisfied to the
extent that the remainder of debt will be restructured to significantly
reduce the working capital deficit.
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.
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.
Derivative Instruments - The Company does not utilize derivative
instruments in the management of its foreign exchange, commodity price or
interest rate market risks.
The fair value of the Company's notes receivable and long-term debt,
excluding the Debentures, at December 31, 1996 and 1997 approximates
carrying value. The carrying value and fair value of the Debentures at
December 31, 1996 and 1997 are as follows:
1996 1997
------------------------------------ --------------------------------------
------------------------------------ --------------------------------------
Carrying Value Fair Value Carrying Value Fair Value
9% convertible
senior subordinated
Debentures-due 2005 $6,438,000 $36,374,700 $3,599,000 $6,298,250
The fair value of the Debentures at March 31, 1998 was $3,059,150.
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, which
includes amortization of assets under capital leases, 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 years
ended December 31, 1995, 1996 and 1997 was $155,900, $293,245 and $477,239,
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 December 31, 1997, the Company had unamortized costs in the amount
of $42,837 and $507,202, net of accumulated amortization of $256,500 and
$1,495,090, relating to its bank credit facilities and Debentures,
respectively. Amortization expense in 1995, 1996 and 1997 was $63,600,
$241,827 and $134,598, 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
Basic earnings per common share are based on the weighted average number of
shares outstanding during each year. The calculation of diluted earnings
per common share includes, when their effect is dilutive, certain shares
subject to stock options and 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.
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 1995. 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 period.
Year Ended
December 31,
1995
(unaudited)
Total revenues $27,677,526
Total operating expenses, including general and
administrative and depletion, depreciation and
amortization (20,036,052)
Interest expense (1,984,594)
Other income (expense) (9,690)
----------------------
Income before income taxes 5,647,190
Provision for taxes on income 2,767,123
----------------------
Net income $ 2,880,067
======================
Net earnings per common share (basic) $ 0.33
======================
The following unaudited summary of gross revenue and direct operating
expenses of the acquired properties for the nine month period ended
September 30, 1995 includes all adjustments (consisting of normal recurring
accruals only) which management considers necessary to present fairly the
gross revenues and direct operating expenses of the acquired properties for
the nine months ended September 30, 1995.
Nine Months
Ended
September 30,
1995
(unaudited)
Gross Revenues:
Sales of oil $ 8,871,288
Pipeline revenues 1,516,876
--------------------
Total gross revenues 10,388,164
--------------------
Direct operating expenses:
Operating expenses (1) 2,537,423
Pipeline operating expenses (1) 990,054
Production and other taxes (2) 474,211
--------------------
--------------------
Total direct operating expenses 4,001,688
--------------------
Excess of gross revenues over
direct operating expenses $ 6,386,476
====================
--------------------------
<FN>
(1) Excludes depreciation, depletion and amortization
expenses. (2) Includes war and pipeline transportation
taxes; does not include provision for income taxes.
</FN>
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 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 and 1997, BLRC issued 35,000 shares and 23,010 shares,
respectively, of common stock to minority shareholders. As a result of these
transactions, the Company owned 74.2% of the outstanding common stock of
BLRC at December 31, 1997.
The sales of shares of common stock by the subsidiary resulted in net gains
in 1995, 1996 and 1997 of $124,773, $8,305 and $4,036, 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, 1996 and
1997:
1996 1997
------------ ------------
Canadian prime plus 0.75% (6.75% at December 31, 1997) production notes
receivable, with interest paid currently, collateralized by producing oil
and
gas properties $ 120,385 $ 65,012
Prime plus 0.75% (9.25% at December 31, 1997) promissory note from an officer
of the Company with quarterly interest only installments, due October 31,
1998, collateralized by vested stock options to purchase the Common Stock
of the
Company 300,000 283,742
Prime plus 0.75% (9.25% at December 31, 1997) 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 739,206 414,205
9% note receivable from affiliated company, with principal and interest due in
full on December 31, 1998, collateralized by the Chief Executive Officer's
vested but unexercised options to purchase the Common Stock of the Company 101,667 101,667
11.5% note receivable from a joint venture partner, with principal and
interest
payments through June, 2002 collateralized by producing oil and gas properties - 1,737,554
10% note receivable from unaffiliated companies due on demand and
collateralized by personal guarantees from the borrowers' Chief Executive
Officers - 175,000
Other 79,917 43,940
------------ ------------
1,341,175 2,821,120
Less current portion (included in other current assets) 404,918 1,436,028
============ ============
$ 936,257 $ 1,385,092
============ ============
4. Oil and Gas Properties, Land, Plant and Equipment
Oil and gas properties, land, plant and equipment at December 31, 1996 and 1997
are as follows:
December 31, 1996 United
Oil and gas properties States Canada Colombia Total
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 costs 30,777,085 4,999,809 8,717,493 44,494,387
Less accumulated depletion
And depreciation 11,038,022 824,752 2,921,559 14,784,333
================== ================= ================ ===================
Capitalized costs, net $ 19,739,063 $ 4,175,057 $ 5,795,934 $ 29,710,054
================== ================= ================ ===================
Other property and equipment
Land $ 1,583,344 $ 843,351 $ 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
================== ================= ================ ===================
December 31, 1997
Oil and gas properties
Unevaluated oil and gas
Properties $ 5,555,350 $ $ $ 5,555,350
- -
Proved oil and gas properties 53,107,650 7,770,588 10,128,691 71,006,929
------------------ ----------------- ---------------- -------------------
Total capitalized costs 58,663,000 7,770,588 10,128,691 76,562,279
Less accumulated depletion
And depreciation 15,489,222 1,265,331 4,550,919 21,305,472
-------------------
================== ================= ================ ===================
Capitalized costs, net $ 43,173,778 $ 6,505,257 $ 5,577,772 $ 55,256,807
================== ================= ================ ===================
Other property and equipment
Land $ 2,380,371 $ $ 305,234 $ 2,685,605
-
Plant and equipment 3,799,515 81,200 1,802,085 5,682,800
------------------ ----------------- ---------------- -------------------
6,179,886 81,200 2,107,319 8,368,405
Less accumulated depreciation 634,225 43,416 342,163 1,019,804
------------------ ----------------- ---------------- -------------------
================== ================= ================ ===================
$ 5,545,661 $ 37,784 $ 1,765,156 $ 7,348,601
================== ================= ================ ===================
At December 31, 1997, plant and equipment and accumulated depreciation
included $620,248 and $ 73,972, respectively, for assets acquired under capital
leases.
Costs incurred in oil and gas property acquisition, exploration, and
development activities are as follows:
United
States Canada Colombia Total
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 incurred $ 10,554,913 $ 1,142,248 $ 474,231 $ 12,171,392
============== ============== ================ =================
============== ============== ================ =================
December 31, 1997
Exploration $ 5,581,637 $ 2,082,419 $ - $ 7,664,056
Development 13,680,108 277,991 1,411,198 15,369,297
Acquisition of proved
properties 9,035,274 488,345 - 9,523,619
============== ============== ================ =================
Total costs incurred $ 28,297,019 $ 2,848,755 $ 1,411,198 $ 32,556,972
============== ============== ================ =================
Oil and gas depletion expense in the years ended December 31, 1995, 1996
and 1997 was $2,605,419, $4,979,361 and $6,610,554 or $1.80, $2.22, and $2.64
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, 1995, 1996 and 1997:
1995 1996 1997
---- ---- ----
Interest paid $ 1,388,369 $ 2,309,475 $ 2,088,252
Income taxes paid $ - $ 1,150,029 $ 2,531,157
Non-cash investing and financing transactions:
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,
($15,655) and ($131,050) were recorded during the years ended December 31, 1995,
1996 and 1997, respectively.
The Company realized gains in 1995, 1996 and 1997 of $124,773, $8,305 and
$4,036, respectively, as a result of the issuance of common stock by a
subsidiary.
The Company incurred capital lease obligations in the amount of $598,827 to
acquire equipment during the year ended December 31, 1997.
Debentures in the principal amount of $2,839,000, less related costs of
$439,515, were converted into 648,882 shares of Common Stock during the year
ended December 31, 1997.
The Company incurred a credit to Stockholders' Equity in the amount of
$909,000 resulting from the granting of stock options to a consultant during the
year ended December 31, 1997.
The Company incurred a credit to Stockholders' Equity in the amount of
$273,496 attributable to the income tax effect of stock options exercised during
the year ended December 31, 1997.
6. Accounts Payable and Accrued Liabilities
Accounts payable and accrued liabilities at December 31, 1996 and 1997 are
as follows:
1996 1997
Trade accounts payable $ 3,545,599 $ 6,705,897
----------------------------------------------
Undistributed revenue payable 341,614 780,475
----------------------------------------------
Insurance and tax assessments payable 618,032 760,177
----------------------------------------------
Other accrued expenses 871,892 1,857,970
================ ================
Total $ 5,377,137 $ 10,104,519
================ ================
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,
1995, 1996 and 1997 are as follows:
1995 1996 1997
United States $ (523,572) $ 383,453 $ 457,166
--------------------------
Canada 134,138 693,439 262,852
--------------------------
Colombia 1,385,602 5,645,807 3,553,149
---------------- -------------------
=================
Total $ 996,168 $ 6,722,699 $ 4,273,167
================ =================== =================
Components of income tax expense (benefit) for the years ended December 31,
1995, 1996 and 1997 are as follows:
1995 1996 1997
Current:
------------------------
Federal $ (112,364) $ 149,600 $ 291,581
State 45,000 259,994 21,201
Foreign 556,000 2,182,000 1,310,987
---------------- ----------------- -------------------
488,636 2,591,594 1,623,769
---------------- ----------------- -------------------
Deferred:
Federal (44,350) 207,787 114,114
State 5,350 158,602 35,265
Foreign - - 102,572
-------------------
---------------- -----------------
(39,000) 366,389 251,951
-------------------
================ =================
$ 449,636 $ 2,957,983 $ 1,875,720
================ ================= ===================
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,
1995, 1996 and 1997 as follows:
1995 1996 1997
Expected tax provision (benefit) 34.0% 34.0% 34.0%
----------------------------------------
State income taxes, net of
----------------------------------------
Federal benefit 3.3 4.1 1.3
----------------------------------------
Effect of foreign earnings 2.6 5.6 7.6
----------------------------------------
Other 5.2 .3 1.0
----------------------------------------
================= =============== ============
45.1% 44.0% 43.9%
================= =============== ============
The tax effected temporary differences which give rise to the deferred tax
provision consist of the following:
1995 1996 1997
Property and equipment $ 337,900 $ 481,700 $ (92,500)
----------------------------------------
Effect of state taxes (12,300) (120,000) 171,800
----------------------------------------
Net operating losses 209,500 (2,200) 39,400
----------------------------------------
Foreign tax credits (640,000) (845,811) (648,394)
----------------------------------------
Alternative minimum tax credits (38,100) (61,200) 2,300
----------------------------------------
Change in valuation allowance 155,000 897,500 817,700
----------------------------------------
Other (51,000) 16,400 (38,355)
============== ============= ==============
$ (39,000) $ 366,389 $ 251,951
============== ============= ==============
The components of the tax effected deferred income tax asset (liability) as
of December 31,1996 and 1997 are as follows:
1996 1997
Property and equipment $ (1,458,300) $ (1,365,800)
------------------------------------------------------
State taxes 171,800 -
------------------------------------------------------
Net operating losses 39,400 -
------------------------------------------------------
Foreign tax credits 1,600,800 2,249,200
------------------------------------------------------
Alternative minimum tax credits 196,400 194,100
------------------------------------------------------
Other 35,200 73,500
----------------- ----------------
585,300 1,151,000
Valuation allowance (1,052,500) (1,870,200)
================= ================
Net deferred income tax liability $ (467,200) $ (719,200)
================= ================
At December 31, 1996 and 1997, $123,000 and $69,000 of current deferred
taxes are included in other current assets, respectively.
At December 31, 1997, the Company had approximately $2,249,200 of foreign
tax credit carryovers, which will begin to expire in the year 2000. A $1,870,200
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 $194,100. The credits carry over indefinitely and can
be used to offset future regular 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.
8. Long-Term Debt
Long-term debt at December 31, 1996 and 1997 consists of the following:
1996 1997
---- ----
9% convertible senior subordinated
Debentures due 2005 $ 6,438,000 $ 3,599,000
Revolving loan agreement with a bank 12,100,000 17,410,000
Term loan agreements with a bank 450,000 8,803,769
Demand loan agreement with a bank 1,605,136 2,362,809
Capital lease obligations - 525,819
Promissory note - 350,000
Promissory note 450,000 -
Promissory notes - Capco 1,574,400 -
------------------ ------------------
22,617,536 33,051,397
Less current portion 1,805,556 13,441,542
================== ==================
$20,811,980 $19,609,855
================== ==================
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 were 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 $2,839,000 of Debentures were converted into 648,882 shares of Common
Stock during the year ended December 31, 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 base term loan
of which $3.4 million was 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 December 31, 1997 the borrowing bases
for the two loans were $17.4 million and $3.1 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 December 31, 1997 was 8.1%. In accordance with
the terms of the Agreement, and after giving effect to the Company's anticipated
capital requirements, $6.6 million of the loan balances are classified as
currently payable at December 31, 1997. The Agreement, at December 31, 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. On March 30, 1998,
the Agreement was amended to provide for deferrals of borrowing base reductions
in the amount of $542,000 per month for a period of three months.
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 December 31, 1997) plus
3.0%. On December 31, 1997, a principal payment in the amount of $7.0 million
was made reducing the outstanding balance to $2.7 million, which is due to be
repaid no later than April 30, 1998, and accordingly, is classified as currently
payable at December 31, 1997.
In November 1997 the Company established a term loan ($3,000,000) with its
principal commercial lender. Interest is payable at the prime rate (8.5% at
December 31, 1997) plus 3.0%. The loan is due to be repaid no later than April
30, 1998, and accordingly, is classified as currently payable at December 31,
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 (6.75% at December 31,
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 $56,000 per month. In accordance with the terms of the
loan agreement, $643,000 of the loan balance is classified as currently payable
at December 31, 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 December 31, 1997 was
8.8%.
The promissory note ($350,000) is due to the seller of an oil and gas
property, which was acquired by the Company in December 1997. The note bears
interest at the rate of 13.5%, and is due to be repaid in 1998.
The promissory note ($450,000) was due to the seller of an oil refining
facility, which was acquired by the Company in June 1994. Final payment of the
note, which bore interest at the prime rate in effect on the note anniversary
date, plus two percent was made on June 24, 1997. The note was collateralized by
a deed of trust on the acquired assets.
The 9% 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. The loan
proceeds were utilized by the Company principally in connection with the
acquisition of producing oil and gas properties in Colombia. The notes were paid
in 1997.
Maturities of long term debt at December 31, 1997 are as follows:
1998 $13,441,542
1999 5,144,241
2000 5,195,129
2001 4,834,485
2002 2,457,000
Thereafter 1,979,000
-------------
$33,051,397
9. Related Party Transactions
Related party transactions are described as follows:
In 1995, 1996 and 1997, the Company charged its affiliates $92,900, $26,300
and $18,600, respectively, for reimbursement of certain general and
administrative expenses.
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 1997 the Company charged interest in the amount of $45,343 to affiliates
and was charged interest in the amount of $60,220 by affiliates. The Company
paid the affiliates a total of $142,000 for such interest charges, which
included amounts charged, but unpaid, at the end of the previous year.
In 1997 the Company received $10,000 in repayment of a short-term advance
to an affiliate, and $61,193 from the Chief Executive Officer for accrued
interest and principal on his loan from the Company.
In 1997 the Company charged an affiliate $23,335 for charges incurred in
connection with a potential property acquisition, and $93,642 for an advance and
related expenses against an indemnification provided by the affiliate.
During the year 1997, the Company billed an affiliate a total of $18,814 and
received payments of $91,983 which included amounts billed in the prior year, in
connection with the affiliate's participation in drilling and production
activities in one of the Company's oil properties.
In 1997, the Company incurred airplane charter expenses in the amount of
$72,774 from non-affiliated airplane leasing services, for the use of an
airplane owned by the Company's Chief Executive Officer
10. Preferred Stock
On December 31, 1997, the Company sold 10,000 shares of Series A 6%
Convertible Preferred Stock ("Preferred Stock") for $10 million. The Preferred
Stock bears a cumulative dividend of 6% per annum, payable quarterly, and, at
the option of the Company, can be paid either in cash or through the issuance of
shares of the Company's Common Stock. The Preferred Stock is senior to all other
classes of the Company's equity securities. The conversion price of the
Preferred Stock is based on the future price of the Company's Common Stock,
without discount, but will be no greater than $9.345 per share. Conversion of
the Preferred Stock cannot begin until May 1, 1998. Three years from date of
issuance, any remaining Preferred Stock will automatically convert into the
Company's Common Stock. The Preferred Stock is redeemable, at the option of the
Company, at various prices commencing at 115% of the issue price plus any
accrued, but unpaid, dividends, and under certain circumstances, at the option
of the Preferred Stock holder. Should the Company choose to redeem the issue,
the Preferred Stock holder will be entitled to receive 200,000 warrants to
purchase the Company's Common Stock. In connection with the sale of the
Preferred Stock, warrants to purchase 224,719 shares of Common Stock were issued
to the purchaser of the Preferred Stock and warrants to purchase 44,944 shares
of Common Stock were issued as a fee for the placement of the issue. The
warrants are exercisable over a three year period at a price of $10.68. The fair
value of the warrants at December 31, 1997, was estimated at $622,000 using the
Black-Scholes pricing model.
11. 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 canceled 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 canceled. 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.
During the year 1996, the Company 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.
On May 30, 1997, the Company issued options to acquire 470,000 and 125,000
shares of Common Stock to certain employees and a consultant, respectively, in
accordance with the provisions of the 1996 Incentive Equity Plan. Options to
acquire 15,000 shares of Common Stock were subsequently cancelled. The options
have an exercise price equal to 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 December 31, 1997. The
Company recognized deferred compensation expense of $909,000 resulting from the
grant to the consultant. Of this amount, $106,000 was reported as compensation
expense during the year ending December 31, 1997. The balance of deferred
compensation expense will be amortized over the remaining vesting period of the
option.
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.
As of December 31, 1997, the Company had outstanding options for 548,000
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 a
portion of these options. Options to acquire 154,000 shares of Common Stock were
exercised in 1997, and options to acquire 40,000 shares of Common Stock were
cancelled in 1997. Options to acquire 344,000 shares of Common Stock were
exercisable at December 31, 1997.
Information regarding the shares under option and weighted average exercise
price for the years ended December 31, 1995, 1996 and 1997 is as follows:
1995 1996 1997
---------------------------- -------------------------- ------------------------------
---------------------------- -------------------------- ------------------------------
Wt. Avg. Wt. Avg. Wt. Avg.
Shares Ex. Pr. Shares Ex. Pr. Shares Ex. Pr.
Beginning of year 890,000 $1.42 740,000 $1.40 742,000 $1.49
Granted 400,000 $1.56 120,000 $4.06 640,000 $15.50
Exercised (116,666) $1.63 (118,000) $3.58 (154,000) $1.47
Canceled (433,334) $1.52 - - (55,000) $5.31
------------- ------------ -------------
============= ============ =============
End Of Year 740,000 $1.40 742,000 $1.49 1,173,000 $8.95
============= ============ =============
Options exercisable
at end of year 176,000 $1.34 306,000 $1.37 344,000 $1.38
============= ============ ============ ============ ============= =============
============= ============ ============ ============ ============= =============
Weighted average fair value of
options granted during the year $0.29 $1.17 $6.99
------ ------ -----
The fair value of each option granted during 1995, 1996 and 1997 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 ranging from 43.2% to 58.4%, (c) average time to
exercise ranging from six months to five years, and (d) expected dividend yield
of 0.0%.
The following table summarizes information about stock options outstanding at
December 31, 1997:
Options Outstanding Options Exercisable
--------------------------------------------------- ------------------------------------
--------------------------------------------------- ------------------------------------
Number Average Weighted Number Weighted
Range of Outstanding at Remaining Average Exercisable at Average
Exercise prices December 31, Contractual Exercise December 31, Exercise Price
1997 Life Price 1997
---------------- ----------------- --------------- -------------- ----------------- ----------------
---------------- ----------------- --------------- -------------- ----------------- ----------------
$1.25 - $1.38 308,000 (1) $ 1.29 240,000 $ 1.29
$1.50 220,000 (2) $ 1.50 100,000 $ 1.50
$4.38 20,000 not stated $ 4.38 4,000 $ 4.38
$15.50 625,000 9.4 years $ 15.50 - $ -
----------------- -----------------
================= =================
$1.25 - $15.50 1,173,000 344,000
================= =================
================= =================
<FN>
(1) No contractual expiration date for 163,000 options; balance of 145,000
options, to the extent they are vested, expire one year following termination of
option holder's employment.
(2) No contractual expiration date for 180,000 options; remaining contractual
life for 40,000 options is ten months.
</FN>
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, 1996 and 1997 was $30,800, $30,136, and $482,793,
respectively. If the compensation cost for the Company's 1995, 1996 and 1997
grants to employees had been determined consistent with SFAS No. 123, the
Company's net income and net earnings per common share (basic) for 1995, 1996
and 1997 would approximate the proforma amounts set forth below:
1995 1996 1997
----------------------------- -------------------------------- -------------------------------
----------------------------- -------------------------------- -------------------------------
As Reported Proforma As Reported Proforma As Reported Proforma
Net income $546,532 $522,785 $3,764,716 $3,745,218 $2,397,447 $2,094,736
Net earnings per
common share
(basic) $0.07 $0.06 $0.43 $0.43 $0.23 $0.20
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 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 1998 provided that certain operating results are reported by the
Company at the end of that year.
12. Earnings Per Share
(In thousands, except per share data)
1995 1996 1997
----------------------------- -------------------------------- -----------------------------------
----------------------------- ------------------------------- ------------------------------------
Income Shares Per share Income Shares Per share Income Shares Per share
Income available to
common stockholders
- basic EPS $ 547 8,327 $ 0.07 $ 3,765 8,804 $ 0.43 $ 2,397 10,650 $ 0.23
Effect of dilutive
securities:
Contingently issuable 330 371 350
shares
Convertible Debentures 9 41 559 2,650 203 1,001
--------- ------- -------------------- ---------- ----------
--------- ------- -------------------- ---------- ----------
Income available to
common stockholders
and assumed conversions
- diluted EPS $ 556 8,699 $ 0.06 $ 4,324 11,825 $ 0.37 $ 2,600 12,001 $ 0.22
========= ======= =========== ==================== ========== ========== ========== ==============
========= ======= =========== ==================== ========== ========== ========== ==============
13. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating results
for 1996 and 1997:
Net Basic Net Diluted Net
Total Gross Income Income (Loss) Income (Loss)
Revenues Profit (Loss) Per Share Per Share
-------- ------ ------- ------------ ------------
1996
----
First Quarter $ 7,387,290 $ 2,506,692 $ 755,488 0.09 $0.08
Second Quarter
8,002,828 2,717,416 734,375 0.09 0.08
Third Quarter
7,762,922 2,530,891 730,869 0.08 0.07
Fourth Quarter
10,049,304 3,970,582 1,543,984 0.17 0.14
-------------- -------------- --------------
============== ============== ==============
$ 33,202,344 $ 11,725,581 $ 3,764,716
============== ============== ==============
1997
----
First Quarter $ 9,563,474 $ 3,912,379 $ 1,441,582 0.14 $0.12
Second Quarter
8,271,953 1,945,168 507,300 0.05 0.05
Third Quarter
8,942,773 2,424,537 598,618 0.06 0.05
Fourth Quarter
9,217,562 2,200,062 (150,053) (0.01) (0.01)
-------------- -------------- --------------
============== ============== ==============
35,995,762 10,482,146 2,397,447
============== ============== ==============
14. 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
$25,745, $44,014 and $41,762 in 1995, 1996 and 1997, respectively.
15. 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 1998 through 2002. Future
minimum lease payments under all leases are as follows:
Year Ending December 31,
1998 $308,660
1999 233,521
2000 86,503
2001 35,697
2002 13,105
==============
$677,486
==============
Rent expense amounted to $129,470, $246,013 and $248,596 for the years ended
December 31, 1995, 1996 and 1997, 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 ($2,461,583 and
$3,951,106 at December 31, 1996 and December 31, 1997, 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, 1996 and 1997 are the following amounts due from
unaffiliated parties (each accounting for 10% or more of accounts receivable):
1996 1997
---- ----
Customer A $ 2,566,700 $ 1,482,600
==================== ===============
Customer B $ 1,267,100 $ 931,965
==================== ===============
Customer C $ 899,600 $ 745,567
==================== ===============
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, 1995, 1996 and 1997 are as
follows:
Geographic Area 1995 1996 1997
---- ---- ----
Customer A Colombia $ 4,505,000 $ 13,594,000 $ 10,769,000
=============== ============== ==============
Customer B United States $ 2,926,000 $ 4,117,000 $ 7,738,280
=============== ============== ==============
Customer C United States $ 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 complete 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 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 leases have expired and the Company is presently considering whether
to attempt to secure new leases. 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.
16. 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, 1995, 1996 and 1997 is as follows:
(Dollars in thousands) United Corporate &
States Canada Colombia Other Total
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
================= =============== ================== =================== =============
Year ended December 31, 1997
Total revenues $ 21,359 $ 2,582 $ 10,769 $ 1,286 $ 35,996
Production costs 10,461 1,080 5,066 - 16,607
-
Other operating expenses 4,112 472 246 295 5,125
Depreciation, depletion and
amortization 4,541 543 1,797 384 7,265
Income tax expense (benefit) 752 158 1,495 (529) 1,876
----------------- --------------- ------------------
Results of operations from oil
and gas producing activities $ 1,493 $ 329 $ 2,165
================= =============== ==================
Interest and other expenses (net) 2,726 2,726
=================== =============
Net income (loss) $ (1,590) $ 2,397
=================== =============
Identifiable assets at
December 31, 1997 $ 46,886 $ 7,460 $ 11,047 $ 12,263 $ 77,656
================= =============== ================== =================== =============
17. Subsequent Events (unaudited)
On March 18, 1998, the Company entered into a preliminary agreement with
Omimex Resources, Inc., a privately held Fort Worth, Texas oil and gas company
("Omimex"), which operates a substantial portion of Company's producing
properties, to enter into a business combination ("Agreement"). At the date of
this report, all of the details of the business combination have not been fully
negotiated. However, the principle features of the combination would be that all
of the assets of the Company, save its California operations, would be combined
with the assets of Omimex, with the Company being the surviving corporation.
Since entering into the Agreement, Omimex has indicated an interest that the
Company include its Indonesian operations in the proposed combination, and this
inclusion is under negotiations. The economic terms of the transaction would be
to issue common shares to the shareholders of Omimex on a basis proportionate to
the respective net asset values of the two companies, determined by replacing
the account for properties on the respective balance sheets by the present
worth, calculated at a ten percent discount, of the proved reserves of the
apposite company and adjusting that number by other assets and liabilities.
Credit would also be given for oil and gas properties deemed to have exploration
or development potential. Should definitive agreements be obtained and the
combination consummated, it is expected that the Company will issue a number of
shares to the holders of Omimex stock such that such holders will own in excess
of fifty but less than sixty percent of the outstanding stock of the Company.
Management of Omimex would become management of the Company, which would be
headquartered in Fort Worth, Texas. The Company's California operations would be
held by Saba Petroleum, Inc., an existing subsidiary, the shares of which would
be distributed proportionately to the Company's shareholders immediately prior
to the consummation of the business combination. Structuring of the transaction
is in the preliminary stage and far from fully negotiated. Consummation of the
transaction would require shareholder approval, various governmental approvals
and agreement on various matters which are yet unresolved. Closing of the
transaction is expected to take approximately three months.
Approximately $8.8 million in principal amount of bank debt matured for payment
on April 30, 1998 (see Note 8, Long Term Debt). The Company and its bank were in
discussions to restructure the terms of the loan agreement and extend the
maturities of the short-term loans to a time which would accommodate the
proposed business combination with Omimex provided that a $2.0 million payment
was made on April 30, 1998 and a definitive agreement with Omimex was executed.
The definitive agreement with Omimex has not as yet been concluded and the
Company was unable to make the $2.0 million payment. Therefore, no extension was
secured and the $8.8 million of principal indebtedness remains due and payable.
The Company is continuing its discussions with the bank in an attempt to
restructure the indebtedness and is continuing its negotiations with Omimex with
a definitive agreement to be executed by May 15, 1998. The bank has not declared
the loan in default by giving notice to the Company as required pursuant to the
terms of the loan agreement.
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
States Canada (1) Colombia Total
------ ---------- -------- -----
Year ended December 31, 1995
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)
=================== ================ ===================== ====================
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
==================================================================================
==================================================================================
<FN>
(1) See reference (1) on page F-33
</FN>
Year ended December 31, 1996
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 9,607,067 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
-
=================== ================ ===================== ====================
Year ended December 31, 1997
Oil (Barrels)
Proved reserves:
Beginning of year 16,151,058 920,800 9,607,067 26,678,925
Acquisition, exploration and
development of minerals in place 4,200,193 9,640 1,600,225 5,810,058
Revisions of previous estimates (6,139,246) (24,055) 2,247,541 (3,915,760)
Production (1,120,645) (99,685) (886,651) (2,106,981)
Sales of minerals in place (2,541,157) - - (2,541,157)
=================== ================ ===================== ====================
End of year 10,550,203 806,700 12,568,182 23,925,085
=================== ================ ===================== ====================
Proved developed reserves, end of year 8,048,356 603,600 7,964,016 16,615,972
=================== ================ ===================== ====================
<FN>
(1) See reference (1) on page F-33
</FN>
Year ended December 31, 1997 (continued) Gas (Thousands of cubic feet) Proved
reserves:
Beginning of year 13,113,965 10,551,000 23,664,965
-
Acquisition, exploration and
development of minerals in place 13,337,886 1,190,546 14,528,432
-
Revisions of previous estimates (4,477,286) (23,832) (4,501,118)
-
Production (1,673,914) (733,714) (2,407,628)
-
Sales of minerals in place 9,805
9,805 - -
=================== ================ ===================== ====================
End of year 20,310,456 10,984,000 31,294,456
-
=================== ================ ===================== ====================
Proved developed reserves, end of year 13,988,220 3,412,000 17,400,220
-
=================== ================ ===================== ====================
<FN>
(1) The proved reserve information on December 31, 1995, 1996 and 1997 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.
</FN>
1995 1996 1997
---- ---- ----
Oil (Bbls) 236,911 208,417
237,237
Gas (Mcf) 2,657,709 2,714,646 2,837,793
Barrels of Oil Equivalent (BOE) 689,352 681,382
680,189
Standardized measure of discounted future
net cash flows $ 1,893,643 $ 2,840,628 $ 2,351,565
Standardized Measure of Discounted Future Net Cash Flows and Changes
Therein Relating to Proved Oil and Gas Reserve
The following information at December 31, 1995, 1996 and 1997 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).
December 31, 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
=============== ================= =============== ================
December 31, 1996
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
=============== ================= =============== ================
December 31, 1997
Future cash inflows $ 184,240 $ 30,826 $ 167,418 $ 382,484
Future production costs (87,803) (11,639) (71,327) (170,769)
Future development costs (18,263) (28,136)
(1,604) (8,269)
Future income tax expenses (15,773) (36,022) (56,102)
(4,307)
--------------- ----------------- --------------- ----------------
--------------- ----------------- --------------- ----------------
Future net cash flows 62,401 13,276 51,800 127,477
10 percent annual discount for
estimated timing of cash flows (16,572) (16,878) (37,624)
(4,174)
--------------- ----------------- --------------- ----------------
--------------- ----------------- --------------- ----------------
Standardized measure of discounted
future net cash flows $ 45,829 $ 9,102 $ 34,922 $ 89,853
=============== ================= =============== ================
=============== ================= =============== ================
<FN>
(1) See reference (1) on page F-33
</FN>
The following are the principal sources of changes in the standardized
measure of discounted future net cash flows during 1995, 1996 and 1997
(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
============== =============== ============== ==============
============== =============== ============== ==============
1996
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) (1,845) (7,605) (17,040)
Changes in estimated future development costs (15,038) 2,430 (16,233) (28,841)
Net changes in prices, net of production costs 14,951 5,680 20,390 41,021
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) (4,958) (9,017) (30,360)
-------------- --------------- -------------- --------------
============== =============== ============== ==============
Balance at end of year $ 73,329 $ 11,041 $ 32,119 $ 116,489
============== =============== ============== ==============
============== =============== ============== ==============
<FN>
(1) See reference (1) on page F-33
</FN>
1997
United
States Canada (1) Colombia Total
------ ---------- -------- -----
Balance at beginning of year $ 73,329 $ 11,041 $ 32,119 $ 116,489
----------------------------
Acquisitions, discoveries and extensions 31,593 40,687
726 8,368
Sales and transfers of oil and gas
produced, net of production costs (10,497) (1,254) (5,611) (17,362)
Changes in estimated future development costs (1,108) 18,043
9,920 9,231
Net changes in prices, net of production costs (51,463) (4,739) (15,151) (71,353)
Sales of reserves in place (4,314) (4,314)
- -
Development costs incurred during the period
1,601 70 (719) 952
Changes in production rates and other (9,298) (8,149)
(927) 2,076
Revisions of previous quantity estimates (20,764) (11,129)
(126) 9,761
Accretion of discount 15,526
9,515 1,540 4,471
Net change in income taxes 16,207 (9,622) 10,464
3,879
-------------- --------------- -------------- --------------
============== =============== ============== ==============
Balance at end of year $ 45,829 $ 9,102 $ 34,923 $ 89,854
============== =============== ============== ==============
============== =============== ============== ==============
<FN>
(1) See reference (1) on page F-33
</FN>
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
Saba Petroleum Company
Our report on the consolidated financial statements of Saba Petroleum
Company and subsidiaries, which includes an explanatory paragraph regarding the
Company's ability to continue as a going concern, is included on page F-2 of
this Form S-1/A. In connection with our audits of such consolidated financial
statements, we have also audited the related consolidated financial statement
schedule listed in the index on page F-1 of this Form S-1/A.
In our opinion, the consolidated financial statement schedule referred to
above, when considered in relation to the basic financial statements taken as a
whole, presents fairly, in all material respects, the information required to be
included therein. This information should be read in conjunction with the
explanatory paragraph of our report referred to above.
COOPERS & LYBRAND L.L.P.
Los Angeles, California
April 15, 1998
SABA PETROLEUM COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 1995, 1996 and 1997
(dollars in thousands)
Additions
---------------------------------
---------------------------------
Balance at Charged Charged Deductions Balance at
beginning to to other from close of
of period income accounts reserves period
1995
Amounts deducted from applicable assets:
Accounts receivable 62 12 (17) - 57
Deferred income taxes
- 155 - - 155
Other non current assets
Reserves included in other non current liabilities: 85 18 17 78 42
Restoration and reclamation 64 26 - - 90
1996
Amounts deducted from applicable assets:
Accounts receivable $ 57 $ 12 $ - $ 4 $ 65
Deferred income taxes 155 897 - - 1,052
Other non current assets 42 12 - 19 35
Reserves included in other non current liabilities:
Restoration and reclamation 90 28 - 30 88
1997
Amounts deducted from applicable assets:
Accounts receivable $ 65 $ 12 $ - $ 8 $ 69
Deferred income taxes 1,052 818 - - 1,870
Other non current assets 35 - - - 35
Reserves included in other non current liabilities:
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.
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
2,165,898 Shares
[graphic omitted]
SABA PETROLEUM COMPANY
Common Stock
PROSPECTUS
May 13, 1998
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.................................. $4,328
---------------------------------------------------------------------- ----------------
---------------------------------------------------------------------- ----------------
NASD filing fee..............................................
---------------------------------------------------------------------- ----------------
---------------------------------------------------------------------- ----------------
American Stock Exchange listing fee.......................... 17,500
---------------------------------------------------------------------- ----------------
---------------------------------------------------------------------- ----------------
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................................................... $ 154,828
---------------------------------------------------------------------- ----------------
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 2,165,898 shares of the
Common Stock (subject to increase in the event of certain dilutive events),
until either shareholder or regulatory approvalis 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 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. However, the holder has the
ability to convert all or any of 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
(File No.
001-13880) 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 (filed as Exhibit 3(i).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
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 (File No. 333-34035) 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 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 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)
10.3 Employment Agreement with Walton C. Vance (filed as
Exhibit 10.31 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.4 First Amendment, Letter Agreement with Bradley T. Katzung
(filed as Exhibit 10.33 to the Company's annual report on
Form 10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.5 Second Amendment to Employment Agreement with Bradley T.
Katzung (Filed as Exhibit 10.5 to the Company's annual
report on Form 10-K for the year ended December 31, 1997
(File No. 001-13880) and incorporated herein by reference)
10.6 Employment Agreement with Burt Cormany (filed as Exhibit
10.1 to the Company's quarterly report on Form 10-QSB for
the quarter ending March 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.7 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 (file
No.001-13880) and incorporated herein by reference)
10.8 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(File No. 001-13880) and
incorporated herein by reference)
10.9 Amendment to Retainer Agreement with Rodney C. Hill, A
Professional Corporation dated March 13, 1998 (Filed as
Exhibit 10.9 to the Company's annual report on Form 10-K
for the year ended December 31, 1997 (File No. 001-13880)
and incorporated herein by reference)
10.10 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 (File No. 333-34035) and
incorporated herein by reference)
10.11 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
(File No. 333-34035) and incorporated herein by reference)
10.12 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-QSB for the
quarter ended September 30, 1996 (File No. 001-13880) and
incorporated herein by reference)
10.13 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 (File No.
1-12322) and incorporated herein by reference)
10.14 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
(File No. 001-13880) and incorporated herein by reference)
10.15 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
on Form 10-Q for the quarter ended September 30, 1997
(File No. 001-13880) and incorporated herein by reference)
10.16 Amendment Number Four to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10 to the Company's Current Report on
Form 8-K filed September 24, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.17 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 the
Company and Bank One, Texas, N.A. (filed as Exhibit 10.4
to the Company's quarterly report on Form 10-Q for the
quarter ended September 30, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.18 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 the Company's Current Report on
Form 8-K filed January 15, 1998 (File No. 001-13880) and
incorporated herein by reference)
10.19 Consent Letter to Preferred Stock Transaction by Bank One,
Texas, N.A. dated December 31, 1997 (filed as Exhibit 10.2
to the Company's Current Report on Form 8-K filed January
15, 1998 (File No. 001-13880) and incorporated herein by
reference)
10.20 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
ReportForm 8-K filed January 15, 1998 (File No. 001-13880)
and incorporated herein by reference)
10.21 Amendment Number Seven to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(Filed as Exhibit 10.21 to the Company's annual report on
Form 10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.22 Stock Purchase Agreement (filed as an exhibit to the
Company's Current Report on Form 8-K dated January 10,
1995 (File No. 1-12322) and incorporated herein by
reference)
10.23 Processing Agreement between Santa Maria Refining Company
and Petro Source 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)
10.24 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire Teca
and 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)
10.25 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)
10.26 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)
10.27 Agreement among Saba Petroleum Company, Beaver Lake
Resources 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)
10.28 Amendment to Agreement among the Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire the
Teca and Nare fields (filed as Exhibit 2.2 to the
Company's Current Report on Form 8-K dated September 14,
1995 (File No. 1-12322) and incorporated herein by
reference)
10.29 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)
10.30 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)
10.31 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).
10.32 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)
10.33 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)
10.34 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 (File No. 001-13880) and
incorporated herein by reference)
10.35 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 (File No. 001-13880) and incorporated
herein by reference)
10.36 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 (File No. 001-13880) and
incorporated by reference)
10.37 Agreement Minutes concerning Colombia oil sales contract
between Omimex as operator and Ecopetrol (filed as
Exhibit 10.21 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.38 Operating Agreement between Omimex and Sabacol-Velasquez
property (filed as Exhibit 10.22 to the Company's annual
report on Form 10-KSB for the year ended December 31, 1996
(File No. 001-13880) and incorporated herein by reference)
10.39 Operating Agreement between Omimex and Sabacol-Cocorna and
Nare properties (filed as Exhibit 10.23 to the Company's
annual report on Form 10-KSB for the year ended December
31, 1996 (File No. 001-13880) and incorporated herein by
reference)
10.40 Operating Agreement between Omimex and
Sabacol-Velasquez-Galan Pipeline (filed as Exhibit 10.24
to the Company's annual report on Form 10-KSB for the year
ended December 31, 1996 (File No. 001-13880) and
incorporated herein by reference)
10.41 Operating Agreement between Omimex and Sabacol-Cocorna
Concession property (filed as Exhibit 10.25 to the
Company's annual report on Form 10-KSB for the year ended
December 31, 1996 (File No. 001-13880) and incorporated
herein by reference)
10.42 Life insurance contract on life of Ilyas Chaudhary (filed
as Exhibit 10.26 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.43 Life insurance contract on life of Ilyas Chaudhary (filed
as Exhibit 10.27 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.44 Agreement for Assignment of Leases between the Company and
Geo Petroleum, Inc. (filed as an exhibit to the Company's
amended annual report on Form 10-KSB/A for the year ended
December 31, 1996 (File No. 001-13880) and incorporated
herein by reference)
10.45 Amendment to Agreement for Assignment of Leases between
the Company and Geo Petroleum, Inc. (Filed as Exhibit
10.45 to the Company's annual report on Form 10-K for the
year ended December 31, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.46 Agreement to Provide Collateral between Capco and Saba
Petroleum Company (filed as Exhibit 10.29 to the Company's
annual report on Form 10-KSB for the year ended December
31, 1996 (File No. 001-13880) and incorporated herein by
reference)
10.47 Purchase and Sale Agreement between DuBose Ventures, Inc.,
Rockbridge Oil & Gas, Inc., Saba Energy of Texas,
Incorporated and Energy Asset Management Corporation to
acquire properties in Jefferson Parish, LA (filed as
Exhibit 10.30 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.48 Beaver Lake Resources Corporation March 1997 Re-Financing
Agreement (filed as Exhibit 10.3 to the Company's
quarterly report on Form 10-QSB for the quarter ending
March 31,1997 (File No. 001-13880) and incorporated herein
by reference)
10.49 Production Sharing Contract between Perusahaan
Pertambangan Minyak Dan Gas Bumi Nagara (Pertamina) and
Saba Jatiluhur Limited (filed as Exhibit 10.5 to the
Company's quarterly report on Form 10-Q for the
quarter ended September 30, 1997 (File No. 001-13880)
and incorporated herein by reference)
10.50 Agreements among the Company, Amerada Hess Corporation and
Hamar Associates II, LLC dated November 1, 1997 (Filed as
Exhibit 10.50 to the Company's annual report on Form
10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.51 Agreements among the Company, Chevron U.S.A. Production
Company and Nahama Natural Gas (Filed as Exhibit 10.51 to
the Company's annual report on Form 10-K for the year
ended December 31, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.52 Exchange Agreement between the Company and Energy Asset
Management Company, L.L.C.dated March 6, 1998 (Filed as
Exhibit 10.52 to the Company's annual report on Form
10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
Office Lease Agreement, 3201 Airpark Drive, Santa Maria,
California (filed as Exhibit 10.2 to the Company's
quarterly report on Form 10-QSB for the quarter ending
March 31,
10.53 1997 (File No. 001-13880) and incorporated herein by
reference)
10.54 Office Lease Agreement, 17526 Von Karman Avenue, Irvine,
California (Filed as Exhibit 10.54 to the Company's annual
report on Form 10-K for the year ended December 31, 1997
(File No. 001-13880) and incorporated herein by reference)
10.55 Purchase and Sale Agreement between the Company and
Statoil Exploration (US) Inc.dated August 19, 1997
(filed as an exhibit to the Company's Current Report on
Form 8-K dated September 24, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.56 Securities Purchase Agreement dated December 31, 1997
(filed as Exhibit 10.1 to Saba's Report Form 8-K
filed January 15, 1998 (File No. 001-13880) and
incorporated herein by reference)
10.57 Registration Rights Agreement dated as of December 31,
1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.58 Stock Purchase Warrant (Closing Warrant) dated December
31, 1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.59 Stock Purchase Warrant (Redemption Warrant) dated December
31, 1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.60 Finder Agreement dated as of December 31, 1997 (Filed as
Exhibit 10.60 to the Company's annual report on Form 10-K
for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.61 Stock Purchase Warrant (Finder Warrant) dated as of
December 31, 1997 (Filed as Exhibit 10.61 to the Company's
annual report on Form 10-K for the year ended December
31, 1997 (File No. 001-13880) and incorporated herein by
reference)
10.62 Preliminary Agreement To Enter Into A Business
Combination dated March 18, 1998 by and among the Company
and Omimex Resources, Inc. (filed as Exhibit 10.1 to
the Company's Current Report on Form 8-K dated March 30,
1998 (File No. 001-13880) and incorporated herein by
reference)
10.63 Press Release announcing the Proposed Combination
between the Company and Omimex Resources, Inc. dated
March 18, 1998 (filed as Exhibit 10.2 to the Company's
Current Report on Form 8-K dated March 30, 1998 (File No.
001-13880) 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 (File No. 1-12322)
and incorporated herein by reference)
21.1 Subsidiaries of the Company (filed as Exhibit 21.1 to the
Company's Registration Statement on Form S-1 dated January
21, 1998 and incorporated herein by reference)
23.1 Consent of Coopers & Lybrand L.L.P. (Los Angeles,
California)*
23.2 Consent of Netherland, Sewell & Associates, Inc.*
23.3 Consent of Sproule Associates Limited*
23.4 Consent of Gibson, Dunn & Crutcher LLP (included in
Exhibit 5.1)**
24.1 Powers of attorney, see p. II-8 (filed as Exhibit 24.1 to
the Company's Registration Statement on Form S-1 dated
January 27, 1998 (File No. 333-45023) and incorporated
herein by reference)
* 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.
SIGNATURES
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 May 12, 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 May 12, 1998
- ---------------------------------------------------- Chief Executive Officer
Ilyas Chaudhary (Principal Executive
Officer)
- ----------------------------------------------------- ------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ WALTON C. VANCE Vice President, Chief May 12, 1998
- ---------------------------------------------------- Financial Officer and
Walton C. Vance Secretary and Director
(Principal Financial and
Accounting Officer)
- ----------------------------------------------------- ------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ ALEX S. CATHCART President, Chief May 12, 1998
- ---------------------------------------------------- Operating Officer and
Alex S. Cathcart Director
------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ WILLIAM N. HAGLER Director May 12, 1998
- ----------------------------------------------------
William N. Hagler
------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ RONALD D. ORMAND Director May 12, 1998
- ----------------------------------------------------
Ronald D. Ormand
------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ RODNEY C. HILL Director May 12, 1998
- ----------------------------------------------------
Rodney C. Hill
------- --------------------------- ------------------------
- ----------------------------------------------------- ------- --------------------------- ------------------------
/s/ FAYSAL SOHAIL Director May 12, 1998
- ----------------------------------------------------
Faysal Sohail
- ----------------------------------------------------- ------- --------------------------- ------------------------
SABA PETROLEUM COMPANY
EXHIBIT INDEX
3. 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
(File No.
001-13880) 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 (filed as Exhibit 3(i).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
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 (File No. 333-34035) 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 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 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)
10.3 Employment Agreement with Walton C. Vance (filed as
Exhibit 10.31 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.4 First Amendment, Letter Agreement with Bradley T. Katzung
(filed as Exhibit 10.33 to the Company's annual report on
Form 10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.5 Second Amendment to Employment Agreement with Bradley T.
Katzung (Filed as Exhibit 10.5 to the Company's annual
report on Form 10-K for the year ended December 31, 1997
(File No. 001-13880) and incorporated herein by reference)
10.6 Employment Agreement with Burt Cormany (filed as Exhibit
10.1 to the Company's quarterly report on Form 10-QSB for
the quarter ending March 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.7 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 (file
No.001-13880) and incorporated herein by reference)
10.8 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(File No. 001-13880) and
incorporated herein by reference)
10.9 Amendment to Retainer Agreement with Rodney C. Hill, A
Professional Corporation dated March 13, 1998 (Filed as
Exhibit 10.9 to the Company's annual report on Form 10-K
for the year ended December 31, 1997 (File No. 001-13880)
and incorporated herein by reference)
10.10 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 (File No. 333-34035) and
incorporated herein by reference)
10.11 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
(File No. 333-34035) and incorporated herein by reference)
10.12 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-QSB for the
quarter ended September 30, 1996 (File No. 001-13880) and
incorporated herein by reference)
10.13 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 (File No.
1-12322) and incorporated herein by reference)
10.14 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
(File No. 001-13880) and incorporated herein by reference)
10.15 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
on Form 10-Q for the quarter ended September 30, 1997
(File No. 001-13880) and incorporated herein by reference)
10.16 Amendment Number Four to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(filed as Exhibit 10 to the Company's Current Report on
Form 8-K filed September 24, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.17 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 the
Company and Bank One, Texas, N.A. (filed as Exhibit 10.4
to the Company's quarterly report on Form 10-Q for the
quarter ended September 30, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.18 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 the Company's Current Report on
Form 8-K filed January 15, 1998 (File No. 001-13880) and
incorporated herein by reference)
10.19 Consent Letter to Preferred Stock Transaction by Bank One,
Texas, N.A. dated December 31, 1997 (filed as Exhibit 10.2
to the Company's Current Report on Form 8-K filed January
15, 1998 (File No. 001-13880) and incorporated herein by
reference)
10.20 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
ReportForm 8-K filed January 15, 1998 (File No. 001-13880)
and incorporated herein by reference)
10.21 Amendment Number Seven to First Amended and Restated Loan
Agreement between the Company and Bank One, Texas, N.A.
(Filed as Exhibit 10.21 to the Company's annual report on
Form 10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.22 Stock Purchase Agreement (filed as an exhibit to the
Company's Current Report on Form 8-K dated January 10,
1995 (File No. 1-12322) and incorporated herein by
reference)
10.23 Processing Agreement between Santa Maria Refining Company
and Petro Source 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)
10.24 Agreement among Saba Petroleum Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire Teca
and 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)
10.25 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)
10.26 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)
10.27 Agreement among Saba Petroleum Company, Beaver Lake
Resources 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)
10.28 Amendment to Agreement among the Company, Omimex de
Colombia, Ltd. and Texas Petroleum Company to acquire the
Teca and Nare fields (filed as Exhibit 2.2 to the
Company's Current Report on Form 8-K dated September 14,
1995 (File No. 1-12322) and incorporated herein by
reference)
10.29 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)
10.30 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)
10.31 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).
10.32 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)
10.33 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)
10.34 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 (File No. 001-13880) and
incorporated herein by reference)
10.35 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 (File No. 001-13880) and incorporated
herein by reference)
10.36 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 (File No. 001-13880) and
incorporated by reference)
10.37 Agreement Minutes concerning Colombia oil sales contract
between Omimex as operator and Ecopetrol (filed as
Exhibit 10.21 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.38 Operating Agreement between Omimex and Sabacol-Velasquez
property (filed as Exhibit 10.22 to the Company's annual
report on Form 10-KSB for the year ended December 31, 1996
(File No. 001-13880) and incorporated herein by reference)
10.39 Operating Agreement between Omimex and Sabacol-Cocorna and
Nare properties (filed as Exhibit 10.23 to the Company's
annual report on Form 10-KSB for the year ended December
31, 1996 (File No. 001-13880) and incorporated herein by
reference)
10.40 Operating Agreement between Omimex and
Sabacol-Velasquez-Galan Pipeline (filed as Exhibit 10.24
to the Company's annual report on Form 10-KSB for the year
ended December 31, 1996 (File No. 001-13880) and
incorporated herein by reference)
10.41 Operating Agreement between Omimex and Sabacol-Cocorna
Concession property (filed as Exhibit 10.25 to the
Company's annual report on Form 10-KSB for the year ended
December 31, 1996 (File No. 001-13880) and incorporated
herein by reference)
10.42 Life insurance contract on life of Ilyas Chaudhary (filed
as Exhibit 10.26 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.43 Life insurance contract on life of Ilyas Chaudhary (filed
as Exhibit 10.27 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.44 Agreement for Assignment of Leases between the Company and
Geo Petroleum, Inc. (filed as an exhibit to the Company's
amended annual report on Form 10-KSB/A for the year ended
December 31, 1996 (File No. 001-13880) and incorporated
herein by reference)
10.45 Amendment to Agreement for Assignment of Leases between
the Company and Geo Petroleum, Inc. (Filed as Exhibit
10.45 to the Company's annual report on Form 10-K for the
year ended December 31, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.46 Agreement to Provide Collateral between Capco and Saba
Petroleum Company (filed as Exhibit 10.29 to the Company's
annual report on Form 10-KSB for the year ended December
31, 1996 (File No. 001-13880) and incorporated herein by
reference)
10.47 Purchase and Sale Agreement between DuBose Ventures, Inc.,
Rockbridge Oil & Gas, Inc., Saba Energy of Texas,
Incorporated and Energy Asset Management Corporation to
acquire properties in Jefferson Parish, LA (filed as
Exhibit 10.30 to the Company's annual report on Form
10-KSB for the year ended December 31, 1996 (File No.
001-13880) and incorporated herein by reference)
10.48 Beaver Lake Resources Corporation March 1997 Re-Financing
Agreement (filed as Exhibit 10.3 to the Company's
quarterly report on Form 10-QSB for the quarter ending
March 31,1997 (File No. 001-13880) and incorporated herein
by reference)
10.49 Production Sharing Contract between Perusahaan
Pertambangan Minyak Dan Gas Bumi Nagara (Pertamina) and
Saba Jatiluhur Limited (filed as Exhibit 10.5 to the
Company's quarterly report on Form 10-Q for the
quarter ended September 30, 1997 (File No. 001-13880)
and incorporated herein by reference)
10.50 Agreements among the Company, Amerada Hess Corporation and
Hamar Associates II, LLC dated November 1, 1997 (Filed as
Exhibit 10.50 to the Company's annual report on Form
10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.51 Agreements among the Company, Chevron U.S.A. Production
Company and Nahama Natural Gas (Filed as Exhibit 10.51 to
the Company's annual report on Form 10-K for the year
ended December 31, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.52 Exchange Agreement between the Company and Energy Asset
Management Company, L.L.C.dated March 6, 1998 (Filed as
Exhibit 10.52 to the Company's annual report on Form
10-K for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
Office Lease Agreement, 3201 Airpark Drive, Santa Maria,
California (filed as Exhibit 10.2 to the Company's
quarterly report on Form 10-QSB for the quarter ending
March 31,
10.53 1997 (File No. 001-13880) and incorporated herein by
reference)
10.54 Office Lease Agreement, 17526 Von Karman Avenue, Irvine,
California (Filed as Exhibit 10.54 to the Company's annual
report on Form 10-K for the year ended December 31, 1997
(File No. 001-13880) and incorporated herein by reference)
10.55 Purchase and Sale Agreement between the Company and
Statoil Exploration (US) Inc.dated August 19, 1997
(filed as an exhibit to the Company's Current Report on
Form 8-K dated September 24, 1997 (File No. 001-13880) and
incorporated herein by reference)
10.56 Securities Purchase Agreement dated December 31, 1997
(filed as Exhibit 10.1 to Saba's Report Form 8-K
filed January 15, 1998 (File No. 001-13880) and
incorporated herein by reference)
10.57 Registration Rights Agreement dated as of December 31,
1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.58 Stock Purchase Warrant (Closing Warrant) dated December
31, 1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.59 Stock Purchase Warrant (Redemption Warrant) dated December
31, 1997(filed as Exhibit 3(I).1(a) to the Company's
Registration Statement on Form S-1, dated January 27, 1998
(File No. 333-45023) and incorporated herein by reference)
10.60 Finder Agreement dated as of December 31, 1997 (Filed as
Exhibit 10.60 to the Company's annual report on Form 10-K
for the year ended December 31, 1997 (File No.
001-13880) and incorporated herein by reference)
10.61 Stock Purchase Warrant (Finder Warrant) dated as of
December 31, 1997 (Filed as Exhibit 10.61 to the Company's
annual report on Form 10-K for the year ended December
31, 1997 (File No. 001-13880) and incorporated herein by
reference)
10.62 Preliminary Agreement To Enter Into A Business
Combination dated March 18, 1998 by and among the Company
and Omimex Resources, Inc. (filed as Exhibit 10.1 to
the Company's Current Report on Form 8-K dated March 30,
1998 (File No. 001-13880) and incorporated herein by
reference)
10.63 Press Release announcing the Proposed Combination
between the Company and Omimex Resources, Inc. dated
March 18, 1998 (filed as Exhibit 10.2 to the Company's
Current Report on Form 8-K dated March 30, 1998 (File No.
001-13880) 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 (File No. 1-12322)
and incorporated herein by reference)
21.1 Subsidiaries of the Company (filed as Exhibit 21.1 to the
Company's Registration Statement on Form S-1 dated January
21, 1998 and incorporated herein by reference)
23.1 Consent of Coopers & Lybrand L.L.P. (Los Angeles,
California)*
23.2 Consent of Netherland, Sewell & Associates, Inc.*
23.3 Consent of Sproule Associates Limited*
23.4 Consent of Gibson, Dunn & Crutcher LLP (included in
Exhibit 5.1)**
24.1 Powers of attorney, see p. II-8 (filed as Exhibit 24.1 to
the Company's Registration Statement on Form S-1 dated
January 27, 1998 (File No. 333-45023) and incorporated
herein by reference)
* Filed herewith
** To be filed by amendment