- - - 1 -
U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-K
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1997 [ ] TRANSITION REPORT
UNDER SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from _____________ to _______________.
Commission file number 1-12322
SABA PETROLEUM COMPANY
(Exact Name of registrant as specified in its Charter)
Delaware 47-0617589
(State or other jurisdiction of (I.R.S. Employer Identification Number)
incorporation or organization)
3201 Airpark Drive, Suite 201
Santa Maria, California 93455
(Address of principal executive offices) (Zip Code)
Issuer's telephone number (805) 347-8700
Securities registered under Section 12(b) of the
Exchange Act:
Title of each class Name of each Exchange
on which registered
Convertible Senior Subordinated Debentures American Stock Exchange
Common Stock, No Par Value American Stock Exchange
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. [ X ] YES [ ] NO
On April 13, 1998, the aggregate market value of shares of voting stock of
Registrant held by non-affiliates was approximately $25,068,985 based on a
closing sales price on the American Stock Exchange of $3.50.
As of April 13, 1998, 10,947,393 shares of the Registrants common stock were
outstanding.
Portions of the Registrant's Proxy Statement for the 1998 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after close of its fiscal year, pursuant to Regulation 14A, are
incorporated by reference into Items 10, 11, 12, and 13 of Part III of this
annual report.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-B is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K.[ X ]
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PART I
With the exception of historical information, the matters discussed in this
report contain forward-looking statements that involve risks and uncertainties.
Although the Company believes that its expectations are based upon reasonable
assumptions, it can give no assurance that its goals will be achieved. Important
factors that could cause actual results to differ materially from those in the
forward-looking statements contained in this report include the time and extent
of changes in commodity prices for oil and gas, increases in the cost of
conducting operations, the extent of the Company's success in discovering,
developing and producing reserves, political conditions, condition of capital
and equity markets, changes in environmental laws and other laws affecting the
ability of the Company to explore for and produce oil and gas and other factors
which are described in this report. Certain risks concerning the Company are set
forth below in "Description of Business-Factors Relating to the Company" and
"Factors Relating to the Oil and Gas Industry." Common terms used in the oil and
gas industry, are defined in the "Glossary" found at the conclusion of this Part
I.
Item 1. Description of Business.
General
Saba Petroleum Company (together with its subsidiaries, "Saba" or the
"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 was incorporated in Colorado in 1979 under the name
Bordeaux Petroleum Company and changed its name in 1991 when Mr. Ilyas Chaudhary
acquired control of the Company. The Company has grown primarily through the
acquisition and exploitation of producing properties in California and Colombia.
The Company has assembled a portfolio of over 200 potential development drilling
locations, the preponderance of which are in Colombia's Middle Magdalena Basin.
The Company also has drilling locations in California, New Mexico and Louisiana.
Based on current drilling forecasts, the Company estimates that such locations
represent a five-year drilling inventory. The Company uses advanced drilling and
production technologies to enhance the returns from its drilling programs. In
1997 the Company, drilled its first Steam Assisted Gravity Drainage ("SAGD")
pair of wells in California, producing operations on which have been held in
abeyance awaiting a permit authorizing steaming operations to be commenced and
oil price increases. Recently, the Company has initiated exploration projects
which it believes have high potential in California, Indonesia and Great
Britain.
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".
Under previous management and prior to its recent reincorporation as a
Delaware corporation, the Company did not make various required filings with the
Securities and Exchange 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 common stock of the Company
("Common Stock") 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. As of the date hereof, no person has asserted a
claim against the Company alleging such person has been denied the opportunity
to exercise preemptive rights to purchase Common Stock or to vote cumulatively.
For further information regarding these matters and the risks related thereto,
see the discussion contained under the caption "Risk Factors - Risks Relating to
Certain Corporate Matters" in the Company's Form S-3 Registration Statement
(File No. 33-94678) dated December 20, 1995, filed with the Commission pursuant
to Rule 424(b) under the Securities Act of 1933, and under the caption
"Description of Business - General - Development of the Business of Saba" in the
Report on Form 10-KSB for the year ended December 31, 1996, filed with the
Commission (File No. 1-12322) under the Securities Exchange Act of 1934, as
amended, which can be obtained from the Commission.
History of the Company
The Company's initial efforts focused on the acquisition of producing
properties with positive cash flow, development potential and an opportunity to
improve cash flow through more efficient operations. The Company has acquired
several properties that met these criteria, including the 1993 acquisition of
Cat Canyon and the other properties that comprise the California Central Coast
Fields ("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.
Having established a core of producing properties with a predictable and
improving cash flow and development potential, the Company has begun to focus on
high potential exploration and development projects.
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, including $8.8 million due April 30, 1998, (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 report, 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 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 fifty
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. Structuring of the
transaction is in the preliminary stage and has not been fully negotiated.
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 ("Preferred Stock") , shareholder approval, various governmental
approvals and agreement on various matters which are yet unresolved.
Factors Relating To The Company
Near Term Cash Requirements
The Company maintains a reducing revolving credit facility with a bank.
As provided for in the loan agreement, the bank 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 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 mature on April 30, 1998. Recently, in expectation of the
Omimex business combination, the Company and the bank have discussed a revision
of terms to extend the maturities of the short-term loans to a time which
accommodates consummation of the business combination provided that a payment of
$2 million is made on April 30, 1998, and provided further that the Company
continues to make scheduled monthly payments of principal and interest as due
under the terms of the reducing revolving credit facility. The definitive
agreement with Omimex is to be executed By April 30, 1998. The Company is in
negotiations to secure a commitment from a lending institution to refinance the
Company's total indebtedness should the Omimex transaction terminate.
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.
Preferred Stock Mandatory Redemption
The Preferred Stock contains terms that impose restrictions on the Company
and may hinder the Company's ability to raise additional capital. Under certain
circumstances the Company will be required to redeem the Preferred Stock at a
price equal to 115% of its stated value. There can be no assurance that the
Company will have the resources to complete such redemption.
Potential Dilution-Preferred Stock, Options, Warrants and Debentures
As of December 31, 1997, 10,000 shares of the Company's Preferred Stock were
issued and outstanding. Each share of the 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 Preferred Stock (as such value may be increased
due to accrued but unpaid interest) by the then current Conversion Price (which
is determined by reference to the then current market price, but in no event
will the Conversion Price be greater than $9.345). If converted based on a
Conversion Price equal to the closing price ($4.06) of the Common Stock on March
31, 1998, the Preferred Stock would have been convertible into approximately
2,461,500 shares of Common Stock. The number of shares could prove to be greater
in the event of further decreases in the trading price of the Common Stock. In
addition, if the Company redeems the Preferred Stock it will be obligated to
issue warrants to purchase 200,000 shares of Common Stock at an exercise price
based on the price of the Common Stock at the time of such redemption. In
connection with the Preferred Stock issuance, the Company issued warrants to
purchase 224,719 shares of Common Stock to the purchasers of the Preferred Stock
and warrants to purchase 44,944 shares of Common Stock to Aberfoyle Capital Ltd.
as a fee in connection with the placement of the Preferred Stock. These warrants
are exercisable over the next three years at a price of $10.68 per share (as may
be adjusted from time to time under certain antidilution provisions).
At December 31, 1997, the Company had outstanding options to purchase up to
1.17 million shares of Common Stock at exercise prices ranging from $1.25 to
$15.50 with a weighted average exercise price of $8.95 per share. Additionally,
as of December 31, 1997, the Company had outstanding Debentures in the aggregate
principal amount of $3,599,000, which may convert into Common Stock at a price
of $4.375 per share (822,629 shares). If Common Stock prices improve, the
Company may call 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.
The existence of the Preferred Stock, the outstanding options, warrants and
Debentures may hinder future financings by the Company and the exercise of such
options and warrants and conversion of the Preferred Stock and the Debentures
will dilute the interests of holders of Common Stock. The possible future resale
of Common Stock issuable on the conversion of the Preferred Stock and Debentures
or exercise of the options and warrants could adversely affect the prevailing
market price of the Common Stock, possibly at a time when the Company would
otherwise be able to obtain additional equity capital on terms more favorable to
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." 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 Equity
and Related Stockholder Matters."
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. 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.
Exploration and Development Drilling Activities
General Activities
The Company has identified approximately 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 exploration prospects to enhance its inventory of drilling
opportunities. 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 additional 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 oil company for the exploration of a
multi-thousand acre lease block in northern California, on which an exploratory
well commenced drilling in March 1998. The Company has initiated high potential
exploration activities in Indonesia and Great Britain.
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 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. The Company believes that its horizontal drilling program will
increase reserve recovery and decrease drilling and operating costs. Another
important element of the Company's horizontal well program is the use of high
efficiency progressive cavity 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. Thus far, the
Company has drilled one pair of SAGD wells. If the initial SAGD wells are
economically successful, the Company intends to expand the use of this
technology on its other California heavy oil properties. The Company is awaiting
a permit authorizing steaming operations to be commenced on its SAGD wells, but
does not anticipate commencing steaming and producing operations until oil
prices increase.
Domestic Activities
California
The Company's drilling operations in California are focused on the Central
Coast Fields, which consist of four onshore fields in Santa Barbara County, that
collectively comprise approximately 4,405 gross (4,367 net) developed acres and
1,139 gross (1,138 net) undeveloped acres. 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.
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 15 existing, shut-in
vertical wells. The horizontal wells would 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 as yet has not determined how many of these
horizons are productive. To date, the Company has tested only a shallow horizon
to an approximate depth of 2,500 feet. The Company intends to begin selectively
exploring additional horizons, the deepest of which is believed to be at
approximately 3,500 feet. A deeper formation, the Monterey, which is a prolific
producing formation offshore and onshore California, lies below the Sisquoc at
approximately 5,500 feet. The Company is currently evaluating the potential of
this formation underlying its lands. 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.
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 million as completed wells. The Company, which would have an 85% working
(68% net revenue) interest in the wells, is currently seeking a joint venture
partner for these prospects.
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 is obligated to pay 30% of the costs of the
initial exploratory well to earn a 20% working interest in the well and in the
block. 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. An exploratory well commenced drilling in
March 1998.
Chevron Seismic Venture. In January 1998, the Company and Nahama Natural Gas
Co. ("Nahama") entered into an agreement with a subsidiary of Chevron Corp.
under which Chevron made available to the Company 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. The Company 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, the Company 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 the Company and Nahama acquire a lease on Chevron
owned lands, the sharing of costs will be 85% and 15% to the Company and Nahama,
respectively, and revenues will be shared 68% to the Company (63.7% after
payout) and 12% (11.24% after payout) to Nahama.
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.
Other United States Properties
Other than its California and Louisiana properties, the Company has working
interests in over 350 oil and gas wells located principally in Texas, Michigan,
New Mexico and Oklahoma, with additional interests located in Utah, Wyoming, and
Alabama. The Company believes that many of these properties may be enhanced by
performing multiple workovers, 3-D seismic surveys, recompletions and
development drilling.
International Activities
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
production and development. Commercial development of the Nare North field will
be commenced in 1998 through the drilling of 16 development wells. The
Association Areas, Cocorna and Nare, are held under Articles of Association
between 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 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
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, all of which have met or
exceeded initial production expectations. The ability 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 have been made 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. Omimex is pursuing the
acquisition of third party 3-D seismic data on the currently producing Velasquez
Field to determine its exploration potential.
Canada
The Company's operations in Canada are conducted exclusively through its 74%
owned subsidiary, Beaver Lake Resources Corporation ("Beaver Lake"), which is
listed on the Alberta Stock Exchange. The Beaver Lake properties represent
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. Proved reserves attributable to
the Canadian properties totaled 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.
Other International Properties
In September 1997, the Company and Pertamina, the Indonesian state-owned oil
company, signed a production sharing contract covering 1.7 million unexplored
acres on the Island of Java near a number of producing oil and gas fields. The
Company is required to spend approximately $17 million over the next three years
on this project 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 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. The Company has entered into an agreement to
become the operator and a 75% working interest holder of two exploration
licenses which cover, in the aggregate, a 123,000 acre area in southern Great
Britain. The Company expects to drill its first exploratory well on this
concession during the second or third quarter of 1998 at an estimated cost of
approximately $1.1 million to the Company's interest. The Company is currently
discussing joint venture opportunities with respect to this property with other
companies.
Business Strategy
The Company seeks to acquire domestic 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 domestic and international high potential exploration prospects
in known productive regions. 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.
Factors Relating to the Oil and Gas Industry
Uncertainty of Estimates of Reserves and Future Net Revenues; Decline in Oil and
Gas Prices
The proved developed and proved undeveloped oil and gas reserves 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. At December 31, 1996, the price of WTI crude
oil was $24.25 per Bbl and the comparable price at December 31, 1997, was
$15.50. Quotations for natural gas at such dates were $3.70 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 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 "Description of Property."
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."
Governmental Regulation
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.
Environmental Matters
General
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. 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.
Refinery
Pursuant to the purchase and sale agreement of the asphalt refinery in Santa
Maria, the sellers agreed to remediate portions of the refinery property by June
1999. Prior to the acquisition of the refinery, the Company had an independent
consultant perform an environmental compliance survey for the refinery. The
survey did not disclose required remediation in areas other than those where the
seller is responsible for remediation, but did disclose that it was possible
that all of the required remediation may not be completed in the five-year
period. The Company, however, believes that either all required remediation will
be completed by the sellers within the five-year period or the Company will
provide the sellers with additional time to complete the remediation. Should the
sellers 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
In 1993, the Company acquired a producing mineral interest from a major oil
company. At the time of acquisition, the Company's investigation revealed that a
discharge of diluent (a light, oil-based fluid which is often mixed with heavier
grade crudes) had occurred on the acquired property. The purchase agreement
required the seller to remediate the area of the diluent spill. After the
Company assumed operation of the property, the Company became aware of the fact
that diluent was seeping into a drainage area which traverses the property. The
Company took action to contain the contamination and requested that the seller
bear the cost of remediation. The seller has taken the position that its
obligation is limited to the specified contaminated area and that the source of
the contamination is not within the area that the seller has agreed to
remediate. The Company has commenced an investigation into the source of the
contamination to ascertain whether it is physically part of the area which the
major oil company agreed to remediate or is a separate spill area. The Company
also found a second area of diluent contamination and is investigating to
determine the source of that contamination. Investigation and discussions with
the seller are ongoing. Should the Company be required to remediate the area
itself, the cost to the Company could be significant. The Company has spent
approximately $240,000 to date on remediation activities, and present estimates
are that the cost of complete remediation could approach $800,000. Since the
investigation is not complete, the Company is unable to accurately estimate the
cost to be borne by the Company.
In 1995, the Company agreed to acquire, for less than $50,000, an oil and
gas interest on which a number of oil wells had been drilled by the seller. None
of the wells were in production at the time of acquisition. The acquisition
agreement required that the Company assume the obligation to abandon any wells
that the Company did not return to production, irrespective of whether certain
consents of third parties necessary to transfer the property to the Company were
obtained. The Company has been unable to secure all of the requisite consents to
transfer the property but nevertheless may have the obligation to abandon the
wells. The 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.
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 operations could be significant and
will occur, from time to time, as properties are abandoned. There can be no
assurance that material costs for environmental compliance will not be incurred
in the future. The incurrence of such environmental compliance costs could be
materially adverse to the Company.
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.
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.
Dependence on Approval by Governmental Agencies
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. 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.
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.
Labor Disturbances
All of the workers employed at the Colombian fields belong to one of two
unions. Contracts with both unions are scheduled for renegotiation later in
1998. While work disruptions have occasionally been experienced, there have been
no major union disturbances. There can be no assurance, however, that the unions
will agree to a new contract or that there will not be disturbances, including
significant production interruption due to sabotage, work slowdowns or work
stoppages.
Marketing of Production
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 any of the following factors:
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 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 regulation on
the production, transportation and sale of oil and natural gas, and other
factors beyond the control of the Company.
Effect of Price Declines
Most of the oil produced by the Company is of low gravity. The costs of
producing such oil are generally much higher than the costs of producing higher
gravity oil. Consequently, heavy oil properties, such as those owned by the
Company in California and Colombia, tend to become marginally economic in
periods of declining oil prices. While profit margins have substantially
narrowed in the current pricing environment, operations of the Company's Central
Coast Fields remain economic in that the oil is sold at a premium to market to
the Company's Santa Maria refinery. Colombian operations have also remained
economic because operating costs in that country are considerably lower than in
the U.S.
Principal Purchasers
North America Production
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. In 1997, approximately 33.2% and 6.6% of the
Company's North American oil and gas revenues were derived from sales to two
purchasers, Petro Source Corporation and Texaco Inc., respectively. The Company
believes that the loss of any purchaser would not be material to its operations
and that alternative purchasers of production may be readily found.
Colombian Production
All of the Company's oil production in Colombia is, and, as a practical
matter, can be, sold only to Ecopetrol, which also owns a 50% working interest
in the Teca and Nare fields. The Company's Colombian oil production accounted
for 31.4% of total oil and gas revenues for the year ended December 31, 1997 and
40.9% of total oil and gas revenues in 1996. Ecopetrol has the power to
determine the prices that the Company will receive for all oil produced in
Colombia. Prices received from the sale of oil and gas 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 Teca and
Nare fields 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 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
future operations.
Oil produced from the Company's Middle Magdalena 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 increase in production, which 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. 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 from
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.
Competition
The oil and gas industry is highly competitive. Many of the Company's
current and potential competitors have 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 such firms. The Company's operations are largely dependent upon
its ability to acquire reserves of oil and gas in commercial quantities. The
general competitive conditions in the oil and gas industry in which the Company
operates have been and are expected to continue to be intense. The Company has
experienced, and will continue to encounter, strong competition from other
parties attempting to acquire oil and gas properties, either directly or through
the acquisition of entities owning mineral resources.
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 work disruptions from its
union employees. See "Description of Business -- Economic and Political Risks of
Foreign Operations -- Colombian Operations -- Labor Disturbances."
GLOSSARY
The following defined terms have the indicated meanings when used in this
Report:
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.
Item 2. Description of Property
The proved developed and proved undeveloped oil and gas reserve figures
presented in this report are estimates based on reserve reports prepared by
independent petroleum engineers. The estimation of reserves requires substantial
judgment on the part of the petroleum engineers, resulting in imprecise
determinations, particularly with respect to new discoveries. Estimates of
reserves and of future net revenues prepared by different petroleum engineers
may vary substantially, depending, in part, on the assumptions made, and may be
subject to material adjustment. 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. The accuracy of any reserve
estimate depends on the quality of available data as well as engineering and
geological interpretation and judgment. Results of drilling, testing and
production or price changes subsequent to the date of the estimate may result in
changes to such estimates. The estimates of future net revenues in this report
reflect oil and gas prices and production costs as of the date of estimation,
without escalation, except where changes in prices were fixed under existing
contracts. There can be no assurance that such prices will be realized or that
the estimated production volumes will be produced during the periods specified
in such reports. At December 31, 1997, the price of West Texas Sweet
Intermediate Crude (a benchmark crude), was $15.50 per barrel and the comparable
price at March 31, 1998 was $13.25per barrel. Quotations for the comparable
periods for natural gas were $2.45 per Mcf and $2.20 per Mcf, respectively. The
estimated reserves and future net revenues may be subject to material downward
or upward revision based upon production history, results of future development,
prevailing oil and gas prices and other factors. A material decrease in
estimated reserves or future net revenues could have a material adverse effect
on the Company and its operations.
Principal Properties
The Company's properties are located in three primary regions: United
States, Colombia, and Canada. The following describes the principal properties
of the Company at December 31, 1997.
United States Properties
California
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 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 during 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 and a 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; this well has experienced mechanical difficulties and is currently
not on production pending completion of a study designed to remedy the problem.
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 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 suffered mechanical problems and plans
are to rework the well during 1998. The three wells drilled in the central
portion, or waterflood area of the field, developed initial production rates of
approximately 150 Bopd per well and have declined to approximately 40 Bopd per
well. In 1997, the Company continued its horizontal well drilling program in the
Cat Canyon Field by drilling eight additional wells into the Sisquoc S1b sand.
Of the eight wells, five were drilled in the waterflood area and the remaining
three were drilled in 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. The Company expects continued improvement in the ratio of
oil to total fluid. Production declines have been in line with the Company's
expectations of roughly a forty to fifty percent decline in production during
the first twelve months of a well's operation, followed by a more moderate ten
percent annual decline in production.
Results from the horizontal well drilling program have not met 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 at least 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 upon 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 proved 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 Santa Maria properties.
Richfield East Dome Unit (REDU). The REDU unit, which represents
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 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.
Louisiana
Potash Field, which represents 13.4% of the Company's PV-10 value as of
December 31, 1997, is located in Plaquemines Parish, Louisiana. The Company
operates all of the wells in the field. The field is a salt dome feature
originally discovered by Humble Oil and Refining Company and covers
approximately 3,600 acres. The field is located in a shallow marine environment
southeast of New Orleans. The Company, in September 1997 acquired an 80% working
interest (67% net revenue interest) in this property. Subsequent to year end
1997 the Company acquired the remaining 20% 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.
Manila Village is located in Jefferson Parish, Louisiana. The Company
operates this field and at December 31, 1997, owned a 40.5% working interest
(28% net revenue interest).. The field represented approximately 1.8% of the
Company's PV-10 Value at December 31, 1997. The field covers approximately 450
gross acres of land covered by shallow waters. Subsequent to year end 1997 the
Company acquired an additional 10.2% working interest. 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.
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 11.3% of the
Company's PV-10 Value at December 31, 1997. At such date, these properties had
proved reserves of 2.7 MMBOE. Included in such other producing properties are:
Southwest Tatum Field, which represents 2.2% of the Company's PV-10 value,
is located in Lea County, New Mexico. The property was acquired by the Company
as an exploratory project in late 1996. The Company holds leases covering
approximately 2,000 gross acres of land, in which the Company has a working
interest of 50% and a net revenue interest of 38.75%. During the last part of
1996, the Company, as operator, commenced the drilling of a 14,000 foot
exploratory Devonian test well. In addition to the deepest zone, the Devonian
(which has been abandoned after having produced in excess of 20,000 barrels of
high gravity oil), the well has three other potential oil producing zones. The
Company has recompleted the well in the shallower Cisco zone with initial flow
rates of 400 Bopd of clean 45(Degree) oil, 450 Mcfd with no water. A second
reentry well to test the shallower zones was completed in September, 1997 as a
Canyon producer and is currently pumping approximately 175 Bopd and 140 Mcfd,
with a small amount of water. Two additional wells are planned to be drilled on
this property in 1998 at an approximate cost of $350,000 each to the Company's
interest. A gas sales line was completed in February 1998, allowing for gas
sales from the two wells.
San Simon Ranch Field, which represents 1.4% of the PV-10 value, is located
in Lea County, New Mexico. The Company owns interests in several wells in this
field and operates three wells. The Company has a 50% working (42%) net revenue
interest in approximately 1,122 gross (742 net) acres in the field. The Company
is participating in a 3-D seismic survey to evaluate the development of the
field.
Colombian Properties
General
The Company's Colombian operations are conducted on two Association Areas
and one mineral fee property. These properties are located in the Middle
Magdalena Basin of Colombia, some 130 miles northwest of Bogota. The Company and
its partner, Omimex, acquired their interests in the Middle Magdalena Basin
properties from Texaco in 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 Moriche 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 "Description of
Business-Economic and Political Risks of Foreign Operations-Colombian
Operations."
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 Omimex and the
Company. 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, reverted to Ecopetrol in
1997.
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 1,938 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 1,085 acres). The Company's Teca and South
Nare Fields, which represented approximately 22.6% 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 (649.5 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 505 Bopd for the year ended December 31,
1997.
The Company's Colombian properties in the aggregate represented 12.6 MMBbls
of proved reserves 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.
Field Name Proved Reserves at Number of Wells Average Daily
Barrels of Oil
Dec. 31, 1997 1997
(MMBbls) 4th Quarter Year
Velasquez 2.9 96 499 505
North Nare 3.8 3 0 0
Magdalena 0.1 1 testing testing
Teca & South Nare 5.8 312 1,905 1871
----------------------- ----------------------- ------------ ------------
Total 12.6 412 2,404 2,376
======================= ======================= ============ ============
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 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. A plan has been formulated for the drilling of approximately
200 development wells in the Teca, Nare, Nare North, and two other fields. This
program, subject to regulatory approval, would be implemented through the year
2001.
The Company and Omimex also reentered a suspended Texaco drilled well to an
area under the Magdalena River and recompleted the well at 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 ranged from 142 Bopd to 223 Bopd.
Studies to date indicate up to 23 additional wells with behind pipe reserves
suitable for re-completion. For 1998, 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
"Description of 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. 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. A new oil field is being developed south of
the Company's properties. The operator of the new oil field has approached the
Company and Omimex requesting the transport of oil from the new field through
the Velasquez-Galan Pipeline.
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. Proved
reserves attributable to the Canadian properties totaled 2.6 MMBOE at December
31, 1997. Two development wells were drilled during 1997, one completed as a gas
well, the other was a dry hole. A horizontal well was also drilled on which
operations have been suspended. The information presented has not been adjusted
for the approximate 26% minority interest in Beaver Lake held by others.
Oil and Gas Reserves
The Company's proved reserves and PV-10 Value from proved developed and
proved undeveloped oil and gas properties have been estimated by the following
independent petroleum engineers: In 1997 and 1996, Netherland, Sewell &
Associates, Inc. prepared reports on the Company's reserves in the United States
and Colombia and Sproule Associates Limited 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 SEC
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 escalations. Future net revenues at December
31, 1997 reflect a weighted average price of $13.13 per BOE compared to $17.05
per BOE at December 31, 1996. There have been no reserve estimates filed with
any 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 proved developed and proved undeveloped
reserve volumes as of December 31, 1997 and 1996 and estimates of the future net
revenues and PV-10 Value therefrom. There can be no assurance that these
estimates are accurate predictions of future net revenues from oil and gas
reserves or their present value. Pursuant to industry standards, the Company's
proved reserves include all of the proved reserves of Beaver Lake.
Estimated Proved Oil and Gas Reserves
Reserve Category
Proved Developed Proved Undeveloped Total
1997 Oil (MBbls) Gas (MMcf) Oil (MBbls) Gas (MMcf) Oil (MBbls) Gas (MMcf)
United States
8,048 13,988 2,502 6,322 10,550 20,310
Canada 604 3,412 203 7,572 807 10,984
Colombia 7,964 - 4,604 - 12,568 -
Total 16,616 17,400 7,309 13,894 23,925 31,294
1996 Oil (MBbls) Gas Oil Gas Oil Gas
(MMcf) (MBbls) (MMcf) (MBbls) (MMcf)
United States
7,994 11,521 8,157 1,593 16,151 13,114
Canada 710 2,654 211 7,897 921 10,551
Colombia 4,692 - 4,915 - 9,607 -
Total 13,396 14,175 13,283 9,490 26,679 23,665
The estimated future net revenues (using current prices and costs at the
respective years end) and the present value of future net revenues (using a
discount factor of 10 percent per annum) before income taxes for Saba's proved
developed and proved undeveloped oil and gas reserves as of December 31, 1997
and 1996 are as follows:
Reserve Category
Proved Developed Proved Undeveloped Total
Present value Present Present value
Future net of future net Future net value of Future net of future net
revenue revenue revenue future net revenue revenue
revenue
(Dollars in
thousands)
1997
United
States $ 60,166 $ 41,323 $ 18,008 $ 10,122 $ 78,174 $ 51,445
Canada 7,240 4,811 10,342 5,237 17,582 10,048
Colombia 46,291 32,178 41,531 24,958 87,822 57,136
Total $ 113,697 $ 78,312 $ 69,881 $ 40,317 $ 183,578 $ 118,629
1996
United
States $ 89,456 $ 60,650 $ 66,354 $ 34,502 $ 155,810 $ 95,152
Canada 14,136 9,235 12,015 6,843 26,151 16,078
Colombia 31,020 24,258 40,921 20,451 71,941 44,709
Total $ 134,612 $ 94,143 $ 119,290 $ 61,796 $ 253,902 $ 155,939
"Proved developed" oil and gas reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
"Proved undeveloped" oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. In recent years, the
market for oil and gas has experienced substantial fluctuations, which have
resulted in significant swings in the prices for oil and gas. The Company cannot
predict the future of oil and gas prices or whether future declines in prices
will occur. Any such decline would have an adverse effect on the Company.
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.
Net Quantities of Oil and Gas Produced
The net quantities of oil and gas produced by the Company for each of the
years in the three year period ended December 31, 1997 are as follows:
Oil (Bbls) Gas (Mcf) BOE
1997
United States 1,120,645 1,673,914 1,399,631
Canada (1) 99,639 733,714 221,925
Colombia 886,651 - 886,651
--------------- --------------- -------------
Total 2,106,935 2,407,628 2,508,207
=============== =============== =============
=============== =============== =============
1996
United States 803,070 1,089,576 984,666
Canada (1) 134,008 561,042 227,515
Colombia 1,031,207 - 1,031,207
--------------- --------------- -------------
===============
Total 1,968,285 1,650,618 2,243,388
=============== =============== =============
=============== =============== =============
1995
United States 710,271 938,577 866,701
Canada (1) 85,800 398,616 152,236
Colombia 430,808 - 430,808
--------------- --------------- -------------
Total 1,226,879 1,337,193 1,449,745
=============== =============== =============
(1) No reduction is made for the minority interest in Beaver Lake.
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,
1997 1996 1995
Average sales price per barrel of oil United States $ 14.92 $ 16.49 $ 13.71
Canada $ 15.48 $ 17.80 $ 13.93
Colombia $ 12.04 $ 12.49 $ 9.44
Combined $ 13.73 $ 14.43 $ 12.23
Average sales price per Mcf of gas United States $ 2.53 $ 2.28 $ 1.67
Canada $ 1.08 $ 1.12 $ 0.94
Colombia $ - $ - $ -
Combined $ 2.09 $ 1.88 $ 1.45
Average production cost per barrel of oil
equivalent United States $ 7.47 $ 8.29 $ 8.57
Canada $ 4.87 $ 5.15 $ 5.92
Colombia $ 5.71 $ 5.11 $ 5.17
Combined $ 6.62 $ 6.51 $ 7.29
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
========= ========== ========= ========= ========== ========
(1) No reduction is made for the minority interest in Beaver Lake.
In addition to its working interest, the Company holds royalty interests in 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
Country 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
============ =========== ============ ===========
(1) Developed acreage is acreage assigned to productive wells. (2) No reduction
is made for the minority interest in Beaver Lake.
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 covering the drillsite 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.
Drilling Activity
The following table 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.
1997 1996 1995
---- ---- ----
Gross(1) Net(2) Gross(1) Net(2) Gross(1) Net(2)
Exploratory
Oil 2 1.0 - - - -
Gas - - 3 1.35 - -
Dry (3) 2 1.5 4 1.29 3 0.46
Development
Oil 26 16.25 11 7.59 4 1.51
Gas 1 0.29 3 0.64 2 0.19
Dry (3) 2 1.87 1 0.35 1 0.04
Total
Oil 28 17.25 11 7.59 4 1.51
Gas 1 0.29 6 1.99 2 0.19
Dry (3) 4 3.37 5 1.64 4 0.50
(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 working interest
ownership 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.
Asphalt Refinery
In June 1994, in an effort to increase margins on the heavy crude oil
produced from the Company's oil and gas properties in Santa Barbara County,
California, the Company, through a wholly owned subsidiary, acquired from Conoco
Inc. ("Conoco") and Douglas Oil Company of California an asphalt refinery in
Santa Maria, California, which had been inoperative since 1992. The Company
refurbished the refinery and, in May 1995, completed a re-permitting
environmental impact review process with Santa Barbara County, receiving a
Conditional Use Permit to operate the refinery. Pursuant to the refinery
purchase agreement, Conoco is required to perform certain remediation and other
environmental activities on the refinery property until June 1999, at which
point the Company will be responsible for any additional remediation, if any.
See "Description of Business-Governmental Regulation and Environmental
Matters-Refinery Matters."
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 or may assume the
marketing responsibilities presently held by Petrosource and may carry the cost
of inventorying crude oil and asphalt.
The refinery is a fully self-contained plant with steam generation,
mechanical shops, control rooms, office, laboratory, emulsion plant and related
facilities, and is staffed with a total of 20 operating, maintenance, laboratory
and administrative personnel. Crude oil is delivered to the refinery by trucks
to current crude oil storage of 40,000 barrels of processing. An additional
60,000 barrels of crude oil storage is also available for future demands. Crude
processing equipment consists of a conventional pre-flash tower, an atmospheric
distillation tower, strippers and a vacuum fractionation tower. The refinery has
truck and rail loading facilities, including some capability of tank car
unloading. Throughput at the refinery has ranged between 2,000 to 4,000 Bopd,
while production capacity is approximately 8,000 Bopd.
Refinery products include light feedstock (naphtha), kerosene distillate,
gas oils and numerous cut-back, paving and emulsion asphalt products, with the
primary product produced at the refinery being asphalt, with some liquids, such
as propane. Historically, marketing efforts have been focused on the asphalt
products which are sold to various users, primarily in the Southern California
area. Liquids are readily marketed to wholesale purchasers.
The Company regards the refinery as a valuable adjunct to its production of
crude oil in the Santa Maria Basin and surrounding areas in that it sells its
production from those areas to the refinery at a price reflecting a premium to
market. 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 and California operations 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, totaling 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.
Item 3. 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 effect on the
Company's financial statements or operations.
Item 4. Submission Of Matters To A Vote Of Security Holders
No matters were submitted to a vote of security holders during the quarter
ended December 31, 1997.
PART II.
Item 5. Market For Common Equity And Related Stockholder Matters
PRICE RANGE OF COMMON STOCK, NUMBER OF HOLDERS 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
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1998
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First Quarter.................................................................. $ 3 .38 $ 8 .50
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1997
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Fourth Quarter $ 8 .00 $ 14 .88
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Third Quarter ................................................................. 12 .81 20 .12
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Second Quarter................................................................. 10 .75 17 .75
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First Quarter.................................................................. 12 .75 25 .25
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1996
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Fourth Quarter................................................................. $ 9 .25 $ 27 .12
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Third Quarter ................................................................. 6 .19 9 .94
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Second Quarter................................................................. 3 .88 8 .00
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First Quarter.................................................................. 3 .56 4 .75
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On April13,1998, the last reported sales price of the Common Stock on the
American Stock Exchange was $3.50. The Company has never paid cash dividends on
its Common Stock and does not anticipate doing so in the foreseeable future. The
Preferred Stock, the Debentures and the Company's principal revolving credit
agreement restrict the payment of cash dividends by the Company. See Note 8 of
Notes to Consolidated Financial Statements of the Company. At December 31, 1997,
the Company had approximately 2,810 stockholders of record.
Series A Convertible Preferred Stock
On December 31, 1997 the Company sold to RGC International Investors, LDC,
10,000 shares of a newly created class of preferred stock, Series A Convertible
Preferred Stock, stated value $10,000 per share, for $10 million. The
transaction was structured as a private placement exempt from registration and
prospectus delivery requirements of the Securities Act of 1933 by reason of the
exemption contained in Section 4 (2) of said act. Included in the price of the
Preferred Stock were warrants to acquire 224,719 shares of Common Stock for a
price of $10.68 per share. The warrants have a term of three years from the date
of issuance. The Preferred Stock bears a cumulative dividend of 6% per annum
payable quarterly in cash or, at the Company's option, the dividend amount can
be added to the "Conversion Amount" as defined. After 120 days from the date of
issuance, the Preferred Stock is convertible at the option of the holder into
Common Stock at a price determined by reference to the closing bid price of the
Common Stock at a time proximate to the Conversion Date as defined, but in no
event will the conversion price exceed $9.345 per share of Common Stock. In
general, conversion of the Preferred Stock can occur after 120 days from its
issuance, in monthly increments of 20% of the amount issued, until 241 days from
December 31, 1997, after which all of the Preferred Stock may be converted. The
Preferred Stock may be converted into approximately 2,100,000 shares of Common
Stock (subject to anti-dilution provisions), unless the Company fails to perform
certain covenants in which case the Preferred Stock will be convertible without
limitation if shareholder and regulatory approvals are obtained. The Preferred
Stock is senior to all other classes of the Company's equity securities.
The Preferred Stock is redeemable at any time and must be redeemed upon the
occurrence of certain events. Until April 29, 1998, the Company may redeem at
115% of the Stated Value plus accrued dividends and issue a five-year warrant to
purchase 200,000 shares of Common Stock at 105% of the average closing bid price
for a five day period preceding the redemption. The Company is obligated to file
a registration statement with the Securities and Exchange Commission covering
the Common Stock underlying the Preferred Stock and should this registration
statement not be declared effective prior to June 28, 1998, the Company will be
obligated to redeem the Preferred Stock.
Item 6. Selected Financial Data
The following table sets forth certain financial information with respect
to the Company and is qualified in it's entirety by reference to the historical
financial statements and notes thereto of the Company included in Item 8,
"Financial Statements and Supplementary Data." The statement of income,
statement of cash flow and balance sheet data included in this table for each of
the five years in the period ended December 31, 1997 were derived from the
audited financial statements and the accompanying notes to those financial
statements (in thousands, except per share data):
--------------- ------------- ------------- --------------- --------------
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 $.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
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 (3)
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
Other Data
EBITDA (4)
$2,171 $3,568 $5,188 $14,652 $13,843
Capital expenditures (5)
2,372 6,573 17,015 12,776 35,270
Production (MBOE) 755 980 1,450 2,243 2,508
(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) For information on terms and interest, see Note 8 of
Notes to Consolidated Financial Statements of
the Company.
(4) 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.
(5) 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.
Item 7. Management's Discussion And Analysis
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 report.
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 five 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 the
disappointing 1997 results, the Company reduced the number of wells it had
originally projected to drill in 1997. 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 have been 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, 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 $5.1million 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, and capital costs recorded by the Company
in its full cost pools beginning in the second quarter of 1996, and the
anticipated future development and abandonment costs to be incurred in
connection with the management of its oil and gas properties. Depreciation and
amortization expenses increased 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 167.4% 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, including $8.8 million due April 30, 1998, (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 million of 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 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 due on April 30, 1998. In connection with the contemplated business
combination with Omimex, the Company is in discussions with its lending bank to
arrange for an extension of the April 30, 1998 loan maturities to a date
following the closing of the business combination, provided that a $2 million
payment is made by April 30, 1998. It is expected that the bank debt of both
companies will, following the merger, 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 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 matures 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
mature on April 30, 1998, and are classified as current liabilities.
Nothwithstanding the maturity date of the loans, the Company is required to make
principal reductions of $2.0 million on April 15, 1998, and not less than $3.0
million on June 1, 1998. 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 as of 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
will be due and payable. 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 matures for payment on April 30, 1998.
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 mature for
payment on April 30, 1998. At December 31, 1997 the loan was fully advanced.
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 million
in April 1998 and a minimum payment of $3 million in June 1998 in addition to
its scheduled monthly payments of principal and interest. 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
million payment due April 1, 1998, was reduced to $2 million and the payment
date was extended to April 30, 1998.
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.
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.
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.
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.
Item 8. Financial Statements and Supplemental Data
The information required by this item is included herein on pages F-1 through
F-38.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
No information is required to be reported under this item.
PART III
Item 10. Directors and Executive Officers of the Registrant
Incorporated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1998 annual
meeting.
Item 11. Executive Compensation
Incorporated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1998 annual
meeting.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Incorporated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1998 annual
meeting.
Item 13. Certain Relationships and Related Transactions
Incorporated by reference to the Company's Proxy Statement to be filed with the
Securities and Exchange Commission in connection with the Company's 1998 annual
meeting.
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as part of this report:
1 and 2. Financial Statements and Financial Statement Schedules: These
documents are listed in the Index To Consolidated Financial Statements
and Financial Statement Schedule.
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
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)
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*
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*
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 Report
Form 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.*
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
Exhibit10.21 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.*
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*
10.51 Agreements among the Company, Chevron U.S.A. Production
Company and Nahama Natural Gas*
10.52 Exchange Agreement between the Company and Energy Asset
Management Company, L.L.C. dated March 6, 1998*
10.53 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 31,1997 (File No. 001-13880) and incorporated herein
by reference)
10.54 Office Lease Agreement, 17526 Von Karman Avenue, Irvine,
California*
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
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
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
and incorporated herein by reference)
10.60 Finder Agreement dated as of December 31, 1997*
10.61 Stock Purchase Warrant (Finder Warrant) dated as of
December 31, 1997*
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)
11.1 Computation of Earnings per Common Share*
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*
27.1 Financial Data Schedule*
* Filed herewith
(b) Reports on Form 8-K:
The Company filed an amended current Report as Item 2 on Form 8-K/A on
October 7, 1997 during the last quarter of the Company's fiscal year.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the city of Santa
Maria, State of California, on the 15th day of April, 1998.
Date: April 15, 1998 SABA PETROLEUM COMPANY
------------------------------
(Registrant)
By:
Ilyas Chaudhary
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report
has been signed by the following persons on the 15th day of April, 1998, on
behalf of the Registrant in the capacities indicated:
Signature Title
/s/ Chairman, Chief Executive Officer
Ilyas Chaudhary and Director
/s/ Chief Financial Officer, Vice President,
Walton C. Vance Secretary and Director
/s/ Director
Alex S. Cathcart
/s/ Director
Rodney C. Hill
/s/ Director
Faysal Sohail
/s/ Director
Ron Ormand
/s/ Director
William N. Hagler
Mr. Ilyas Chaudhary
Saba Petroleum Company
Page number 2
March 24, 1998
F-2
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 April 15, 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 $ $ 1,507,641
734,036
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 $ $ 10,104,519
5,377,137
Income taxes payable 1,981,064 733,887
Current portion of long-term debt 1,805,556 13,441,542
------------------------ ----------------------
------------------------ ----------------------
Total current liabilities 24,279,948
9,163,757
------------------------ ----------------------
------------------------ ----------------------
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 23,640,124
17,715,210
------------------------ ----------------------
======================== ======================
$ 49,116,886 $ 77,656,946
======================== ======================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
Years ended December 31, 1995, 1996 and 1997
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 (19,273) (19,273)
subsidiary
Exercise of 189,583
options 116,666 117 189,466
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 (803,000)
exercise of 154,000 154 1,409,842 606,996
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) $ 23,640,124
$7,200,292
============ ========== =============== ============= =============== ============ ================
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
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 (1,750,000) 1,750,000 -
deposit
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
================= ==================== =================
6
SABA PETROLEUM COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
F-35
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
====================
--------------------------
(1) Excludes depreciation, depletion and amortization
expenses. (2) Includes war and pipeline transportation
taxes; does not include provision for income taxes.
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 $- $ 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 December 31, Contractual Exercise December 31, Exercise Price
prices 1997 Life Price 1997
--------------- ----------------- --------------- -------------- ----------------- ----------------
--------------- ----------------- --------------- -------------- ----------------- ----------------
$1.25 - $1.38 (1) $
308,000 1.29 240,000 $
1.29
$1.50 (2) $
220,000 1.50 100,000 $
1.50
$4.38 not stated $
20,000 4.38 4,000 $
4.38
$15.50 9.4 years $ -
625,000 15.50 $
-
----------------- -----------------
================= =================
$1.25 - $15.50
1,173,000 344,000
================= =================
================= =================
(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.
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.
11. 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 $ 8,327 $ 0.07 $ 8,804 $ $ 10,650 $ 0.23
547 3,765 0.43 2,397
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 $ 8,699 $ 0.06 $ 11,825 $ $ 12,001 $ 0.22
556 4,324 0.37 2,600
========= ======= =========== ==================== ========== ========== ========== ==============
========= ======= =========== ==================== ========== ========== ========== ==============
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)
1996 Revenues Profit (Loss) Per Share Per Share
----
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
74
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 $ 757
130
================= =============== ==================
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 $ 33,202
596
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 $ 2,165
329
================= =============== ==================
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 Event (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.
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 7,135,731
464,390 -
Acquisition, exploration and
Development of minerals in
place 1,295,876 5,473,310 7,058,299
289,113
Revisions of previous estimates (691,553) (427,056)
264,497 -
Production (710,271) (85,800) (430,808) (1,226,879)
Sales of minerals in place (8,798)
(2,798) (6,000) -
=================== ================ ===================== ====================
End of year 6,562,595 5,042,502 12,531,297
926,200
=================== ================ ===================== ====================
Proved developed reserves, end of year 5,385,856 4,731,369 10,867,725
750,500
=================== ================ ===================== ====================
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 1,797,697
464,028 -
Revisions of previous estimates 1,519,718 7,832,888 9,352,606
-
Production (938,577) (398,616) (1,337,193)
-
Sales of minerals in place (37,734) (88,100) (125,834)
-
=================== ================ ===================== ====================
End of year 9,103,049 10,376,000 19,479,049
-
=================== ================ ===================== ====================
Proved developed reserves, end of year 8,190,986 2,051,000 10,241,986
-
==================================================================================
==================================================================================
(1) See reference (1) on page F-33
Year ended December 31, 1996
Oil (Barrels)
Proved reserves:
Beginning of year 6,562,595 5,042,502 12,531,297
926,200
Acquisition, exploration and
development of minerals in place 4,501,828 4,605,665
103,837 -
Revisions of previous estimates 5,950,525 5,595,772 11,571,068
24,771
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 9,607,067 26,678,925
920,800
=================== ================ ===================== ====================
Proved developed reserves, end of year 7,993,854 4,692,140 13,395,994
710,000
=================== ================ ===================== ====================
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 5,110,217
924,033 -
Revisions of previous estimates 1,046,326 1,094,539
48,213 -
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 9,607,067 26,678,925
920,800
Acquisition, exploration and
development of minerals in place 4,200,193 1,600,225 5,810,058
9,640
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 12,568,182 23,925,085
806,700
=================== ================ ===================== ====================
Proved developed reserves, end of year 8,048,356 7,964,016 16,615,972
603,600
=================== ================ ===================== ====================
(1) See reference (1) on page F-33
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
-
=================== ================ ===================== ====================
(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.
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
=============== ================= =============== ================
=============== ================= =============== ================
(1) See reference (1) on page F-33
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
============== =============== ============== ==============
============== =============== ============== ==============
(1) See reference (1) on page F-33
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
============== =============== ============== ==============
============== =============== ============== ==============
(1) See reference (1) on page F-33
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 10-K. 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
10-K.
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 $ $ $ (17) $ $
62 12 - 57
Deferred income taxes
- 155 - - 155
Other non current assets 78
85 18 17 42
Reserves included in other non current liabilities:
Restoration and reclamation
64 26 - - 90
1996
Amounts deducted from applicable assets:
Accounts receivable $ $ $ $ 4 $
57 12 - 65
Deferred income taxes
155 897 - - 1,052
Other non current assets 19
42 12 - 35
Reserves included in other non current liabilities:
Restoration and reclamation 30
90 28 - 88
1997
Amounts deducted from applicable assets:
Accounts receivable $ $ $ $ 8 $
65 12 - 69
Deferred income taxes 1,052
818 - - 1,870
Other non current assets
35 - - - 35
Reserves included in other non current liabilities:
Restoration and reclamation 44
88 34 - 78