- - - 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
<TABLE>
<CAPTION>
SABA PETROLEUM COMPANY
(Exact Name of registrant as specified in its Charter)
<S> <C>
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
</TABLE>
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 ]
<PAGE>
- 26 -
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.
<PAGE>
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.
<PAGE>
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.
<TABLE>
<S> <C> <C> <C> <C>
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
======================= ======================= ============ ============
</TABLE>
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
<TABLE>
<CAPTION>
Reserve Category
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
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: <TABLE> <CAPTION>
Reserve Category
<S> <C> <C> <C> <C> <C>
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
</TABLE>
"Proved developed" oil and gas reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
"Proved undeveloped" oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. In recent years, the
market for oil and gas has experienced substantial fluctuations, which have
resulted in significant swings in the prices for oil and gas. 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:
<TABLE>
<S> <C> <C> <C>
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
=============== =============== =============
</TABLE>
(1) No reduction is made for the minority interest in Beaver Lake.
<PAGE>
Average Sales Price and Production Cost
The following table sets forth information concerning average per unit
sales price and production cost for the Company's oil and gas production for the
periods indicated:
<TABLE>
<S> <C> <C> <C> <C>
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
</TABLE>
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:
<TABLE>
<S> <C> <C> <C>
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
========= ========== ========= ========= ========== ========
</TABLE>
(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.
<PAGE>
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:
<TABLE>
<S> <C> <C> <C> <C>
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
============ =========== ============ ===========
</TABLE>
(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.
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
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
</TABLE>
(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.
<PAGE>
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.
<TABLE>
<S> <C> <C> <C> <C>
Low High
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
1998
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
First Quarter.................................................................. $ 3 .38 $ 8 .50
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
1997
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Fourth Quarter $ 8 .00 $ 14 .88
..................................................................................
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Third Quarter ................................................................. 12 .81 20 .12
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Second Quarter................................................................. 10 .75 17 .75
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
First Quarter.................................................................. 12 .75 25 .25
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
1996
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Fourth Quarter................................................................. $ 9 .25 $ 27 .12
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Third Quarter ................................................................. 6 .19 9 .94
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
Second Quarter................................................................. 3 .88 8 .00
- - --------------------------------------------------------------------------------------------------------------------
- - --------------------------------------------------------------------------------------------------------------------
First Quarter.................................................................. 3 .56 4 .75
- - --------------------------------------------------------------------------------------------------------------------
</TABLE>
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): <TABLE> <CAPTION>
--------------- ------------- ------------- --------------- --------------
1993 1994 1995 1996 1997
--------------- ------------- ------------- --------------- --------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
(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.
<PAGE>
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.
<PAGE>
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: <TABLE> <S> <C>
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
</TABLE>
Mr. Ilyas Chaudhary
Saba Petroleum Company
Page number 2
March 24, 1998
<TABLE>
<CAPTION>
F-2
SABA PETROLEUM COMPANY AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
AND FINANCIAL STATEMENT SCHEDULE
<S> <C>
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
</TABLE>
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.
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
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
<S> <C> <C>
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
======================== ======================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
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
<S> <C> <C> <C>
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
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SABA PETROLEUM COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
Years ended December 31, 1995, 1996 and 1997
<S> <C> <C> <C> <C> <C> <C> <C>
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
============ ========== =============== ============= =============== ============ ================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
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
<S> <C> <C> <C>
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
================= ==================== =================
</TABLE>
<PAGE>
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.
<PAGE>
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:
<TABLE>
<S> <C> <C>
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
</TABLE>
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.
<PAGE>
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.
<TABLE>
<CAPTION>
Year Ended
December 31,
1995
(unaudited)
<S> <C>
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
======================
</TABLE>
<PAGE>
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.
<TABLE>
<CAPTION>
Nine Months
Ended
September 30,
1995
(unaudited)
<S> <C>
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.
</TABLE>
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:
<TABLE>
<S> <C>
Working capital deficiency $ (105,981)
Oil and gas properties 316,420
------------------
$ 210,439
==================
</TABLE>
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
<TABLE>
<CAPTION>
Notes receivable are comprised of the following at December 31, 1996 and
1997:
<S> <C> <C>
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
============ ============
</TABLE>
<PAGE>
4. Oil and Gas Properties, Land, Plant and Equipment
<TABLE>
<CAPTION>
Oil and gas properties, land, plant and equipment at December 31, 1996 and 1997 are as follows:
<S> <C> <C> <C> <C>
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
================== ================= ================ ===================
</TABLE>
At December 31, 1997, plant and equipment and accumulated depreciation
included $620,248 and $ 73,972, respectively, for assets acquired under
capital leases.
<PAGE>
Costs incurred in oil and gas property acquisition, exploration, and
development activities are as follows:
<TABLE>
<S> <C> <C> <C> <C>
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
============== ============== ================ =================
</TABLE>
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:
<TABLE>
<S> <C> <C> <C>
1995 1996 1997
---- ---- ----
Interest paid $ 1,388,369 $ 2,309,475 $ 2,088,252
Income taxes paid $ - $ 1,150,029 $ 2,531,157
</TABLE>
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:
<TABLE>
<S> <C> <C>
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
================ ================
</TABLE>
<PAGE>
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:
<TABLE>
<S> <C> <C> <C>
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
================ =================== =================
</TABLE>
Components of income tax expense (benefit) for the years ended December 31,
1995, 1996 and 1997 are as follows:
<TABLE>
<S> <C> <C> <C>
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
================ ================= ===================
</TABLE>
The provision (benefit) for income taxes differs from the amount that would
result from applying the federal statutory rate for the years ended
December 31, 1995, 1996 and 1997 as follows:
<TABLE>
<S> <C> <C> <C>
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%
================= =============== ============
</TABLE>
<PAGE>
The tax effected temporary differences which give rise to the deferred tax
provision consist of the following:
<TABLE>
<S> <C> <C> <C>
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
============== ============= ==============
</TABLE>
The components of the tax effected deferred income tax asset (liability) as
of December 31,1996 and 1997 are as follows:
<TABLE>
<S> <C> <C>
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)
================= ================
</TABLE>
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.
<PAGE>
8. Long-Term Debt
Long-term debt at December 31, 1996 and 1997 consists of the following:
<TABLE>
<S> <C> <C>
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
================== ==================
</TABLE>
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.
<PAGE>
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.
<PAGE>
Maturities of long term debt at December 31, 1997 are as follows:
<TABLE>
<S> <C>
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
</TABLE>
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
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
---------------------------- ---------------------------------------------------------
---------------------------- -------------------------- ------------------------------
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
------ ------ -----
</TABLE>
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:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
--------------------------------------------------- ------------------------------------
--------------------------------------------------- ------------------------------------
<S> <C> <C> <C> <C> <C>
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.
</TABLE>
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:
<TABLE>
<S> <C> <C> <C> <C> <C>
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
</TABLE>
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.
<PAGE>
11. Earnings Per Share
<TABLE>
<CAPTION>
(In thousands, except per share data)
<S> <C> <C> <C>
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
========= ======= =========== ==================== ========== ========== ========== ==============
========= ======= =========== ==================== ========== ========== ========== ==============
</TABLE>
13. Quarterly Financial Data (unaudited)
The following is a tabulation of unaudited quarterly operating results for
1996 and 1997:
<TABLE>
<S> <C> <C> <C> <C> <C>
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
============== ============== ==============
</TABLE>
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:
<TABLE>
<S> <C>
Year Ending December 31,
1998 $308,660
1999 233,521
2000 86,503
2001 35,697
2002 13,105
==============
$677,486
==============
</TABLE>
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):
<TABLE>
<S> <C> <C>
1996 1997
---- ----
Customer A $ 2,566,700 $ 1,482,600
==================== ===============
Customer B $ 1,267,100 $ 931,965
==================== ===============
Customer C $ 899,600 $ 745,567
==================== ===============
</TABLE>
<PAGE>
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:
<TABLE>
<S> <C> <C> <C> <C>
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 $ - $ -
=============== ============== ==============
</TABLE>
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.
<PAGE>
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.
<PAGE>
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:
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
(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
================= =============== ================== =================== =============
</TABLE>
<PAGE>
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.
<PAGE>
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:
<TABLE>
<S> <C> <C> <C> <C>
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
</TABLE>
<PAGE>
<TABLE>
<S> <C> <C> <C> <C>
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
-
=================== ================ ===================== ====================
</TABLE>
(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.
<TABLE>
<S> <C> <C> <C>
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
</TABLE>
<PAGE>
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).
<TABLE>
<CAPTION>
December 31, 1995
<S> <C> <C> <C> <C>
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
</TABLE>
<PAGE>
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).
<TABLE>
<S> <C> <C> <C> <C>
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
<PAGE>
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
</TABLE>
<PAGE>
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
<PAGE>
<TABLE>
<CAPTION>
SABA PETROLEUM COMPANY AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
Years ended December 31, 1995, 1996 and 1997
(dollars in thousands)
Additions
---------------------------------
---------------------------------
<S> <C> <C> <C> <C> <C>
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
</TABLE>
Exhibit 10.5
SECOND AMENDMENT TO EMPLOYMENT AGREEMENT
- BRADLEY T. KATZUNG -
This Second Amendment To Employment Agreement ("Amendment") is made
effective as of the 1st day of January, 1998, by and between Saba Petroleum
Company, a Delaware corporation ("Company"), and Bradley T. Katzung ("Employee")
and amends and modifies that certain Employment Agreement ("Agreement") between
the two parties dated November 8, 1993, and the first amendment to the Agreement
dated April 15, 1994.
Recitals
A. WHEREAS, it is in the best interest of the Company to promote
Employee to the position of Executive Vice President, General
Manager - U.S. of Saba Petroleum Company, subject to and in
accordance with the terms and provisions set forth below.
B. WHEREAS, after review and consideration of the Agreement, Company
and Employee agree to amend and modify the Agreement as set forth below:
NOW, THEREFORE, for good and valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, the parties agree as follows:
1. Subject to the terms, conditions and provisions of the Agreement, the
Company promotes Employee to Executive Vice-President, General
Manager-U.S. of Saba Petroleum Company.
2. Annual salary for Employee will be $125,000.00 and will be reviewed on
an annual basis on the anniversary date of the Agreement.
3. The incentive bonus plan as described in Paragraph 4 of the first
amendment to the Agreement will cease on December 31, 1997.
4. All other terms and conditions of the Agreement, as amended, remain in
full force and effect.
IN WITNESS WHEREOF, the parties have executed this Amendment effective
as of the day first written above.
COMPANY: EMPLOYEE:
Saba Petroleum Company,
a Delaware corporation
By: _____________________ ________________________
Ilyas Chaudhary, Chairman/CEO Bradley T. Katzung
Exhibit 10.9
RODNEY C. HILL,
A PROFESSIONAL CORPORATION
2010 BIRNAM WOOD DRIVE
SANTA BARBARA, CA. 93108-2206
(805) 565-5893
March 13, 1998
Mr. Ilyas Chaudhary, Chairman
And Chief Executive Officer
Saba Petroleum Company
2301 Skyway Drive, Suite 201
Santa Maria, Ca. 93455
Re: Representation of Saba Petroleum Company
Dear Mr. Chaudhary:
When accepted by you, this letter will constitute an agreement for the
representation of Saba Petroleum Company and its subsidiaries (collectively,
"Saba") by the undersigned, Rodney C. Hill, A Professional Corporation ("Hill"),
and the written fee agreement required under California law. This letter will
also modify the terms of representation set forth in the letter between Saba and
Hill dated March 18, 1997 and shall be effective as of March 13,1998. The terms
of the engagement are as follows:
1. Saba engages Hill to represent Saba in its proposed business combination
with Omimex Resources, Inc., which shall include assisting management with
the negotiation and execution of agreements in respect of such combination
and to hire and supervise outside counsel for Saba, to direct the
performance of legal services by such outside counsel, all in respect of
such business combination.
2. Saba shall compensate Hill for March representation at the rate of $10,000
payable on March 31, 1998. Payment for further representation shall be as
provided in section 3 of this letter.
<PAGE>
1. 3. Hill's responsibility shall be for the completion of the business
combination between Saba and Omimex Resources, Inc. and its incidental
responsibility shall be to assist and oversee the preparation of
Saba's Form 10-K for the year 1997 and the preparation of the
registration statement on form S-1 presently pending. David Melman
shall assume responsibility for the completion of the latter two
projects and Hill shall cooperate with Melmen in the latter's efforts.
In addition, Hill shall provide advice to Mr. Melman with respect to
general Saba matters during the period ending May 30, 1998. Hill shall
be paid $100,000 for his services if a combination with Omimex is
completed and $50,000 if that transaction aborts. Payment shall be
made on closing of the transaction, if such is the case, or on or
before December 31, 1998 if the transaction aborts. If the transaction
has not closed by December 31, 1998, it shall be deemed that it has
aborted. Saba will reimburse Saba shall reimburse Hill for its out of
pocket expenses which have been incurred for the benefit of Saba,
including telephone (other than local) charges, travel, postage and
other expenses on a monthly basis.
<PAGE>
22
179816.02
4. At March 1, 1998, Saba was indebted to Hill in the following amounts, which
together with interest as provided below, will be paid to Hill by Saba on
December 31, 1998 or the closing of any loan or financing transaction, whichever
shall first occur:
a. Accrued and deferred portion of monthly retainer to February 28,
1998, thirty - one thousand, seven hundred fifty dollars ($31,750); b.
Four thousand, five hundred dollars ($4,500) representing Hill's
portion of the payment of a gross of thirty thousand dollars ($30,000)
due
under Saba's agreements with Hamar II Associates, LLC and Amerada
Hess Corporation; and c. Twenty-five thousand dollars ($25,000) as an
accrued bonus.
The sum of such amounts is Sixty One Thousand, Two Hundred Fifty Dollars
($61,250). Interest shall accrue on the unpaid balance of such amounts from
March 1, 1998 until paid at Saba's existing bank borrowing rate, which is
WSJ prime plus two percentage points, but such interest shall not exceed
the usury limit in the state of California.
5. Saba will, on a monthly basis, reimburse Hill for a portion of its car
expenses in the amount of $400 per month until the end of the calendar
year 1998, the last payment to be made in January 1999.
6. Rodney C. Hill, the shareholder of Hill, has at the request of Saba
acted as a director of Saba and a vice-president of Saba until the end
of the year 1997. As such, Saba has granted Rodney C. Hill options to
purchase 125,00 shares of Saba's common stock. Such options were
orally agreed to be cancelled on March 15, 1998 and replaced with
replaced by a grant of twenty thousand shares (20,000) of fully paid
common stock valued at the closing price on the last trading day
preceding and an option, presently vested and expiring on March 15,
1999, to purchase thirty thousand (30,000) shares of the common stock
at the closing price on March 13, 1998. On said date, the closing
price of the common stock was $3.875 per share. Saba shall cause the
shares and options to be granted as soon as practicable, but prior to
April 30, 1998 and shall use its best efforts to cause both the common
stock granted and the shares underlying such options to be registered
with the Securities and Exchange Commission as soon as is reasonably
practicable. Saba shall report the grant of the shares to Rodney C.
Hill on a form 1099 at the above price.
Saba is advised that it should have this letter of agreement reviewed
by counsel other than Hill, so that Saba may have an unbiased and disinterested
opinion as to the contents and effect thereof. After such review and
consideration as Saba determines is appropriate, kindly sign and return one copy
of this letter to the undersigned, and it will constitute the retention and fee
agreement required by the Rules of Professional Conduct.
Very truly yours,
Rodney C. Hill, A Professional Corporation
By_________________________________
Rodney C. Hill, its president
ACCEPTED AND AGREED TO
on this ___ day of March 1998.
SABA PETROLEUM COMPANY
By________________________________
Ilyas Chaudhary, Chief Executive Officer
Exhibit 10.21
SEVENTH AMENDMENT
TO
FIRST AMENDED AND RESTATED LOAN AGREEMENT
DATED SEPTEMBER 23, 1996
BY AND BETWEEN SABA PETROLEUM COMPANY, ET AL
AND BANK ONE, TEXAS, N.A.
This Seventh Amendment to the First Amended and Restated Loan Agreement
dated September 23, 1996 (this "Seventh Amendment") by and among SABA PETROLEUM
COMPANY, a Delaware corporation, successor by merger to Saba Petroleum Company,
a Colorado corporation (the "Borrower") each of the undersigned Guarantors, and
BANK ONE, TEXAS, N.A., a national banking association (the "Bank"), is entered
into on this 30th day of March 1997.
W I T N E S S E T H:
Borrower and Bank have entered into a First Amended and Restated Loan
Agreement dated September 23, 1996, as amended by the First Amendment thereto
dated November 5, 1996, the Second Amendment thereto dated August 28, 1997, the
Third Amendment thereto dated September 5, 1997, and the Fourth Amendment
thereto dated September 9, 1997, the Fifth Amendment thereto dated November 11,
1997, and the Sixth Amendment thereto dated December 31, 1997 (collectively, the
"Loan Agreement").
Borrower has requested that, among other things, Bank waive certain
Events of Default that otherwise would have arisen under the Loan Agreement as
the result of certain principal reductions owed on the Loan not having been paid
when due, and that Bank agree to further defer the payment date for such
principal reductions as well as other principal reductions due on the Loans, and
Bank has agreed to such waivers and amendments to the extent expressly set forth
herein.
NOW, THEREFORE, in consideration of the promises herein contained, and
for other good and valuable consideration, the receipt and sufficiency of which
are acknowledged by the Borrower, the Guarantors and the Bank, and each
intending to be legally bound hereby, the parties agree as follows:
I. Specific Amendments to Loan Agreement.
Article I is hereby amended by adding the following defined term
thereto:
"Sixth Amendment" means that certain Amendment to this
Agreement executed by Borrower and Bank on December 31, 1997.
<PAGE>
"Seventh Amendment" means the Seventh Amendment to this
Agreement executed by Borrower and Bank on March 30, 1997.
Section 2.03 is hereby amended by replacing the first grammatical
paragraph thereof that was added by the Third Amendment with the following text:
As of August 1, 1997, Borrowing Base I is redetermined to be Nineteen
Million One Hundred Thousand and No/100 Dollars ($19,100,000.00), which
shall thereafter decline in the amount of $400,000.00, monthly (except
for the months expressly excluded, below), beginning on September 1,
1997, and continuing on the first day of each successive month
thereafter; provided, however, that such $400,000.00 monthly reduction
in Borrowing Base I shall not occur during the months of February,
March and April 1998, but shall then resume effective on May 1, 1998,
and continue monthly thereafter until the effective date of the next
redetermination of Borrowing Base I as set forth in this Section. As of
the effective date of the Third Amendment, Borrowing Base II is
redetermined to be $3,400,000.00, which shall thereafter decline by
$142,000.00 monthly (except for the months expressly excluded, below)
beginning on November 1, 1997, and continuing on the first day of each
successive month thereafter; provided, however, that such $142,000.00
monthly reduction in Borrowing Base II shall not occur during the
months of February, March and April 1998.
Section 5.37, as added to the Loan Agreement by the Sixth Amendment, is
hereby amended by replacing the sum A$3,000,000.00" that appears in the third
line thereof with the sum A$2,000,000.00," and by replacing the date AApril 1,
1998" that appears in the fourth line thereof with the date AApril 15, 1998.@
<PAGE>
II. Certain Waivers. The Bank hereby waives the Events of Default and/or
Unmatured Events of Default that occurred when Borrower failed to cure the Loan
Excess that existed, prior to the execution of this Seventh Amendment, as the
result of: (a) the monthly reductions in Borrowing Base I that occurred on
February 1 and March 1, 1998, and (b) the monthly reductions in Borrowing Base
II that occurred on February 1 and March 1, 1998. BORROWER AND EACH GUARANTOR
HEREBY ACKNOWLEDGE AND AGREE THAT, EXCEPT FOR WAIVERS AND AMENDMENTS EXPRESSLY
SET FORTH HEREIN, BANK HAS NOT GIVEN OR MADE, NOR HAS BANK AGREED TO GIVE OR
MAKE, ANY OTHER WAIVERS OF DEFAULTS OR EVENTS OF DEFAULT THAT HAVE EXISTED OR
THAT MIGHT HEREAFTER EXIST UNDER ANY OF THE LOAN DOCUMENTS, OR ANY AMENDMENTS TO
ANY OF THE PROVISIONS OF THE LOAN DOCUMENTS, AND NO INTENT TO GRANT FUTURE
WAIVERS OR AMENDMENTS HAS BEEN OR MAY BE INFERRED AS THE RESULT OF ANY COURSE OF
DEALING BETWEEN BANK, BORROWER, AND GUARANTORS WITH RESPECT TO ANY PRIOR
WAIVERS, CONSENTS, OR AMENDMENTS WITH RESPECT TO ANY OF THE LOAN DOCUMENTS.
III. Ratification of Guaranties. Each Guarantor hereby ratifies and confirms its
liability under the Guaranty heretofore executed by it, and, except as stated to
the contrary in this paragraph, confirms and agrees that such Guaranty continues
in full force and effect with respect to all of the Indebtedness covered by the
Loan Agreement, as the same may be restated, amended, modified, renewed, or
rearranged from time to time, including, but not limited to, the Indebtedness
evidenced by the Note, the Term Note and the Mezzanine Note; provided, however,
that the Guaranty of Sabacol relates only to the Indebtedness evidenced by the
Term Note and the Mezzanine Note, and the Guaranty of Ilyas Chaudhary relates
only to the Indebtedness evidenced by the Term Note and the Mezzanine Note. This
ratification is given for the purpose of inducing the Bank to enter into this
amendment, and each Guarantor is aware that, but for such ratification and
agreement contained herein, the Bank would not grant the waivers and amendments
set forth herein.
IV. Reaffirmation of Representations and Warranties. To induce the Bank to enter
into this Seventh Amendment, the Borrower and each Guarantor hereby reaffirms,
as of the date hereof, its representations and warranties contained in Article
IV of the Loan Agreement and in all other documents executed pursuant thereto,
and additionally represents and warrants as follows:
A. The execution and delivery of this Seventh Amendment and
the performance by the Borrower and each Guarantor of its obligations
under this Seventh Amendment are within the Borrower's and each
Guarantor's power, have been duly authorized by all necessary corporate
action, have received all necessary governmental approval (if ANY shall
be required), and do not and will not contravene or conflict with ANY
provision of law or of the charter or by-laws of the Borrower or ANY
Guarantor or of ANY agreement binding upon the Borrower or ANY
Guarantor.
B. The Loan Agreement as amended by this Seventh Amendment
represents the legal, valid and binding obligations of the Borrower and
each Guarantor, enforceable against each in accordance with their
respective terms subject as to enforcement only to bankruptcy,
insolvency, reorganization, moratorium or other similar laws affecting
the enforcement of creditors' rights generally.
<PAGE>
C. No Event of Default or Unmatured Event of Default has
occurred and is continuing as of the date hereof.
V. Defined Terms. Except as amended hereby, terms used herein that are defined
in the Loan Agreement shall have the same meanings herein.
VI. Reaffirmation of Loan Agreement. This Seventh Amendment shall be deemed to
be an amendment to the Loan Agreement, and the Loan Agreement, as further
amended hereby, is hereby ratified, approved and confirmed in each and every
respect. All references to the Loan Agreement herein and in ANY other document,
instrument, agreement or writing shall hereafter be deemed to refer to the Loan
Agreement as amended hereby.
VII. Entire Agreement. The Loan Agreement, as hereby further amended, embodies
the entire agreement between the Borrower, the Guarantors and the Bank and
supersedes all prior proposals, agreements and understandings relating to the
subject matter hereof. The Borrower and each Guarantor certifies that it is
relying on no representation, warranty, covenant or agreement except for those
set forth in the Loan Agreement, as hereby amended, and the other documents
previously executed or executed of even date herewith.
VIII. Governing Law. THIS SEVENTH AMENDMENT SHALL BE GOVERNED BY AND CONSTRUED
IN ACCORDANCE WITH THE LAWS OF THE STATE OF TEXAS AND THE APPLICABLE LAWS OF THE
UNITED STATES OF AMERICA. This Seventh Amendment has been entered into in Harris
County, Texas, and it shall be performable for all purposes in Harris County,
Texas. Courts within the State of Texas shall have jurisdiction over ANY and all
disputes between the Borrower and the Bank, whether in law or equity, including,
but not limited to, ANY and all disputes arising out of or relating to this
Seventh Amendment or ANY other Loan Document; and venue in ANY such dispute
whether in federal or state court shall be laid in Harris County, Texas.
IX. Severability. Whenever possible each provision of this Seventh Amendment
shall be interpreted in such manner as to be effective and valid under
applicable law, but if ANY provision of this Seventh Amendment shall be
prohibited by or invalid under applicable law, such provision shall be
ineffective to the extent of such prohibition or invalidity, without
invalidating the remainder of such provision or the remaining provisions of this
Seventh Amendment.
<PAGE>
X. Execution in Counterparts. This Seventh Amendment may be executed in ANY
number of counterparts and by the different parties on separate counterparts,
and each such counterpart shall be deemed to be an original, but all such
counterparts shall together constitute but one and the same instrument, and ANY
signed counterpart shall be deemed delivered by the party executing such
counterpart if sent to ANY other party hereto by electronic facsimile
transmission.
XI. Section Captions. Section captions used in this Seventh Amendment are
for convenience of reference only, and shall not affect the construction of
this Seventh Amendment.
XII. Successors and Assigns. This Seventh Amendment shall be binding upon the
Borrower, each Guarantor and the Bank and their respective successors and
assigns, and shall inure to the benefit of the Borrower, each Guarantor and the
Bank, and the respective successors and assigns of the Bank.
XIII. Non-Application of Chapter 15 of Texas Credit Codes. The provisions of
Chapter 15 of the Texas Credit Code (Vernon's Texas Civil Statutes, Article
5069-15) are specifically declared by the parties hereto not to be applicable to
the Loan Agreement as hereby further amended or ANY of the other Loan Documents
or to the transactions contemplated hereby.
XIV. NOTICE OF FINAL AGREEMENT. THIS SEVENTH AMENDMENT, TOGETHER WITH THE LOAN
AGREEMENT AND THE OTHER LOAN DOCUMENTS (COLLECTIVELY, THE AWRITTEN AGREEMENT@),
REPRESENT THE FINAL AGREEMENT AMONG BANK, BORROWER, AND GUARANTORS, AND MAY NOT
BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS OR SUBSEQUENT ORAL
AGREEMENTS OF THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE
PARTIES.
IN WITNESS WHEREOF, the parties hereto have caused this Seventh
Amendment to be duly executed as of the day and year first above written.
BORROWER
SABA PETROLEUM COMPANY
By:___________________________
Walton C. Vance
Vice President and
Chief Financial Officer
BANK
BANK ONE, TEXAS, N.A.
By:___________________________
Name:_________________________
Title:_________________________
GUARANTORS:
SABA ENERGY OF TEXAS, INCORPORATED
By:________________________________
Walton C. Vance
Secretary
SABA PETROLEUM, INC.
By:________________________________
Walton C. Vance
Secretary
SABA PETROLEUM OF MICHIGAN, INC.
By:________________________________
Walton C. Vance
Secretary
MV VENTURES, G. P.
By: Saba Energy of Texas, Incorporated,
Managing Partner
By:___________________________
Walton C. Vance
Secretary
<PAGE>
SABACOL, INC.
By:
Walton C. Vance
Secretary
ILYAS CHAUDHARY
Exhibit 10.45
<PAGE>
AMENDMENT TO AGREEMENT FOR
ASSIGNMENT OF LEASES
THIS INSTRUMENT (the "Amendment',) is made and entered as of November 1,
1997, by and between GEO PETROLEUM. INC. ("GEO") and SABA PETROLEUM.
("SABA") with respect to the matters set forth herein.
RECITALS:
I . Pursuit to that "Agreement for Assignment of Leases" (the "Agreement") by
and between the parties dated December 19, 1996, Geo agreed to assign to Saba an
undivided two-thirds interest in the "Properties" as defined in the Agreement,
consists of oil and gas leases, the wells, equipment, and fixtures located
thereon, and appurtenant interests, contracts, and rights. Pursuant to that
Assignment dated December 20, 1996, and recorded April 23, 1997, as document
97-050381, in the Official Records of Ventura County, California, Geo assigned
said two-thirds interest in the Properties to Saba. By letter agreement (the
"Extension") dated August 25, 1997, the parties agreed that Saba could extend
the period for commencement of drilling operations to no later than November 30,
1997.
2. In order to provide for the orderly and timely development of the Properties,
the parties desire that Saba reduce its interest in the Properties to one-third,
that Geo's interest be increased to two-thirds, and that the parties continue
with performance under the Agreement, as amended hereby. Saba's financial
involvement will be reduced in proportion to the reduction of its ownership
interest.
AGREEMENT:
. For and in consideration of the mutual covenants contained herein, the
parties hereto agree as follows:
Amendment.
1 . The Agreement is hereby deemed amended by the terms and provisions of this
2. At page 1 of the Agreement, the first, unnumbered paragraph and paragraphs A,
B. and C are amended to provide that the ownership of the Properties shall be
and is hereby vested one" third in Saba and two-thirds in Geo, provided that as
to Saba's interest Saba shall be required to perform the provisions hereof in
order to earn and retain such interest. Saba agrees to assign to Geo an
undivided one-third interest in the Properties upon the execution of this
Agreement. As a result, the Agreement is hereby deemed modified such that
wherever Saba's interest, shares in costs and revenues, and ownership are stated
as "two-thirds" ("2/3",), such shall now be deemed to be "one-third" ("1/3",).
In the same manner, Geo's interest, shares in costs ant revenues, and
<PAGE>
ownership shall be deemed to be "two thirds" ("2/3") throughout the Agreement
and this Amendment.
3. "Paragraph 1. Royalty Purchases" of the Agreement and Paragraph 3 of the
Extension are replaced their entirety by the following: Saba has purchased
certain overriding royalty and landowners' royalty interests and paid the cost
thereof. Geo shall have the option to acquire a two-thirds interest in the
royalties described in Exhibit "A" of the Agreement which option shall be
exercised only by Geo delivering to Saba a written notice of exercise
accompanied by a check representing good funds in an amount equivalent to
two-thirds of Saba's total cost of acquisition of the royalties by April l,
1998. If not so exercised, the option shall expire on April l, 1998. The
interests of the parties shall be two-thirds to Geo and one-third to Saba with
respect to further acquisitions of land, royalties, and mineral interests in the
area of mutual interest. Geo shall be the party responsible for making farther
acquisitions and notifications of acquisitions.
4. Paragraph 2. "Operations" of the Agreement and paragraphs 2, 4, and 5 of the
Extension are replaced in their entirety by the following: Geo shall be the
"Operator" under the Agreement, as amended, and the Operating Agreement. Saba
shall promptly transfer to Geo all pending applications before all agencies with
respect to drilling and operations on the Properties. Geo shall diligently
pursue the obtaining of all permits and approvals prerequisite to drilling,
obtain a drilling rig and equipment, and prepare for the drilling of the first
well. The first well shall be drilled and completed as a SAGD well in the Vaca
Tar Sand and commenced, if practicable in the judgment of Geo, no later than
March 31, 1998. Geo shall give Saba not less than 30 days written notice prior
to the commencement of drilling operations.
S. (a). Paragraphs 3, 4 and 5 of the Agreement are deleted and the following
terms shall apply: Commencing November l, 1 g97, each party shall be entitled to
receive 50% of the revenues from the Properties and shall pay 50% of the costs,
subject to the further provisions hereof. If Saba spends a minimum amount of
$5,000,000 with respect to its 50% interest in the conduct of operations on the
Properties, pursuant to the Operating Agreement, within five years from November
1, 1997, only then shall Saba earn and retain its one-third interest in the
Properties. Geo shall, in its judgment as a prudent Operator, drill SAGD wells
with approximately six months between the completion of one and the commencement
of operations for the next well. Geo shall bear and pay 50% of the costs during
the period that Saba is responsible for 50% of the costs. If and when Saba has
spent said $5,000,000, then the parties shall bear and pay the costs of further
drilling and the related operations on the basis of two-thirds by Geo and
one-third by Saba. As to the wells paid for, in part, by Saba's $5,000,000
expenditure, the parties shall each receive 50% of the total revenues derived
from all such wells combined and pay 50% of the costs thereof until their costs
have been recovered ("Payout") and thereafter Saba shall own a one-third
interest in the Properties and Geo shall own two-thirds. Geo shall Amish Saba
with monthly statements of costs of operation, revenue, and all other
information required to calculate the Payout status.
(b). Should (a) Saba fail to expend said sum of $5,000,000 within five years
from November l, 1997, or (b) prior to the time it has expended said $5,000,000
sum fail to participate for its full interest in a well actually drilled by Geo
in accordance with the provisions of
<PAGE>
paragraphs 4 or 5 hereof, this agreement shall terminate and Saba shall
re-assign to Geo all its interests hereunder save and except for (a) the
interests acquired by Saba pursuant to paragraph 3 hereof, insofar only as such
interests affect and burden the wells in which Saba shall retain its interests,
and (b) its interests in the wells and the spacing unit around each well for
which Saba has put its share of drilling, and completion costs, and reassignment
to Geo conditioned upon Saba's recovery and receipt from Geo of the actual
amount of Saba's expenditures on wells in which Saba participated but failed to
Filly acquire. The production facilities located outside any spacing unit
retained by Saba which are used in connection with the operation of the wells
retained by Saba shall be owned, maintained and operated by the parties at a
cost equal to the ratio of dollars actually expended by Saba to the sum of
$5,000,000, times one-third. Saba shall not retain any interests in any well
located outside the retained spacing units and Geo shall be responsible for the
operation and/or abandonment of the same.
(c) Should Geo fail to participate in a well actually drilled by Geo in
accordance with the provisions of paragraphs 4 or 5 hereof, the terms of the
Operating Agreement shall apply
6. Spacing Unit. Paragraph 6 of the Agreement is deleted and replaced by
the following:
To qualify as a spacing unit well, the well must have been designated by Geo as
a well to be reworked, recompleted, or drilled, and Saba shall have expended a
minimum of $75,000 thereon. The spacing unit shall be in the form of a rectangle
from the surface down to all depths, the exterior boundaries of which shall be a
distance of one hundred and fifty feet on either side measured from each and of
the perforated liner of the spaced unit well.
Should the surface well site and/or portions of the well bore lie outside the
confines of any spacing unit created for a well, the well site and well bore
shall be considered as part of the spacing unit in which Saba has retained an
interest.
7. Paragraph 7 of the Agreement is deleted and replaced by the follov~ng:
Geo and Saba shall be equally responsible for any "pollution liability",
consisting of remediation, abatement, liability, find costs associated with
hazardous substances on the Properties until Saba shall have completed the
expenditure of its $5,000,000 condition or has terminated its continuing
interest in the Properties, provided that the parties shall continue to share
equally thereafter as to pollution liability incurred through joint operations
before such completion. As to pollution liability arising after such completion,
Geo shall be responsible for two-thirds and Saba for one-third of such
obligation. If Saba has not completed such expenditure, then the obligation
shall be borne 100% by Geo as to the areas not retained by Saba, and equally by
the parties as to the retained areas until Saba has achieved payout with respect
to the same, and by Geo as to two-thirds and Saba as to one-third when payout
has been achieved with respect to such areas.
8. Paragraph 8 of the Agreement is deleted and replaced by the following:
i
l
<PAGE>
Mickelson Land Services, Inc. has prepared and delivered to the parties a
detailed title report on the lands and leases comprising the Properties. The
parties have examined such description and have determined that there are no
title defects as defined in the Agreement or otherwise.
9. Paragraphs 9 through 20 of the Agreement are not amended hereby, except that
the address for notice of the parties shall be changed to provide:
<TABLE>
<S> <C>
Geo Petroleum, Inc. Also to:
Attn.: Larry R. Burroughs 4204 Sand Springs, OK 74063
President and Chief Operating Officer Telephone 918-241-8587
501 Deep Valley Drive, Suite 300 Fax 918-241-4825
Rolling Hills Estates, CA 90274
Telephone: 310-265-0721,Fax: 310-265-9452
Saba Petroleum, Inc.
Attn.: Ilyas Chaudhary
Chief Executive Officer
3201 Airpark Drive, No. 201
Santa Maria, CA 93455
Telephone: 805-347-8700
Fax: 805-347-1072
</TABLE>
10. The terms and provisions of the Extension are deemed superseded by this
Amendment and canceled, except for any obligations which may have accrued in
favor of Geo pursuant to paragraph 6 thereof The period for accrual of losses
shall end as of October 31 , 1997.
11 . By executing this Amendment, each of the parties intends to and does hereby
extinguish the obligations heretofore existing between them under the Agreement
and Extension, as amended hereby. Each of the parties on behalf of itself, its
successors, assigns, parent and subsidiary organizations, affiliates, partners,
agents, stockholders, employees and representatives hereby fully releases and
discharges the other party and that party's successors, assigns, parent and
subsidiary organizations, affiliates, partners, agents, stockholders, employees
and representatives from all rights, claims, and actions which each party and
the above-named successors now have against the other party and the above-named
successors, stemming from the Agreement and Extension.
12. (a) In Exhibit A-l to the Agreement, it is provided that certain wells
completed in zones, below the Vaca Tar Sand are excluded from the Agreement and
are downed owned and ret entirely by Geo in connection with a disposal project
operated by Geo. It is agreed that as to certain wells completed in zones below
the Vaca Tar Sand, namely the VTSU 1-3, 4-1, 2, and 4-3, Moo reasonably deems
that any of the same is not suitable for completion or re-drilling into the Vaca
Tar Sand, and so notifies Saba with a period of 30 days for a response from
Saba, then Geo may elect to take said well over at its sole cost, risk, ant
expense for disposal or other operations not involving production from the Vaca
Tar Sand. In such case, Geo shall assume the compete cost and risk of abandons g
the well.
l
<PAGE>
b. As to any lands or leases acquired within the area of mutual interest, Geo
shall have the sole debt to take over any injection wells not needed for
injection of waters produced on the joint lands, and use them in connection with
its disposal project, and the sole right to operate commercial disposal
operations on the acquired lands.
13. As modified and amended hereby' the Agreement shall be deemed in full force
and effect in accordance with its terms.
14. The terms of this agreement shall be binding upon and inure to the benefit
of the successors and assign of the parties hereto.
In witness Whereof, the parties have executed this agreement effective the date
first written above.
Geo Petroleum, Inc., SABA Petroleum , Inc.
a California corporation a California corporation
By:____________ By: ________________
Larry R.Burroughs Ilyas Chaudhary, Chief Executive Officer
President
When recorded please return
Geo Petroleum, Inc.
501 Deep Valley Drive, Suite 300
Rolling Hills Estates, CA 90274
ASSIGNMENT
Saba Petroleum, Inc., 3201 Airpark Drive, Suite 201, Santa Maria, CA 93455,
hereinafter referred to as "Assignor", for and in consideration of Ten Dollars
($10.00) and other good and valuable consideration, the receipt and sufficiency
of which are acknowledged, does hereby assign and convey, WITHOUT WARRANTIES OR
COVENANTS OF TITLE. EITHER EXPRESS OR IMPLIED unto Geo Petroleum, Inc., 501 Deep
Valley Drive, Suite 300, Rolling Hills, CA 90274, hereinafter referred to as
"Assignee", a one-third interest in and to the "Assets" described below and in
Exhibit "A" attached hereto and made a part hereof; being one-half of Assignor's
right, title and interest in, to and under the "Assets", as follows:
(a) The oil, gas and other mineral leasehold interests described in Exhibit "A"
attached hereto and made a part hereof, insofar as such cover and affect the
lands, substances and depths described in Exhibit "A";
(b) The wells, equipment and facilities located on the lands described in
Exhibit "A" or for use directly in the operation of the interests described in
Exhibit "A";
(c) Oil, condensate, and gas produced after the Effective Date, inventory,
include "line fill" and inventory below the pipeline connection in tanks,
attributable to the interests described in Exhibit "A";
Exhibit "A";
(d) All contracts and agreements concerning the interests described in
(e) All surface use agreements, easements, rights of way, licenses,
authorizations, permits, and similar rights and interests applicable to, or used
or useful in connection with, any or all of the interests described in Exhibit
"A".
Equipment, wells and personal property located on or used directly in the
operation of the Assets are assigned AS IS AND WHERE IS. AND WITHOUT
WARRANTY OF
MERCHANTABILITY. CONDITION OR MASS FOR A PARTICULAR PURPOSE. EITHER EXPRESS
OR IMPLIES.
From and after the Closing Date, insofar as an interest in the Assets is
conveyed hereby, Assignee agrees to comply with any and all laws, ordinances,
rules and regulations with respect to the Assets whale applicable, ordinances,
laws, rules and regulations governing the plugging of wells, laws or rules
regarding inactive or unplugged wells, including bonding requirements, and the
use of explosive in shooting or pulling of casing and tubing. Assignee agrees
that it shall properly obtain and maintain all permits required by pubes
authorities on the Assets contained herein. Assignee certifies and acknowledges
that it has all the necessary licenses under applicable state and federal law to
accept this assignment of the property.
TO HAVE AND TO HOLD the same unto Assignee, its successors and assigns, forever.
<PAGE>
The terms and conditions contained herein shall constitute covenant. running
with the land, and shall be binding upon, and for the benefit of, the respective
successors and assigns of Assignor and Assignee.
This Assignment is made subject to all of the terms and conditions of that
Agreement for Assignment of Leases by and between Geo Petroleum, Inc. and
Saba Petroleum, Inc. dated December 19, 1996, as amended by that Amendment
to Agreement for Assignment of Leases dated November I, 1997.
This Assignment shall be effective as of November I, 1997 at 7:00 a.m. local
time where the Assets are located.
EXECUTED THIS 1st day of November, 1997.
ASSIGNOR:
SABA PETROLEUM, INC.
A California corporation
By: Ilyas Chaudhary
Title: Chief Executive Officer
ASSIGNEE.
GEO PETROLEUM, INC.
A California corporation
Title: President
State of Oklahoma)
County of Tulsa )
On this 13th day of November, 1997 personally appeared before me, Larry
Burroughs and acknowledged before me, as President of GEO Petroleum, Inc.
My Commission Expires:
May 25, 2000 Lavern Berry Notary Public
CALIFORNIA ALL~PURPOSE ACKNOWLEDGMENT
STATE OF CALIFORNIA
COUNTY OF SANTA BARBARA
On November 13, 1997 before me, Grant Rodges , Notary Public, personally
appeared Ilyas Chaudhary, Chief Executive Officer, Saba Petroleum, Inc. a
California corporation, on behalf of such corporation, and acknowledged to me
that he executed the same in his authorized capacity, and that by his signature
on the instrument the person, or the entity upon behalf of which the person
acted, executed the instrument.
WITNESS my hand and official seal.
Signature
GRANT RODGES
<PAGE>
Exhibit "A"
Attached to and Made Part of
Assignment of Leases Dated, December I, 1996
Ventura Count, California
Vaca Tar Sand Unit Leases
E.E. Lenox, Singe Man
Lessee:
Raleigh P. Trimble, 04-24-34, Book 426 Page: 241, Part of the Rancho el Rio a la
Colonia known as the west 80 acres of the 119.24 acres in subdivisions numbered
53 and 54, lying between the Sturgis Road, the Railroad and the Wolff Road,
containing 80 acres.
John Hollis-Lenox and Alice Lenox
Lessee:
Exeter Oil Company
Ltd and Vaca Oil Company, 06-04-46, Book 777 Page: 232, 39 acres, more or
less, out of subdivision 53 Rancho el Rio de Santa Clara o la Colnia W.R
Livingston
Lessee:
Raleigh P. Trimble, 04-26-34, Book 461 Page: 267, 159.5 acres, more or less
out of subdivision 53 of Rancho el Rio de Santa Clara o la Colonial
Robert S. Livingston and Mayrie Daily Livingston, his wife
Lessee:
Raleigh P. Trimble, 04 26-34, Book 460 Page: 478, Insofar and only insofar as
lease covers 149.10 acres, more or less out of subdivision 53 and 55 of Rancho d
Rio de Santa Clara o la Colonia
<PAGE>
Exhibit "A"
Attached to and Made Part of
Assignment of Leases Dated, December 23, 1996
Ventura County, California
Non-Unit Lease
Lessor
Clarence Hunsucker, J Thomas Hunsucker, and Evelyn Hunsucker, AKA Evelyn
Hunsucker, AKA Eva Newman Hunsucker, Trustees of the Thomas O Hunsucker Faily
Turst, and Clarence W. Hunsucker, as Executor of the Estate of Thomas O
Hunsucker deceased
Lesse:
Sun Operating Limited Partnership, 04-02-86, 86-128442, Parcels B C and D of
Subdivision 55 of the Rancho El Rio De Santa Clara O'La Colonia in the County of
Ventura, State of California according to the map recorded in Book 3 page 112 of
maps in the office of the County Recorder of said county. Together with those
portions of SSturgis Road Pleasant Valley northwesterly and westerly
respectively of the centerline of said roads. EXCEPT that portion of said land
lying northerly of the following described line: Beginning at a point in the
centerline of Wood Road, distant thereon South 0 23' 58" West 1182.96 feet from
the intersection thereof with the westerly prolongation of the northerly line of
subdivision 58 of said Rancho: thence, 1st: North 88 48' 34" West 3376.48 feet
more or less to a point in the westerly lime of said Subdivision 55.
Exhibit 10.50
HAMAR II ASSOCIATES, LLC HAMAR II ASSOCIATES, LLC HAMAR II ASSOCIATES, LLC
214 West Aliso Street
Ojai, Ca. 93023
(805) 646-4276
November 1, 1997
Saba Petroleum Company
3201 Skyway Drive
Santa Maria, Ca. 93455
Attention: Mr. Ilyas Chaudhary.
Re: Behemoth Prospect - Glenn County, California
Gentlemen:
When accepted by Saba Petroleum Company ("SABA") in the manner specified below,
this letter will constitute an agreement between SABA and the undersigned, Hamar
II Associates, LLC, a limited liability company comprised of Mark A. Nahabedian,
Hamm-J, a limited liability company, and Rodney C. Hill ("Hamar") respecting the
exploration and development of the captioned prospect.
Our agreement is as follows:
Acquisition of Oil and Gas Leases and Prospect AreaAcquisition of Oil and
Gas Leases and Prospect AreaAcquisition of Oil and Gas Leases and Prospect
Area
<PAGE>
1. Hamar shall acquire from Black Mountain Oil Company ("BMOC") all of
BMOC's interest in those oil and gas leases covering the "Prospect Area" being
those lands circumscribed by the bordering line on the plat attached hereto as
Exhibit A. BMOC has secured leases purporting to cover approximately 75,000
gross acres of land within the Prospect Area and is continuing to secure
additional leases within the Prospect Area. To the extent that BMOC acquires
other leases within the Prospect Area, such leases will become subject to the
terms of this agreement as a result of Hamar's agreement with BMOC. Under such
agreement, BMOC will not retain any interest in such leases or in the Prospect
Area and any consideration received by it shall come solely from Hamar and not
from SABA. Neither Hamar nor BMOC have made or shall make any warranties or
representations concerning title, environmental conditions, the predicted
results of drilling or other matters concerning this agreement or the activities
to be taken pursuant hereto, it being agreed that SABA shall satisfy itself as
to all such matters, save only that Hamar and BMOC shall warrant that the
interests assigned to SABA are free from liens and encumbrances created by,
through or under either, save as permitted by this agreement.
2. Hamar shall continue to attempt to acquire leases within the
Prospect Area on such terms as it deems acceptable, but will endeavor to
acquire leases at a cost of not more than $5 per acre advanced rental and with
a royalty burden reserved by the lessor of not more than 1/5 of 8/8 of all oil
and gas which may be produced pursuant to the terms of the lease. In addition,
Hamar shall endeavor
to cause its existing leases to be modified by extending the terms thereof and
securing lessor ratifications thereof. Hamar shall continue such efforts until
it has acquired leases (or has renewed or extended the terms of leases) covering
all of the Prospect Area or until such time as the hereinafter described Test
Well has been abandoned as a dry hole. SABA shall refrain from acquiring or
attempting to acquire any leases or other oil and gas interests within the
Prospect Area until the expiration of the period established by the
Confidentiality Agreement dated September __, 1997 between Hamar and SABA. If
the Operating Agreement is effective after such expiration, acquisitions shall
be governed by the terms of the Operating Agreement, but in all circumstances,
Hamar shall be entitled to receive the overriding royalty described in paragraph
4 hereof.
3. SABA shall reimburse Hamar or advance to the lessor under each lease
acquired, renewed, modified or extended in the Prospect Area, two thirds
(2/3rds) of SABA's Participating Interest Share (such 2/3rds reimbursement or
advance being referred to as the "Payment") of the cost of acquiring, modifying,
renewing, extending or otherwise maintaining (including brokerage costs) each
such lease. SABA shall deposit the remaining 1/3rd of its Participating Interest
Share (such 1/3rd amount being hereafter referred to as the "Escrow Amount")
into an escrow account to be maintained by an independent third party or SABA,
whichever Hamar chooses. SABA's Participating Interest Share is defined in
paragraph 9 of this letter. Such payment and deposit of the Escrow Amount shall
be made within fifteen days after receipt of an invoice from Hamar for the
appropriate cost, which invoice shall describe the lease acquired or to be
acquired, including the lands purported to be covered thereby, the royalty
reserved and other material terms of the lease. To the extent feasible, Hamar
shall endeavor to employ the form of lease attached hereto as Exhibit B.
Promptly upon recordation of a lease or a memorandum thereof, Hamar shall notify
SABA thereof in writing and provide a copy of such lease to SABA.
<PAGE>
4. The Nahabedian Group shall be entitled to receive together in the
aggregate with respect to all oil and gas interests subject to this agreement or
hereafter acquired in the Prospect Area during the term of the Operating
Agreement, a gross undivided overriding royalty equal to the positive difference
between seventy-five percent and the net revenue interest in any leases or
interests therein acquired by SABA (but in all cases at least two and one-half
percent), all proportionately reduced to the working interest in such lease or
interest acquired by SABA. To the extent that a lease or interest therein is
conveyed to SABA pursuant to this Agreement, such overriding royalty shall be
reserved or excepted, and if SABA should thereafter acquire any leases or
interests therein in the Prospect Area during the term of the Operating
Agreement or this agreement, whichever later terminates, it shall make an
appropriate recordable conveyance (to the extent that such conveyance has not
theretofore been made) thereof to the members of the Nahabedian Group within ten
days of SABA's acquisition. The Nahabedian Group consists of Mark A. Nahabedian,
Rodney C. Hill, Martin I. Smith, Patrick J. Fazio, Jr., Bradford Johnson, and
Sam Briglio. Notwithstanding anything to the contract provided for herein,
either expressed or implied, no member of the Nahabedian Group as such shall
have any rights under this agreement and the interests in the overriding royalty
to be conveyed to each such person shall be determined solely by Hamar, which
may, from time to time, vary the interest of one or more such persons in the
overriding royalty in any portion of the Contract Area to the extent that a
conveyance has not then been made to such person. Hamar agrees to defend,
indemnify and hold SABA harmless from any claims or assertions made by any such
persons with respect to the overriding royalty, except for SABA's failure to pay
the overriding royalty in accordance with the instrument creating the same.
5. Concurrently with its receipt of the notice given under paragraph 15
of this Agreement, SABA shall pay to Mark A. Nahabedian and Rodney C. Hill, A
Professional Corporation, respectively as to eighty-five percent and fifteen
percent, an amount equal to SABA's Participating Interest Share of One Hundred
Thousand Dollars `($100,000) for geological and other work heretofore done with
respect to the Prospect Area. Neither such payment nor this agreement, shall
give SABA any interests in or rights to geological, geophysical, interpretive or
other data or records of Hamar or any of its affiliates.
6. SABA shall have earned its interest in the Prospect Area if the Test
Well has been drilled to its objective depth and one of the following conditions
exist:
a. If neither SABA, Hamar nor any other working interest owner attempts
the completion of the Test Well, SABA shall have participated in and
paid its Participating Interest Share of the cost of drilling, testing
(not as part of a completion attempt), and abandoning the Test Well as
a dry hole and restoring the site of the Test Well
b. If Hamar or a working interest owner, attempts the completion of the
Test Well, SABA shall also have participated as to its Participating
Interest Share in the completion attempt and if such well is completed
as producible of oil or gas, SABA shall have participated as to its
Participating Interest Share in the testing and equipping through the
well-head in the case of a gas well and through the installation of
temporary tanks in the case of an oil well;
c. If Hamar or another working interest owner, attempts the completion
of the Test Well and it is not productive of oil or gas, SABA shall
also have paid its Participating Interest Share of the costs of the
completion attempt, abandonment and site restoration;
<PAGE>
d. If prior to reaching its Objective Depth, if drilling of the Test
Well is discontinued or the Test Well is abandoned, and Hamar or one of
the working interest owners have not elected to attempt the completion
of the Test Well, SABA shall have participated as to its Participating
Interest Share in the drilling of a Substitute Well.
7. So long as this agreement shall be in effect and prior to earning
its interest as provided in paragraph 6 above, SABA shall pay prior to
delinquency its Participating Interest Share of all delay rentals and other
amounts required to maintain each oil and gas lease in the Prospect Area in good
standing and effect. SABA shall likewise pay to Hamar within fifteen days of
receipt of an invoice therefore, SABA's Participating Share of all reasonable
cost of all title curative work in respect of the Test Well and the drillsite
tract therefore.
8. Should SABA not earn its Participating Share of leases as provided
in this agreement, then within five days of receipt of Hamar's request
therefore, SABA shall furnish Hamar with a recordable acquittance of all of
SABA's rights under this agreement, in the Prospect Area.
Drilling of the Test WellDrilling of the Test WellDrilling of the Test Well
9.When used in this agreement, the terms defined in this paragraph 9
shall have the meanings given to them in this paragraph
SABA's Participating Interest Share shall mean,
a. With respect to the costs referred in paragraphs 2, 3, 5, 6
and 7 thirty percent (30 %) of the cost of the apposite operation;
b. Provided that SABA earns its interest as provided in
paragraph 6, SABA shall have acquired and be assigned, twenty
percent (20%) of all of Hamar's right, title and interest in
the Prospect Area, including the Test Well or the Substitute
Well, subject to the overriding royalties described in
paragraph 4 hereof.
Casing Point means, after having run an electric log in a well
which has reached its objective depth, the point at which an election is made to
attempt to complete the well or abandon the same.
<PAGE>
Complete means, with respect to a well, the performance of
such activities, including setting casing, perforating,
testing, and the installation of such equipment as may be
necessary to render such well capable of producing and
marketing therefrom oil or gas, and includes the installation
of a wellhead and in the case of an oil well, the installation
of temporary tanks, separators, treaters, heaters and other
surface equipment requisite to market oil in the locale.
Operating Agreement means the Operating Agreement attached
hereto as Exhibit B.
Operator means, with respect to the Test Well or a Substitute
therefore, Hamar and means with respect to all operations
subsequent to the completion as a producer of the Test Well or
a Substitute therefore, Amerada Hess Corporation.
Test Well means the exploratory well which is to be drilled in
the Prospect Area pursuant to paragraph 5 of this agreement, and includes a
Substitute Well therefore.
Substitute Well means a well drilled by one or more of the
Working Interest Owners or Hamar to the objective depth of and
in substitution for the Test Well and which is commenced
within thirty days after the abandonment of the Test Well or a
permitted substitute for the Substitute Well.
10. Subject to the provisions of sections 15 and 16 of this agreement, SABA
agrees to participate in the drilling of the Test Well for oil or gas at a
location selected by Hamar in the Prospect Area, which well shall have as its
objective depth such depth as Hamar believes to be sufficient to adequately test
the Leesville Sandstone Formation of Lower Cretaceous Age, which is believed to
underlie the Prospect Area at a depth of approximately 8,000 feet, or such
greater depth, not in excess of 9,500 feet, as to which Hamar and at least one
other Working Interest Owner in the Test Well, believe based upon information
obtained from the well during its drilling is appropriate under the
circumstances then prevailing (the "Test Well"). SABA shall participate in the
drilling of such well as to its Participating Interest Share of the cost
thereof. Attached hereto as Exhibit C is the AFE for the Test Well. If during
the drilling of the Test Well, Hamar determines that the accumulated drilling
(being exclusively the cost of running the rig, providing mud, chemicals and
bits) costs have reached 120% of the AFE cost, Hamar shall notify SABA thereof.
SABA shall have twenty-four hours from its receipt of such notice in which to
elect one of the following options:
a. To continue the drilling of the Test Well, in which case SABA's
Participating Interest Share of the cost of drilling to the objective
depth shall be limited to its Participating Interest Share of 125% of
the AFE cost and two-thirds of its Participating Interest Share of any
additional drilling costs, or
<PAGE>
b. To discontinue participating in the drilling of the Test Well and to
relinquish any potential interest in it and the Prospect Area after
having paid its Participating Interest Share of up to and including
125% of the AFE cost of the Test Well.
11. Attached to this agreement is an Operating Agreement in the form of
AAPL Model 610 (1989 Version), including an incorporated Accounting Procedure in
the form prepared by the Council of Petroleum Accountants Society. Operation of
the Test Well and subsequent operations in the Prospect Area shall be governed
by such Operating Agreement, except to the extent that the same may be
inconsistent with the provisions of this agreement, in which case the latter
shall control. Until such time as SABA shall be entitled to a conveyance of its
Participating Interest Share in leases in the Prospect Area, only the provisions
of Article I, IV A (first paragraph), B.3, V. C., D., VII, X, XI and XIV shall
be applicable.
12. Drilling of the Test Well shall be conducted by Hamar, as
operator. SABA agrees to advance within fifteen days of SABA's receipt of an
invoice therefore, SABA's Participating Interest Share of the AFE cost of
drilling the Test Well, which shall include the cost of setting a string of
intermediate casing at approximately 6,000 feet.
13. Upon reaching the Casing Point in the Test Well, Hamar shall notify
SABA and the other Working Interest Owners thereof by telephone or facsimile
transmission and shall advise SABA of Hamar's recommendation with respect to the
attempted completion or abandonment of the Well. Hamar shall provide SABA with a
copy of any logs and other information concerning the well reasonably available
to Hamar, as specifically requested by SABA. Within twenty-four (24) hours of
such notice, SABA shall elect either to attempt to complete the well or
relinquish its potential interest in the Test Well and the Prospect Area if one
or more of the Working Interest Owners or Hamar attempt the completion of it.
Should one or more of the other Working Interest Owners elect not to attempt the
Completion of the Test Well, Hamar shall have the exclusive right and option to
acquire all or such portion as is available by electing to pay such Working
Interest Owner's share of the cost of the Completion attempt.
14. If the Test Well fails to reach its objective depth, SABA
may propose and cause the drilling within thirty days of the abandonment of the
Test Well, of a Substitute Well at a location acceptable to Hamar with Hamar as
Operator. If such Substitute Well shall be abandoned, SABA may propose the
drilling of a substitute therefore and in like manner may propose the drilling
of substitute wells, with the same effect as if each such Substitute Well were
the Test Well. If the Test Well or a Substitute Well has been completed as a
producer at a depth less than the objective depth, and SABA has paid its share
of the cost of completion at such lesser depth and thereafter participates as to
its Participating Interest Share in the drilling of a Substitute Well which
reaches the objective depth and SABA thereby earns its interest, SABA as of such
date shall have earned an interest in the previously completed well. In the
event a Test Well or Substitute Well has been completed as a producing well at a
depth less than the objective depth and SABA has paid its share of the costs of
a completion at such lesser depth, and thereafter does not participate in the
drilling of a Substitute Well to the objective depth, then SABA will have earned
one-half of the interest specified in paragraph 9.b. in the unit for the
producing well down to 100' below total producing depth.
Other Parties, Conveyance of Interest Earned, MiscellaneousOther Parties,
Conveyance of Interest Earned, MiscellaneousOther Parties, Conveyance of
Interest Earned, Miscellaneous
15. Promptly after securing the agreement of other parties which,
together with SABA, have agreed to bear one hundred percent of the cost of
drilling the Test Well, Hamar shall give SABA written notice of such fact,
together with the names and contact person of each such party. Such notice shall
also specify the intended date for the commencement of drilling in the ground of
the Test Well, which in no event will be greater than 45 days following the date
of the notice. If such notice is not given by December 31, 1997, this agreement
shall terminate and neither party shall have any liability to the other with
respect to this agreement. . Upon receipt of timely notice as provided in this
paragraph 15, SABA shall release the Escrow Amount to Hamar and will thereafter
pay the full Participating Interest Share (consisting of the Payment and the
Escrow Amount) to Hamar. In the event this agreement terminates as provided in
this paragraph 15, Hamar may reimburse SABA for the monies paid under paragraphs
3 and 5 above or assign SABA an undivided 2/3rd of its Participating Interest
Share in the leases acquired or extended pursuant to paragraph 2 above. In
either event, the full value of the proceeds of the escrow account provided for
in paragraph 3 above, including interest, will be released or reimbursed, as the
case may be, to SABA.
16. Promptly after the execution of this letter, Hamar shall commence
an examination of title to the drillsite tract preparatory to the drilling of
the Test Well. Hamar shall furnish to SABA the results of such investigation and
any title curative work which may have been undertaken by Hamar as a result
thereof. Hamar shall not undertake the drilling of the Test Well at its proposed
location unless it has first provided its title information to SABA and SABA,
acting as a reasonable non-operator, has approved of title to the drillsite
tract.
17. Provided that SABA has earned its interest in the Prospect Area
leases as provided in this agreement, promptly after the completion of the Test
Well or the Substitute Well, Hamar shall assign to SABA, the interest in such
area earned by SABA hereunder, without warranty of title, save by, through or
under Hamar, but subject to the overriding royalties herein described. Such
assignment shall be in recordable form.
18. Provided that SABA shall have earned its interest in the Prospect
Area leases as provided in this agreement and a Test Well or Substitute Well has
not been completed as productive of oil or gas on the Prospect Area, either
party may nominate pursuant to the Operating Agreement the drilling of another
well anywhere on the Prospect Area. If a party does not participate in the
drilling of such well and elects to go non-consent pursuant to the Operating
Agreement, the consenting party will determine the non-consent penalty to be
either: (a) surrender to the consenting party all of the non-consenting parties
right, title and interest in the four sections of land (approximately 2,560
acres) surrounding the proposed well as delineated on the well proposal, or (b)
a 500% penalty with respect to the cost of drilling such well and 100% of the
cost of completing and equipping such well. If Hamar shall elect to go
non-consent in such well, Hamar shall be subject to a 500% non-consent penalty
with respect to the cost of drilling such well and 100% of the cost of
completing and equipping such well. In each case, the well must be commenced
before this non-consent provision shall apply and only one well may be nominated
within sixty days of the drilling of the preceding well. The foregoing
provisions shall not affect the overriding royalty held by the Nahabedian Group.
<PAGE>
19. Except as otherwise specifically provided in this agreement, all
communications shall be given by written instrument sent by U.S. Postal Service,
postage prepaid, registered or certified, return receipt requested, by facsimile
transmission, confirmation requested, by commercial overnight carrier or
personally delivered and directed as follows:
If to Hamar:
Hamar II Associates, LLC
214 West Aliso Street
Ojai, California 93023
Facsimile: (805) 646-3476
With a copy to:
Rodney C. Hill, Esq.
2010 Birnam Wood Drive
Santa Barbara, California 93108
Facsimile: (805) 565-5884
If to SABA:
Mr. Ilyas Chaudhary
Saba Petroleum Company
3201 Skyway Drive
Santa Maria, California 93455
Facsimile: (805) 347-1072
or at such other addresses as may have been specified by like notices. All
notices shall be effective, (i) upon receipt, if personally or overnight carrier
delivered, (ii) five (5) business days after deposit in the post as aforesaid,
and (iii) immediately upon receipt of confirmation from the receiving machine if
by facsimile transmission.
20. In any action or proceeding arising out of or related to this
Agreement or any agreement executed pursuant hereto, the prevailing party shall
be entitled to reasonable attorneys' fees, costs and expenses from the
non-prevailing party. This agreement shall be governed by the laws of the State
of California, without regard to principles of conflict of laws.
21. Mark A. Nahabedian, Rodney C. Hill, Rodney C. Hill, A Professional
Corporation and Hamm-J have signed this agreement solely for purpose of
expressing their respective consents to this agreement. Neither of such
signatories assumes any personal liability or obligation, or shall derive
individually any rights, under this agreement.
22. SABA is advised that Hamar intends to enter into an agreement
substantially the same as this with Amerada Hess Corporation covering a portion
of the interest retained by Hamar in the Prospect Area. SABA agrees that to the
extent that such company acquires a portion of the interest retained by Hamar
under this agreement, such company may exercise separately any elections
possessed by Hamar hereunder and that the interest of such company shall be
deemed to be a distinct holding separate from that of Hamar. A provision
substantially identical to this one will be included in the agreement with
Amerada Hess Corporation providing that SABA's interest is separate and distinct
from that of Hamar.
<PAGE>
If the foregoing accurately states our agreement, kindly sign and return
one copy of this letter to the undersigned prior to November 22, 1997,
after which date it may no longer be accepted.
Very truly yours,
HAMAR II ASSOCIATES, LLC
By_________________________
Mark A. Nahabedian, Member
ACCEPTED AND AGREED
TO ON THIS DAY OF NOVEMBER 1997
SABA PETROLEUM COMPANY
By________________________________
______________ its _____President
JOINDER:
For the purpose of expressing their respective consents to the foregoing, the
undersigned have executed a counterpart of this agreement:
- - ---------------------
Mark A. Nahabedian, individually
Rodney C. Hill, A Professional Corporation
By_________________________________
Rodney C. Hill, president and individually
Exhibit "A" - Plat Map of Prospect Area
[graphic omitted]
Exhibit "B" - Form of Lease
California OIL AND GAS LEASE
THIS AGREEMENT, made and entered into as of the 24 day of May 1995, between
the undersigned ---
---------------------------------------------------------------
(and all other parties executing this lease or any counterpart hereof)
hereinafter called "Lessor," and Black Mountain Oil Company hereinafter called
"Lessee,"
1. Lessor for and in consideration of one dollar and other valuable
consideration, receipt and sufficiency of which is hereby acknowledged, and of
the royalties and agreements of the Lessee herein provided, hereby grants; lets
and leases exclusively unto Lessee the land described and included in paragraph
18 hereof and hereinafter referred to as "said land" for the purposes of
exploring and prospecting for (by geological, geophysical, and all other means
whether now known or not), drilling for, producing, saving, taking, owning,
transporting, storing, handling, treating, and processing oil, gas, and all
other hydrocarbons, and all other substances produced herewith, collectively
hereinafter referred to as "said substances," in, on, under or that may be
produced from said land, and hereby grants all rights, privileges and easements
useful or convenient for lessee's operations or, said land, on adjacent or
contiguous lands, and on other lands in the same vicinity, including, but not
limited to, the right to construct, install, maintain, repair, use, replace, and
at any time remove therefrom, roads, bridges, pipelines, tanks, pump and power
stations, power and communication facilities and lines, facilities for surface
and subsurface disposal of produced water and other substances, plants and
structures to treat, process, and transport said substances and products
manufactured therefrom; and the right to drill wells and use Lessee's existing
wells including producing wells to inject gas, water, air or other substances
into the subsurface zones.
2. This lease shall remain in force for a term of six 6 years from the date
hereof, called "primary term," and either as long thereafter as any of said
substances is produced from said land in paying quantities (being quantities
sufficient to pay operating costs) or so long as continuos operations (as
defined in paragraph 5 hereof) are conducted on said land or so long as this
lease is kept in force under any other provision hereof.
3. The consideration expressed in Paragraph 1 covers all rental for the
first ............ year(s) of the primary term. If drilling operations are
not commenced on said land on or before one (1) year(s) from the date
hereof then, subject to the provisions of Paragraph l5 hereof, Lessee shall
pay or tender to Lessor or to Lessor's credit in
...........................................................................
........XXXXXXXXXXXXXXXXXXXXXX.........................................Bank
at.....XXXXXXXXXXXXXXXXXXXXXX. .......................................
____________________ (which bank and Its successors are Lessor's agents and
shall continue as depository for all rentals payable hereunder regardless
of changes in the ownership of said land or of the right to receive
rentals) the sum of Five Dollars..........per acre...........dollars
($5.00/ac.) which shall maintain this lease in force and extend for one
additional year the time within which such operations may be commenced.
Thereafter, annually and in like manner and upon like payments or tender
(all of which are herein called "rentals"), such operations may be deferred
for successive periods of one year each during the primary term. Payments
or tenders of rental may be made by mailing costs, check, or draft to
Lessor or to the depository bank and site date of the mailing shall be
considered the date of payment. Payments or tenders of rentals may be made
by Lesser or by any person or persons on Lessee's behalf, and may be made
jointly to all parties Lessor or to their credit in the depository bank or
such rentals may be tendered or paid separately to each owner or to his
separate credit. From time to time during the primary term, if (a) Lessee
shall drill and abandon a well as being in Lessee's 'opinion incapable of
producing any of said substances and there is at the time of abandonment no
other well so producing, or (b) all production of said substances shall
cease, then Lessee may (subject to provisions of paragraph 5 hereof) the
production of any of said substances 'or the payment of delay rental and in
such event this lease shall remain in full force and effect as though there
had been no interruption in operations, production, or rental payments, as
the case may be. If abandonment under (a) above or the cessation of
production under (b) above occurs more than six months before the next
ensuing anniversary date of this lease, Lessee shall have until such
anniversary date in which to commence or resume operations', production or
rental payments; if such abandonment or cessation of production occurs less
than six months before the next ensuing anniversary date of this lease, the
Lessee shall have until the second ensuing anniversary date in which to
commence or resume operations, production or rental payments; provided,
Lessee shall not have the right under this provision to extend the primary
term of this lease.
4. The term "agreed share" as used herein means.....1/6th.......Royalties to be
paid by Lessee are: (a) on oil, the value of the agreed share of that produced
and saved from said land. It as mutually agreed that the value shall be the
price currently offered or paid by Lessee for oil of like gravity and quality in
the same field. The volume of oil upon which royalty payments are based may be
determined either by metering and sampling or by tank gauges. After such
measurement, all or any part of the oil may be transported to locations on said
land or other lands and commingled with oil from other lands. Lesser may at any
time or times, upon 90 days written notice to lessee, elect to take Lessor's
agreed share of oil in kind, in lieu of such share in value, provided that such
election must be for a period of at least one year, and upon such election,
Lessor's share shall be delivered at the wells into storage furnished by Lessor
or to the credit of Lessor into the pipeline to which the wells may be
connected. If royalty on oil is payable in cash, Lessee may deduct therefrom the
agreed share of the cost of tenting unmerchantable oil produced from the leased
land to render it merchantable. In the event such oil is treated elsewhere than
on the leased land, the lessor's cash royalty shall also bear the agreed share
of the cost of transporting the oil to the treating plant. Nothing herein
contained shall be construed as obligating Lessee to treat oil. If Lessor shall
elect to receive the royalty on oil in kind, it shall be of the same quality as
the oil removed from the leased land for Lessee's own account, and if Lessee's
own oil shall be treated before such removal, Lessor's oil will be treated
therewith before delivery to Lessor, and Lessor, in such event, shall pay a part
equal to the agreed share of the cost of treatment, Lessee may deduct from
Lessor's royalties a part equal to the agreed share of the cost of disposing of
waste water produced with said substances; (b) on gas including casinghead gas
and all gaseous substances produced, saved and sold from said land, the agreed
share of the net proceeds (which shall be the amount realized from such sale
less compressing costs) of the gas so sold; (c) on gas not sold but used off the
premises, the agreed share of the market value at the well of the gas so used.
All or any part of the gas produced from said land may be transported to
locations on said land of other lands and commingled with gas from other lands.
Lessee shall meter such transported gas and such meter readings together with
Lessee's analysis of gasoline content of gas shall furnish the basis for
prorating the amount of gasoline to be credited to said land. Lessee shall not
be accountable to Lessor for gas lost or used or consumed in operations
hereunder. Lessee may produce gas from said land or from lands with which said
land is pooled or unitized in accordance with any method of ratable taking at
any time or from time to time hereafter generally in effect in any pool of which
said land or any portion thereof is a part. In the absence of any such method of
ratable taking, Lessee shall produce from said land or lands pooled or unitized
therewith a fair and equitable proportion of the quantity of gas which it
markets from lands under lease to it in the pool of which said land is a part
Lessee shall be obligated to produce only so much gas as it may be able to
market at the well or wells. When there is no market for gas at the wells,
Lessee's obligation to produce gas shall be suspended: (d) on gasoline extracted
from gas produced on said land, the value of 48% of the agreed share of the
gasoline credited to said land by Lessee. It is mutually agreed that the value
shall be the price currently offered or paid by Lessee for gasoline of like
specifications and quality it' the same vicinity: (e) on any other substance,
the agreed share of the market value at the well.
For all operations hereunder, Lessee may use, free of royalty, oil, gas or other
hydrocarbons and water from said land except water from the Lessor's wells.
However, if Lessee shall use in operations hereunder, fuel, power, or other
substances not obtained from said land, then Lessee shall be entitled to deduct
from the amount of the additional royalty accruing thereby to Lessor the agreed
share of the cost of such substituted fuel, power or other substances: provided,
no deduction hereunder shall exceed the amount of such additional royalty.
When any of said substances, not produced from said land are injected into said
land or land pooled or unitized therewith,, the initial production thereafter of
said substances from any such land shall be free of royalty until the amount of
the said substances produced and saved therefrom shall equal that of said
substances injected therein.
5. Operations as used in paragraphs 2 and 3 hereof means drilling, redrilling,
deepening, any preparatory work for doing any of the foregoing if commenced in
good faith and prosecuted with reasonable diligence, completion or abandonment
work, testing or flowing or other work to determine productivity, secondary
recovery operations or the exercise of any other right given Lessee in paragraph
1 hereof for the purpose of obtaining or resuming production in paying
quantities (as defined in paragraph 2 hereof). Such operations are continuous
when no more than six months elapses between the date on which production ceased
or any of such operations ceased, whichever is the later, and the date on which
further operations are begun or production is commenced or resumed, and this
lease shall remain in full force and effect during each and every six month
period. Production in such paying quantities may be followed of preceded by
continuous operations from time to time for the purpose of keeping this lease in
force in accordance with paragraph 2 hereof.
6. Except as otherwise provided herein, royalty payments shall be computed and
paid monthly. Lessee shall furnish to Lessor monthly written statements of the
production credited or allocated to said land during the preceding calendar
month Royalties payable in money with respect to production credited or
allocated to said land during any calendar month shall be paid not later than
the last day of the next succeeding calendar month. If the amount estimated to
be payable to any party hereto for royalties is less than ten dollars ($10), or
if the amount of oil produced does not justify shipments on a monthly basis,
then Lessee may, upon prior written notice to such party, make such royalty
payments and written statements, on a quarterly, semiannual or annual basis:
provided, however, all sums theretofore accrued and unpaid shall be paid it
least once each calendar year. Royalty payments may be made or tendered to
Lessor or to Lessor's credit in the depository named in Paragraph 3.
7. Lessee shall pay for damages caused by Lessee's operations to existing
houses, barns, fences, and to growing crops and trees. Lessee shall not be
liable to Lessor for damages to any oil and gas reservoir underlying said land
or for the loss of said substances therein or therefrom resulting from its
operations hereunder unless such damage or loss is caused by Lessee's gross
negligence or willful misconduct. Lessee shall have the right at any time during
the term hereof or within a reasonable time thereafter to remove all Lessee's
properties and fixtures, including the right to draw and remove all casing. No
wells shall be drilled closer than one hundred (100') feet to any house or barn
now on said land without the consent of the owner of said house or barn. Lessee
agrees to fill all sump holes and excavations made by it
8. If, during or after the primary term hereof, a well is drilled upon adjacent
property, whether by Lessee or by another party, and the Lessor has no interest
in the production therefrom and the well is located within three hundred thirty
feet of the exterior boundaries of the land at that time included in this lease
and is completed as a producer of oil or gas in commercial quantities and causes
the migration of oil or gas from said land, then Lessee shall (provided it is
not then drilling or has not theretofore drilled an offset well on said land)
within ninety (90) days from the date the owner of such well commences marketing
production therefrom, either commence operations for the drilling of an offset
well on said land of surrender and terminate this lease, in the manner provided
in paragraph 15 hereof, as to a portion of said land, the dimensions of which
said portion shall be equal to the distance of such well from such well from
said exterior boundary. Such surrender shall be limited to the zone or zones
being drained by the well on the adjacent property. Lessee shall never be
required to drill (or surrender in lieu thereof) any offset well which, in
Lessee's opinion, would be incapable of producing said substances in quantities
sufficient to yield a return which, after deducting the of all said substances
to be drained into said land from such zone or zones by existing wells thereon,
would exceed the drilling and operating costs of such offset well.
9. The rights of Lessor and Lessee hereunder may be transferred, in whole or in
part and as to any substance or zone. No change in ownership of Lessor's
interest, however accomplished, shall be binding on Lessee until Lessor has
furnished Lessee with written notice of such change, and then only with respect
to payments thereafter made; such notice to consist of original or certified
copies of all recorded instruments, documents and other information necessary to
establish a complete chain of record title from Lessor, and written instructions
from Lessor and Lessor's transferee directing the disbursement of any payments
which may be made thereafter, No other kind of notice, whether actual or
constructive, shall be binding on Lessee, and in the absence of such notice
Lessee may make payments precisely as if no change had occurred. No present or
future division of Lessor's ownership as to different portions or parcels of
said land shall operate to enlarge the obligations or diminish the rights of
Lessee, and all Lessee a operations, particularly as to division of this lease
the measurement of production may be conducted without regard to any such
division. If all or any part of this lease is assigned, no act or omission of
any leasehold owner shall offset the rights or liabilities of any other such
owner, except that operations or production on any part of said land, whether
assigned or not, shall serve to keep the entire lease in force as though no
assignment had been made, and all payments to Lessor, except royalties or,
actual production, shall be apportioned between assignor and assignee in
proportion to acreage.
10. If any rental or royalty is not paid when due Lessor shall notify Lessee
thereof in writing and this lease shall not terminate unless the Lessee fails to
make such payment within fifteen (15) days after receipt of such written notice,
provided, however, that if there is a dispute as to the amount due and all
undisputed amounts are paid, said l5 day period shall be extended until 5 days
after such dispute is settled by final court decree, arbitration or agreement.
If Lessee fails to make such payment after receipt of such notice within said
period (or such extension thereof), then this lease shall terminate as to the
portion, or portions thereof as to which Lessee is in default.
In the event Lessor considers that Lessee has not complied with any other
covenant, condition or obligation hereunder, either express or implied, Lessor
shall notify Lessee, in writing, setting out specifically in what respects it is
claimed that Lessee has breached this lease, and Lessee shall not be liable to
Lessor for any damages caused by any breach of a covenant, condition,
obligation, express or implied, occurring more than sixty (60) days prior to the
receipt by Lessee of the aforesaid written notice of such breach. The receipt of
such notice by Lessee and the lapse of Sixty (60) days thereafter without Leases
meeting or commencing to meet the alleged breaches shall be a condition
precedent to any action by Lessor for any cause hereunder. Neither the service
of said notice nor the doing of any acts by Lessee aimed to meet all or any of
the alleged breaches shall be deemed an admission or presumption that Lessee has
failed to perform all of its obligations hereunder. This lease shall never be
forfeited or cancelled in whole or in part. either during or after the primary
term hereof, for failure of Lessee to perform any of its express or implied
covenants, conditions, or obligations until it shall have first been finally
judicially determined that such failure exists, and any decree of termination,
cancellation of forfeiture shall be in the alternative and shall provide for
termination, cancellation, or forfeiture unless Lessee comply with the
covenants, conditions, or obligations breached within a reasonable time to be
determined by the Court. No default in the performance of any condition or
obligation hereof shall affect the rights of Lessee hereunder with respect to
any drilling or producing well or wells in regard to which Lessee is not in
default, together with a parcel of forty acres surrounding each oil well then
completed or being drilled and a parcel of six hundred forty acres surrounding
each such gas well then completed or being drilled.
11. If Lessee is prevented or hindered from drilling or conducting other
operations for the purpose of obtaining or restoring production or from
producing said substances by fire, flood, storm, act of God, or any cause beyond
Lessee's control (including, but not limited to governmental law, order or
regulation, labor disputes, war, inability to secure men, materials or,
transportation, inability to secure a market for gas, or an adverse claim to
Lessor's title when Lessor has been notified pursuant to paragraph 14 hereof),
then the performance of any such operations or the production of said substances
shall be suspended during the period of such prevention or hindrance. If such
suspension occurs during the primary term, the payment of delay rental during
such suspension shall be excused and the primary term shall be extended for a
period of time equal to the period of such suspension and this lease shall
remain in full force and effect during each period of suspension and any such
extension of the primary term. Lessee may commence or resume the payment or
tender of rentals in accordance with paragraph 3 hereof after the period of
suspension by paying or tendering within 60 days after the period of suspension
the proportionate part of the rental for the rental year remaining after such
period of suspension. If suspension occurs after the primary term, this lease
shall remain in full force and effect during. such suspension and for a
reasonable time thereafter provided that within such time following the period
of suspension Lessee diligently commences or resumes operations or the
production of said substances. Lessee's obligation to pay royalty on actual
production shall never be suspended under this paragraph. Whenever Lessee would
otherwise be required to surrender any of said land as an alternative to the
performance so suspended, then so long as such performance is suspended by this
paragraph Lessee shall not be required to surrender any portion of said land.
If the permission or approval of any governmental agency is necessary before
drilling operations may be commenced on said land, then if such permission or
approval has been applied for at least 30 days prior to the date upon which such
operations must be commences under the terms hereof, the obligation to commence
such operations shall be suspended until thirty (30) days after the governmental
permit is granted or approval given, or if such permit or approval is denied
initially, then so long as Lessee in good faith appeals from such denial or
conducts further proceedings in an attempt to secure such permit or approval and
thirty days thereafter.
12. For the consideration paid at the time of execution of this agreement and
without any additional consideration to be paid therefor, except provided below,
Lessor hereby grants to Lessee, its successors and assigns, the following
rights, rights of way a easements in, under, upon, through and across said land
which may be exercised at any time or from time to time during the duration of
this lease and as long thereafter Lessee exercises any of the rights granted in
this paragraph: (a) The sole and exclusive right to locate a well or wells on
the surface of said land and to slant drill said well or wells into, under,
across, and through said land and into and under lands other than said land
together with the right to repair, redrill, deepen, maintain, rework and operate
or abandon such well or well's for the production of oil, gas, hydrocarbons, and
other minerals from such other lands together with the right to develop water
from said land for any of Lessee's operations, pursuant to this paragraph and
together with the right to construct, erect. maintain, use, operate, replace,
and remove all pipelines, power lines, telephone lines, tanks, machinery, and
other facilities, together with all other rights necessary or convenient for
Lessee's operations under this paragraph and together with rights of way for
passage over and upon and across and ingress and egress to and from said land;
(b) The sole and exclusive right to drill into and through said land below a
depth of five hundred feet (500') from the surface thereof, by means of a well
or wells drilled from the surface of lands other than said land, and the right
to abandon or repair, redrill, deepen, maintain, rework and operate such well or
wells for the production of oil, gas, hydrocarbons and other minerals from lands
other than said lands.
If Lessee exercises the rights granted by Lessor in Subparagraph (a) hereof,
Lessee shall pay to Lessor an annual rental computed at the rate or one hundred
dollars ($100) per acre for each surface acre of said lands being exclusively
occupied by Lessee pursuant to such grant. If Lessee exercises the rights
granted In Subparagraph (b) hereof thereafter completes a well capable of
producing oil or gas in quantities deemed paying quantities by Lessee, then
Lessee shall within sixty (60) day's after each completion pay Lessor an annual
rental computed at the rate of one dollar ($1) per rod of horizontal projection
of the survey course of that part of the bore hole of such well traversing the
subsurface of such land, provided. however, that Lessor shall not be entitled to
receive any rental under the provisions of this paragraph during such times as
Lessor is entitled to receive royalty or rentals under other provisions of this
lease. Any such rentals shall continue until such well is abandoned. Any well
drilled under the provisions of this paragraph shall be drilled so that the
producing interval thereof shall lie wholly outside the boundary of said land
and Lessor recognizes and agrees that Lessor has no interest in such well or
wells drilled pursuant to this paragraph or any production therefrom.
Any surrender or termination under any other provision of this lease shall be
effective notwithstanding the fact that Lessee in and by such surrender or
termination reserves the rights granted to Lessee under this paragraph, and
regardless of such surrender or termination, the rights granted under this
paragraph shall continue for the term hereinabove granted in this paragraph.
13. Lessee may at any time or times within twenty-one (21) years from the date
hereof without Lessor's joinder or further consent, pool, consolidate or unitize
this lease and said land in whole or in part or as to any zone, with other
lands, mineral interests, and leases in the vicinity thereof so as to constitute
a unit or units whenever such action in Lessee's judgment is required to comply
with applicable laws or to promote or encourage the conservation of natural
resources or the efficient end economical location and spacing of wells,
cycling, pressure-maintenance, repressuring, or secondary recovery programs, or
to join in any cooperative or unit plan of development or operation approved by
State or Federal authorities. The size or shape of any such unit may be changed
at any time or times within twenty one (21) years from the date hereof without
Lessor's joinder or further consent to permit more efficient and economical
operation, to include acreage believed to be productive and to exclude acreage
believed to be unproductive or which is not committed to the unit, but any
increase or decrease in Lessor's royalties resulting from any such change in
such unit shall not be retroactive. Any such unit may be established or changed,
and in the absence of production therefrom may be abolished and dissolved, by
filing for record an instrument so declaring a copy of which shall be delivered
to Lessor or to the depository bank, Drilling or other operation's (as defined
in paragraph 5 hereof) upon, or production of any one of said substances from
any part of such unit shall be treated and considered for all purposes of this
lease as such operations upon or such production from said land, Lessee shall
allocate to the portion of said land included in any such unit a fractional part
of all production from any part of such unit on the same basis as is provided in
the agreement between Lessee and others whereby such unit is established or, in
the absence of such an agreement or of a method of allocation therein, Lessee
shall elect one of the following bases: (a) The ratio between the surface
acreage in this lease included in such unit and the total of all surface acreage
included in such unit; or (b) The ratio between the value, as estimated by
Lessee of recoverable production within the portion of this lease included in
such unit and the total value, as estimated by Lessee, of all recoverable
production within such unit. Lessee may change from one of the aforesaid bases
to the other at any time or times within 21 years from the date hereof without
Lessor's further joinder or consent but any increase or decrease in Lessor's
royalty resulting from any such change shall not be retroactive. No offset
obligation shall accrue under this lease as a result of any well drilled within
any such unit.
14.Lessor warrants and agrees to defend the title to said land. The rentals and
royalties hereinabove provided are determined with respect to the entire mineral
estate, and if Lessor owns a Lessee interest, the rentals and royalties to be
paid Lessor may be reduced proportionately. If the of Lessor covered by this
lease is subject to any outstanding royalties payable to another, such royalties
shall be deducted from Lessor's royalties herein provided. Lessee shall pay all
taxes levied against Lessee's plants, machinery and personal property and all
taxes (except the agreed share thereof) assessed upon mineral rights or assessed
upon or measured by production from or allocated to said land, Lessor shall pay
all other taxes assigned against said land and the agreed share of taxes
attested upon mineral rights and is assessed upon or measured by producing from
or allocated to said land. Lessee may discharge in who in part, on behalf of
Lessor, any tax, mortgage or other lien upon said land, or may redeem due same
from any purchase at any tax sale or adjudication, and may reimburse itself from
any rental and royalties accruing hereunder and shall be subrogated to such lien
with the right to enforce same. Lessee shall have the right to hold or acquire
mineral rights or leases from others claiming any interest in any part of said
land, and to withhold from Lessor payment of rentals and royalties attributable
to any interest so claimed or to any other interest which is subject to adverse
claim, dispute or litigation and the same shall not be due until the ownership
of such interest has been determined, and Lessee shall not thereby be held in
default of any provision hereof or to have disputed Lessor's title. When Lessee
becomes aware of any adverse claim to Lessor's title to said land being asserted
by another, Lessee shall notify Lessor in writing, and upon such notification,
Lessee shall be excused from drilling offset or other wells on or producing from
said lands until such adverse claim has been finally determined . 15. Lessee may
at any time or times surrender this lease or any zone or portion of either
thereof by delivering or mailing a written notice of surrender to Lessor or to
the depository bank and upon such delivery or mailing Lessee shall be relieved
of all obligations as to the portion surrendered, and thereafter all payments to
Lessor provided herein, except royalties on actual production, shall be reduced
in the same proportion that the acreage covered hereby is reduced. If Lessee
surrenders less than all horizons in any portion of this lease the rental as to
such portion shall not be reduced. Within a reasonable time after any such
surrender, Lessee shall file appropriate surrender instruments for record. In
the event this lease is surrendered or assigned as to any zone or portion, then
so long as this lease shall remain in effect as to any other zone or portion
Lessee shall have such rights of way or easements over, under, through, upon and
across the surrendered or assigned zone or portion as shall be necessary or
convenient for Lessee's operations on the retained portion or other lands in the
vicinity thereof.
16. If any of said substances is discovered by Lessee in said land in quantities
deemed paying quantities by Lessee, then Lessee shall keep one string of tools
in continuous operation on said land, allowing not more than, six months to
elapse between completion or abandonment of the first or any succeeding well and
the commencement of operations for the drilling of the next succeeding well
except that if Lessee shall drill on said land a well which in Lessee's opinion
is not capable of producing said substances in paying quantities, then Lessee
may allow not more than one year to elapse between completion and abandonment of
each such well before commencing operations for the next succeeding well. Lesser
shall be given credit for so much of the time its each six month or one year
drilling interval as is not utilized and such credit may be used extend
subsequent drilling intervals in such manner as Lessee may determine. Lessee's
drilling, development and offset obligations under this lease shall be fully
satisfied and discharged when Lessee has drilled and completed or abandoned a
total number of wells on said land, regardless of the buttonhole locations
therein, equal to the nearest whole number obtained by dividing the total
acreage of said land then held hereunder; (a) If oil was discovered, by 40 if no
well is drilled to a depth of more than 8,500 feet below the surface, or by 80
if any well is drilled down to a depth of more than 8,500 feet but not below
13,000 feet below the surface, or by 160 if any well is drilled to a depth of
more than 13,000 feet below the surface, or (b) if any said substances other
that oil was found, by 640; provided however, that Lessee shall be required to
conduct such continuous operations in the event of a discovery of gas, only if
in Lessee's opinion such additional drilling is warranted by existing or
anticipated market requirements for such gas, and in the event of a discovery of
oil, only if the market price in the field for oil of like quality or gravity is
more than One Dollar per barrel at the well.
If both oil and gas are discovered in said land in quantities deemed paying
quantities by Lessee, then Lessee shall drill the number of wells herein
provided for an oil discovery with respect to the portion of said land which in
Lessee's opinion is capable of producing oil in paying quantities and Lessee
shall be entitled to retain all of said lands for the term hereof.
Lessee shall not be required to but may drill more wells on said land than
those herein specified.
17. This lease shall be binding upon all who execute it, whether or not they are
named in the granting clause hereof and whether or not all parties named
granting clause execute this lease. This lease maybe executed in any number of
counterparts and for all purposes hereof all of such counterparts shall be
considered as one lease. All the provisions of this lease shall inure to the
benefit of and be binding upon the heirs, executors, administrators, successors,
and assigns of Lessor and Lessee. 18. The land which is subject to this lease is
situated in the County of Glenn , State of California, and is described as
follows:
SEE EXHIBIT "A" ATTACHED HERETO AND MADE A PART HEREOF
including all accretions thereto and all lakes, streams, canals, waterways,
dikes, roads, streets, alleys, easements and rights of way, on, within, or
adjoining the lands above described and including all strips or parcels of land
contiguous, adjacent to or adjoining the above-described land and owned or
claimed by Lessor. For the purpose of calculating any payments based on acreage,
Lessee, at Lessee's option, may act as if said land and its constituent parcels
contain 2,475.65 acres, whether they actually contain more or less. This lease
shall cover all the interest in said land now owned or hereafter acquired by
Lessor.
IN WITNESS WHEREOF, the parties hereto have executed this agreement.
LESSEE: BLACK MOUNTAIN OIL COMPANY
Bv Patrick J. Fazio, Jr, President
Patrick J. Fazio, Jr, President
LESSOR
Henry D. Altorfer
Mary E. Altorfer
<PAGE>
ADDENDUM
19. Notwithstanding the provisions of Paragraph Three hereof, in the event
Lessor receives a bonafide offer to lease the leased land for oil and gas
exploration during the first year of the 'primary term' of this lease and prior
to Lessee making payment of the rental for the second year of the term hereof,
from a person, firm or corporation primarily in the oil and gas exploration
and/or production business, having a net worth of at least $2,500,000.00, Lessee
within thirty days of receipt of said offer, or copy thereof, shall either:
1. Terminate this lease as provided in Paragraph 15 hereof; OR
2. Tender to Lessor, as additional rental for the first year, the sum of
five dollars per acre, prorated from the date said offer to lease, or copy
thereof, is received by Lessee to the first anniversary date of this lease.
Said offer to lease, or copy thereof, shall be mailed to Lessee by registered or
certified mail, addressed to Lessee at 213 West Aliso Street, Ojai, CA. 93023.
20. Lessee shall not commence drilling operations on the leased land until
it has made the rental payment as provided in paragraph three for the
second year of the term hereof.
EXHIBIT "B"
ATTACHED TO AND MADE A PART OF THOSE CERTAIN PARTICIPATION AGREEMENTS
BETWEEN AMERADA HESS CORPORATION, HAMAR II ASSOCIATES, LLC, AND SABA
PETROLEUM COMPANY DATED NOVEMBER 1, 1997
A.A.P.L. FORM 61O - 1989
MODEL FORM OPERATING AGREEMENT
OPERATING AGREEMENT
DATED
NOVEMBER 1 , 19 97
OPERATOR 1. Hamar II Associates,
LLC for the drilling of the initial test and substitute test (drilling and
completing).
2. Amerada Hess corporation for
post completion of the initial test or substitute test and all subsequent wells.
CONTRACT AREA
Behemoth Prospect as depicted on the plat attached hereto as Exhibit A-1
COUNTY OR PARISH OF Glenn STATE OF California
COPYRIGHT 1989 - ALL RIGHTS RESERVED
AMERICAN ASSOCIATION OF PETROLEUM
LANDMEN, 4100 FOSSIL CREEK BLVD.
FORT WORTH, TEXAS, 76137, APPROVED FORM.
A.A.P.L. NO. 610 1989
A.A.P.L FORM 610- MODEL FORM OPERATING AGREEMENT - 1989~
<PAGE>
A.A.P.L. FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
TABLE OF CONTENTS
Article Title Page
I. DEFINITIONS
II. EXHIBITS I
III. INTERESTS OF PARTIES 2
A. OIL AND GAS INTERESTS 2
B. INTERESTS OF PARTIES IN COSTS AND PRODUCTION: 2
C. SUBSEQUENTLY CREATED INTERESTS 2
IV. TITLES 2
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A. TITLE EXAMINATION 2
B. LOSS OR FAILURE OF TITLE: 3
1. Failure of Title 3
2. Loss by Non-Payment or Erroneous Payment of Amount Due 3
3. Other Losses 3
4. Curing Title 3
V. OPERATOR 4
A. DESIGNATION AND RESPONSIBILITIES OF OPERATOR 4
B. RESIGNATION OR REMOVAL OF OPERATOR AND SELECTION OF SUCCESSOR 4
1. Resignation or Removal of Operator 4
2. Selection of Successor Operator 4
3. Effect of Bankruptcy 4
C. EMPLOYEES AND CONTRACTORS: 4
D. RIGHTS AND DUTIES OF OPERATOR 4
I. Competitive Rates and Use of Affiliates 4
2. Discharge of Joint Account Obligations 4
3. Protection from Liens 4
4. Custody of Funds 5
5. Access to Contract Area and Records 5
6. Filing and Furnishing Governmental Reports 5
7. Drilling and Testing Operations 5
8. Cost Estimates 5
9. Insurance 5
VI DRILLING AND DEVELOPMENT 5
A. INITIAL WELL: 5
B. SUBSEQUENT OPERATIONS' 5
I. Proposed Operations 5
2. Operations by Less Than All Parties 6
3. Stand-By Costs 7
4. Deepening 8
5. Sidetracking 8
6. Order of Preference of Operations 8
7. Conformity to Spacing Pattern 9
8. Paying Wells 9
C. COMPLETION OF WELLS; REWORKING AND PLUGGING BACK' 9
1. Completion 9
2. Rework, Recomplete or Plug Back 9
D. OTHER OPERATIONS' 9
E. ABANDONMENT OF WELLS: 9
1. Abandonment of Dry Holes 9
2. Abandonment of Wells That Have Produced 10
3. Abandonment of Non-Consent Operations 10
F. TERMINATION OF OPERATIONS' 10
G. TAKING PRODUCTION IN KIND 10
(Option 1) Gas Balancing Agreement 10
(Option 2) No Gas Balancing Agreement 11
VII. EXPENDITURES AND LIABILITY OF PARTIES 11
-------------------------------------
A. LIABILITY OF PARTIES: 11
B. LIENS AND SECURITY INTERESTS .11
C. ADVANCES: .12
D. DEFAULTS AND REMEDIES' 12
1. Suspension of Rights
2. Suit for Damages 13
3. Deemed Non-Consent 13
4. Advance Payment 13
5. Costs and Attorneys' Fees 13
E. RENTALS, SHUT-IN WELL PAYMENTS AND MINIMUM ROYALTIES 13
F. TAXES: 13
VIII. ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST 14
--------------------------- --------------------
A. SURRENDER OF 1.EASES' 14
B. RENEWAL OR EXTENSION OF LEASES: 14
C. ACREAGE OR CASH CONTRIBUTIONS: 14
<PAGE>
A.A.P.L. FORM 610- MODEL FORM OPERATING AGREEMENT 1989
TABLE OF CONTENTS
D. ASSIGNMENT; MAINTENANCE OF UNIFORM INTEREST 15
E. WAIVER OF RIGHTS TO PARTITION: 15
F. PREFERENTIAL RIGHT TO PURCHASE 15
IX. INTERNAL REVENUE CODE ELECTION 15
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X. CLAIMS AND LAWSUITS 15
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XI. FORCE MAJEURE 16
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XII. NOTICES 16
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XIII. TERM OF AGREEMENT ........................................ 16
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XIV. COMPLIANCE WITH LAWS AND REGULATIONS 16
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A. LAWS, REGULATIONS AND ORDERS'. 16
B. GOVERNING LAW: 16
C. REGULATORY AGENCIES: .......................... 16
XV. MISCELLANEOUS 17
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A. EXECUTION: 17
B. SUCCESSORS AND ASSIGNS'. 17
C. COUNTERPARTS: 17
D. SEVERABILITY: 17
XVI.: OTHER PROVISIONS: 17
<PAGE>
A.A.P.L. FORM 610 MODEL FORM OPERATING AGREEMENT - 1989
OPERATING AGREEMENT
THIS AGREEMENT, entered into by and between AMERADA HESS CORPORATION hereinafter
designated and referred to as "Operator," and the signatory party or parties
other than Operator, sometimes hereinafter referred to individually as
"Non-Operator," and collectively as "Non-Operators." WITNESSETH: WHEREAS, the
parties to this agreement are owners of Oil and Gas Leases and/or Oil and Gas
Interests in the land identified in Exhibit "A," and the parties hereto have
reached an agreement to explore and develop these Leases and/or Oil and Gas
Interests for the production of Oil and Gas to the extent and as hereinafter
provided, NOW, THEREFORE, it is agreed as follows:
ARTICLE I.
DEFINITIONS
A. As used in this agreement, the following words and terms shall have the
meanings here ascribed to them: . The term "AFE" shall mean an Authority
for Expenditure prepared by a party to this agreement for the purpose of
estimating the costs to be incurred in conducting an operation hereunder.
B. The term "Completion" or "Complete" shall mean a single operation intended to
complete a well as a well capable of producing of Oil and Gas in one or more
Zones, including, but not limited to, the setting of production casing,
perforating, well stimulation and production testing conducted in such
operation.
C. The term "Contract Area" shall mean all of the lands, Oil and Gas Leases
and/or Oil and Gas Interests intended to be developed and operated for Oil
and Gas purposes under this agreement. Such lands, Oil and Gas Leases and
Oil and Gas Interests are described in Exhibit "A.
D. The term "Deepen" shall mean a single operation whereby a well is
drilled to an objective Zone below the deepest Zone in which the well was
previously drilled, or below the Deepest Zone proposed in the associated
AFE, whichever is the lesser. E. The terms "Drilling Party" and "Consenting
Party" shall mean a party who agrees to join in and pay its share of the
cost of any operation conducted under the provisions of this agreement.
F. The term "Drilling Unit" shall mean the area fixed for the drilling of one
well by order or rule of any state or federal body having authority. If a
Drilling Unit is not fixed by any such rule or order, a Drilling Unit shall be
the drilling unit as established by the pattern of drilling in the Contract Area
unless fixed by express agreement of the Drilling Parties.
G. The term "Drillsite" shall mean the Oil and Gas Lease or Oil and Gas
Interest on which a proposed well is to be located.
H. The term "Initial Well" shall mean the well required to be drilled by the
parties hereto as provided in Article VI.A.
I. The term "Non-Consent Well" shall mean a well in which less than all parties
have conducted an operation as provided in Article VI.B.2.
J. The terms "Non-Drilling Party" and "Non-Consenting Party" shall mean a party
who elects not to participate in a proposed operation.
K. The term "Oil and Gas" shall mean oil, gas, casinghead gas, gas
condensate, and/or all other liquid or gaseous hydrocarbons and other
marketable substances produced therewith, unless an intent to limit the
inclusiveness of this term is specifically stated.
L. The term "Oil and Gas Interests" or "Interests" shall mean unleased fee
and mineral interests in Oil and Gas in tracts of land lying within the
Contract Area which are owned by parties to this agreement.
M. The terms "Oil and Gas Lease," "Lease" and "Leasehold" shall mean the
oil and gas leases or interests therein covering tracts of land lying
within the Contract Area which are owned by the parties to this agreement.
N. The term "Plug Back" shall mean a single operation whereby a deeper Zone
is abandoned in order to attempt a Completion in a shallower Zone.
0. The term "Recompletion" or "Recomplete" shall mean an operation whereby
a Completion in one Zone is abandoned in order to attempt a Completion in a
different Zone within the existing wellbore.
P. The term "Rework" shall mean an operation conducted in the wellbore of a well
after it is Completed to secure, restore, or improve production in a Zone which
is currently open to production in the wellbore. Such operations include, but
are not limited to, well stimulation operations but exclude any routine repair
or maintenance work or drilling, Sidetracking, Deepening, Completing,
Recompleting, or Plugging Back of a well.
Q. The term "Sidetrack" shall mean the directional control and intentional
deviation of a well from vertical so as to change the bottom hole location
unless done to straighten the hole or to drill around junk in the hole to
overcome other mechanical difficulties.
R. The term "Zone" shall mean a stratum of earth containing or thought to
contain a common accumulation of Oil and Gas separately producible from any
other common accumulation of Oil and Gas.
** Unless the context otherwise clearly indicates, words used in the
singular include the plural, the word "person" includes natural and
artificial persons, the plural includes the singular, and any gender
includes the masculine, feminine, and neuter.
ARTICLE II.
EXHIBITS
The following exhibits, as indicated below and attached hereto, are incorporated
in and made a part hereof:
X A. Exhibit "A," shall include the following information:
(1) Description of lands subject to this agreement,
(2) Restrictions, if any, as to depths, formations, or substances,
(3) Parties to agreement with addresses and telephone numbers for notice
purposes,
(4) Percentages or fractional interests of parties to this agreement,
(5) Oil and Gas Leases and/or Oil and Gas Interests subject to this agreement,
(6) Burdens on production.
B. Exhibit "A-1" - Plat of Contract Area
X C. Exhibit "C," Accounting Procedure.
- - -
X D. Exhibit "D," Insurance.
X E. Exhibit "E," Gas Balancing Agreement.
X F. Exhibit "F," Non- Discrimination and Certification of Non-Segregated
Facilities. -
X G. Exhibit "G," Tax Partnership.
X H.Other: Memorandum of Operating Agreement and Financing Statement
---------------------------------------------------------
X I. Other: Well Requirements
- - -
* Except to the extent Hamar II Associates, LLC shall be Operator on a temporary
basis under the terms of that certain Agreement between Amerada Hess Corporation
and Hamar II Associates, LLC dated November 1,1997. The term Participation
Agreement" means the several agreements in substantially the same form, each
dated November 1, 1997, among Hamar II Associates LLC, and Amereda Hess
Corporation.
<PAGE>
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989
If any provision of any exhibit, except Exhibits "E and "F" is inconsistent
with any provision contained in the body of this agreement, the provisions in
the body of this agreement shall prevail.
ARTICLE III.
INTERESTS OF PARTIES
A. Oil and Gas lnterests:Except as provided in the Participation Agreement,
the parties to this agreement own no Oil and Gas Interests in the Contract
Area.
B. Interests of Parties in Costs and Production: Except for
the Test Well and any Substitute Test Well as provided in the
Participation Agreement, unless changed by other provisions, all
costs and liabilities incurred in operations under this agreement
shall be borne and paid, and all equipment and materials acquired
in operations on the Contract Area shall be owned, by the parties
as their interests are set forth in Exhibit "A." In the same
manner, the parties shall also own all production of Oil and Gas
from the Contract Area subject, however, to the payment of
royalties and other burdens on production as described hereafter.
Regardless of which party has contributed any Oil and Gas Lease or Oil and Gas
Interest on which royalty or other burdens may be payable and except as
otherwise expressly provided in this agreement, Operator shall pay or deliver,
or cause to be paid or delivered, all burdens shown on Exhibit "A". Except as
otherwise expressly provided in this agreement, if any party has contributed
hereto any Lease or Interest which is burdened with any royalty, overriding
royalty, production payment or other burden on production in excess of the
amounts stipulated above, such party so burdened shall assume and alone bear all
such excess obligations and shall indemnify, defend and hold the other parties
hereto harmless from any and all claims attributable to such excess burden.
Nothing contained in this Article III.B. Shall be deemed an assignment or
cross-assignment of interests covered hereby, and in the event two or more
parties contribute to this agreement jointly owned Leases, the parties'
undivided interests in said Leaseholds shall be deemed separate leasehold
interests for the purposes of this agreement. C. Subsequently Created Interests:
If any party has contributed hereto a Lease or Interest that is burdened with an
assignment of production given as security for the payment of money, or if,
after the date of this agreement, any party creates an overriding royalty,
production payment, net profits interest, assignment of production or other
burden payable out of production attributable to its working interest hereunder,
such burden shall be deemed a "Subsequently Created Interest." Further, if any
party has contributed
hereto a Lease or Interest burdened with an overriding royalty, production
payment, net profits interest, or other burden payable out of production created
prior to the date of this agreement, and such burden is not shown on Exhibit
"A," such
burden also shall be deemed a Subsequently Created Interest to the extent such
burden causes the burdens on such party's Lease or Interest to exceed the amount
stipulated in Article llI.B. above. The party whose interest is burdened with
the Subsequently Created Interest (the "Burdened Party") shall assume and alone
bear, pay and discharge the Subsequently Created Interest and shall indemnify,
defend and hold harmless the other parties from and against any liability
therefor. Further, if the Burdened Party fails to pay, when due, its share of
expenses chargeable hereunder, all provisions of Article VII.B. shall be
enforceable against the Subsequently Created Interest in the same manner as they
are enforceable against the working interest of the Burdened Party. If the
Burdened Party is required under this agreement to assign or relinquish to any
other party, or parties, all Or a portion of its working interest and/or the
production attributable thereto, said other party, or parties, shall receive
said assignment and/or production free and clear of said Subsequently Created
Interest, and the Burdened Party shall indemnify, defend and hold harmless said
other party, or parties, from any and all claims and demands for payment
asserted by owners of the Subsequently Created Interest.
ARTICLE IV.
TITLES
A. Title Examination:
Title examination shall be made on the Drillsite of any proposed well prior to
commencement of drilling operations and, if a majority in interest of the
Drilling Parties so request or Operator so elects, title examination shall be
made on the entire Drilling Unit, or maximum anticipated Drilling Unit, of the
well. The opinion will include the ownership of the working interest, minerals,
royalty, overriding royalty and production payments under the applicable Leases.
Each party contributing Leases and/or Oil and Gas Interests to be included in
the Drillsite or Drilling Unit, if appropriate, shall furnish to Operator all
abstracts (including federal lease Status reports), title opinions, title papers
and curative material in its possession free of charge. All such information not
in the possession of or made available to Operator by the parties, but necessary
for the examination of the title, shall be obtained by Operator. Operator shall
cause title to be examined by attorneys on its staff or by outside attorneys.
Copies of all title opinions shall be furnished to each Drilling l)arty. Costs
incurred by Operator in procuring abstracts, fees paid outside attorneys for
title examination (including preliminary, supplemental, shut-in royalty opinions
and division order title opinions) and other direct charges as provided in
Exhibit "C" shall be borne by the Drilling Parties in the proportion that the
interest of each Drilling Party bears to the total interest of all Drilling
Parties as such interests appear in Exhibit "A." Operator shall make no charge
for services rendered by its staff attorneys or other personnel in the
performance of the above functions.
* shall be responsible for securing curative matter and pooling amendments
or agreements required in
connection with leases ** Operator shall be responsible for the preparation
and recording of pooling designations or declarations and communitization
agreements as well as the conduct of hearings before governmental agencies
for the securing of spacing or pooling orders or any other orders necessary
or appropriate the conduct of operations hereunder. This shall not prevent
any party from appearing on its own behalf at such hearings.
Costs incurred by Operator, including fees paid to outside attorneys, which
are associated with hearings before governmental agencies, and which costs
are necessary and proper for the activities contemplated tinder this
agreement, shall be direct charges to the joint account and shall not be
covered by the administrative overhead charges as provided in Exhibit "C."
* Operator
** subject to this agreement
Page 2
<PAGE>
A.A.P.L FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989
Operator shall make no charge for services rendered by its
staff attorneys or other personnel in the performance of the above functions.
No well shall be drilled on the Contract Area until after (1) the title to
the Drillsite or Drilling Unit, if appropriate, has been examined as above
provided. and (2) the title has been approved by the examining attorney or
title has been accepted by all of the Drilling Parties in such well.
<deleted items>
3. Other Losses: .All losses of Leases or Interests committed to this
agreement, shall be joint losses and shall be borne by all parties in
proportion to their interests shown on Exhibit "A." This shall include but
not be limited to the loss of any Lease or Interest through failure to
develop or because express or implied covenants have not been performed
(other than performance which requires only the payment of money), and the
loss of any Lease by expiration at the end of its primary term if it is not
renewed or extended. There shall be no readjustment of interests in the
remaining portion of the Contract Area on account of any joint loss.
3
<PAGE>
A.A.P.L FORM 610 MODEL FORM OPERATING AGREEMENT - 1989
ARTICLE V.
OPERATOR
A. Designation and Responsibilities of Operator:
Amereda Hess Corporation ** shall be the Operator of the Contract Area, and
shall conduct and direct and have full control of all operations on the Contract
Area as permitted and required by, and within the limits of this agreement. In
its performance of services hereunder for the Non-Operators, Operator shall be
an independent contractor not subject to the control or direction of the
Non-Operators except as to the type of operation to be undertaken in accordance
with the election procedures contained in this agreement. Operator shall not be
deemed, or hold itself out as, the agent of the Non-Operators with authority to
bind them to any obligation or liability assumed or incurred by Operator as to
any third party. Operator shall conduct its activities under this agreement as a
reasonable prudent operator, in a good and workmanlike manner, with due
diligence and dispatch, in accordance with good oilfield practice, and in
compliance with applicable law and regulation, but in no event shall it have any
liability as Operator to the other parties their officers, employees and/or
agent except such as may result from gross negligence or willful misconduct.
B. Resignation or Removal of Operator and Selection of Successor:
1. Resignation or Removal of Operator: Operator may resign at any time by giving
written notice thereof to Non-Operators. If Operator terminates its legal
existence, no longer owns an interest hereunder in the Contract Area, or is no
longer capable of serving as Operator, Operator shall be deemed to have resigned
without any action by Non-Operators, except the selection of a successor.
Operator may be removed only for good cause by the affirmative vote of
Non-Operators owning a majority interest based on ownership as shown on Exhibit
"A" remaining after excluding the voting interest of Operator; such vote shall
not be deemed effective until a written notice has been delivered to the
Operator by a Non-Operator detailing the alleged default in, Operator has failed
to cure the default within thirty (30) days from its receipt of the notice or,
if the default concerns an operation then being conducted, within forty-eight
(48) hours of its receipt of the notice. For purposes hereof, "good cause" shall
mean not only gross negligence or willful misconduct but also the material
breach of or inability to meet the standards ,of operation contained in Article
V.A. or material failure or inability to perform its obligations tinder this
agreement.
Subject to Article VII.D.1., such resignation or removal shall not become
effective until 7:00 o'clock A.M. on the first day of the calendar month
following the expiration of ninety (90) days after the giving of notice of
resignation by Operator or action by the Non-Operators to remove Operator,
unless a successor Operator has been selected and assumes the duties of Operator
at an earlier date. Operator, after effective date of resignation or removal,
shall be bound by the terms hereof as a Non-Operator. A change of a corporate
name or structure of Operator or transfer of Operator's interest to any single
subsidiary, parent or successor corporation shall not be the basis for removal
of Operator.
2. Selection of Successor Operator: Upon the resignation or removal of Operator
under any provision of this agreement, a successor Operator shall be selected by
the parties. The successor Operator shall be selected from the parties owning an
interest in the Contract Area at the time such successor Operator is selected.
*The successor Operator shall be selected by the affirmative vote of two (2) or
more parties owning a majority interest based on ownership as shown on Exhibit
"A" provided, however, if an Operator which has been removed or is deemed to
have resigned fails to vote or votes only to succeed itself, the successor
Operator shall be selected by the affirmative vote of the party or parties
owning a majority interest based on ownership as shown on Exhibit "A" remaining
after excluding the voting interest of the Operator that was removed or
resigned. The former Operator shall promptly deliver to the successor Operator
all records and data relating to the operations conducted by the former Operator
to the extent such records and data are not already in the possession of the
successor operator. Any cost of obtaining or copying the former Operator's
records and data shall be charged to the joint account.
3. Effect of Bankruptcy: If Operator becomes insolvent, bankrupt or is placed in
receivership, it shall be deemed to have resigned without any action by
Non-Operators, except the selection of a successor. If a petition for relief
under the federal bankruptcy laws is filed by or against Operator, and the
removal of Operator is prevented by the federal bankruptcy court, all
Non-Operators and Operator shall comprise an interim operating committee to
serve until Operator has elected to reject or assume this agreement pursuant to
the Bankruptcy Code, and an election to reject this agreement by Operator as a
debtor in possession, or by a trustee in bankruptcy, shall be deemed a
resignation as Operator without any action by Non-Operators, except the
selection of a successor. During the period of time the operating committee
controls operations, all actions shall require the approval of two (2) or more
parties owning a majority interest based on ownership as shown on Exhibit "A."
In the event there are only two (2) parties to this agreement, during the period
of time the operating committee controls operations, a third party acceptable to
Operator, Non-Operator and the federal bankruptcy court shall be selected ,as a
member of the operating committee, and all actions shall require the approval of
two (2) members of the operating committee without regard for their interest in
the Contract Area based on Exhibit "A."
C. Employees and Contractors:
The number of employees or contractors used by Operator in conducting operations
hereunder, their selection, and the hours of labor and the compensation for
services performed shall be determined by Operator, and all such employees or
contractors shall be the employees or contractors of Operator.
D. Rights and Duties of Operator:
I. Competitive Rates and Use of Affiliates: All wells drilled on the Contract
Area shall be drilled on a competitive contract basis at the usual rates
prevailing in the area. If it so desires, Operator may employ its own tools and
equipment in the drilling of wells, but its charges therefor shall not exceed
the prevailing rates in the area and the rate of such charges shall be agreed
upon by the parties in writing before drilling operations are commenced, and
such work shall be performed by Operator under the same terms and conditions as
are customary and usual in the area in contracts of independent contractors who
are doing work of a similar nature. All work performed or materials supplied by
affiliates or related parties of Operator shall be performed or supplied at
competitive rates, pursuant to written agreement, and in accordance with customs
and standards prevailing in the industry.
Discharge of Joint Account Obligations: Except as herein otherwise
specifically provided, Operator shall promptly pay
and discharge expenses incurred in the development and operation of the
Contract Area pursuant to this agreement and shall
charge each of the parties hereto with their respective proportionate shares
upon the expense basis provided in Exhibit "C."
Operator shall keep an accurate record of the joint account hereunder, showing
expenses incurred and charges and credit made and received.
3, Protection from Liens: Operator shall pay, or cause to be paid, as and when
they become due and payable, all accounts
of contractors and suppliers and wages and salaries for services rendered
or performed, and for materials supplied on, to or in
respect of the Contract Area or any operations for the joint account
thereof, and shall keep the Contract Area free from
*In the event only two (2) parties then own an interest in the Contract Area,
the other party shall be the successor Operator.
**The provisions of this Article V shall apply to Hamar II Associates, LLC
during such period Hamar II Associates, LLC is operator under the terms of that
certain Agreement. between Amerada Hess Corporation.
<PAGE>
A.A.P.L FORM 61O - MODEL FORM OPERATING AGREEMENT - 1989
liens and encumbrances resulting therefrom except for those resulting from a
bona fide dispute as to services rendered or materials supplied. 4. Custody of
Funds: Operator shall hold for the account of the Non-Operators any funds of the
Non-Operators advanced or paid to the Operator, either for the conduct of
operations hereunder or as a result of the sale of production from the Contract
Area, and such funds shall remain the funds of the Non-Operators on whose
account they are advanced or paid until used for their intended purpose or
otherwise delivered to the Non-Operators or applied toward the payment of debts
as provided in Article VIl.B. Nothing in this paragraph shall be construed to
establish a fiduciary relationship between Operator and Non-Operators for any
purpose other than to account for Non-Operator funds as herein specifically
provided. Nothing in this paragraph shall require the maintenance by Operator of
separate accounts for the funds of Non-Operators unless the parties otherwise
specifically agree. 5. Access to Contract Area and Records: Operator shall,
except as otherwise provided herein, permit each Non-Operator or its duly
authorized representative, at the Non-Operator's sole risk and cost, full and
free access at all reasonable times to all operations of every kind and
character being conducted for the joint account on the Contract Area and to the
records of operations conducted thereon or production therefrom, including
Operator's books and records relating thereto. Such access rights shall not be
exercised in a manner interfering with Operator's conduct of an operation
hereunder and shall not obligate Operator to furnish any geologic or geophysical
data of an interpretive nature unless the cost of preparation of such
interpretive data was charged to the joint account. Operator will furnish to
each Non-Operator upon request copies of any and all reports and information
obtained by Operator in connection with production and related items, including,
without limitation, meter and chart reports, production purchaser statements,
run tickets and monthly gauge reports, but excluding purchase contracts and
pricing information to the extent not applicable to the production of the
Non-Operator seeking the information. Any audit of Operator's records relating
to amounts expended and the appropriateness of such expenditures shall be
conducted in accordance with the audit protocol specified in Exhibit "C." 6.
Filing and Furnishing Governmental Reports: Operator will file, and upon written
request promptly furnish copies to each requesting Non-Operator not in default
of its payment obligations, all operational notices, reports or applications
required to be filed by local, State, Federal or Indian agencies or authorities
having jurisdiction over operations hereunder. Each Non-Operator shall provide
to Operator on a timely basis all information necessary to Operator to make such
filings. 7. Drilling and Testing Operations: The following provisions shall
apply to each well drilled hereunder, including but not limited to the Initial
Well: (a) Operator will promptly advise Non-Operators of the date on which the
well is spudded, or the date on which drilling operations are commenced. (b)
Operator will send to Non-Operators such reports, test results and notices
regarding the progress of operations on the well as the Non-Operators shall
reasonably request, including, but not limited to, daily drilling reports,
completion reports, and well logs. (c) Operator shall adequately test all Zones
encountered which may reasonably be expected to be capable of producing Oil and
Gas in paying quantities as a result of examination of the electric log or any
other logs or cores or tests conducted hereunder. 8. Cost Estimates: Upon
request of any Consenting Party, Operator shall furnish estimates of current and
cumulative costs incurred for the joint account at reasonable intervals during
the conduct of any operation pursuant to this agreement. Operator shall not be
held liable for errors in such estimates so long as the estimates are made in
good faith. 9. Insurance: At all times while operations are conducted hereunder,
Operator shall comply with the workers compensation law of the state where the
operations are being conducted, provided, however, that Operator may be a
self-insurer for liability under said compensation laws in which event the only
charge that shall be made to the joint account shall be as provided in Exhibit
"C." Operator shall also carry or provide insurance for the benefit of the joint
account of the parties as outlined in Exhibit '~D" attached hereto and made a
part hereof. Operator shall require all contractors engaged in work on or for
the Contract Area to comply with the workers compensation law of the state where
the operations are being conducted and to maintain such other insurance as
Operator may require. In the event automobile liability insurance is specified
in said Exhibit "D," or subsequently receives the approval of the parties, no
direct charge shall be made by Operator for premiums paid for such insurance for
Operator's automotive equipment. ARTICLE VI. DRILLING AND DEVELOPMENT
A. Initial Well:
On or before the 15th day of February , 19 98 , Operator shall commence the
drilling of the Initial Well at the following location: Section 22, T22N,
R5W, Glenn County, California. --------- -------------------
and shall thereafter continue the drilling of the well with due
diligence to 8,000' or to a depth sufficient to test the
Leesville Sandstone Formation of lower cretaceous age, whichever
is lesser, but in no event deeper than 9500'.
The drilling of tile Initial Well and (be participation therein by all parties
is obligatory, subject to Article VI.Cl. as to participation in Completion
operations and Article VI.F. as to termination of operations and Article Xl as
to occurrence of force majeure.
B. Subsequent Operations:
1. Proposed Operations: If any party hereto should desire to drill any well on
the Contract Area other than the Initial Well, or if any party should desire to
Rework, Sidetrack, Deepen, Recomplete or Plug Back a dry hole or a well no
longer capable of producing in paying quantities in which such party has not
otherwise relinquished its interest it' the proposed objective Zone under this
agreement, the party desiring to drill, Rework, Sidetrack, Deepen, Recomplete or
Plug Back such a well shall give written notice of the proposed operation to the
parties who have not otherwise relinquished their interest in such objective
Zone
- - -5-
<PAGE>
A.A.P.L FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
under this agreement and to all other parties in the case of a proposal
for Sidetracking or Deepening, specifying the work to be
performed, the location, proposed depth, objective Zone and the
estimated cost of the operation. The Parties to whom such a
notice is delivered shall have thirty (30) days after receipt of the notice
within which to notify the party proposing to do the work whether they elect
to participate in the cost of the proposed operation. If a drilling rig is
on location, notice of a proposal to
Rework, Sidetrack, Recomplete, Plug Back or Deepen may be given
by telephone and the response period shall be limited to
forty-eight (48) hours, exclusive of Saturday. Sunday and legal
holidays. Failure of a party to whom such notice is delivered to
reply within the period above fixed shall constitute an election
by that party not to participate in the cost of the proposed
operation. Any proposal by a party to conduct an operation
conflicting with the operation initially proposed shall be
delivered to all Parties
within the time and in the manner provided in Article XVI.D.
If all parties to whom such notice is delivered elect to participate in such a
proposed operation, the parties shall be
contractually committed to participate therein provided such operations are
commenced within the time period hereafter set 12 forth, and Operator
shall, no later than ninety (90) days after expiration of the notice period
of thirty (30) days (or as promptly as practicable after the expiration of
the forty-eight (48) hour
period when a drilling rig is on location, as the case may be),
actually commence the proposed operation and thereafter complete
it with due diligence at the risk and expense of the parties
participating therein; provided. however, said commencement date
may be extended upon written notice of same by Operator to the
other parties, for a period of up to thirty (30) additional days
if, in the sole opinion of Operator, such additional time is
reasonably necessary to obtain permits from governmental
authorities, surface rights (including rights-of-way) or
appropriate drilling equipment. or to complete title examination
or curative matter required for title approval or acceptance. If
the actual operation has not been commenced within the time
provided (including any extension thereof as specifically
permitted herein or in the force majeure provisions of Article
Xl) and if any party hereto still desires to conduct said
operation, written notice proposing same must be resubmitted to
the other parties in accordance herewith as if no prior proposal
had been made. Those parties that did not participate in the
drilling of a well for which a proposal to Deepen or Sidetrack is
made hereunder shall, if such parties desire to participate in
the proposed Deepening or Sidetracking operation. reimburse the
Drilling Parties in accordance with Article V1.B.4. in the event
of a Deepening operation and in accordance with Article VI.B.5.
in the event of a Sidetracking operation.
2. Operations by Less Than All Parties:
(a) Determination of Participation. If any party to whom such
notice is delivered as provided in Article VI.B.1. or VI.C.l.
(Option No.2) elects not to participate in the proposed
operation. then, in order to be entitled to the benefits of this
Article, the party or parties giving the notice and such other
parties as shall elect to participate in the operation shall, no
later than ninety (90) days after the expiration of the notice
period of thirty (30) days (or as promptly as practicable after
the expiration of the forty-eight (48) hour period when a
drilling rig is on location, as the case may be) actually
commence the proposed operation and complete it with due
diligence. Operator shall perform all work for the account of the
Consenting Parties; provided, however, if no drilling rig or
other equipment is on location, and if Operator is a
Non-Consenting Party, the Consenting Parties shall either: (i)
request Operator to perform the work required by such proposed
operation for the account of the Consenting Parties, or (ii)
designate one of the Consenting Parties as Operator to perform
such work. The rights and duties granted to and imposed upon the
Operator under this agreement are granted to and imposed upon the
party designated as Operator for an operation in which the
original Operator is a Non-Consenting Party. Consenting Parties,
when conducting operations on the Contract Area pursuant to this
Article VI.B.2., shall comply with all terms and conditions of
this agreement.
If less than all parties approve any proposed operation, the
proposing party, immediately after the expiration of the
applicable notice period, shall advise all Parties of the total
interest of the Parties approving such operation and its
recommendation as to whether the Consenting Parties should
proceed with the operation as proposed. Each Consenting Party,
within forty-eight (48) hours (exclusive of Saturday, Sunday and
legal holidays) after delivery of such notice, shall advise the
proposing party of its desire to (i) limit participation to such
party's interest as shown on Exhibit "A" or (ii) carry only its
proportionate part (determined by dividing such party's interest
in the Contract Area by the interests of all Consenting Parties
in the Contract Area) of Non-Consenting Parties' interests, or
(iii) carry its proportionate part (determined as provided in
(ii) of Non-Consenting Parties' interests together with all or a
portion of its proportionate part of any Non-Consenting Parties'
interests that any Consenting Party did not elect to take. Any
interest of Non-Consenting Parties that is not carried by a
Consenting Party shall be deemed to be carried by the party
proposing the operation if such party does not withdraw its
proposal. Failure to advise the proposing party within the time
required shall be deemed an election under (i) . In the event a
drilling rig is on location, notice may be given by telephone,
and the time permitted for such a response shall not exceed a
total of forty-eight (48) hours (exclusive of Saturday, Sunday
and legal holidays). The proposing party, at its election, may
withdraw such proposal if there is less than 100% participation
and shall notify all parties of such decision within ten (10)
days, or within twenty-four (24) hours if a drilling rig is on
location, following expiration of the applicable response period
If 100% subscription to the proposed operation is obtained, the
proposing party shall promptly notify the Consenting Parties of
their proportionate interests in the operation and the party
serving as Operator shall commence such operation within the
period provided in Article VI.B.1., subject to the same extension
right as provided therein.
(b) Relinquishment of Interest for Non-Participation. The
entire cost and risk of conducting such operations shall be borne
by the Consenting Parties in the proportions they have elected to
bear same under the terms of the preceding paragraph. Consenting
Parties shall keep the leasehold estates involved in such
operations free and clear of all liens and encumbrances of every
kind created by or arising from the operations of the Consenting
Parties. If such an operation results in a dry hole, then subject
to Articles VI.B.6. and VI.E.3., the Consenting Parties shall
plug and abandon the well and restore
the surface location at their sole cost, risk and expense; provided, however,
that those Non-Consenting Parties that participated in the drilling, Deepening
or Sidetracking of the well shall remain liable for, and shall pay, their
proportionate
shares of the cost of plugging and abandoning the well and
restoring the surface location insofar only as those costs were
not increased by the subsequent operations of the Consenting
Parties. If any well drilled, Reworked, Sidetracked, Deepened,
Recompleted or Plugged Back under the provisions of this Article
results in a well capable of producing Oil and/or Gas in paying
quantities, the Consenting Parties shall Complete and equip the
well to produce at their sole cost and risk, and the well shall
then be turned over to Operator (if the Operator did not conduct
the operation) and shall be operated by it at the expense and for
the account of the Consenting Parties. Upon commencement of
operations for the drilling, Reworking, Sidetracking,
Recompleting, Deepening or Plugging Back of any such well by
Consenting Parties in accordance with the provisions of this
Article, each Non-Consenting Party shall be deemed to have
relinquished to Consenting Parties, and the Consenting Parties
shall own and be entitled to receive, in proportion to their
respective interests, all of such Non' Consenting Party's
interest in the well and share of production therefrom or, in the
case of a Reworking, Sidetracking,
- - -6-
<PAGE>
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989
l Deepening, Recompleting or Plugging Back, or a Completion pursuant
Article VI.C.1. Option No.2, all of such Non-Consenting Party's interest in
the production obtained from the operation in which the Non-Consenting
Party did not elect
to participate. Such relinquishment shall be effective until the proceeds of the
sale of such share, calculated at the well, or market value thereof if such
share is not sold (after deducting applicable and valorem, production,
severance, and excise taxes, royalty, overriding royalty and other interests not
excepted by Article lI1.C. payable out of or measured by the production from
such well accruing with respect to such interest until it reverts), shall equal
the total of the following:
(i) 100% of each such Non-Consenting Party's share of the cost of any newly
acquired surface equipment beyond the wellhead connections (including but not
limited to stock tanks, separators. treaters, pumping equipment and piping),
plus 100% of cads such Non-Consenting Party's share of the cost of operation of
the well commencing with first production and continuing until each such
Non-Consenting Party's relinquished interest shall revert to it under other
provisions of this Article, it being agreed that each Non-Consenting Party's
share of such costs and equipment will be that
interest which would have been chargeable to such Non-Consenting Party had
it participated in the well from the beginning ~f the operations; and
(ii) 500% of (a) that portion of the costs and expenses of
drilling, Reworking, Sidetracking, Deepening, Plugging Back, testing,
Completing, and Recompleting, after deducting any cash contributions
received under Article VIII.C., and of (b) that portion of the cost of newly
acquired equipment in the well (to and including the wellhead connections),
which would have been chargeable to such Non-Consenting Party if it had
participated therein.
Notwithstanding anything to the contrary in this Article Vl.B., if the well does
not reach the deepest objective Zone described in the notice proposing the
well for reasons other than the encountering of granite or practically
impenetrable substance or other condition in the hole rendering further
operations impracticable, Operator shall give notice thereof to each
Non-Consenting Party who submitted or voted for an alternative proposal
under Article V1.B.6. to drill the well to a shallower Zone than the deepest
objective Zone proposed in the notice under which the well was drilled, and
each such NonConsenting Party shall have the option to participate in the
initial proposed Completion of the well by paying its share of the cost of
drilling the well to its actual depth. calculated in the manner provided in
Article Vl.B.4. (a). If any such NonConsenting Party does not elect to
participate in the first Completion proposed for such well, the
relinquishment provisions of this Article VI.B.2. (b) shall apply to such
party's interest.
(c) Reworking. Recompleting or Plugging in Back. An election not to participate
in the drilling, Sidetracking or Deepening of a well shall be deemed an
election not to participate in any Reworking or Plugging Back operation
proposed in such a well, or portion thereof, to which the initial
non-consent election applied that is conducted at any time prior to full
recovery by the Consenting Parties of the Non-Consenting Party's recoupment
amount. Similarly, an election not to participate in the Completing or
Recompleting of a well shall be deemed an election not to participate in any
Reworking operation proposed in such a well, or portion thereof, to which
the initial non-consent election applied that is conducted at
any time prior to full recovery by the Consenting Parties of the Non-Consenting
Party's recoupment amount. Any such Reworking, Recompleting or Plugging Back
operation conducted during the recoupment period shall be deemed part of the
cost of operation of said well and there shall be added to the sums to be
recouped by the Consenting Parties 5 00 % of that portion of the costs of the
Reworking, Recompleting or Plugging Back operation which would have been
chargeable to such Non-Consenting Party had it participated therein. If such a
Reworking, Recompleting or Plugging Back operation is proposed during such
recoupment period, the provisions of this Article VI.B. shall be applicable as
between said Consenting Parties in said well.
(d) Recoupment Matters. During the period of time Consenting Parties are
entitled to receive Non-Consenting Party's share of production, or the
proceeds therefrom, Consenting Parties shall be responsible for the payment
of all ad valorem, production. severance, excise, gathering and other taxes,
and all royalty, overriding royalty and other burdens applicable to
Non-Consenting Party's share of production not excepted by Article IIl.C. In the
case of any Reworking, Sidetracking, Plugging Back, Recompleting or Deepening
operation, the Consenting Parties shall be permitted to use, free of cost, all
casing, tubing and other equipment in the well, but the ownership of all
such equipment shall remain unchanged; and upon abandonment of a well after
such Reworking, Sidetracking, Plugging Back, Recompleting or Deepening, the
Consenting Parties shall account for all such equipment to the owners
thereof, with each party receiving its proportionate part in kind or in
value, less cost of salvage.
Within ninety (90) days after the completion of any operation under this
Article, the party conducting the operations for the Consenting Parties
shall furnish each Non-Consenting Party with an inventory of the equipment
in and connected to the well, and an itemized statement of the cost of
drilling, Sidetracking, Deepening, Plugging Back, testing. Completing.
Recompleting, and equipping the well for production; or, at its option, the
operating party, in lieu of an itemized statement
of such costs of operation, may submit a detailed statement of monthly
billings. Each month thereafter, during the time the Consenting Parties are
being reimbursed as provided above, the party conducting the operations for
the Consenting Parties
shall furnish the Non-Consenting Parties with an itemized statement of all costs
and liabilities incurred in the operation of the well, together with a
statement of the quantity of Oil and Gas produced from it and the amount of
proceeds realized from the sale of the well's working interest production
(during the preceding month. In determining the quantity of Oil and Gas
produced during any month, Consenting Parties shall use industry accepted
methods such as but not limited to metering or periodic well tests. Any
amount realized from the sale or other disposition of equipment newly
acquired in connection with any such operation which would have been owned
by a Non-Consenting Party had it participated therein shall be credited
against the total unreturned costs of the work done and of the equipment
purchased in determining when the interest of such Non-Consenting Party
shall revert to it as above provided; and if there is a credit balance, it
shall be paid to such Non-Consenting Party.
If and when the Consenting Parties recover from a Non-Consenting Party's
relinquished interest the amounts provided for above, the relinquished interests
of such Non-Consenting Party shall automatically revert to it as of 7:00 a.m. on
the day following the day on which such recoupment occurs, and, from and after
such reversion, such Non-Consenting Party shall own (be same interest in such
well, the material and equipment in or pertaining thereto, and the production
therefrom as such Non-Consenting Party would have been entitled to had it
participated in the drilling, Sidetracking, Reworking, Deepening, Recompleting
or Plugging Back of said well. Thereafter, such Non-Consenting Party shall be
charged with and shall pay its proportionate part of the further costs of the
operation of said well in accordance with the terms of this agreement and
Exhibit "C" attached hereto.
3. Stand-By Costs: When a well which has been drilled or Deepened has reached
its authorized depth and all tests have been completed and the results thereof
furnished to the parties, or when operations on the well have been otherwise
terminated pursuant to Article VI.F., stand-by costs incurred pending response
to a party's notice proposing a Reworking,
7
<PAGE>
A.A.P.L. FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
Sidetracking, Deepening, Recompleting, Plugging Back or
Completing Operation in such a well (including the period
required under Article XVI.D to resolve competing proposals)
shall be charged and borne as part of the drilling or Deepening
operation just completed. Stand-by costs subsequent to all
parties responding, or expiration of the response time permitted,
whichever first occurs, and prior to agreement as to (the
participating interests of all Consenting Parties pursuant to the
terms of (the second grammatical paragraph of Article VI.B.2.
(a), shall be charged to and borne as part of the proposed
Operation. but if the proposal is subsequently withdrawn because
of insufficient participation, such stand-by costs shall be
allocated between the Consenting Parties in the proportion each
Consenting Party's interest as shown on Exhibit "A" bears to the
total interest as shown on Exhibit "A" of all Consenting Parties.
In the event that notice for a Sidetracking operation is given while the
drilling rig to be utilized is on location, any party may request and receive up
to five (5) additional days after expiration of the forty-eight hour response
period specified in Article VI.B.l. within which to respond by paying for all
stand-by costs and other costs incurred during such extended response period;
Operator may require such party to pay the estimated stand-by time in advance as
a condition to extending the response period. If more than one party elects to
take such additional time to respond to the notice, standby costs shall be
allocated between the parties taking additional time to respond on a day-to-day
basis in the proportion each electing party's interest as shown on Exhibit "A"
hears to the total interest as shown on Exhibit "A" of all the electing parties.
4. Deepening: If less than all the parties elect to participate in a drilling,
'Sidetracking, or Deepening operation proposed pursuant to Article VI.B.l., the
interest relinquished by the Non-Consenting Parties to the Consenting Parties
under Article VI.B.2. shall relate only and be limited to the lesser of (i) the
total depth actually drilled or (ii) the objective depth or Zone of which the
parties were given notice under Article VI.B.l. ("Initial Objective"). Such well
shall not be Deepened beyond the Initial Objective without first complying with
this Article to afford the Non-Consenting Parties the opportunity to participate
in the Deepening operation.
In the event any Consenting Party desires to drill or Deepen a Non-Consent Well
to a depth below the Initial Objective, such party shall give notice thereof,
complying with the requirements of Article VI.B.1., to all parties (including
Non-Consenting Parties). Thereupon, Articles VI.B.l. and 2. shall apply and all
parties receiving such notice shall have the right to participate or not
participate in the Deepening of such well pursuant to said Articles VI.B.l. and
2. If a Deepening operation is approved pursuant to such provisions, and if any
Non-Consenting Party elects to participate in the Deepening operation, such
Non-Consenting party shall pay or make reimbursement (as the case may be) of the
following costs and expenses:
(a) If the proposal to Deepen is made prior to the Completion of such well as a
well capable of producing in paying quantities, such Non-Consenting Party shall
pay (or reimburse Consenting Parties for, as the case may be) that share of
costs and expenses incurred in connection with the drilling of said well from
the surface to the Initial Objective which Non-Consenting Party would have paid
had such Non-Consenting Party agreed to participate therein, plus the
Non-Consenting Party's share of the cost of Deepening and of participating in
any further operations on the well in accordance with the other provisions of
this Agreement; provided, however, all costs for testing and Completion or
attempted Completion of the well incurred by Consenting Parties prior to the
point of actual Operations to Deepen beyond the Initial Objective shall be for
the sole account of Consenting Parties.
(b) If the proposal is made for a Non-Consent Well that has been previously
Completed as a well capable of producing in paying quantities, but is no longer
capable of producing in paying quantities, such Non-Consenting Party shall pay
(or reimburse Consenting Parties for, as the case may be) its proportionate
share of all costs of drilling, Completing, and equipping said well from the
surface to the Initial Objective, calculated in the manner provided in paragraph
(a) above, less those costs recouped by the Consenting Parties from the sale of
production from the well. The Non-Consenting Party shall also pay its
proportionate share of all costs of re-entering said well. The Non-Consenting
Parties' proportionate part (based on the percentage of such well Non-Consenting
Party would have owned had it previously participated in such Non-Consent Well)
of the costs of salvable materials and equipment remaining in the hole and
salvable surface equipment used in connection with such well shall be determined
in accordance with Exhibit "C." If the Consenting Parties have recouped the cost
of drilling, Completing, and equipping the well at the time such Deepening
operation is conducted, then a Non-Consenting Party may participate in the
Deepening of the well with no payment for costs incurred prior to re-entering
the well for Deepening.
The foregoing shall not imply a right of any Consenting Party to propose
any Deepening for a Non-Consent Well prior to the drilling of such well to
its Initial Objective without the consent of the other Consenting Parties
as provided in Article VI.F.
5, Sidetracking: Any party having the right to participate in a proposed
Sidetracking operation that does not own an interest in the affected wellbore at
the time of the notice shall, upon electing to participate, tender to the
wellbore owners its proportionate share (equal to its interest in the
Sidetracking operation) of the value of that portion of the existing wellbore to
be utilized as follows: (a) If the proposal is for Sidetracking an existing dry
hole, reimbursement shall be on the basis of the actual costs incurred in the
initial drilling of the well down to the depth at which, the Sidetracking
operation is initiated. (b) If the proposal is for Sidetracking a well which has
previously produced, reimbursement shall be on the basis of such party's
proportionate share of drilling and equipping costs incurred in the initial
drilling of the well down to the depth at which the Sidetracking operation is
conducted, calculated in the manner described in Article VI.B.4(b) above. Such
party's proportionate share of the cost of the well's salvable materials and
equipment down to the depth at which the Sidetracking operation is initiated
shall be determined in accordance with the provisions of Exhibit "C."
<deleted items>
<PAGE>
A.A.P.L FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989
7. Conformity to Spacing Pattern. Notwithstanding the provisions of this Article
VI.B.2., It is agreed that no wells shall be proposed to be drilled to or
Completed in or produced from a Zone from which a well located elsewhere on the
Contract Area is producing, unless such well conforms to the then-existing well
spacing pattern for such Zone.
8. Paying Wells. No party shall conduct any Reworking. Deepening, Plugging Back,
Completion, Recompletion, or Sidetracking operation under this agreement with
respect to any well then capable of producing in paying quantities except with
the consent of all parties that have not relinquished interests in the well at
the time of such operation.
C. Completion of Wells; Reworking and Plugging Back:
1. Completion: Without the consent of all parties, no well shall be drilled,
Deepened or Sidetracked, except any well drilled, Deepened or Sidetracked
pursuant to the provisions of Article VI.B.2. of this agreement. Consent to the
drilling, Deepening or Sidetracking shall include:
Option No. 1: All necessary expenditures for the drilling, Deepening or
Sidetracking, testing, Completing and equipping of the well, including
necessary tankage and/or surface facilities.
X Option No.2: All necessary expenditures for the drilling, Deepening or
Sidetracking and testing of the well. When such well has reached its authorized
depth, and all logs, cores and other tests have been completed, and the results
thereof furnished to the parties, Operator shall give immediate notice to the
Non-Operators having the right to participate in a Completion attempt whether or
not Operator recommends attempting to Complete the well, together with
Operator's AFE for Completion costs if not previously provided. The parties
receiving such notice shall have forty-eight (48) hours (exclusive of Saturday,
Sunday and legal holidays) in which to elect by delivery of notice to Operator
to participate in a recommended Completion attempt or to make a Completion
proposal with an accompanying AFE. Operator shall deliver any such Completion
proposal, or any Completion proposal conflicting with Operator's proposal, to
the other parties entitled to participate in such Completion in accordance with
the
procedures specified in Article XVI.D. Election to participate in a Completion
attempt shall include consent to all necessary expenditures for the Completing
and equipping of such well, including necessary tankage and/or surface
facilities but excluding any stimulation operation not contained on the
Completion AFE. Failure of any party receiving such notice to reply within the
period above fixed shall constitute an election by that party not to participate
in the cost of the Completion attempt; provided, that Article Vl.B.6. shall
control in the case of conflicting Completion proposals. If one or more, but
less than all of the parties, elect to attempt a Completion, the provisions of
Article VI.B.2. hereof (the phrase "Reworking, Sidetracking, Deepening,
Recompleting or Plugging Back" as contained in Article VI.B.2. shall be deemed
to include "Completing") shall apply to the operations thereafter conducted by
less than all parties; provided, however, that Article VI.B.2 shall apply
separately to each separate Completion or Recompletion attempt undertaken
hereunder, and an election to become a Non-Consenting Party as to one Completion
or Recompletion attempt shall not prevent a party from becoming a Consenting
Party in subsequent Completion or Recompletion attempts regardless whether the
Consenting Parties as to earlier Completions or Recompletions have recouped
their costs pursuant to Article VI.B.2.; provided further, that any recoupment
of costs by a Consenting Party shall be made solely from the production
attributable to the Zone in which the Completion attempt is made. Election by a
previous Non-Consenting Party to participate in a subsequent Completion or
Recompletion attempt shall require such party to pay its proportionate share of
the cost of salvable materials and equipment installed in the well pursuant to
the previous Completion or Recompletion attempt, insofar and only insofar as
such materials and equipment benefit the Zone in which such party participates
in a Completion attempt.
2. Rework, Recomplete or Plug Back: No well shall be Reworked, Recompleted or
Plugged Back except a well Reworked,
Recompleted, or Plugged Back pursuant to the provisions of Article VI.B.2.
of this agreement. Consent to the Reworking, Recompleting or Plugging Back
of a well shall include all necessary expenditures in conducting such
operations and Completing and equipping of said well, including necessary
tankage and/or surface facilities.
D. Other Operations:
Operator shall not undertake any single prospect reasonably estimated to require
an expenditure in excess of Forty Thousand and 0/100 ------------ Dollars
($40,000.00) except in connection with the drilling, Sidetracking, Reworking,
Deepening, Completing, Recompleting or Plugging Back of a well that has been
previously authorized by or pursuant to this agreement; provided, however, that,
in case of explosion, fire, flood or other sudden emergency, whether of the same
or different nature, Operator may take such steps and incur such expenses as in
its opinion are required to deal with the emergency to safeguard life and
property but Operator, as promptly as possible, shall report the emergency to
the other parties. l~ Operator prepares an AFE for its own use, Operator shall
furnish any Non-Operator so requesting an information copy thereof for any
single project costing in excess of Thirty-five Thousand Dollars ( 35,000.00 ).
Any party who has not relinquished its interest in a well shall have the right
to propose that Operator perform repair work or undertake the installation of
artificial lift equipment or ancillary production facilities such as salt water
disposal wells or to conduct additional work with respect to-a well drilled
hereunder or other similar project (but not including the installation of
gathering lines or other transportation or marketing facilities, the
installation of which shall be governed by separate agreement between the
parties) reasonably estimated to require an expenditure in excess of the amount
first set forth above in this Article VI.D. (except in connection with an
operation required to be proposed under Articles VI.B.1. or VI.C.1. Option No.
2, which shall be governed exclusively by those Articles). Operator shall
deliver such proposal to all parties entitled to participate therein. If within
thirty (30) days thereof Operator secures the written consent of any party or
parties owning at least 50 % of the interests of the parties entitled to
participate in such operation, each party having the right to participate in
such project shall be hound by the terms of such proposal and shall be obligated
to pay its proportionate share of the costs of the proposed project as if it had
consented to such project pursuant to the terms of the proposal.
E. Abandonment of Wells:
1. Abandonment of Dry Holes: Except for any well drilled or Deepened
pursuant to Article Vl.B.2., any well which has been drilled or Deepened
under the terms of this agreement and is proposed to be
-------------------------
completed as a dry hole shall not be
- - -9-
<PAGE>
A.A.P.L FORM 610 MODEL FORM OPERATING AGREEMENT - 1989
plugged and abandoned without the consent of all parties.
Should Operator, after diligent effort, be unable to contact any
party, or should any party fail to reply within forty-eight (48)
hours (exclusive of Saturday, Sunday and legal holidays) after
delivery of notice of the proposal to plug and abandon such well,
such party shall be deemed to have consented to the proposed
abandonment. All such wells shall be plugged and abandoned in
accordance with applicable regulations and at the cost, risk and
expense of the parties who participated in the cost of drilling
or Deepening such well. Any party who objects to plugging and
abandoning such well by notice delivered to Operator within
forty-eight (48) hours (exclusive of Saturday, Sunday and legal
holidays) after delivery of notice of the proposed plugging shall
take over the well as of the end of such forty-eight (48) hour
notice period and conduct further operations in search of Oil
and/or Gas subject to the provisions of Article VI.B.; failure of
such party to provide proof reasonably satisfactory to Operator
of its financial capability to conduct such operations or to take
over the well within such period or thereafter to conduct
operations on such well or plug and abandon such well shall
entitle Operator to retain or take possession of the well and
plug and abandon the well. The party taking over (be well shall
indemnify Operator (if Operator is an abandoning party) and the
other abandoning parties against liability for any further
operations conducted on such well except for the costs of
plugging and abandoning the well and restoring the surface, for
which the abandoning parties shall remain proportionately liable.
2. Abandonment of Wells That Have Produced: Except for any well in which a
Non-Consent operation has been conducted hereunder for which the Consenting
Parties have not been fully reimbursed as herein provided, any well which has
been completed as a producer shall not be plugged and abandoned without the
consent of all parties. If all parties consent to such abandonment, the well
shall be plugged and abandoned in accordance with applicable regulations and at
the cost, risk and expense of all the parties hereto. Failure of a party to
reply within sixty (60) days of delivery of notice of proposed abandonment shall
be deemed an election to consent to the proposal. If, within sixty (60) days
after delivery of notice of the proposed abandonment of any well, all parties do
not agree to the abandonment of such well, those wishing to continue its
operation from the Zone then open to production shall be obligated to take over
the well as of the expiration of the applicable notice period and shall
indemnify Operator (if Operator is an abandoning party) and the other abandoning
parties against liability for any further operations on the well conducted by
such parties. Failure of such party or parties to provide proof reasonably
satisfactory to Operator of their financial capability to conduct such
operations or to take over the well within the required period or thereafter to
conduct operations on such well shall entitle Operator to retain or take
possession of such well and plug and abandon the well.
Parties taking over a well as provided herein shall tender to each of the other
parties its proportionate share of the value of the well's salvable material and
equipment, determined in accordance with the provisions of Exhibit "C," less the
estimated cost of salvaging and the estimated cost of plugging and abandoning
and restoring the surface; provided, however, that in the event the estimated
plugging and abandoning and surface restoration costs and the estimated cost of
salvaging are higher than the value of the well's salvable material and
equipment, each of the abandoning parties shall tender to the parties continuing
operations their proportionate shares of the estimated excess cost. Each
abandoning party shall assign to the non-abandoning parties, without warranty,
express or implied, as to title or as to quantity, or fitness for use of the
equipment and material, all of its interest in the wellbore of the well and
related equipment, together with its interest in the Leasehold insofar and only
insofar as such Leasehold covers the right to obtain production from that
wellbore in the Zone then open to production. <deleted items>The assignments or
leases so limited shall encompass the Drilling Unit upon which the well is
located. The payments by, and the assignments or leases to, the assignees shall
be in a ratio based upon the relationship of their respective percentage of
participation in the Contract Area to the aggregate of the percentages of
participation in the Contract Area of all assignees. There shall be no
readjustment of interests in the remaining portions of the Contract Area.
Thereafter, abandoning parties shall have no further responsibility, liability,
or interest in the operation of or production from the well in the Zone then
open other than the royalties retained in any lease made under the terms of this
Article. Upon written request, Operator shall continue to operate the assigned
well for the account of the non-abandoning parties at the rates and charges
contemplated by this agreement, plus any additional cost and charges which may
arise as the result of the separate ownership of the assigned well. Upon
proposed abandonment of the producing Zone assigned or leased, the assignor or
lessor shall then have the option to repurchase its prior interest in the well
(using the same valuation formula) and participate in further operations therein
subject to the provisions hereof.
3. Abandonment of Non-Consent Operations: The provisions of Article VI.E.l. or
VI.E.2. above shall be applicable as between Consenting Parties in the event of
the proposed abandonment of any well excepted from said Articles; provided,
however, no well shall be permanently plugged and abandoned unless and until all
parties having the right to conduct further operations therein have been
notified of the proposed abandonment and afforded the opportunity to elect to
take over the well in accordance with the provisions of this Article VI.E.; and
provided further, that Non-Consenting Parties who own an interest in a portion
of the well shall pay their proportionate shares of abandonment and surface
restoration costs for such well as provided in Article Vl.B.2.(b).
F. Termination of Operations:
Upon the commencement of an operation for the drilling, Reworking, Sidetracking,
Plugging Back, Deepening, testing, Completion or plugging of a well, including
but not limited to the Initial Well, such operation shall not be terminated
without consent of parties bearing 50 % of the costs of such operation;
provided, however, that in the event granite or other practically impenetrable
substance or condition in the hole is encountered which renders further
operations impractical, Operator may discontinue operations and give notice of
such condition in the manner provided in Article VIB.l, and the provisions of
Article Vl.B. or VI.E. shall thereafter apply to such operation, as appropriate.
G. Taking Production in Kind:
X Option No. I: Gas Balancing Agreement
Each party shall have the right to dispose of its proportionate share of all Oil
and Gas produced from the Contract Area, exclusive of production which may be
used in development and producing operations and in preparing and treating Oil
and Gas for marketing purposes and production unavoidably lost. Any extra
expenditure incurred in the taking in kind or separate disposition by any party
of its proportionate share of the production shall be borne by such party Any
party taking its share of production in kind shall be required to pay for only
its proportionate share of such part of Operator's surface facilities which it
uses. Each party shall execute such division orders and contracts as may be
necessary for the sale of its interest in production from the Contract Area,
and, except as provided in Article VII.B., shall be entitled to receive payment
10
<PAGE>
A.A.P.L FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
directly from the purchaser thereof for its share of all production. If any
party fails to make the arrangements necessary to take in kind or separately
dispose of its proportionate share of the Oil and/or Gas in the Contract Area,
Operator shall have the right subject to the revocation at will by the party
owning it, but not the obligation, to purchase such Oil and or Gas or sell it to
others at any time and from time to time, for the account of the non-taking
party. Any such purchase or sale by Operator may be terminated by Operator upon
at least * days written notice to the owner of said production and shall be
subject always to the right of the owner of the production upon at least * days
written notice to Operator to exercise at any time its right to take in kind, or
separately dispose of, its share of all Oil and/or Gas not previously delivered
to a purchaser. Any purchase or sale by Operator of any other party's share of
Oil and/or Gas shall be only for such reasonable periods of time as are
consistent with the minimum needs of the industry under the particular
circumstances, but in no event for a period in excess of one (1) year. Operator
shall market such party's share of production ratably with that of Operator.
Any such sale by Operator shall be in a manner commercially reasonable under the
circumstances but Operator shall have no duty to share any existing market or to
obtain a price equal to that received under any existing market. The sale or
delivery by Operator of a non-taking party's share of Oil under the terms of any
existing contract of Operator shall not give the non-taking party any interest
in or make the non-taking party a party to said contract. No purchase shall be
made by Operator without first giving the non-taking party at least ten (10)
days written notice of such intended purchase and the price to be paid or the
pricing basis to be used.
All parties shall give timely written notice to Operator of their Gas marketing
arrangements for the following month, excluding price, and shall notify Operator
immediately in the event of a change in such arrangements. Operator shall
maintain records of all marketing arrangements, and of volumes actually sold or
transported, which records shall be made available to Non-Operators upon
reasonable request.
In the event one or more parties' separate disposition of its share of the Gas
causes split-stream deliveries to separate pipelines and/or deliveries which on
a day-to-day basis for any reason are not exactly equal to a party's respective
proportionate share of total Gas sales to be associated to it, the balancing or
accounting between the parties shall be in accordance with any Gas balancing
agreement between the parties hereto, whether such an agreement is attached as
Exhibit .'E.' or is a separate agreement. Operator shall give notice to all
parties of the first sales of Gas from any well under this agreement.
<deleted items>
ARTICLE VII..
EXPENDITURES AND LIABILITY OF PARTIES
A. Liability of Parties:
The liability of the parties shall be several, not joint or collective. Each
party shall be responsible only for its obligations, and shall be liable only
for i(5 proportionate share of the costs of developing and operating the
Contract Area. Accordingly, the liens granted among (be parties in Article
VII.B. are given to secure only (be debts of each severally, and no party shall
have any liability to third parties hereunder to satisfy the default of any
other party in the payment of any expense or obligation hereunder. It is nor the
intention of the parties to create, nor shall this agreement be construed as
creating, a mining or other partnership, joint venture, agency relationship or
association, or to tender the parties liable as partners, co-venturers, or
principals. In their relations with each other under this agreement, the parties
shall not be considered fiduciaries or to have established a confidential
relationship but rather shall be free to act on an arm's-length basis in
accordance with their own respective self-interest, subject, however, to the
obligation of the parties to act in good faith in their dealings with each other
with respect to activities hereunder.
* thirty (30) days
11
<PAGE>
A.A.P.L FORM 610 MODEL FORM OPERATING AGREEMENT - 1989
B. Liens and Security Interests:
Each party grants to other parties hereto a lien upon any interest it
now owns or hereafter acquires in Oil and Gas Leases and Oil and Gas
Interests in the Contract Area, and a security interest and/or purchase
money security interest in any interest it now owns or hereafter acquires
in the personal property and fixtures on or used or obtained for use in
connection (herewith, to secure performance of all of its obligations under
this agreement including but not limited to payment of expense, interest
and fees, the proper disbursement of all monies paid hereunder, the
assignment or relinquishment of interest in Oil and Gas Leases as required
hereunder, and the proper performance of operations hereunder. Such lien
and security interest granted by each party hereto shall include such
party's leasehold interests, working interests, operating rights, and
royalty and overriding royalty interests in the Contract Area now owned or
hereafter acquired and in lands pooled or unitized therewith or otherwise
becoming subject to this agreement, the Oil and Gas when extracted
therefrom and equipment situated thereon or used or obtained for use in
connection therewith (including, without limitation, all wells, tools, and
tubular goods), and accounts (including, without limitation, accounts
arising from gas imbalances or from the sale of Oil and/or Gas at the
wellhead), contract rights, inventory and general intangibles relating
thereto or arising therefrom, and all proceeds and products of the
foregoing.
To perfect the lien and security agreement provided herein, each
party hereto shall execute and acknowledge the recording supplement and/or any
financing statement prepared and submitted by any party hereto in conjunction
herewith or at any time following execution hereof, and Operator is authorized
to file this agreement or the recording supplement executed herewith as a lien
or mortgage in the applicable real estate records and as a financing statement
with the proper officer under the Uniform Commercial Code in the state in which
the Contract Area is situated and such other states as Operator shall deem
appropriate to perfect the security interest granted hereunder. Any party may
file this agreement, the recording supplement executed herewith, or such other
documents as it deems necessary as a lien or mortgage in the applicable real
estate records and/or a financing statement with the proper officer under the
Uniform Commercial Code.
Each party represents and warrants to the other parties hereto
that the lien and security interest granted by such party to the other parties
shall be a first and prior lien, and each party hereby agrees to maintain the
priority of said lien and security
interest against all persons acquiring an interest in Oil and Gas Leases and
Interests covered by this agreement by, through or under such party. All parties
acquiring an interest in Oil and Gas Leases and Oil and Gas Interests covered by
this agreement, whether by assignment, merger, mortgage, operation of law, or
otherwise, shall be deemed to have taken subject to the lien and security
interest granted by this Article VII.B. as to all obligations attributable to
such interest hereunder whether or not such obligations arise before or after
such interest is acquired.
To the extent that parties have a security interest under the Uniform Commercial
Code of the state in which the Contract Area is situated, they shall be entitled
to exercise the rights and remedies of a secured party under the Code. The
bringing of a suit and the obtaining of judgment by a party for the secured
indebtedness shall not be deemed an election of remedies or otherwise affect the
lien rights or security interest as security for the payment thereof. In
addition, upon default by any party in the payment of its share of expenses,
interests or fees, or upon the improper use of funds by the Operator, the other
parties shall have the right, without prejudice to other rights or remedies, to
collect from the purchaser the proceeds from the sale of such defaulting party's
share of Oil and Gas until the amount owed by
such party, plus interest as provided in "Exhibit C." has been received, and
shall have the right to offset the amount owed against the proceeds from the
sale of such defaulting party's share of Oil and Gas. All purchasers of
production may rely on a notification of default from the non-defaulting party
or parties stating the amount due as a result of the default, and all parties
waive any recourse available against purchasers for releasing production
proceeds as provided in this paragraph.
If any party fails to pay its share of cost within one hundred twenty (120) days
after rendition of a statement therefor by Operator, the non-defaulting parties.
including Operator, shall, upon request by Operator, pay the unpaid amount in
the proportion that the interest of each such party bears to the interest of all
such parties. The amount paid by each party so paying its share of the unpaid
amount shall be secured by the liens and security rights described in Article
VII.B., and each paying party may independently pursue any remedy available
hereunder or otherwise.
If any party does not perform all of its obligations hereunder,
and the failure to perform subjects such party to foreclosure or execution
proceedings pursuant to the provisions of this agreement, to the extent
allowed by governing law, the defaulting
party waives any available right of redemption from and after the date of
judgment, any required valuation or appraisement of the mortgaged or secured
property prior to sale, any available right to stay execution or to require a
marshalling of assets
and any required bond in the event a receiver is appointed. In addition, to
the extent permitted by applicable law, each party hereby grants to the other
parties a power of sale as to any property that is subject to the lien and
security rights granted hereunder, such power to be exercised in the manner
provided by applicable law or otherwise in a commercially reasonable manner and
upon reasonable notice.
Each party agrees that the other parties shall be entitled to
utilize the provisions of Oil and Gas lien law or other lien law of any state in
which the Contract Area is situated to enforce the obligations of each party
hereunder Without limiting the generality of the foregoing, to the extent
permitted by applicable law, Non-Operators agree that Operator may invoke or
utilize the mechanics or materialmen's lien law of the state in which the
Contract Area is situated in order to secure the payment to Operator of any such
due hereunder for services performed or materials supplied by Operator.
C. Advances:
Operator, at its election, shall have the right from time to time to demand and
receive from one or more of the other parties payment in advance of their
respective shares of the estimated amount of the expense to be incurred in
operations
hereunder during the next succeeding month, which right may be exercised only by
submission to each such party of an itemized statement of such estimated
expense, together with an invoice for its share thereof, Each such statement
and invoice for the payment in advance of estimated expense shall be
submitted on or before the thirty 20th day of the preceding month
Each party shall pay to Operator its proportionate share of such estimate within
thirty (30) days after such estimate and invoice is received. If any party fails
to pay its share of said estimate within said time, the amount due shall bear
interest as provided in Exhibit "C" until paid. Proper adjustment shall be made
monthly between advances and actual expense to the end that each party shall
bear and pay its proportionate share of actual expenses incurred, and no more.
D. Defaults and Remedies:
If any party fails to discharge any financial obligation under
this agreement, including without limitation the failure to make any advance
under the preceding Article VII.C. or any other provision of this agreement,
within the period required for such payment hereunder, then in addition to the
remedies provided in Article VII.B. or elsewhere in this agreement, the remedies
specified below shall be applicable. For purposes of this Article VII.D., all
notices and elections shall be delivered
12
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A.A.P.L FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
only by Operator, except that Operator shall deliver any such
notice and election requested by a non-defaulting Non-Operator,
and when Operator is the party in default, the applicable notices
and elections can be delivered by any Non-Operator.
Election of any one or more of the following remedies shall not preclude the
subsequent use of any other remedy specified below or otherwise available to a
non-defaulting party.
1. Suspension of Rights: Any party may deliver to the party in
default a Notice of Default, which shall specify the default,
specify the action to be taken to cure the default, and specify
(hat failure to take such action will result in the exercise of
one or more of the remedies provided in this Article. If the
default is not cured within thirty (30) days of the delivery of
such Notice of Default, all of the rights of the defaulting party
granted by this agreement may upon notice be suspended until the
default is cured, without prejudice to the right of the
non-defaulting party or parties to continue to enforce the
obligations of the defaulting party previously accrued or
thereafter accruing under this agreement. If Operator is the
party in default, theNon-Operators shall have in addition the
right, by vote of Non-Operators owning a majority in interest in
the Contract Area 12 after excluding the voting interest of
Operator, to appoint a new Operator effective immediately. The
rights of a defaultingparty that may be suspended hereunder at
the election of the non-defaulting parties shall include, without
limitation, the right to receive information as to any operation
conducted hereunder during the period of such default, the right
to elect to is participate in an operation proposed under Article
VI.B. of this agreement, the right to participate in an operation
being conducted under this agreement even if the party has
previously elected to participate in such operation, and the
right to receive proceeds of production from any well subject to
this agreement.
2. Suit for Damages: Non-defaulting parties or Operator for the
benefit of non-defaulting parties may sue (at joint account
expense) to collect the amounts in default, plus interest
accruing on the amounts recovered from the dare of default until
the date of collection at the rate specified in Exhibit "C"
attached hereto. Nothing herein shall prevent any party from
suing any defaulting party to collect consequential damages
accruing to such party as a result of the default.
3. Deemed Non-Consent: The non-defaulting party may deliver a
written Notice of Non-Consent Election to the defaulting party at
any time after the expiration of the thirty-day cure period
following delivery of the Notice of Default, in which event if
the billing is for the drilling of a new well or the Plugging
Back, Sidetracking, Reworking or Deepening of a well which is to
be or has been plugged as a dry hole, or for the Completion or
Recompletion of any well, the defaulting party will be
conclusively deemed to have elected not to participate in the
operation and to be a Non-Consenting Party with respect thereto
under Article VI.B. or V1.C., as the case may be, to the extent
of the costs unpaid by such party, notwithstanding any election
to participate theretofore made. If election is made to proceed
under this provision, then the non-defaulting parties may not
elect to sue for the unpaid amount pursuant to Article VII.D.2.
Untilthe delivery of such Notice of Non-Consent Election to the
defaulting party, such party shall have the right to cure its
default by paying its unpaid share of costs plus interest at the
rate set forth in Exhibit "C," provided, however, such payment
shall not prejudice the rights of the non-defaulting parties to
pursue remedies for damages incurred by the non-defaulting
parties as a result of the default. Any interest relinquished
pursuant to this Article VII.D.3. shall be offered to the
non-defaulting parties in proportion to their interests, and the
non-defaulting parties electing to participate in the ownership
of such interest shall be required to contribute their shares of
the defaulted amount upon their election to participate therein.
4. Advance Payment: If a default is not cured within thirty (30)
days of the delivery of a Notice of Default, Operator. or
Non-Operators if Operator is the defaulting party, may thereafter
require advance payment from the defaulting party of such
defaulting party's anticipated share of any item of expense for
which Operator, or Non-Operators, as the case may be, would be
entitled to reimbursement under any provision of this agreement,
whether or not such expense was the subject of the previous
default. Such right includes, but is not limited to, the right to
require advance payment for the estimated costs of drilling a
well or Completion of a well as to which an election to
participate in drilling or Completion has been made. If the
defaulting party fails to pay the required advance payment, the
non-defaulting parties may pursue any of the remedies provided in
this Article VII.D. or any other default remedy provided
elsewhere in this agreement. Any excess of funds advanced
remaining when the operation is completed and all costs have been
paid shall be promptly returned to the advancing party.
5. Costs and Attorneys' Fees. In the event any party is required to
bring legal proceedings to enforce any financial obligation of a
party hereunder, the prevailing party in such action shall be
entitled to recover all court costs, costs of collection, and a
reasonable attorney's fee, which the lien provided for herein
shall also secure. E. Rentals, Shut-in Well Payments and Minimum
Royalties: Rentals, shut-in well payments and minimum royalties
which may be required under the terms of any lease shall be paid
by the party or parties who subjected such lease to this
agreement at its or their expense. In the event two or more
parties own and have contributed interests in the same lease to
this agreement, such parties may designate one of such parties to
make said payments for and on behalf of all such parties. Any
party may request, and shall be entitled to receive, proper
evidence of all such payments. In the event of failure to make
proper payment of any rental, shut-in well payment or minimum
royalty through mistake or oversight where such payment is
required to continue the lease in force, any loss which results
from such non-payment shall be borne in accordance with the
provisions of Article IV.B 3.
Operator shall notify Non-Operators of the anticipated completion of a
shut-in well, or the shutting in or return to production of a
producing well, at least five (5) days (excluding Saturday,
Sunday and legal holidays) prior to taking such action, or at the
earliest opportunity permitted by circumstances, but assumes no
liability for failure to do so. In the event of failure by
Operator to so notify Non-Operators, the loss of any lease
contributed hereto by Non-Operators for failure to make timely
payments of any shut-in well payment shall be borne jointly by
the parties hereto under the provisions of Article IV.B.3. F.
Taxes: Beginning with the first calendar year after the effective
date hereof, Operator shall render for ad valorem taxation all
property subject to this agreement which by law should be
rendered for such taxes, and it shall pay all such taxes assessed
thereon before they become delinquent. Prior to the rendition
date, each Non-Operator shall furnish Operator information as
property subject to this agreement which by law should be
rendered for such taxes, and it shall pay all such taxes assessed
thereon before they become delinquent. Prior to the rendition
date, each Non-Operator shall furnish Operator information as to
burdens (to include, but not be limited to, royalties, overriding
royalties and production payments) on Leases and Oil and Gas
Interests contributed by such Non-Operator. If the assessed
valuation of any Lease is reduced by reason of its being subject
to outstanding excess royalties, overriding royalties or
production payments, the reduction in ad valorem taxes resulting
therefrom shall inure to the benefit of the owner or owners of
such Lease, and Operator shall adjust the charge to such owner or
owners so as to reflect the benefit of such reduction. If the ad
valorem taxes ate based in whole or in part upon separate
valuations of each party's working interest, then notwithstanding
anything to the contrary herein, charges to the joint account
shall be made and paid by the parties hereto in accordance with
the tax value generated by each party's working interest.
Operator shall bill the other parties for their proportionate
shares of all tax payments in the manner provided in Exhibit "C."
13
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A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989
If Operator considers any tax assessment improper, Operator may. at
its discretion, protest within the time and manner prescribed by
law, and prosecute the protest to a final determination, unless
all parties agree to abandon the protest prior to final
determination During the pendency of administrative or judicial
proceedings, Operator may elect to pay, under protest, all such
taxes and any interest and penalty. When any such protested
assessment shall have been finally determined, Operator shall pay
the tax for the joint account, together with any interest and
penalty accrued, and the total cost shall then be assessed
against the parties, and be paid by them, as provided in Exhibit
"C"
Each party shall pay or cause to be paid all production, severance, excise,
gathering and other taxes imposed upon or with respect to the production or
handling of such party's share of Oil and Gas produced under the terms of
this agreement.
ARTICLE VIII.
ACQUISITION, MAINTENANCE OR TRANSFER OF INTEREST
A. Surrender of Leases:
The leases covered by this agreement, insofar as they embrace acreage in the
Contract Area, shall not be surrendered in whole or in part unless all parties
consent thereto.
However, should any party desire to surrender its interest in any lease or
in any portion thereof, such party shall give written notice of
the proposed surrender to all parties, and the parties to whom
such notice is delivered shall have thirty (30) days after
delivery of the notice within which to notify the party proposing
the surrender whether they elect to consent thereto. Failure of a
party to whom such notice is delivered to reply within said 30day
period shall constitute a consent to the surrender of the leases
described in the notice. If all parties do not agree or consent
thereto, the party desiring to surrender shall assign, without
express or implied warranty of title, all of its interest in such
lease, or portion thereof, and any well, material and equipment
which may be located thereon and any rights in production
thereafter secured, to the parties not consenting to such
surrender.
<deleted items>
Upon such assignment or lease, the assigning party shall be
relieved from all obligations thereafter accruing, but not
theretofore accrued, with respect to the interest assigned or
leased and the operation of any well attributable thereto, and
the assigning party shall have no further interest in the
assigned or leased premises and its equipment and production
other than the royalties retained in any lease made under the
terms of this Article. The party assignee or lessee shall pay to
the party assignor or lessor the reasonable salvage value of the
latter's interest in any well's salvable materials and equipment
attributable to the assigned or leased acreage. The value of all
salvable materials and equipment shall be determined in
accordance with the provisions of Exhibit "C," less the estimated
cost of salvaging and the estimated cost of plugging and
abandoning and restoring the surface. If such value is less than
such costs, then the party assignor or lessor shall pay to the
party assignee or lessee the amount of such deficit. If the
assignment or lease is in favor of more than one party, the
interest shall be shared by such parties in the proportions that
the interest of each bears to the total interest of all such
parties. If the interest of the parties to whom the assignment is
to be made varies according to depth, then the interest assigned
shall similarly reflect such variances.
Any assignment, lease or surrender made under this provision shall
not reduce or change the assignor's, lessor's or surrendering
party's interest as it was immediately before the assignment,
lease or surrender in the balance of the Contract Area; and the
acreage assigned, leased or surrendered, and subsequent
operations thereon, shall not thereafter be subject to the terms
and provisions of this agreement but shall be deemed subject to
an Operating Agreement in the form of this agreement.
B. Renewal or Extension of Leases: If any party secures a renewal or
replacement of an Oil and Gas lease or Interest subject to this
agreement, then all other parties shall be notified promptly upon
such acquisition or, in the case of a replacement lease taken
before expiration of an existing lease, promptly upon expiration
of the existing lease. The parties notified shall have the right
for a period of thirty (30) days following delivery of such
notice in which to elect to participate in the ownership of the
renewal or replacement lease, insofar as such lease affects lands
within the Contract Area, by paying to the party who acquired it
their proportionate shares of the acquisition cost allocated to
that part of such lease within the Contract Area, which shall be
in proportion to the interests held at that time by the parties
in the Contract Area. Each party who participates in the purchase
of a renewal or replacement lease shall be given an assignment of
its proportionate interest therein by the acquiring party. If
some, but less than all, of the parties elect to participate in
the purchase of a renewal or replacement lease, it shall be owned
by the parties who elect to participate therein, in a ratio based
upon the relationship of their respective percentage of
participation in the Contract Area to the aggregate of the
percentages of participation in the Contract Area of all parties
participating in the purchase of such renewal or replacement
lease. The acquisition of a renewal or replacement lease by any
or all of the parties hereto shall not cause a readjustment of
the interests of the parties stated in Exhibit "A," but any
renewal or replacement lease in which less than all parties elect
to participate shall not be Subject to this agreement but shall
be deemed subject to a separate Operating Agreement in the form
of this agreement. If the interests of the parties in the
Contract Area vary according to depth, then their right to
participate proportionately in renewal or replacement leases and
their right to receive an assignment of interest shall also
reflect such depth variances. The provisions of this Article
shall apply to renewal or replacement leases whether they are for
the entire interest covered by the expiring lease or cover only a
portion of its area or an interest therein. Any renewal or
replacement lease taken before the expiration of its predecessor
lease, or taken or contracted for or becoming effective within
six (6) months after the expiration of the existing lease, shall
be subject to this provision so long as this agreement is in
effect at the time of such acquisition or at the time the renewal
or replacement lease becomes effective; but any lease taken or
contracted for more than six (6) months after (be expiration of
an existing lease shall not be deemed a renewal or replacement
lease and shall not be subject to the provisions of this
agreement. The provisions in this Article shall also be
applicable to extensions of Oil and Gas leases. The provisions in
this Article shall also be applicable to extensions of Oil and
Gas Leases. C Acreage or Cash Contributions: While this agreement
is in force, if any party contracts for or receive contribution
of cash towards the drilling of a well or any other operation on
the Contract Area, such contribution shall be paid to the party
who conducted the drilling or other operation and shall be
applied by it against the cost of such drilling or other
operation. If the contribution be in (be form of acreage, the
party to whom the contribution is made shall promptly tender an
assignment of the acreage, without warranty of title, to the
Drilling Parties in the proportions said Drilling Parties shared
the cost of drilling the well. Such acreage shall become a
separate Contract Area and, to the extent possible, be governed
by provisions identical to this agreement. Each party shall
promptly notify all other parties of any acreage or cash
contributions it nay obtain in support of any well or any other
operation on the Contract Area The above provisions shall also be
applicable to optional rights to earn acreage outside the
Contract Area which are in support of well drilled inside the
Contract Area.
14
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A.A.P.L FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
If any party contracts for any consideration relating to disposition of
such party's share of substances produced hereunder, such consideration
shall not be deemed a contribution as contemplated in this Article VIII.C.
D. Assignment; Maintenance of Uniform Interest:
For (be purpose of maintaining uniformity of ownership in the Contract Area in
the Oil and Gas Leases, wells, equipment and production covered by this
agreement no party shall sell, encumber, transfer or make other disposition of
its interest in the Oil and Gas Leases and Oil and Gas Interests embraced within
the Contract Area or in wells, equipment and production unless such disposition
covers either:
1. the entire interest of the party in all Oil and Gas Leases, wells,
equipment and production; or 2 an equal undivided percent of the party's
present interest in all Oil and Gas Leases, wells, equipment and production
in the Contract Area. Every sale, encumbrance, transfer or other
disposition made by any party shall be made expressly subject to this
agreement and shall be made without prejudice to the right of the other
parties, and any transferee of an ownership interest in any Oil and Gas
Lease shall be deemed a party to this agreement as to the interest conveyed
from and after the effective date of the transfer of ownership; provided,
however, that the other parties shall not be required to recognize any such
sale, encumbrance, transfer or other disposition for any purpose hereunder
until thirty (30) days after they have received a copy of the instrument of
transfer or other satisfactory evidence thereof in writing from the
transferor or transferee. No assignment or other disposition of interest by
a party shall relieve such party of obligations previously incurred by such
party hereunder with respect to the interest transferred, including without
limitation the obligation of a party to pay all costs attributable to an
operation conducted hereunder in which such party has agreed to participate
prior to making such assignment, and the lien and security interest granted
by Article Vll.B. shall continue to burden the interest transferred to
secure payment of any such obligations. If, at any time the interest of any
party is divided among and owned by four or more co-owners, Operator, at
its discretion, may require such co-owners to appoint a single trustee or
agent with full authority to receive notices, approve expenditures, receive
billings for and approve and pay such party's share of the joint expenses,
and to deal generally with, and with power to bind, the co-owners of such
party's interest within the scope of the operations embraced in this
agreement; however, all such co-owners shall have the right to enter into
and execute all contracts or agreements for the disposition of their
respective shares of the Oil and Gas produced from the Contract Area and
they shall have the right to receive, separately, payment of the sale
proceeds thereof.
E. Waiver of Rights to Partition: If permitted by the laws of the state or
states in which the property covered hereby is located, each party hereto
owning an undivided interest in the Contract Area waives any and all rights
it may have to partition and have set aside to it in severalty its
undivided interest therein. <deleted items>
ARTICLE IX.
INTERNAL REVENUE CODE ELECTION
If, for federal income tax purposes, this agreement and the operations hereunder
are regarded as a partnership, and if the parties have not otherwise agreed to
form a tax partnership pursuant to Exhibit "G" or other agreement between them,
each party thereby affected elects to be excluded from the application of all of
the provisions of Subchapter "K," Chapter 1, Subtitle "A," of the Internal
Revenue Code of 1986, as amended ("Code"), as permitted and authorized by
Section 761 of the Code and the regulations promulgated thereunder. Operator is
authorized and directed to execute on behalf of each party hereby affected such
evidence of this election as may be required by the Secretary of the Treasury of
the United States or the Federal Internal Revenue Service, including
specifically, but not by way of limitation, all of the returns, statements, and
the data required by Treasury Regulations ss.1.761. Should there be any
requirement that each party hereby affected give further evidence of this
election, each such party shall execute such documents and furnish such other
evidence as may be required by the Federal Internal Revenue Service or as may be
necessary to evidence this election. No such party shall give any notices or
take any other action inconsistent with the election made hereby. If any present
or future income tax laws of the state or states in which the Contract Area is
located or any future income tax laws of the United States contain provisions
similar to those in Subchapter "K," Chapter I, Subtitle "A," of the Code, under
which an election similar to that provided by Section 761 of the Code is
permitted, each party hereby affected shall make such election as may be
permitted or required by such laws. In making the foregoing election, each such
party states that the income derived by such party from operations hereunder can
be adequately determined without the computation of partnership taxable income.
ARTICLE X.
CLAIMS AND LAWSUITS
Operator may settle any single uninsured third party damage claim or suit
arising from operations hereunder if the expenditure does not exceed Ten
Thousand and O/100 Dollars ($10,000.00 ) and if the payment is in complete
settlement of such claim or suit. If the amount required for settlement exceeds
the above amount, the parties hereto shall assume and take over the further
handling of the claim or suit, unless such authority is delegated to Operator.
All costs and expenses of handling, settling, or otherwise discharging such
claim or suit shall be at the joint expense of the parties participating in the
operation from which the claim or suit arises. If a claim is made against any
party or if any party is sited on account of any matter arising from operations
hereunder over which such individual has no control because of the rights given
Operator by this agreement, such Party shall immediately notify all other
parties, and the claim or suite shall be treated as any other claim or suit
involving operations hereunder.
15
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A.A.P.L. FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
ARTICLE XI'
FORCE MAJEURE
If any party is rendered unable, wholly or in part, by force majeure to carry
out its obligations under this agreement, other than the obligation to indemnify
or make money payments or furnish security, that party shall give to all other
parties prompt written notice of the force majeure with reasonably full
particulars concerning it; thereupon, the obligations of the party giving the
notice, so far as they are affected by the force majeure, shall be suspended
during, but no longer than, the continuance of the force majeure. The term
"force majeure," as here employed, shall mean an act of God, strike, lockout, or
other industrial disturbance, act of the public enemy, war, blockade, public
riot, lightning, fire, storm, flood or other act of nature, explosion,
governmental action, governmental delay, restraint or inaction, unavailability
of equipment, and any other cause, whether of the kind specifically enumerated
above or otherwise, which is not reasonably within the control of the party
claiming suspension. The affected party shall use all reasonable diligence to
remove the force majeure situation as quickly as practicable. The requirement
that any force majeure shall be remedied with all reasonable dispatch shall not
require the settlement of strikes, lockouts, or other labor difficulty by the
party involved, contrary to its wishes; how all such difficulties shall be
handled shall be entirely within the discretion of the party concerned.
ARTICLE XII,
NOTICES
All notices authorized or required between the parties by any of the provisions
of this agreement, unless otherwise specifically provided, shall be in writing
and delivered in person or by United States mail, courier service, telegram,
telex, telecopier or any other form of facsimile, postage or charges prepaid,
and addressed to such parties at the addresses listed on Exhibit "A." All
telephone or oral notices permitted by this agreement shall be confirmed * by
written notice. The originating notice given under any provision hereof shall be
deemed delivered only when received by the party to whom such notice is
directed, and the time for such party to deliver any notice in response thereto
shall run from the date the originating notice is received. "Receipt" for
purposes of this agreement with respect to written notice delivered hereunder
shall be actual delivery of the notice to the address of the party to be
notified specified in accordance with this agreement, or to the telecopy,
facsimile or telex machine of such party. The second or any responsive notice
shall be deemed delivered when deposited in the United States mail or at the
office of the courier or telegraph service, or upon transmittal by telex,
telecopy or facsimile, or when personally delivered to the party to be notified,
provided, that when response is required within 24 or 48 hours, such response
shall be given orally or by telephone, telex, telecopy or other facsimile within
such period. Each party shall have the right to change its address at any time,
and from time to time, by giving written notice thereof to all other parties. If
a party is not available to receive notice orally or by telephone when a party
attempts to deliver a notice required to be delivered within 24 or 48 hours, (be
notice may be delivered in writing by any other method specified herein and
shall be deemed delivered in the same manner provided above for any responsive
notice.
*within forty-eight (48) hours thereafter
ARTICLE XIII,
TERM OF AGREEMENT
This agreement shall remain in full force and effect as to the Oil and Gas
Leases and/or Oil and Gas Interests subject hereto for the period of time
selected below; provided, however, no party hereto shall ever be construed as
having any right, title or interest in or to any Lease or Oil and Gas Interest
contributed by any other party beyond the term of this agreement. XX Option No.
1: 50 long as any of the Oil and Gas Leases subject to this agreement remain or
are continued in force as to any part of the Contract Area, whether by
production, extension, renewal or otherwise.
<deleted items>
The termination of this agreement shall not relieve any party hereto from any
expense, liability or other obligation or any remedy therefor which has accrued
or attached prior to the date of such termination. Upon termination of this
agreement and the satisfaction of all obligations hereunder, in the event a
memorandum of this Operating Agreement has been filed of record, Operator is
authorized to file of record in all necessary recording offices a notice of
termination, and each party hereto agrees to execute such a notice of
termination as to Operator's interest, upon request of Operator, if Operator has
satisfied all its financial obligations. ARTICLE XIV COMPLIANCE WITH LAWS AND
REGULATIONS
A. Laws, Regulations and Orders: This agreement shall be subject to
the applicable laws of the state in which the Contract Area is located, to
the valid rules, regulations, and orders of any duly constituted regulatory
body of said state; and to all other applicable federal, state regulations,
and orders of any duly constituted regulatory body of said state; and to
all other applicable federal, state, and local laws, ordinances, rules,
regulations and orders.
B. Governing Law:
This agreement and all matters pertaining hereto, including but not limited to
matters of performance, non-performance, breach, remedies, procedures, rights,
duties, and interpretation or construction, shall be governed and determined by
the law of the state in which the Contract Area is located. If the Contract Area
is in two or more states, the law of (be state of California shall govern.
C. Regulatory Agencies:
Nothing herein contained shall grant, or be construed to grant, Operator the
right or authority to waive or release any rights, privileges, or obligations
which Non-Operators may have under federal or state laws or under rules,
regulations or
16
A.A.P.L. FORM 610- MODEL FORM OPERATING AGREEMENT - 1989
orders promulgated under such laws in reference to oil, gas and mineral
operations, including the location, operation, or production of wells, on tracts
offsetting or adjacent to the Contract Area. With respect to the operations
hereunder, Non-Operators agree to release Operator from any and all losses,
damages, injuries, claims and causes of action arising out of, incident to or
resulting directly or indirectly from Operator's interpretation or application
of rules, rulings, regulations or orders of the Department of Energy or Federal
Energy Regulatory Commission * , or predecessor or successor agencies to (be
extent such interpretation or application was made in good faith and does not
constitute gross negligence. Each Non-Operator further agrees to reimburse
Operator for such Non-Operator's share of production or any refund, fine, levy
or other governmental sanction that Operator may be required to pay as a result
of such an incorrect interpretation or application, together with interest and
penalties thereon owing by Operator as a result of such incorrect interpretation
or application.
*Internal Revenue Service
ARTICLE XV.
MISCELLANEOUS
A. Execution:
This agreement shall be binding upon each Non-Operator when this
agreement or a counterpart thereof has been executed by such Non-Operator
and Operator notwithstanding that this agreement is not then or thereafter
executed by all of the parties to which it is tendered or which are listed
on Exhibit "A' as owning an interest in the Contract Area or which own, in
fact, an interest in the Contract Area. Operator may, however, by written
notice to all Non-Operators who have become bound by this agreement as
aforesaid, given at any time prior to the actual spud date of the Initial
Well but in no event later than five days prior to the date specified in
Article VI.A. for commencement of the Initial Well, terminate this
agreement if Operator in its sole discretion determines that there is
insufficient participation to justify commencement of drilling operations.
In the event of such a termination by Operator, all further obligations of
the parties hereunder shall cease as of such termination. In the event any
Non-Operator has advanced or prepaid any share of drilling or other costs
hereunder, all sums so advanced shall be returned to such Non-Operator
without interest. In the event Operator proceeds with drilling operations
for the Initial Well without the execution hereof by all persons listed on
Exhibit "A" as having a current working interest in such well, Operator
shall indemnify Non-Operators with respect to all costs incurred for the
Initial Well which would have been charged to such person under this
agreement if such person had executed the same and Operator shall receive
all revenues which would have been received by such person under this
agreement if such person had executed the same.
B. Successors and Assigns:
This agreement shall be binding upon and shall inure to the
benefit of the parties hereto and their respective heirs, devisees, legal
representatives, successors and assigns, and the terms hereof shall be
deemed to run with the Leases or
Interests included within the Contract Area.
C. Counterparts:
This instrument may be executed in any number of counterparts, each of
which shall be considered an original for all purposes.
D. Severability:
For the purposes of assuming or rejecting this agreement as an
executory contract pursuant to federal bankruptcy laws, this agreement
shall not be severable, but rather must be assumed or rejected in its
entirety, and the failure of any party to this agreement to comply with all
of its financial obligations provided herein shall be a material default.
ARTICLE XVI.
OTHER PROVISIONS
(Refer to pages 17a, 17b,17c,17d, and 17e)
17
<PAGE>
ARTICLE XVI.
OTHER PROVISIONS
A. ACQUISITION OF PROPRIETARY GEOPHYSICAL DATA:
Should any party wish to acquire or acquires any proprietary geophysical
data within the Contract Area, it shall give written notice of same to the
non-acquiring party, who shall have twenty (20) days within which to elect
whether or not to participate in said acquisition in proportion to its working
interest herein as described in Exhibit "A". Failure to respond within said
twenty (20) day period shall be deemed to be an election not to participate in
said acquisition. if any party does not agree to participate in a geophysical
data acquisition, then said data shall be excluded from this Agreement and the
non-acquiring party shall have no ownership rights in said geophysical data.
B. LIABILITY:
All liability hereunder shall be several and not joint or collective. It is
not the purpose of this Agreement, nor the intent of the parties, to create a
partnership, partnership for a specific purpose, joint venture, or any other
relationship which would render the parties liable as partners, associates or
joint venturers.
Each Non-Operator shall indemnify and hold Operator harmless against any and
all liability in excess of insurance coverage carried for the joint account for
injury to each such Non-Operator's officers, employees and/or agents, resulting
from or in any way relating to such officers, employees and/or agents presence
on a drilling rig on the Contract Area or from such person traveling by air or
water between any point and such drilling rig.
C. DELAY RENTALS:
Subject to Article VII.E., Operator shall pay all delay rentals, shut-in
royalties, and/or minimum royalties which may be required by the terms of any
lease within the Contract Area and subject to this Agreement. Non-Operator shall
promptly reimburse Operator for its share of any such payment, in accordance
with its working interest percentage as set out in Exhibit "A".
D. ORDER OF OPERATIONS:
Where a well, authorized under the terms of this Agreement has been drilled
to the Contract Depth, and if within 24 hours of delivery of the initially
proposed further operation, the parties participating in the well cannot agree
on the sequence and timing of further operations regarding such well, the
following elections shall control in order enumerated below:
1. An election to do additional logging, coring or testing;
2. An election to attempt to complete the well at either the authorized
depth or objective formation;
3. An election to deepen the well;
17a.
<PAGE>
4. An election to plug back and attempt to complete the well;
5. An election to sidetrack the well;
6. Plugging and abandonment.
It is provided, however, that if at any time while the parties
are considering the above election, the hole is in such a
condition that a reasonably prudent Operator would not conduct
the operations contemplated by the particular election involved
for fear of placing the hole in jeopardy or losing the same prior
to completing the well, such election shall not be given the
priority hereinabove set forth. In such an event, the operation
which is less likely to jeopardize the well will be conducted.
E. OBLIGATION WELL:
If any party hereto does not consent to join in the drilling of
any Obligation Well (as hereinafter defined), such "non-Drilling"
party shall assign and forfeit to the "Drilling Party or Parties"
all of its interest in the Leases or Farmout Acreage, or portion
thereof1 to the formations and/or depths covered thereby which
would be lost or not earned if such Obligation Well were not
drilled. Such assignment shall be made to the Drilling Parties
promptly after the Obligation Well is spud.
The term "Obligation Well", as used herein, shall mean any well
which must be drilled in order to prevent a termination of any
Lease or Farmout Acreage or portion thereof. In the event a
proposal to drill a well is made within 90 days from the
termination of any Lease or Farmout Acreage not otherwise held or
maintained in force and effect, such well would also be deemed an
Obligation Well.
Subject to the provisions of Article XVI.D. if less than all
parties elect to participate in a completion attempt on any
Obligation Well where production from such Obligation Well is
required to prevent the loss of any Lease, Farmout Acreage or
portion thereof, and if such completion attempt is made and
results in a well which serves to maintain such Lease, Farmout
Acreage or portion thereof in force and effect, each non-Drilling
party shall assign and forfeit its interest to the same extent as
if such party had failed to participate in the actual drilling of
the Obligation Well. Such assignment shall be made to the
Drilling Parties promptly after commencement of such completion
operations.
F. REAL COVENANT.
The terms, covenants and conditions of this Agreement shall be covenants running
with the lands and leasehold estates covered hereby and with each transfer or
assignment of said lands or leasehold estates, each party making an assignment
or transfer of any lands or leasehold estates covered hereby shall state that
such assignment or transfer is subject to all the terms, covenants and
conditions hereof. Notice of any such assignment or transfer shall promptly be
given to the Operator.
17b.
<PAGE>
G. AREA OF MUTUAL INTEREST:
1. An Area of Mutual Interest (AMI) covering the lands set forth
in Exhibit "A-i" attached hereto is hereby established between
the parties hereto to become effective as of the date of this
Operating Agreement, and shall remain in full force and effect
pursuant to Article XIII. herein.
2. Should any party subject hereto acquire an interest within the
AMI, by lease, purchase, farm-in, or otherwise, including but not
limited to leasehold interests, royalty interests, overriding
royalty interests, mineral fee interests, and non-participating
royalty interest, the acquiring party shall give, within thirty
(30) days after acquiring such interest, written notice to the
non-acquiring party setting forth a description of the acquired
interest and the consideration paid therefore. The non-acquiring
party shall make its election in writing within fifteen (15) days
after its receipt of said notice whether or not to reimburse the
acquiring party for its proportionate share of the acquisition
costs. An election to so reimburse the acquiring party shall
entitle the non-acquiring party to a recordable assignment of its
proportionate working interest in the acquired interest as soon
as possible after said reimbursement. Failure by the acquiring
party to make an election within fifteen (15) days of receipt of
said notice shall constitute an election on its part not to
reimburse the acquiring party and shall not entitle the
non-acquiring party to an assignment of such non-acquired
interest.
3. Any interest acquired pursuant to this paragraph XVIG will be
subject to the overriding royalty provided for in paragraph four
(4) of the October 13, 1997 Agreement to which this Operating
Agreement is attached as Exhibit "B".
H. CONFIDENTIALITY AND LIMITED DISCLOSURE:
Except as otherwise provided below and except for necessary disclosures to
appropriate court and governmental agencies, no party to this Agreement shall
release any "Confidential Data," which shall include but shall not be limited to
any geological, geophysical, reservoir, engineering, production, or technical
information or any logs, maps, reports, interpretations, records, data, or other
information pertaining to proposed operations, the progress, tests, or results
of any well unless agreed to, in writing, by all the participating parties. Any
party who transfers an interest hereunder to any third party shall, along with
any such third party assignee,
17c.
<PAGE>
remain subject to all of the terms and conditions set forth herein. Any party
may make Confidential Data available to affiliates, prospective purchasers of
all or a portion of its interest, reputable consulting firms, and gas
transmission companies for hydrocarbon reserve and other technical evaluations,
and to reputable financial institutions for study prior to commitment of funds.
Any third party permitted such access shall first agree in writing to be bound
by the confidentiality provisions of this Agreement, and under no circumstances
shall such third party be allowed to utilize such data for its personal
advantage or any other purposes not related to this Agreement. It shall not be a
breach of this provision if a party provides such data pursuant to a valid order
of a Federal or state Court or regulatory agency, and the party makes provision
for an appropriate protective order, if available. Releases to the news media,
industry journals, or any other published or broadcast medium concerning any
operations or other matters related to this Agreement are prohibited unless any
such proposed release is agreed to in advance in writing by all parties entitled
to the information concerning any such operations or other matters pursuant to
the terms and provisions of this Agreement. It is agreed between the parties
hereto and its successors and assigns that the terms of provision shall be
limited to the data acquired pursuant to and subject to this agreement.
I. BANKRUPTCY
If, following the granting of relief under the Bankruptcy Code to
any party as debtor thereunder, this Agreement should be held to
be an executory contract within the meaning of 11 U.S.C. Section
365, then the Operator, or (if the Operator is the debtor in
bankruptcy) any other party hereto, shall be entitled to receive
a determination by debtor, or any trustee for debtor, within
thirty days from the date an order for relief is entered under
the Bankruptcy Code, of such debtor or trustee's rejection or
assumption of this Operating Agreement. In the event of an
assumption, Operator or said other party shall be entitled to
receive adequate assurances from such debtor or trustee as to the
future performance of debtor's obligation hereunder and the
protection of the interest of all other parties hereto.
J. PARTICIPATION AGREEMENT:
The parties agree that, this Operating Agreement is subject to those certain
Participation Agreements in substantially the same form between Hamar II
Associates, LLC, and Amerada Hess Corporation, and Saba Petroleum Company, each
dated November 1, 1997. Any conflict
17d.
<PAGE>
between this Operating Agreement and the Participation Agreements1 the
Participation Agreements shall prevail.
K. WELL DATA REQUIREMENTS:
During the drilling and completion of any well drilled under the terms of
this Agreement, it is agreed that Operator shall provide the Non-Operators with
the information listed on Exhibit "G", which is attached hereto and made a part
hereof.
L. MEMORANDUM OF OPERATING AGREEMENT AND FINANCING STATEMENT:
The Parties agree that in conjunction with the execution of this
Agreement, each party will sign two (2) copies of the Memorandum of
Operating Agreement and Financing Statement ("Memorandum"), a copy of which
is attached hereto as Exhibit "H".
N. Mark A. Nahabedian, Rodney C. Hill, Rodney C. Hill, A Professional
Corporation have signed this agreement solely for purpose of expressing their
respective consents to this agreement. Neither of such signatories assumes any
personal liability or obligation, or shall derive individually any rights, under
this agreement.
17e.
<PAGE>
A.A.P.L. FORM 610 - MODEL FORM OPERATING AGREEMENT - 1989 _
IN WITNESS WHEREOF, this agreement shall be effective as of the 19th day of
November 19 97. ----------------- -------- --
2 19. :7 .
ATTEST OR WITNESS:
AMERADA HESS CORPORATION
By (signature)
J.Y. CHRISTOPHER
Type or print name
Title: ATTORNEY-IN-FACT
NOV 19 1997
Tax ID or S.S. No.
HAMAR II ASSOCIATES. LLC
By (signature)
MARK A. NAHABEDIAN
Type or print name
INDIVIDUALLY AND AS A MEMBER
RODNEY C. HILL
A PROFESSIONAL CORPORATION
By (signature)
RODNEY C. HILL
Type or print name
Title INDIVIDUALLY AND ON BEHALF OF RODNEY C.
HILL
A PROFESSIONAL CORPORATION
Date
Tax ID or S.S. No.
SABA PETROLEUM COMPANY
By (signature)
Ilyas Chaudhary
EXHIBIT "A"
Attached to and made a part of that certain Operating Agreement dated
November 1, 1997 by and between Amerada Hess Corporation, Hamar II Associates,
LLC, and Saba Petroleum Company.
(1) The lands subject to this agreement ("Contract Area") are shown
outlined on Exhibit "A-1" attached hereto.
(2) There are no restrictions as to depths, formations or substances,
except as provided for in the oil and gas leases subject to this agreement
and listed below.
(3)&(4)The Parties to this agreement and their respective working interest
percentages are as follows:
B.
A.
<TABLE>
<S> <C>
Initial Test or Substitute Test (Drilling and Completion) Post Completion
of Initial Test or Substitute Test
-----------------------
and
all subsequent wells
Amerada Hess Corporation- 60% 40%
Operator - B Non-operator - A
500 Dallas Street
One Allen Center
Houston, TX 77002
Attention: Mr. James S. Hughart
Telephone: (713) 609-5517
Facsimile: (713) 609-5608
Hamar II Associates, LLC Operator 10% 40%
Operator A
Non-operator - B
214 West Aliso St.
Ojai, CA 93023
Telephone: (805) 646-4276
Facsimile: (805) 646-3476
Saba Petroleum Company 30% 20%
Non-operator
3201 Skyway, Suite 204
Santa Maria, Ca 93455
Telephone: (805) 347-8700
Facsimile: (805) 347-1072
</TABLE>
(5) Oil and Gas Leases subject to this agreement. (See next page)
(6) Burdens on the leases not to exceed twenty-seven and one-half percent
(27.5%).
<PAGE>
Exhibit "A-1"
Attached to and made a part of that certain Operating Agreement dated November
1, 1997 by and between Amerada Hess Corporation, Hamar II Associates, LLC, and
Saba Petroleum Company.
<PAGE>
<PAGE>
COPAS - 19B4 - ONSHORE
EXHIBIT "C"
l Attached. to and made a part of that certain Operating Agreement
dated November 1 , 1997 by and between Amerada Hess Corporation Hamar II
Associates, LLC and Saba Petroleum Company.
ACCOUNTING PROCEDURE
JOINT OPERATIONS
I. GENERAL PROVISIONS
I. Definitions
16 "Joint Property" shall mean the real and personal property .subject to the
agreement to which this Accounting Procedure 17 is attached. 18 "Joint
Operations" shall mean all operations necessary or proper for the development,
operation. protection and 19 maintenance of the Joint Property. 20 "Joint
Account" shall mean the account showing the charges paid and credits received in
the conduct of the Joint 21 Operations and which are to be shared by the
Parties. 22 "Operator" shall mean the party designated to conduct the Joint
Operations. 23 "Non-Operators" shall mean the Parties to this agreement other
than the Operator. 24 "Parties" shall mean Operator and Non-Operators. 25 "First
Level Supervisors" shall mean those employees whose primary function in Joint
Operations is the direct supervision of other employees and/or contract labor
directly employed on the Joint Property in a field operating 27 capacity. 28
"Technical Employees" shall mean those employees having special and specific
engineering. geological or other 29 professional skills, and whose primary
function in Joint Operations is the handling of specific operating conditions
and :30 problems for the benefit of the Joint Property. 31 "Personal Expenses"
shall mean travel and other reasonable reimbursable expenses of Operator's
employees. 32 "Material" shall mean personal property. equipment or supplies
acquired or held for use on the Joint Property. :33 "Controllable Material"
shall mean Material which at the time is so classified in the Material
Classification Manual 'is 34 most recently recommended by the Council of
Petroleum Accountants Societies. 35 36 2. Statement and Billings 37 38 Operator
shall bill Non-Operators on or before the last day of each month for their
proportionate share of the Joint 39 Account for the preceding month. Such hills
will be accompanied by statements which identify the authority for 40
expenditure. lease or facility, and all charges and credits summarized by
appropriate classifications of investment an(l 41 expense except that items of
Controllable Material and unusual charges and credits shall be separately
identified and 12 fully described in detail. 43 44 3. Advances and Payments by
Non-Operators
A. Unless otherwise provided for in the agreement, the Operator may require the
Non-Operators to advance their share of estimated cash outlay for the succeeding
month's operation within after receipt of the billing or by the first day of the
month for which the advance is required. whichever is later. Operator shall
adjust each monthly billing to reflect advances received from the Non-Operators.
B. Each Non-Operator shall pay its proportion of all bills within thirty (30)
days after receipt. If payment is not made within such time, the unpaid balance
shall bear interest monthly at the prime rate in effect at
______________________ Chase Manhattan Bank on the first day of the month in
which delinquency occurs plus 1% or the maximum contract rate permitted by the
applicable usury laws in the state in which the Joint Property is located,
whichever is the lesser, plus attorney's fees, court costs, and other costs in
connection with the collection of unpaid amounts.
58 4. Adjustments
Payment of any such bills shall not prejudice the right of any Non-Operator to
protest or question the correctness thereof provided, however. all bills and
statements rendered to Non-Operators by Operator (during any calendar year shall
conclusively be presumed to be true and correct after twenty-four (24) months
following the end of any such calendar year, unless within the said twenty-four
(24) month period a Non-Operator takes written exception thereto and makes claim
on Operator for adjustment. No adjustment favorable to Operator shall be made
unless it is made within the same prescribed period. The provisions of this
paragraph shall not prevent adjustments resulting from a physical inventory
Controllable Material as provided for in Section V.
COPYRIGHT(C) 1985 by the Council of Petroleum Accountants Societies.
- - -1-
<PAGE>
5. Audits
A. A Non-Operator, upon notice in writing to Operator and all other
Non-Operators, shall have the right to audit Operator's accounts and records
relating to the Joint Account for any calendar year within the twenty-four (24)
month period following the end of such calendar year: provided. however. the
making of an audit shall not extend the time for the taking of written exception
to and the adjustments of accounts as provided for in Paragraph 4 of this
Section I. Where there are two or more Non-Operators. the Non-Operators shall
make every reasonable effort to conduct a joint audit in a manner which will
result in a minimum of inconvenience to the Operator. Operator shall bear no
portion of the Non-Operators' audit cost incurred under this paragraph unless
agreed to by the Operator. The audits shall not be conducted more than once each
year without prior approval of Operator, except upon the resignation or removal
of the Operator, and shall be made at the expense of those Non-Operators
approving such audit.
B. The Operator shall reply in writing to an audit report within ~8O days
after receipt of such report.
6. Approval By Non-Operators
Where an approval or other agreement of the Parties or Non-Operators is
expressly required under other sections of this Accounting Procedure and if the
agreement to which this Accounting Procedure is attached contains no contrary
provisions in regard thereto, Operator shall notify all Non-Operators of the
Operator's proposal, and the agreement or approval of a majority in interest of
the Non-Operators shall be controlling on all Non-Operators.
II. DIRECT CHARGES
Operator shall charge the Joint Account with the following items:
1. Ecological and Environmental
Costs incurred for the benefit of the Joint Property as a result of governmental
or regulatory requirements to satisfy environ-mental considerations applicable
to the Joint Operations. Such costs may include surveys of an ecological or
archaeological nature and pollution control procedures as required by applicable
laws and regulations.
2. Rentals and Royalties
Lease rentals and royalties paid by Operator for the Joint Operations.
3. Labor
A. (1) Salaries and wages of Operator's field employees directly
employed on the Joint Property in the conduct of Joint Operations.
(2) Salaries of First Level Supervisors in the field.
(3) Salaries and wages of Technical Employees directly employed on
the Joint Property if such charges are excluded from the overhead
rates
(4) Salaries and wages of Technical Employees either temporarily or
permanently assigned to and directly employed in the operation of
the Joint Property if such charges are excluded from the overhead
rates.
B. Operator's cost of holiday, vacation, sickness and disability benefits
and other customary allowances paid to employees whose salaries and wages are
chargeable to the Joint Account under Paragraph 3A of this Section II. Such
costs under this Paragraph 3B may be charged on a "when and as paid basis" or by
"percentage assessment" on the amount of salaries and wages chargeable to the
Joint Account under Paragraph 3A of this Section II. If percentage assessment is
used, the rate shall be based on the Operator's cost experience.
C. Expenditures or contributions made pursuant to assessments
imposed by governmental authority which are applicable to
Operator's costs chargeable to the Joint Account under Paragraphs
3A and 3B of this Section II.
D. Personal Expenses of those employees whose salaries and wages are
chargeable to the Joint Account under Paragraph 3A of this Section II.
4. Employee Benefits
Operator's current costs of established plans for employees' group life
insurance, hospitalization, pension, retirement, stock purchase, thrift, bonus,
and other benefit plans of a like nature, applicable to Operator's labor cost
chargeable to the Joint Account under Paragraphs 3A and 3B of this Section II
shall be Operator's actual cost not to exceed the percent most recently
recommended by the Council of Petroleum Accountants Societies.
5, Material
Material purchased or furnished by Operator for use on the Joint Property as
provided under Section TV. Only such Material shall be purchased for or
transferred to the Joint Property as may be required for immediate use and is
reasonably practical and consistent with efficient and economical operations.
The accumulation of surplus stocks shall be avoided.
6. Transportation
Transportation of employees and Material necessary for the Joint Operations but
subject to the following limitations:
A. If Material is moved to the Joint Property from the Operator's warehouse or
other properties, no charge shall be made to the Joint Account for a distance
greater than the distance from the nearest reliable supply store where like
material is normally available or railway receiving point nearest the Joint
Property unless agreed to by the Parties.
2
<PAGE>
B. If surplus Material is moved to Operator's warehouse or other storage
point, no charge shall be made to the Joint Account for a distance greater than
the distance to the nearest reliable supply store where like material is
normally available, or railway receiving point nearest the Joint Property unless
agreed to by the Parties. No charge shall be made to the Joint Account for
moving Material to other properties belonging to Operator, unless agreed to by
the Parties.
C. In the application of subparagraphs A and B above, the option to
equalize or charge actual trucking cost is available when the actual charge
is $400 or less excluding accessorial charges. The $400 will be adjusted to
the amount most recently recommended by the Council of Petroleum
Accountants Societies.
7.Services
The cost of contract services, equipment and utilities provided by outside
sources, except services excluded by Paragraph 10 of Section II and
Paragraph iii, and iii, of Section III. The cost of professional consultant
services and contract services of technical personnel directly engaged on
the Joint Property if such charges are excluded from the overhead rates.
The cost of professional consultant services or contract services of
technical personnel not directly engaged on the Joint Property shall not be
charged to the Joint Account unless previously agreed to by the Parties.
8. Equipment and Facilities Furnished By Operator
A. Operator shall charge the Joint Account for use of Operator owned
equipment and facilities at rates commensurate with costs of
ownership and operation. Such rates shall include costs of
maintenance, repairs, other operating expense. insurance, taxes,
depreciation, and interest on gross investment less accumulated
depreciation not to exceed eleven percent (11%) per annum. Such
rates shall not exceed average commercial rates currently
prevailing in the immediate area of the Joint Property.
B. In lieu of charges in paragraph 8A above, Operator may elect to
use average commercial rates prevailing in the immediate area of
the Joint Property less 20%. For automotive equipment, Operator
may elect to use rates published by the Petroleum Motor Transport
Association.
9. Damages and Losses to Joint Property
All costs or expenses necessary for the repair or replacement of Joint Property
made necessary because of damages or losses incurred by fire, flood, storm,
theft, accident, or other cause, except those resulting from Operator's gross
negligence or willful misconduct. Operator shall furnish Non-Operator written
notice of damages or losses incurred as soon as practicable after a report
thereof has been received by Operator.
10. Legal Expense
Expense of handling, investigating and settling litigation or claims,
discharging of liens, payment of judgements and amounts paid for settlement of
claims incurred in or resulting from operations under the agreement or necessary
to protect or recover the Joint Property, except that no charge for services of
Operator's legal staff or fees or expense of outside attorneys shall be made
unless previously agreed to by the Parties. All other legal expense is
considered to be covered by the overhead provisions of Section III unless
otherwise agreed to by the Parties, except as provided in Section I, Paragraph
3.
11. Taxes
All taxes of every kind and nature assessed or levied upon or in connection with
the Joint Property, the operation thereof. or the production therefrom, and
which taxes have been paid by the Operator for the benefit of the Parties. If
the ad valorem taxes are based in whole or in part upon separate valuations of
each party's working interest. then notwithstanding anything to the contrary
herein, charges to the Joint Account shall be made and paid by the Parties
hereto in accordance with the tax value generated by each party's working
interest.
12. Insurance
Net premiums paid for insurance required to be carried for the Joint Operations
for the protection of the Parties. In the event Joint Operations are conducted
in a state in which Operator may act as self-insurer for Worker's Compensation
and/or Employers Liability under the respective state's laws. Operator may. at
its election, include the risk under its self-insurance program and in that
event. Operator shall include a charge at Operator's cost not to exceed manual
rates.
13. Abandonment and Reclamation
Costs incurred for abandonment of the Joint Property, including costs required
by governmental or other regulatory authority.
14. Communications
Cost of acquiring. leasing, installing, operating, repairing and maintaining
communication Systems, including radio and microwave facilities directly serving
the Joint Property. In the event communication facilities/systems serving the
joint Property are Operator owned, charges to the Joint Account shall be made as
provided in Paragraph 8 of this Section II.
15. Other Expenditures
Any other expenditure not covered or dealt with in the foregoing provisions
of this Section II. or in Section III and which is of direct benefit to the
joint Property and is incurred by the Operator in the necessary and proper
conduct of the Joint Operations.
3
<PAGE>
III. OVERHEAD
1. Overhead - Drilling and Producing Operations
i. As compensation for administrative, supervision, office services and
warehousing costs, Operator shall charge drilling and producing operations on
either:
(XX) Fixed Rate Basis, Paragraph lA,
( ) or ( ) Percentage Basis, Paragraph lB
Unless otherwise agreed to by the Parties, such charge shall be in lieu of costs
and expenses of all offices and salaries or wages plus applicable burdens and
expenses of all personnel, except those directly chargeable under Paragraph 3A,
Section 11. The cost and expense of services from outside sources in connection
with matters of taxation, traffic, accounting or matters before or involving
governmental agencies shall be considered as included in the overhead rates
provided for in the above selected Paragraph of this Section III unless such
cost and expense are agreed to by the Parties as a direct charge to the Joint
Account.
ii.The salaries, wages and Personal Expenses of Technical Employees and/or
the cost of professional consultant services and contract services of technical
personnel directly employed on the Joint Property:
( ) shall be covered by the overhead rates, or
(XX) shall not be covered by the overhead rates.
iii. The salaries, wages and Personal Expenses of Technical Employees and/or
costs of professional consultant services and contract services of technical
personnel either temporarily or permanently assigned to and directly employed in
the operation of the Joint Property:
(X~ shall be covered by the overhead rates. or
( ) shall not be covered by the overhead rates.
A. Overhead - Fixed Rate Basis
(1) Operator shall charge the Joint Account at the following rates per well per
month:
Drilling Well Rate $5,750.00
(Prorated for less than a full month)
Producing Well Rate $575.50
(2) Application of Overhead - Fixed Rate Basis shall be as follows:
(a) Drilling Well Rate
(1) Charges for drilling wells shall begin on the date the well is spudded and
terminate on the date the drilling rig, completion rig, or other units used in
completion of the well is released, whichever is later, except that no charge
shall be made during suspension of drilling or completion operations for fifteen
(15) or more consecutive calendar days.
(2) Charges for wells undergoing any type of workover or recompletion for a
period of five (5) consecutive work days or more shall be made at the drilling
well rate. Such charges shall be applied for the period from date workover
operations, with rig or other units used in workover, commence through date of
rig or other unit release, except that no charge shall be made during suspension
of operations for fifteen (15) or more consecutive calendar days.
(b) Producing Well Rates
(I) An active well either produced or injected into for any portion of the
month shall be considered as a one-well charge for the entire month. (2)
Each active completion in a multi-completed well in which production is not
commingled down hole shall be considered as a one-well charge providing
each completion is considered a separate well by the governing regulatory
authority.
(3) An inactive gas well shut in because of overproduction or failure of
purchaser to take the production shall be considered as a one-well charge
providing the gas well is directly connected to a permanent sales outlet.
(4) A one-well charge shall be made for the month in which plugging and
abandonment operations are completed on any well. This one-well charge
shall be made whether or not the well has produced except when drilling
well rate applies.
(5) All other inactive wells (including but not limited to inactive wells
covered by unit allowable, lease allowable, transferred allowable, etc.)
shall not qualify for an overhead charge.
(3) The well rates shall be adjusted as of the first day of April each year
following the effective date of the agreement to which this Accounting Procedure
is attached. The adjustment shall be computed by multiplying the rate currently
in use by the percentage increase or decrease in the average weekly earnings of
Crude Petroleum and Production Workers for the last calendar year compared to
the calendar year preceding as shown by the index of average weekly earnings of
Crude Petroleum and Production Workers as published by the United States
Department of Labor, Bureau of Labor Statistics, or the equivalent Canadian
index as published by Statistics Canada. as applicable. The adjusted rates shall
be the rates currently in use. plus or minus the computed adjustment.
- - -4-
<PAGE>
2. Overhead - Major Construction
To compensate Operator for overhead costs incurred in the construction and
installation of fixed assets, the expansion of fixed assets, and any other
project clearly discernible as a fixed asset required for the development and
operation of the Joint Property, Operator shall either negotiate a rate prior to
the beginning of construction, or shall charge the Joint Account for overhead
based on the following rates for any Major Construction project in excess of $
A. 5% of first $100,000 or total cost if less, plus B. 3% of costs in excess of
$100,000 but less than $1,000,000, plus C. 2% of costs in excess of $1,000,000.
Total cost shall mean the gross cost of any one project. For the purpose of
this paragraph, the component parts of a single project shall not be
treated separately and the cost of drilling and workover wells and
artificial lift equipment shall be excluded.
3. Catastrophe Overhead
To compensate Operator for overhead costs incurred in the event of expenditures
resulting from a single occurrence due to oil spill, blowout, explosion, fire,
storm, hurricane, or other catastrophes as agreed to by the Parties, which are
necessary to restore the Joint Property to the equivalent condition that existed
prior to the event causing the expenditures, Operator shall either negotiate a
rate prior to charging the Joint Account or shall charge the Joint Account for
overhead based on the following rates: A. 5% of total costs through $100,000;
plus B. 3% of total costs in excess of $100,000 but less than $1,000,000; plus
C. 2% of total costs in excess of $1,000,000.
Expenditures subject to the overheads above will not be reduced by insurance
recoveries, and no other overhead provisions of this Section III shall apply.
4. Amendment of Rates
The overhead rates provided for in this Section III may be amended from time to
time only by mutual agreement between the Parties hereto if, in practice, the
rates are found to be insufficient or excessive.
IV. PRICING OF JOINT ACCOUNT MATERIAL PURCHASES, TRANSFERS AND DISPOSITIONS
Operator is responsible for Joint Account Material and shall make proper and
timely charges and credits for all Material movements affecting the Joint
Property. Operator shall provide all Material for use on the Joint Property;
however, at Operator's option, such Material may be supplied by the
Non-Operator. Operator shall make timely disposition of idle and/or surplus
Material, such disposal being made either through sale to Operator or
Non-Operator, division in kind, or sale to outsiders. Operator may purchase, but
shall be under no obligation to purchase, interest of Non-Operators in surplus
condition A or B Material. The disposal of surplus Controllable Material not
purchased by the Operator shall be agreed to by the Parties.
I. Purchases
Material purchased shall be charged at the price paid by Operator after
deduction of all discounts received. In case of Material found to be
defective or returned to vendor for any other reasons, credit shall be
passed to the Joint Account when adjustment has been received by the
Operator.
2. Transfers and Dispositions
Material furnished to the Joint Property and Material transferred from the
Joint Property or disposed of by the Operator, unless otherwise agreed to
by the Parties, shall be priced on the following basis exclusive of cash
discounts:
- - -5-
<PAGE>
A. New Material (Condition A)
(1) Tubular Goods Other than Line Pipe
(a) Tubular goods, sized 2 3/8 inches OD and larger except line pipe. shall be
priced at Eastern mill published carload base prices effective as of date of
movement plus transportation cost using the 80,000 pound carload weight basis to
the railway receiving point nearest the Joint Property for which published rail
rates for tubular goods exist. If the 80,000 pound rail rate is not offered. the
70,000 pound or 90,000 pound rail rate may be used. Freight charges for tubing
will be calculated from Lorain, Ohio and casing from Youngstown, Ohio.
(b) For grades which are special to one mill only. prices shall be computed at
the mill base of that mill plus transportation cost from that mill to the
railway receiving point nearest the Joint Property as provided above in
Paragraph 2.A.(l)(a). For transportation cost from points other than Eastern
mills, the 30,000 pound Oil Field Haulers Association interstate truck rate
shall be used.
(c) Special end finish tubular goods shall be priced at the lowest
published out-of-stock price. f.o.b. Houston. Texas, plus transportation
cost, using Oil Field Haulers Association interstate 30,000 pound truck
rate. to the railway receiving point nearest the Joint Property.
(d) Macaroni tubing (size less than 2 3/8 inch OD) shall be priced at the lowest
published out-of-stock prices f.o.b. the supplier plus transportation costs,
using the Oil Field Haulers Association interstate truck rate per weight of
tubing transferred, to the railway receiving point nearest the Joint Property.
(2) Line Pipe
(a) Line pipe movements (except size 24 inch OD and larger with walls 3/4
inch and over) 30,000 pounds or more shall be priced under provisions of
tubular goods pricing in Paragraph A.(I)(a) as provided above. Freight
charges shall be calculated from Lorain, Ohio.
(b) Line pipe movements (except size 24 inch OD and larger with walls 3/4 inch
and over) less than 30,000 pounds shall be priced at Eastern mill published
carload base prices effective as of date of shipment, plus 20 percent. plus
transportation costs based on freight rates as set forth under provisions of
tubular goods pricing in Paragraph A.(l)(a) as provided above. Freight charges
shall be calculated from Lorain, Ohio.
(c) Line pipe 24 inch OD and over and3/4inch wall and larger shall be
priced f.o.b. the point of manufacture at current new published prices plus
transportation cost to the railway receiving point nearest the Joint
Property.
(d) Line pipe, including fabricated line pipe, drive pipe and conduit not listed
on published price lists shall be priced at quoted prices plus freight to the
railway receiving point nearest the Joint Property or at prices agreed to by the
Parties.
(3) Other Material shall be priced at the current new price, in effect at date
of movement, as listed by a reliable supply store nearest the Joint Property, or
point of manufacture, plus transportation costs, if applicable, to the railway
receiving point nearest the Joint Property.
(4) Unused new Material, except tubular goods, moved from the Joint Property
shall be priced at the current new price, in effect on date of movement, as
listed by a reliable supply store nearest the Joint Property, or point of
manufacture, plus transportation costs, if applicable, to the railway receiving
point nearest the Joint Property. Unused new tubulars will be priced as provided
above in Paragraph 2 A (1) and (2).
B. Good Used Material (Condition B)
Material in sound and serviceable condition and suitable for
reuse without reconditioning:
(1) Material moved to the Joint Property
At seventy-five percent (75%) of current new price, as determined by Paragraph
A.
(2) Material used on and moved from the Joint Property
(a) At seventy-five percent (75%) of current new price, as determined by
Paragraph A, if Material was originally charged to the Joint Account as new
Material or (b) At sixty-five percent (65%) of current new price, as
determined by Paragraph A, if Material was originally charged to the Joint
Account as
used Material.
(3) Material not used on and moved from the Joint Property At seventy-five
percent (75%) of current new price as determined by Paragraph A.
The cost of reconditioning, if any, shall be absorbed by the transferring
property.
C. Other Used Material
(1) Condition C
Material which is not in sound and serviceable condition and not suitable for
its original function until after reconditioning shall be priced at fifty
percent (50%) of current new price as determined by Paragraph A. The cost of
reconditioning shall be charged to the receiving property, provided Condition C
value plus cost of reconditioning does not exceed Condition B value.
- - -6-
<PAGE>
(2)Condition D
Material, excluding junk, no longer suitable for its original purpose, but
usable for some other purpose shall be priced on a basis commensurate with its
use. Operator may dispose of Condition D Material under procedures normally used
by Operator without prior approval of Non-Operators.
(a) Casing, tubing, or drill pipe used as line pipe shall be priced as
Grade A and B seamless line pipe of comparable size and weight. Used
casing, tubing or drill pipe utilized as line pipe shall be priced at used
line pipe prices.
(b) Casing. tubing or drill pipe used as higher pressure service lines
than standard line pipe, e.g. power oil lines. shall be priced under normal
pricing procedures for casing, tubing, or drill pipe. Upset tubular goods
shall be priced on a non upset basis.
(3) Condition E
Junk shall be priced at prevailing prices. Operator may dispose of condition E
Material under procedures normally utilized by Operator without prior approval
of Non-Operators.
D. Obsolete Material
Material which is serviceable and usable for its original function but condition
and/or value of such Material is not equivalent to that which would justify a
price as provided above may be specially priced as agreed to by the Parties.
Such price should result in the Joint Account being charged with the value of
the service rendered by such Material.
E. Pricing Conditions
(1) loading or unloading costs may be charged to the Joint Account at the rate
of twenty-five cents (25(cent)) per hundred weight on all tubular goods
movements, in lieu of actual loading or unloading costs sustained at the
stocking point. The above rate shall be adjusted as of the first day of April
each year following January 1, 1985 by the same percentage increase or decrease
used to adjust overhead rates in Section III, Paragraph 1.A(3). Each year, the
rate calculated shall be rounded to the nearest cent and shall be the rate in
effect until the first day of April next year. Such rate shall be published each
year by the Council of Petroleum Accountants Societies.
(2) Material involving erection costs shall be charged at applicable
percentage of the current knocked-down price of new Material.
3. Premium Prices
Whenever Material is not readily obtainable at published or listed prices
because of national emergencies, strikes or other unusual causes over which the
Operator has no control, the Operator may charge the Joint Account for the
required Material at the Operator's actual cost incurred in providing such
Material, in making it suitable for use, and in moving it to the Joint Property;
provided notice in writing is furnished to Non-Operators of the proposed charge
prior to billing Non-Operators for such Material. Each Non-Operator shall have
the right, by so electing and notifying Operator within ten days after receiving
notice from Operator, to furnish in kind all or part of his share of such
Material suitable for use and acceptable to Operator.
4. Warranty of Material Furnished By Operator
Operator does not warrant the Material furnished. In case of defective
Material, credit shall not be passed to the Joint Account until adjustment
has been received by Operator from the manufacturers or their agents.
V. INVENTORIES
The Operator shall maintain detailed records of Controllable Material.
1 Periodic Inventories, Notice and Representation
At reasonable intervals, inventories shall be taken by Operator of the Joint
Account Controllable Material. Written notice of intention to take inventory
shall be given by Operator at least thirty (30) days before any inventory is to
begin so that Non-Operators may be represented when any inventory is taken.
Failure of Non-Operators to be represented at an inventory shall bind
Non-Operators to accept the inventory taken by Operator.
2. Reconciliation and Adjustment of Inventories
Adjustments to the Joint Account resulting from the reconciliation of a physical
inventory shall be made within six months following the taking of the inventory.
Inventory adjustments shall be made by Operator to the Joint Account for
overages and shortages, but, Operator shall be held accountable only for
shortages due to lack of reasonable diligence.
3. Special Inventories
Special inventories may be taken whenever there is any sale, change of interest,
or change of Operator in the Joint Property. It shall be the duty of the party
selling to notify all other Parties as quickly as possible after the transfer of
interest takes place. In such cases, both the seller and the purchaser shall be
governed by such inventory. In cases involving a change of Operator, all Parties
shall be governed by such inventory.
4. Expense of Conducting Inventories
A. The expense of conducting periodic inventories shall not be charged to the
Joint Account unless agreed to by the Parties.
B. The expense of conducting special inventories shall be charged to
the Parties requesting such inventories. except inventories required due to
change of Operator shall be charged to the Joint Account.
- - -7-
<PAGE>
Exhibit "D"
Attached to and made a part of that certain Joint Operating
Agreement dated November 1, 1997 by and between
Amerada Hess Corporation, Hamar II Associates, LLC, and
Saba Petroleum Company
INSURANCE
At all times while operations are conducted, Operator shall either qualify
as a self-insurer under applicable federal and state laws or maintain in
force for its protection and the parties the following insurance coverage:
Workers' Compensation Insurance to cover full liability under the Workers'
Compensation Law of Texas and any other applicable law.
Employers' Liability Insurance with a limit of $100,000 each occurrence.
All insurance purchased or carried for the parties by Operator shall, to the
extent possible, provide for waiver of insurers' rights of subrogation against
all parties. No insurance, other than that described above, shall be carried for
the benefit of the parties by Operator. Each party individually may acquire
insurance as it deems prudent to protect itself against any
uninsured/self-insured losses or exposures; provided, however, such insurance
shall contain a waiver of insurers' rights of subrogation against all other
parties to the monetary extent the party so insured is obligated under this
agreement to bear its share of losses.
For the protection of the parties. Operator shall require contractors performing
work to obtain and maintain all insurance and bonds as may be required by any
applicable law, regulation, rule or contract and any other insurance and bonds
as Operator deems prudent to require. To the extent possible, any indemnities
Operator is able to obtain from contractors shall also be for the benefit of
other parties.
<PAGE>
EXHIBIT "E"
TO OPERATING AGREEMENT
dated November 1 , 1997 by and between Amerada Hess Corporation,
Hamar II Associates, LLC, Saba Petroleum Company.
GAS BALANCING AGREEMENT
(ONSHORE)
1. General Provisions
1.1 Scope. It is the intent of this Agreement that during the productive life of
the oil and gas leases subject to the Operating Agreement, the parties shall
have had the opportunity to share in the total cumulative production from the
leases in proportion to their working interests as Set out in the Operating
Agreement. This Agreement is intended to promote that purpose and to protect
each party against other parties receiving more than their proportionate share
or the total cumulative production. For the purposes of this Agreement, at
volumes and amounts of gas shall be thermally adjusted so that such volumes and
amounts shall be reported and balanced hereunder on a BTU equivalent basis. For
the purposes of determining cumulative production hereunder. gas used in tease
operations. vented or lost shall be excluded.
1.2 Definitions. As used in this Agreement:
Cumulative overproduction means the amount by which the cumulative volume
of gas taken by a party within a category or gas exceeds the cumulative
volume that party was entitled to take within such category according to
its working interest.
Cumulative Underproduction means the amount by which the cumulative volume
or gas taken by a party within a category is less than the cumulative
volume that party was entitled to lake within such category according to
its working interest. Make-Up Gas means the volume taken by an
Underproducer to make up Cumulative
Underproduction pursuant to Paragraph 23 below.
Nonaffilliate as it relates to a party means any corporation
or other business organization not in control of and not controlled by and not
under common control with such party.
Overproducer means a party charged with Cumulative
Overproduction.
Underproducer means a party credited with Cumulative
Underproduction.
1.3 Balancing by Category. Volumetric balancing hereunder shall apply separately
to each category established by law, regulation or governmental order for the
purposed setting a ceiling price for gas. including but not limited to
categories established by the Natural Gas Policy Acto of 1978 and the Federal
Energy Regulatory Commission. All gas which is now or hereafter becomes
unregulated as to price shall be considered a separate category. In all cases
involving he revision of a category. any Cumulative Overproduction and
Cumulative Underproduction accrued prior to the revision shall remain in the
previous category and not be carried forward to the category as revised.
Underproduction of one category of gas shall not be recouped by overproduction
of any other category of gas.
2. Gas Balances
2.1 Gas Imbalances. Notwithstanding anything to the contrary in the Operating
Agreement. if any party lakes and disposes of less than its working interest
share of gas (including casinghead gas) produced and saved during any calendar
month. the volume not taken by such party may be taken by any other party or
parties hereto. if such volume is taken by more than one party. Each taking
party shall be entitled to take the proportion thereof that its working interest
beans to the sum of the working interests of all taking parties, or in such
other proportions as the taking parties may agree upon among themselves.
2.2 Operators Statements. On or before the end of each calendar month. Operator
shall furnish the parties with a written statement showing for each category (a)
the total volume of gas taken by each party during the preceding calendar month:
(b) the Make-Up Gas taken by each party during that month: and (c) the
Cumulative Overproduction or Cumulative Underproduction, if any, of each party
as of the end of that month.
2.3 MakeUp Underproduction. Parties desiring to make up cumulative
underproduction must give the Operator 30 days prior written notice. Until their
individual accounts are no longer in an underproduced status. underproduced
parties desiring to make up cumulative underproduction shall have the collective
right to take or deliver gas to its purchaser under the formula: total
underbalance/365 - total daily makeup share (in addition to entitlement) by
underproduced parties. from all overproduced parties, provided that an
individual party's right to take such additional amount shall be in the
proportion that its working interest beans to the total working interest of all
underproduced parties desiring to make up. white such underproduction is being
made up, each overproduced party shall reduce its respective share of production
in the proportion that such party's working interest bears to the total working
interest of all overproduced parties. but in no event shall any overproduced
party be required to reduce its gas takes to less than 50 percent (50%) of such
overproduced party's working interest share of current production. Once an
underproduced party begins making up underproduction it shall continue to do so
until the account becomes balanced. An underproduced party shall have the right
to cease taking makeup gas only if it loses its gas market. It must continue to
make up underbalance once market is regained.
2.4 Oil and Other Minerals. Regardless of the volume of gas actually taken by
any party hereto, such party shall share, as otherwise provided in the Operating
Agreement, in the production of crude oil, condensate and other minerals
separated from the gas in facilities operated for the joint account.
2.5 Costa and Expenses. Regardless of the volume of gas actually taken by
any party hereto, such party shall bear costs and expenses as otherwise
provided in the Operating Agreement.
3. Cash Balancing
3.1 Termination: If all parties have not achieved volumetric gas balance in all
categories upon termination of the Operating Agreement or upon a permanent
cessation of all gas production thereunder. Operator shall furnish to all
parties a statement showing the final Cumulative Overproduction and Cumulative
Underproduction of each party by category. and the month and year in which it
accrued. In determining the timing of accruals. MakeUp Gas shall be applied
against Cumulative Overproduction and Cumulative Underproduction on a first in
first out basis. Within sixty (60) days after receipt of operating statement,
each Overproducer shall furnish to all other parties a statement showing the
value of its Cumulative Overproduction for each category. based on the price the
Overproducer actually received for the gas in a sale to a Nonaffiliate during
the months in which the Cumulative Overproduction accrued, less all payments
made by The Overproducer pursuant to Paragraph 4 below. In the absence of a sale
to a Nonaffiliate, value shall be based on the weighted average price received
by the parties hereto in sales to Nonaffiliates during the month in question or
such other method as is appropriate to determine the fair market value of the
gas. Each upon the statements furnished by Overproducers. the net amount owed by
or to each party for all categories combined shall be calculated by Operator and
furnished to all parties in a final cash balancing statement.
3.2 Dispositions. In the event any party sells, assigns. or otherwise transfers
any of its interest In the leases to which this Agreement applies, and if at the
time of such disposition such party is an Overproducer. any Underproducer shall
receive, upon written request made within sixty (60) days of being notified of
such disposition, an immediate cash balancing of its share of the Cumulative
Overproduction of the disposing party in accordance with the concepts set forth
in this Agreement. In addition. in the event there is a permanent cessation of
all gas production from a particular category of gas, an Underproducer shall
receive, upon written request made within sixty (60) days of such cessation an
immediate cash balance of its share of the Cumulative Overproduction of the
Overproducer as to that category of gas in accordance with the concepts set
forth in this Agreement. The provisions of this section shall not be applicable
in the event an overproduced party has disposed of its interest by transfer of
its assets, in whole or in part to a subsidiary or parent company in which such
parent or subsidiary owns a majority interest in such overproduced party.
3.3 Settlements. Any underproduced party may demand in writing within forty-five
(45) days after receipt of the overproduced party's notice, natural gas or like
grade. quantity and quality from another mutually agreeable source. If ninety
(90) days after the overproduced party receives the underproduced parties'
written demand the parties cannot reach agreement to said natural gas of like
grade, quantity end quality from another mutually agreeable source, then the
parties shall elect a cash settlement. Any monetary settlement between the
parties shall be made net of any royalties. production taxes, transportation
charges and any severance taxes previously paid on the overproduction by the
overproduced party, and also net of any outstanding amounts related to the
lease(s) or unit which are owned by the underproduced party to the overproduced
party.
4. Payments on Production
Each party shall pay all production or severance taxes, excise taxes. royalties.
overriding royalties, production payments and other such payments on production
which it is obligated by law or by lease or by contract (including the Operating
Agreement). and nothing in this Gas Balancing Agreement shall be construed as
affecting such obligations. Each party hereto agrees to indemnity and hold
harmless the other parties hereto against all claims, losses or liabilities
arising out of its failure to fulfil such obligations.
<PAGE>
5. Complete Taking by Overproducer
In any situation in which there exists an imbalance of gas,
Operator shall make every effort to determine the point in time
when an Overproducer has taken and produced one hundred percent
(100%) of its working interest share of gas reserves for a
particular category of gas. Upon notice by Operator that it
believes that such point in time has been reached. Operator shall
suspend delivery of such gas to such Overproducer and each
Underproducer shall be entitled to take one hundred percent
(100%) of production as to that category until recovery of its
Cumulative Underproduction for that category. and from the time
of such notice until such recovery. the Overproducer shall have
no rights to the gas from such category. Notwithstanding the
above, if at any time the Underproducers fail to take on hundred
percent (100%) of such production. then at such time. all other
parties. including the Overproducer. shall be entitled to produce
and sell the gas the Underproducers fail to take as provided for
in this Paragraph
6. Choice of Law
This Agreement and all matters pertaining hereto, including, but not
limited to matters of performance, non-performance. breach,
remedies, procedures. rights. duties and interpretation or
construction, shall be governed and determined by the law of the
State of California.
7. Dispute Settlement
Any dispute arising out of or relating to this agreement shell be
settled by binding arbitration in accordance with the rules of
the American Arbitration Association. Each party shall appoint an
arbitrator and the two so appointed shall select a third
arbitrator within sixty (60) days. The award of any two
arbitrators shall be conclusive upon the party judgement upon the
award may be entered in any court having jurisdiction thereof.
The arbitrators shall not award punitive damages in settlement of
any controversy or claim. The fees and expenses of arbitration
shall be born equally by the parties hereto. The parties agree to
be bound by the result of arbitration and hereby waive any right
to appeal the award. Any arbitration proceedings shall take place
in Houston, Texas.
<PAGE>
Exhibit "F"
Attached to and made a part of that certain Joint Operating
Agreement dated November 1, 1997
between Amerada Hess Corporation Hamar II Associates, LLC,
and Saba Petroleum Company.
In order to insure compliance with the Equal Employment Opportunity provisions
of Executive Orders 11246, 11375 and 11701, Operator agrees and certifies as
follows:
A. Operator is aware of and is fully informed of Operator's responsibilities
under Executive Orders 11246, 11375 and 11701, and shall file compliance reports
as required by Section 203 of Executive Order 11246 and otherwise comply with
the requirements of such orders and with all rules and regulations promulgated
thereunder, including but not limited to, 41 CFR Part 60-1, 41 CFR Part 60-2 and
41 CFR Part 50-250, and all amendments or additions thereto.
B. During the performance of this contract, Operator shall be bound by and
agrees to the following provisions as contained in Section 202 of Executive
Order 11246, to-wit:
1. The Operator will not discriminate against any employee or applicant for
employment because of race, color, religion, sex, age or national origin. Such
action shall include, but not be limited to, the following: employment,
upgrading, demotion or transfer; recruitment or recruitment advertising; lay-off
or termination; rates of pay or other forms of compensation, and selection for
training including apprenticeship. The Operator agrees to post in conspicuous
places available to employees and applicants for employment, notices to be
provided by the contracting officer setting forth the provisions of this
non-discrimination clause.
2. The Operator will, in all solicitations or advertisements for employees
placed by or on behalf of the Operator, state that all qualified applicants
will receive consideration for employment without regard to race, color,
religion, sex, age or national origin.
3. The Operator will send to each labor union or representative of workers with
which he has a collective bargaining agreement or other contract or
understanding, a notice, to be provided by the agency or other contracting
officer, advising the labor union or worker's representative of the Operator's
commitments under Section 202 of Executive Order 11 248 of September 24, 1 965,
and shall post copies of the notice in conspicuous places available to employees
and applicants for employment.
4. The Operator will comply with all provisions of Executive Order 11 246
of September 24, 1 965, and of the rules, regulations and relevant orders
of the Secretary of Labor.
5. The Operator will furnish all information and reports required by Executive
Order 11246 of September 24, 1 965, and by the rules, regulations and orders of
the Secretary of Labor, or pursuant thereto, and will permit access to his
books, records and accounts by the contracting agency and the Secretary of Labor
for purposes of investigation to ascertain compliance with such rules,
regulations and orders.
6. In the event of the Operator's noncompliance with the non-discrimination
clauses of this contract or with any of such rules, regulations or orders, this
contract may be cancelled, terminated or suspended in whole or in part and the
Operator may be declared ineligible for further Government contracts in
accordance with procedures authorized in Executive Order 11246 of September 24,
1965, and such other sanctions may be imposed and remedies invoked as provided
in Executive Order 11 246 of September 24, 1 965, or by rule, regulation or
order of the Secretary of Labor, or as otherwise provided by law.
7. The Operator will include the provisions of paragraphs 1. through
7. in every subcontract or purchase order unless exempted by rules,
regulations or orders of the <PAGE>
Secretary of Labor issued pursuant to Section 204 of Executive Order 11 246 of
September 24, 1 965, 50 that such provisions will be binding upon each
subcontractor or vendor. The Operator will take such action with respect to any
subcontract or purchase order as the contracting agency may direct as a means of
enforcing such provisions including sanctions for noncompliance; provided,
however, that in the event the Operator becomes involved in, or is threatened
with, litigation with a subcontractor or vendor as a result of such direction by
the contracting agency, the Operator may request the United States to enter into
such litigation to protect the interests of the United States.
<PAGE>
C Operator certifies that he does not maintain or provide for his
employees any segregated facilities at any of his establishments, and
that he does not permit his employees to perform their services at any
location, under his control, where segregated facilities are
maintained. He certifies further that he will not maintain or provide
for his employees any segregated facilities at any of his
establishments, and that he will not permit his employees to perform
their services at any location1 under his control, where segregated
facilities are maintained. Operator agrees that a breach of his
certification is a violation of the Equal Opportunity Clause in this
contract. As used in this certification, the term "segregated
facilities" means any waiting rooms, work areas, rest rooms and wash
rooms, restaurants and other eating areas, time clocks, locker rooms
and other storage or dressing areas, parking lots, drinking fountains,
recreation or entertainment areas, transportation and housing
facilities provided for employees which are segregated by explicit
directive or are in face segregated on the basis of race, color,
religion, sex, age or national origin, because of habit, local custom
or otherwise; Operator's policies and practices must assure appropriate
physical facilities to both sexes. He further agrees that (except where
he has obtained identical certifications from proposed subcontractors
for specific time periods) he will obtain identical certifications from
proposed subcontractors prior to the award of subcontracts exceeding
$10,000 which are not exempt from the provisions of Equal Opportunity
Clause; that he will retain such certifications in his files; and that
he will forward the following notice to such proposed subcontractors
(except where the proposed subcontractors have submitted identical
certifications for specific time periods). NOTICE TO PROSPECTIVE
SUBCONTRACTORS OF REQUIREMENT FOR CERTIFICATIONS OF NONSEGREGATED
FACILITIES. A Certification of Nonsegregated Facilities as required by
the May 9, 1967 order on Elimination of Segregated Facilities, by the
Secretary of Labor (32 Fed. Reg. 7439, May 19, 1967), must be submitted
prior to the award of a subcontract exceeding $10,000 which is not
exempt from the provisions of the Equal Opportunity Clause. The
certification may be submitted either for each subcontract or for all
subcontracts during a period (i.e., quarterly, semiannually or
annually). (1968 MAR.) (Note: The penalty for making false statements
in offers is prescribed in 18 U.S.C. 1001.)
D. Operator further agrees and certifies that, if the value of any contract
or purchase order is $50,000 or more and the Operator has 50 or more
employees, Operator will:
1. File a complete and accurate report on Standard Form 100 (EEO-1) with the
Joint Reporting Committee, Federal Depot, Jeffersonville, Indiana, within thirty
(30) days of the date of contract award, unless such report has been filed
within the twelve (1 2) month period preceding the date of the contract award
and otherwise comply with and file such other compliance reports as may be
required under Executive Order 11246, as amended, and rules and regulations
adopted thereunder.
2. Develop a written affirmative-action compliance program for each of its
establishments as required by Title 41, Code of Federal Regulations, Section
60-1.40.
E. If this contract is a subcontract under contract(s) with the United States
Government and subject to Executive Order 11701 (Listing of Job Vacancies) and
the Regulations promulgated thereunder and/or subject to the Regulations of the
United States Government promoting the utilization of minority business
enterprises, it incorporates by reference all provisions required by such
Regulations to be incorporated in such a subcontract.
<PAGE>
EXHIBIT "G"
TAX PARTNERSHIP PROVISIONS ATTACHED TO AND MADE PART OF THAT CERTAIN AGREEMENT
DATED AS OF November 1, 1997 by and between Amerada Hess Corporation, Hamar II
Associates, LLC, and Saba Petroleum Company.
1. General Provisions
1.1 Designation of Documents. This exhibit is referred to in, and is a part of
that Agreement identified above, and if so provided, a part of any agreement to
which the Agreement is an exhibit. Such agreement(s) (including all exhibits
thereto, other than this exhibit) shall be hereinafter referred to collectively
as the "Agreement"; and this exhibit to the Agreement is hereinafter referred to
as the "Exhibit". Except as may be otherwise provided in this Exhibit, terms
defined and used in the Agreement shall have the same meaning when used in this
Exhibit as in the Agreement.
1.2 Relationship of Parties. The parties to this Agreement shall be hereinafter
referred to individually as the "Party" or collectively as the "Parties." The
Parties understand and agree that the arrangement and undertakings evidenced by
the Agreement, taken together, result in a partnership for purposes of federal
income taxation and for purposes of certain state income tax laws which
incorporate or follow federal income tax principles as to tax partnerships. Such
partnership for tax purposes is hereinafter referred to as the "Tax
Partnership." For every other purpose of the Agreement, however, and
notwithstanding any other provision of the Agreement, express or implied, to the
contrary, the Parties understand and agree that their legal relationship to each
other under applicable state law with respect to all property subject to the
Agreement is one of tenants in common, or undivided interest owners, or
lessee-sublessees and not one of partnership; that the liabilities of the
Parties shall be several and not joint or collective; and that each Party shall
be solely responsible for its obligations.
1.3 Priority of Provisions. In the event of a conflict or inconsistency, whether
direct or indirect, actual or apparent, between the terms and conditions of this
Exhibit and the terms and conditions of the Agreement or any other exhibit or
any part thereof, the terms and conditions of this Exhibit shall govern and
control.
1.4 Survivorship.
(a) Any termination of the Agreement shall not affect the continuing
application of the Tax Partnership provisions as necessary for the
termination and liquidation of the Tax Partnership.
(b) Any termination of the Agreement shall not affect the continuing
application of the Tax Partnership provisions as necessary to resolve all
matters regarding federal and state income tax reporting of the
Partnership.
(c) These Tax Partnership provisions shall inure to the benefit of, and be
binding upon, the Parties hereto and their successors and assigns.
1.5 Term. The effective date of the Tax Partnership shall be the effective date
of the Agreement. The Tax Partnership shall continue in full force and effect
from and after such date until termination.
2. Income Tax Compliance and Capital Accounts
2.1 Tax Returns. The Tax Matters Partner ("TMP") shall prepare and file all
required federal and state partnership income tax returns. In preparing such
returns the TMP shall use its best efforts and in doing so shall incur no
liability to any other Party with regard to such returns. Not less than thirty
(30) days prior to the earlier of the filing date or the due date (including
extensions), the TMP shall submit to each Party a copy of the return, as
proposed, for review.
<PAGE>
2
2.2 Fair Market Value Capital Accounts. The TMP shall establish
and maintain fair market value ("FMV") capital accounts and tax
basis capital accounts for each Party. Upon request, the TMP
shall submit to each Party along with a copy of any proposed
partnership income tax return an accounting of its respective FMV
capital accounts as of the end of the tax return period.
2.3Information Requests. Each Party agrees to furnish to the TMP not later
than sixty (60) days before the return due date (including extensions) such
information relating to the operations conducted under this Agreement as may be
required for the proper preparation of such returns and capital accounts.
3. Tax Matters Partner
3.1Tax Matters Partner. The Operator is designated TMP as defined in Section
6231(a)(7) of the Internal Revenue Code of 1986, as amended ("I.R.C."). In the
event of any change in the TMP, the Party serving as TMP at the beginning of a
given taxable year shall continue as TMP with respect to all matters concerning
such year. The TMP and other Parties shall use their best efforts to comply with
responsibilities outline in this section and in l.R.C.ss.ss.6222 through 6233
and 6050K (including any Treasury Regulations promulgated thereunder) and in
doing so shall incur no liability to any other Party. Notwithstanding the TMP's
obligation to use its best efforts in the fulfillment of its responsibilities,
the TMP shall not be required to incur any expenses for the preparation for, or
pursuance of administrative or judicial proceedings, unless the Parties agree on
a method for sharing such expenses.
3.2Information Request by the TMP. The Parties shall furnish the TMP within
two (2) weeks from the receipt of a request from the TMP with such information
(including information specified in l.R.C. ss.ss.6230(e) and 6050K) as the TMP
may reasonably request to permit it to provide the Internal Revenue Service with
sufficient information for purposes of I.R.C. ss.ss.6230(e) and 6050K.
3.3TMP Agreement with IRS. The TMP shall not agree to any extension of the
statute of limitations for making assessments on behalf of any other Party
without first obtaining the written consent of that Party. The TMP shall not
bind any Party to a settlement agreement in tax audits without obtaining the
written concurrence of any such Party.
Any other Party who enters into a settlement agreement with the Secretary
of the Treasury with respect to any partnership items, as defined by
I.R.C.ss.6231(a) (3), shall notify the other Parties of such settlement
agreement and its terms within thirty (30) days from the date of
settlement.
3.4 Inconsistent Treatment of Partnership Item. If any Party
intends to file a notice of inconsistent treatment under I.R.C.
ss.6222(b), such Party shall, prior to the filing of such notice,
notify the TMP of such intent and the manner in which the Party's
intended treatment of a partnership item is (or may be)
inconsistent with the treatment of that item by the Partnership.
Within one (1) week of receipt, the TMP shall remit copies of
such notification to other Parties to the Partnership. If an
inconsistency notice is filed solely because a Party has not
received a Schedule K1 in time for filing of its income tax
return, the TMP need not to be notified.
3.5 Requests for Administrative Adjustment. No Party shall file a request
pursuant to I.R.C. ss.6227 for an administrative adjustment of partnership items
for any Partnership taxable year without first notifying all other Parties and
receiving notice of the consent of the other Parties, or lack thereof, from the
TMP. The TMP shall promptly notify the requesting Party of this consent or lack
thereof If all other Parties agree with the requested adjustment, the TMP shall
file the request for administrative adjustment on behalf of the Partnership. If
unanimous consent or notice from the TMP is not obtained within thirty (30) days
from the date of the requesting Party's notice, or, if shorter, within the
period required to timely file the
<PAGE>
3
request for administrative adjustment, any Party, including the
TMP, may file a request for administrative adjustment on its own behalf.
3.6 Judicial Proceedings. Any Party, intending to file a petition
under I.R.C. ss.ss.6226, 6228, or any other I.R.C. section with
respect to any partnership item, or other tax matters involving
the Partnership, shall notify the other Parties, prior to such
filing, of the nature of the contemplated proceeding. In the case
where the TMP is the Party intending to file such petition, such
notice shall be given within a reasonable time to allow the other
Parties to participate in the choosing of the forum in which such
petition will be filed. If the Parties do not agree on the
appropriate forum, then the appropriate forum shall be decided by
the affirmative vote of two (2) or more Parties owning at least
sixty-five (65) percent in the Joint Lease. Each Party shall have
a vote in accordance with its percentage Working Interest in the
Partnership for the year under audit. If a majority cannot agree,
the TMP shall choose the forum. If a Party intends to seek review
of any court decision rendered as a result of such a proceeding
such Party shall notify the other Parties prior to seeking such
review.
4. Elections
4.1 General Elections. For both income tax return and capital
account purposes, the Partnership shall elect:
(a) to deduct currently intangible drilling and development costs ("IDC"),
(b)to use the maximum allowable accelerated tax method and the
shortest permissible tax life for depreciation purposes,
(c) to use the accrual method of accounting,
(d) to report income on a calendar year basis,
(e) to account for dispositions of depreciable assets under the general
asset method to the extent permitted by I.R.C.ss.168(i)(4), (f) to elect to
use the cumulative method to compute and report income based on the
quantity of Gas taken under the Agreement, and (g) adjust the basis of
partnership property, in the case of a distribution of property, in the
manner provided in I.R.C.ss.734 and, in the case of a transfer of a
partnership interest, in the manner provided in I.R.C.ss.743. In the case
of a distribution of property pursuant to I.R.C.ss.734, the TMP shall
adjust all tax basis capital accounts. In the case of a transfer of a
partnership interest pursuant to I.R.C.ss.743, the acquiring Party shall
establish and maintain its tax basis capital account. 4.2 Depletion. Solely
for FMV capital account purposes, depletion shall be calculated by using
simulated percentage depletion within the meaning of Treas. Reg. ss.1.704.1
(b)(2)(iv)(k)(2).
For purposes of a simulated percentage depletion calculation:
(a) All operating mineral interests shall be treated as one property; (b)The
depletion rate shall be the rate specified in I.R.C. ss.613A(c)(1); and (c)The
50 percent of taxable income from the property limitation shall not be
applied.
If the simulated percentage depletion method is not permitted,
then the Parties agree that simulated cost depletion, that is,
cost depletion as determined under the principles of I.R.C.
ss.612 and based upon the adjusted FMV capital account basis of
each Lease (rather than adjusted tax basis), shall be used.
Solely for purposes of this calculation, remaining reserves shall
be as determined by the TMP.
4.3 Electing Out under I.R.C. ss.761(a). The IMP shall notify all Parties of an
intended election to be excluded from the application of Subchapter K of Chapter
1 of the Internal Revenue Code not less than sixty (60) days before the earlier
of the filing date or the due date (including extensions) for the federal
partnership income tax return. Any Party that does not consent shall provide the
TMP with written objection within thirty (30) days of receipt of such notice.
<PAGE>
4
4.4 Other Elections or Consents. Any election other than those referenced
above must be approved by the affirmative vote of the Parties in accordance
with the voting procedure provided in the Agreement.
5. Capital Contributions and FMV Capital Accounts
5.1 Capital Contributions. The respective capital contributions
of each Party to the Partnership shall be (a) each Party's
interest in the oil and gas lease(s), including all associated
lease and well equipment, committed to this Partnership, and (b)
all amounts of money paid by each Party in connection with the
acquisition, exploration, development and operation of the
lease(s), and all other costs characterized as contributions or
expenses borne by such Party under the Agreement. The
contribution of the leases and any other properties committed to
this Partnership shall be made by each Party's agreement to hold
legal title to its interest in such leases or any other
properties as nominee of this Partnership.
5.2 FMV Capital Accounts. The FMV capital accounts shall be maintained in
Treasury Regulations ss.1.704-1 and shall be increased and accordance with
decreased as follows:
(a) The FMV capital accounts shall be increased by: (i) the
amount of money and the fair market value of any property
contributed by each Party, respectively, to the Partnership (net
of liabilities assumed by the Partnership or to which the
contributed property is subject); (ii) that Party's Sec. 6.1
allocated share of Partnership income and gains, or items
thereof; and (iii) that Party's share of I.R.C. ss.705(a)(1)(B)
and (C) items.
(b) The FMV capital accounts shall be decreased by: (i) the
amount of money and the fair market value of property distributed
to each Party (net of liabilities assumed by such Party or to
which the property is subject); (ii) that Party's Sec. 6.1
allocated share of Partnership loss and deductions, or items
thereof; and (iii) that Party's share of I.R.C. ss.705(a)(2)(B)
and I.R.C. ss.709 nondeductible and nonamortizable items.
"Fair market value" when it applies to property contributed by a Party to
the Partnership shall be assumed to equal the adjusted basis of that
property, as defined in I.R.C.ss.1011, unless the Parties agree otherwise
as indicated on a separate schedule attached hereto and made a part hereof.
5.3 FMV Capital Account Revaluation. The FMV capital accounts will be
revalued to reflect revaluation of partnership property pursuant to Treas.
Reg.ss.1.704-1 (b) (2) (iv) (f) in accordance with the procedure set forth
in Sec. 4.4.
6. Partnership Allocations
6.1 FMV Capital Account Allocations. Each item of income, gain, loss or
deduction shall be allocated to each Party as follows:
(a) Actual or deemed income from the sale, exchange, distribution or other
disposition of production shall be allocated to the Party entitled to such
production or the proceeds from the sale of such production. The amount of
income from the sale of and fair market value of production taken in kind by the
Parties are deemed to be identical; accordingly', such items may be omitted from
the adjustments made to the Parties' FMV capital accounts.
(b) Exploration cost, IDC, operating and maintenance cost shall be
allocated to each Party in accordance with its respective contribution, or
obligation to contribute, to such cost.
(c) Depreciation shall be allocated to each Party in accordance with its
contribution, or obligation to contribute, to such cost.
<PAGE>
5
(d) Simulated depletion shall be allocated to each Party in
accordance with its FMV capital account adjusted basis in each oil and gas
property.
(e) Loss (or simulated loss) upon the sale, exchange,
distribution, abandonment or other disposition of depreciable or
depletable property shall be allocated to the Parties in the
ratio of their respective FMV capital account adjusted basis in
the depreciable or depletable property.
(f) Gain (or simulated gain) upon the sale, exchange,
distribution, or other disposition of depreciable or depletable
property shall be allocated to the Parties so that the FMV
capital account balances of the Parties will most closely reflect
their respective percentage or fractional interests under the
Agreement. However, as provided in Treas. Reg. ss.1.704-1
(b)(4)(v) for oil and gas properties, the amount realized is
allocated as follows: (i) First, an amount that represents
recovery of adjusted simulated depletion basis is allocated
(without being credited to the capital accounts) to the Parties
in the same proportion as the aggregate simulated depletion basis
was allocated to such Parties under Sec. 5.2; (ii) Next, from the
remainder of the amount realized, if any, an amount up to any
remaining pre-contribution gain under I.R.C. ss.704(c), but only
to the extent not included in the allocation under the first
allocation step, is allocated to the Parties having contributed
the respective property; (iii) Finally, any amount of realization
remaining after these allocations under (i) and (ii) is allocated
in accordance with the first sentence of this Sec.
6.1(f).
(g) Costs or expenses of any other kind shall be allocated to each
Party in accordance with its respective contribution, or
obligation to contribute, to such costs or expenses.
(h) Any other income item shall be allocated to the Parties in
accordance with the manner in which such income is realized by
each Party.
6.2 Tax Returns and Tax Basis Capital Account Allocations
(a) Unless otherwise expressly provided herein the allocations of
Partnership items of income, gain, loss or deduction for tax
return and tax basis capital account purposes shall be the same
as those contained in Sec. 6.1. However, the Partnership's gain
or loss on the taxable disposition of a Partnership property in
excess of the gain or loss under Sec. 6.1, if any, is allocated
to the contributing Party to the extent of such Party's
pre-contribution gain or loss.
(b) The Parties recognize that under I.R.C. ss.613A(c)(7)(D), the
depletion allowance is to computed separately by each Party. For
this purpose, each Party's share of the adjusted tax basis of
each oil and gas property shall be equal to its contribution to
the adjusted tax basis of such property.
(c) The Parties recognize that under I.R.C.ss.613A(c)(7)(D) the
computation of gain or loss on the taxable disposition of an oil
or gas property is to be computed separately by each Party. (d)
Depreciation shall be allocated to each Party in accordance
with its contribution to the adjusted tax basis of the depreciable asset.
(e) Any recapture of depreciation, IDC, and any other item of
deduction or credit shall, to the extent possible, be allocated
among the Parties in accordance with their sharing of the
depreciation, IDC, or other item of deduction or credit which is
recaptured.
(f) Any recapture of depletion shall be computed separately by each Party, in
accordance with its depletion allowance computed pursuant to Sec. 6.2(b).
<PAGE>
6
(g) For Partnership properties with FMV capital account values
different from their adjusted tax bases, the Parties intend that
the allocations described in this Sec. 6.2 constitute a
"reasonable method" of allocating gain or loss under Treas.
Reg.ss.1.704-3(a)(1).
(h) The income attributable to take-in-kind production will not be
reflected on the tax return. 7 Termination and Liquidating
Distributions
7.1 Termination of the Tax Partnership. Termination shall occur on the
earlier of the events described in I.R.C.ss.ss.708(b)(1)(B) or708(b)(1)(A).
(a) Termination Under I.R.C. ss.708(b)(1~(B). Upon termination under I.R.C.
ss.708(b)(1)(B), each Party's FMV capital account shall be adjusted as provided
for in Treas. Reg. ss.1.704-1 (b)(2)(iv)(1) and Sec. 7.3. The distributions
provided for in Sections 7.2 through 7.4 shall be deemed to have occurred, with
the Partnership money and properties deemed contributed to a new Partnership,
the terms of which are identical to those contained in this Exhibit.
(b) Termination Under I.R.C. ~708(b~(1)(A). Upon termination under I.R.C.
ss.708(b)(1)(A), the business shall be wound-up and concluded, and the assets
shall be distributed to the Parties as described below by the end of such
calendar year (or, if later, within ninety (90) days after the date of such
termination). The assets shall be valued and distributed to the Parties in the
order provided in Sections 7.2 through 7.4.
7.2 Reversion. First, all money representing unexpended contributions
by any Party and any property where no interest has been earned
in that property under the agreement by any other Party shall be
returned to the contributor.
7.3 Balancing. Second, the FMV capital accounts of the Parties shall be
determined under this Sec. 7.3 The TMP shall take the actions specified under
this Sec. 7.3 in order to cause the ratio of the Parties' FMV capital accounts
to reflect as closely as possible their Working Interests under the Agreement.
The ratio of a Party's FMV capital account is represented by a fraction, the
numerator of which is the Party's FMV capital account balance and the
denominator of which is the sum of all Parties' FMV capital account balances.
Such actions are hereafter referred to as "balancing the FMV capital accounts,"
and when completed, the FMV capital accounts of the Parties shall be referred to
as being "balanced." The manner in which the FMV capital accounts of the Parties
are to be balanced under this Sec. 7.3 shall be determined as follows:
(a)The fair market value of all Partnership properties shall be
determined and the gain or loss for each property, which would
have resulted if sold at such fair market value, shall be
allocated in accordance with Sec. 6.1(e) and (f). If thereafter
any Party has a negative FMV capital account balance, that is, a
balance' less than zero, in accordance with Treas. Reg.
ss.1.704-1 (b)(2)(ii)(b)(3) such Party is obligated to contribute
an amount of money to the Partnership sufficient to achieve a
zero balance FMV capital account (the "Deficit Make-Up
Obligation"). Moreover, any Party may contribute an amount of
money to the Partnership to facilitate the balancing of the FMV
capital accounts. If after these adjustments, FMV capital
accounts are not balanced, Sec. 7.3(b) or (c) shall apply.
(b) If all the Parties consent, any money or an undivided interest in certain
selected properties shall be distributed to one or more Parties as necessary for
the purpose of balancing the FMV capital accounts.
(c) Unless (b) above applies, an undivided interest in each and every property
shall be distributed to one or more Parties in accordance with the ratios of
their positive FMV capital accounts.
<PAGE>
7
(d) If a property is valued under (a) above or distributed
pursuant to (b) or (c) above, the fair market value of the
property shall be agreed to by the Parties. In the event all of
the Parties do not reach agreement as to the fair market value of
property, the TMP shall cause a nationally recognized independent
engineering firm to prepare an evaluation of fair market value of
such property.
7.4Final Distribution. Third, after the FMV capital accounts of the Parties
have been adjusted, 'pursuant to Sec. 7.3 above, all remaining property and
interests then held by the Partnership shall be distributed to the Parties in
accordance with their positive FMV capital account balances.
8. Transfers, Indemnification, Correspondence and Amendments 8.1 Transfers of
Partnership Interests. Transfers of partnership interests shall be governed
by the Agreement. A party transferring its interest, or any part thereof,
shall notify the TMP in writing within two (2) weeks of such transfer.
8.2 Indemnification. This agreement does not include any indemnification
provisions to protect Parties against any harm caused by an I.R.C.
ss.708(b)(1)(B) termination. If the Parties desire indemnification provisions, a
separate indemnification agreement should be drafted.
8.3 Correspondence. All correspondence relating to the preparation and filing of
the Partnership's income tax returns and capital accounts shall be forwarded to
the Parties in accordance with the Article on notices contained in the
Agreement, and the mailing address used for each Party shall be the address
provided for that Party in that Article on notices contained in the Agreement,
unless the Party requests in a written notice to the TMP that a different
address be used for tax matters only.
<PAGE>
EXHIBIT "H"
Attached to and made a part of that certain Operating Agreement
dated November 1, 1997 by and between Amerada Hess Corporation, Hamar II
Associates, LLC, and Saba Petroleum Company.
MEMORANDUM OF OPERATING AGREEMENT
AND FINANCING STATEMENT
1.0 This Memorandum of Operating Agreement and Financing Statement
("Memorandum") is made this day of __________, 1997 by and between Amerada Hess
Corporation ("AHC"), a Delaware corporation, Hamar II Associates, LLC,
("HAMAR"), collectively referred to herein as the "Parties".
2.0 The Parties hereto have entered into an Operating Agreement, effective the
1st day of November 1, 1997, which provides for the development and production
of crude oil, natural gas and associated substances from the lands described in
Exhibit "A" attached hereto (the "Contract Area"), and designating AHC as
Operator to conduct such operations.
3.0 The Operating Agreement provides for certain liens and/or security interests
to secure payment by the Parties of their respective share of costs under the
Operating Agreement. The Operating Agreement contains an Accounting Procedure
along with other provisions which supplement the lien and/or security interest
provisions, including non-consent clauses which provide that Parties who elect
not to participate in certain operations shall be deemed to have relinquished
their interest until the consenting Parties are able to recover their costs of
such operations plus a specified amount. Should any person or firm desire
additional information regarding the Operating Agreement or wish to inspect a
copy of the Operating Agreement, said person or firm should contact the Operator
at the following address:
Drilling Operator: Initial Test and Substitute Test
Hamar II Associates, LLC
214 West Aliso Street
Ojai, CA 93023
Operator, Production and all Subsequent Wells
Amerada Hess Corporation
500 Dallas Street
One Allen Center
Houston, Texas 77002
4.0 The purpose of this Memorandum is to more fully describe and secure the
liens and/or security interests provided for in the Operating Agreement,
and to place third parties on notice thereof.
5.0 In consideration of the mutual rights and obligations of the Parties
hereunder, the Parties hereto have agreed as follows:
5.1 The Operator will conduct, direct and have full control of all
Operations on the Contract Area as permitted and required by, and within
the limits of, the Operating Agreement.
5.2 Each Non-Operator has granted to the Operator (i) a lien upon its oil and
gas rights in the Contract Area, and (ii) a security interest in its share of
oil and/or gas when extracted and its interest in all equipment, to secure
payment of its share of expenses, together with interest thereon at the rate
provided in the Accounting Procedure referred to in Paragraph 3.0 above. To the
extent that the Operator has a security interest under the Uniform Commercial
Code ("UCC") of the state, the Operator is entitled to exercise the rights and
remedies of a secured party under the UCC. The bringing of a suit and the
obtaining of judgment by the Operator for the secured indebtedness is not deemed
to be an election of remedies, nor does it otherwise affect the rights or
security interest for the payment thereof
5.3 If any Non-Operator fails to pay its share of costs when due, the
Operator may require other Non-Operators to pay their proportionate part of
the unpaid share, whereupon the other Non-Operators will be subrogated to
Operator's lien and security interest. 5.4 The Operator has granted to
Non-Operators a lien and security interest equivalent to that granted to
the Operator as described in Paragraph 5.2 above, to secure payment by the
Operator of its own share of costs when due.
6.0 For purposes of protecting said liens and security interests, the
Parties hereto agree that this Memorandum shall cover all right, title and
interest of the debtor(s) in:
6.1 The following property is subject to a security interest:
A. All personal property located on, or used in connection with, the
Contract Area.
B. All fixtures on the Contract Area.
C. All oil, gas and associated substances of value in, on or under the Contract
Area which may be extracted therefrom.
<PAGE>
D. All accounts resulting from the sale of the substances described in
subparagraph C. at the well head of every well located on the Contract Area
or on lands pooled therewith.
E. All items used, useful or purchased for the production, treatment, storage,
transportation, manufacture or sale of the substances described in subparagraph
C.
F. All accounts, contract rights, rights under any gas balancing agreement,
general intangibles, equipment inventory, farmout rights, option farmout rights,
acreage and/or cash contributions, and conversion rights, whether now owned or
existing or hereafter acquired or arising, including but not limited to all
interest in any partnership, limited partnership, association, joint venture, or
other entity or enterprise that holds, owns, or controls any interest in the
Contract Area or in any property encumbered by this Memorandum.
G. All severed and extracted oil, gas and associated substances now or hereafter
produced from or attributable to the Contract Area, including without limitation
oil, gas and associated substances in tanks or pipelines or otherwise held for
treatment, transportation, manufacture, processing or sale.
H. All the proceeds and products of the items described in the foregoing
paragraphs now exiting or hereafter arising, and all substitutions
therefor, replacements thereof, or accessions thereto. I. All personal
property and fixtures now and hereafter acquired in furtherance of the
purposes of this Operating Agreement. Certain of the above-described items
are or are to become fixtures on the Contract Area.
J. The proceeds and products of collateral are also covered.
6.2 The following property is subject to a lien:
A. All real property within the Contract Area, including all oil, gas and
associated substances of value in, on or under the Contract Area which may
be extracted therefrom.
B. All fixtures within the Contract Area.
C. All real property and fixtures now or hereafter acquired in furtherance of
the purposes of this Operating Agreement.
7.0The above items will be financed at the well head of the well or wells
located on the Contract Area, and this Memorandum is to be filed of record in
the real estate records of the county or counties in which the Contract Area is
located, and in the UCC records of the state in which the Contract Area is
located, and in the UCC records of the state in which the Contract Area is
located. All Parties who have executed the Operating Agreement are identified on
Exhibit "A".
8.0On default of any covenant or condition of the Operating Agreement, in
addition to any other remedy afforded by law or the practice of this state, each
Party to the Operating Agreement and any successor to such Party by assignment,
operation of law, or otherwise, shall have, and is hereby given and vested with,
the power and authority to take possession of and sell any interest which the
defaulting Party has in the subject lands and to foreclose this lien in the
manner provided by law.
9.0Upon request at expiration of the subject Operating Agreement and the
satisfaction of all debts, the Operator shall file of record a release and
termination on behalf of all Parties concerned. Upon the filing of such release
and termination, all benefits and obligations under this Memorandum shall
terminate as to all parties who have executed or ratified this Memorandum. In
addition, the Operator shall have the right to file a continuation statement on
behalf of all Parties who have executed or ratified this Memorandum.
10.0 It is understood and agreed by the Parties hereto that if any part,
term, or provision of this Memorandum is held by the courts to be illegal or in
conflict with any law of the state where made, the validity of the remaining
portions or provisions shall not be affected, and the rights and obligations of
the Parties shall be construed and enforced as if the Memorandum did not contain
the particular part, term or provision held to be invalid.
11.0 This Memorandum shall be binding upon and shall inure to the benefit of
the Parties hereto and to their respective heirs, devisees, legal
representatives, successors and assigns. The failure of one or more persons
owning an interest in the Contract Area to execute this Memorandum shall not in
any manner affect the validity of the Memorandum as to those persons who have
executed this memorandum.
12.0 A Party having an interest in the Contract Area can ratify this
memorandum by execution and delivery of any instrument of ratification,
adopting and entering into this memorandum, and such ratification shall
have the same effect as if the ratifying Party had executed this Memorandum
or a counterpart thereof. By execution or ratification of this Memorandum,
such Party hereby consents to 2 its ratification and adoption by any Party
who may have or may acquire any interest in the Contract Area.
13.0 This Memorandum may be executed or ratified in one or more
counterparts, and all of the executed or ratified counterparts
shall together constitute one instrument. For purposes of
recording, only one copy of this memorandum with individual
signature pages attached thereto needs to be filed of record.
This Memorandum shall apply to each of Hamar II Associates, LLC and Amerada
Hess Corporation in its respective capacity as Operator or Non-Operator, as the
case may be.
14.0 Mark A. Nahabedian, Rodney C. Hill, Rodney C. Hill, A Professional
Corporation have signed this agreement solely for purpose of expressing their
respective consents to this agreement. Neither of such signatories assumes any
personal liability or obligation, or shall derive individually any rights, under
this agreement.
AMERADA HESS CORPORATION
By (signature)
J.Y. CHRISTOPHER
Type or print name
Title: ATTORNEY-IN-FACT
HAMAR II ASSOCIATES. LLC
By (signature)
MARK A. NAHABEDIAN
Type or print name
INDIVIDUALLY AND AS A MEMBER
RODNEY C. HILL
A PROFESSIONAL CORPORATION
By (signature)
RODNEY C. HILL
Type or print name
Title INDIVIDUALLY AND ON BEHALF OF RODNEY C.
HILL
A PROFESSIONAL CORPORATION
SABA PETROLEUM COMPANY
By (signature)
Ilyas Chaudhary
<PAGE>
EXHIBIT "I"
Attached to and made a part of that certain Operating Agreement dated November
1, 1997 by and between Amerada Hess Corporation, Hamar II Associates, LLC, and
Saba Petroleum Company.
AMERADA HESS CORPORATION
500 Dallas Street
Houston. TX 77002
P.O. Box 2040
Houston. TX 77252
Attention: KEITH WAGNER
(713) 609-5556
DAILY PROGRESS REPORTS TO BE TELECOPIED TO For Amerada Hess Corporation:
AMERADA HESS CORPORATION
Attention: SUSAN LEE
(713) 609-5469
Telecopier: (713) 609-5609
<TABLE>
<S> <C>
- - --------------------------------------------------------------------------------------------------- ----------------------
State & Federal Government Reports, Plats & Applications 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Well Prognosis 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Daily Progress Report 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Electric Wireline Log Surveys (Field Print) (Also Fax) 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys (Final, Paper Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys-Composite Film & Tape (6250 BPI LIS) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Field Copy-Fax Daily) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Final Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Reports-DST, Core,Sample,Geological,Paleo,Directional Surveys 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Phone Call Prior to DST,Cores,Logging,Testing,Plugging X
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Samples Cuttings (Washed & Dried) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Core Slab 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Sample 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Analysis 2
- - --------------------------------------------------------------------------------------------------- ----------------------
</TABLE>
<PAGE>
EXHIBIT "I"
Attached to and made a part of that certain Operating Agreement dated November
1, 1997 by and between Amerada Hess Corporation, Hamar II Associates, LLC, and
Saba Petroleum Company.
FOR HAMAR II ASSOCIATES
Hamar II Associates
Attn Sam Briglio
214 W. Aliso St. OJai, Cal 93023
(805) 646-4276 Fax (805) 646-3476
Same as above
<TABLE>
<S> <C>
- - --------------------------------------------------------------------------------------------------- ----------------------
State & Federal Government Reports, Plats & Applications 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Well Prognosis 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Daily Progress Report 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Electric Wireline Log Surveys (Field Print) (Also Fax) 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys (Final, Paper Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys-Composite Film & Tape (6250 BPI LIS) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Field Copy-Fax Daily) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Final Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Reports-DST, Core,Sample,Geological,Paleo,Directional Surveys 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Phone Call Prior to DST,Cores,Logging,Testing,Plugging X
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Samples Cuttings (Washed & Dried) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Core Slab 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Sample 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Analysis 2
- - --------------------------------------------------------------------------------------------------- ----------------------
</TABLE>
<PAGE>
EXHIBIT "I"
Attached to and made a part of that certain Operating Agreement dated November
1, 1997 by and between Amerada Hess Corporation, Hamar II Associates, LLC, and
Saba Petroleum Company.
FOR SABA PETROLEUM COMPANY
ATTN. Mr. Ilyas Chadaury
3201 Airport Drive Suite 201
Santa Maria California 93455
(805) 347-8700
Fax (805) 347-1072
Same as above
<TABLE>
<S> <C>
- - --------------------------------------------------------------------------------------------------- ----------------------
State & Federal Government Reports, Plats & Applications 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Well Prognosis 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Daily Progress Report 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Electric Wireline Log Surveys (Field Print) (Also Fax) 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys (Final, Paper Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Wireline Log Surveys-Composite Film & Tape (6250 BPI LIS) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Field Copy-Fax Daily) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Mud Logs (Final Print) 4
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Reports-DST, Core,Sample,Geological,Paleo,Directional Surveys 2
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Phone Call Prior to DST,Cores,Logging,Testing,Plugging X
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Samples Cuttings (Washed & Dried) 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Core Slab 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Sample 1
- - --------------------------------------------------------------------------------------------------- ----------------------
- - --------------------------------------------------------------------------------------------------- ----------------------
Fluid Analysis 2
- - --------------------------------------------------------------------------------------------------- ----------------------
</TABLE>
EXHIBIT "C"
ATTACHED TO AND MADE A PART OF THAT CERTAIN PARTICIPATION AGREEMENT
BETWEEN AMERADA HESS CORPORATION AND HAMAR II ASSOCIATES, LLC
DATED NOVEMBER 1, 1997
COST ESTIMATE & AUTHORITY FOR EXPENDITURE
DATE: November 10, 1997
<TABLE>
<CAPTION>
OPERATOR: Hamar II Associates, LLC
LEASE & WELL NO. Behemoth 1-22 FIELD OR AREA:
LOCATION: SE/4 of Sec. 22, T22N, R5W, MDB&M
COUNTY: Glenn STATE: California PROJECTED TD: 8500'
DIRECTIONAL TARGETS: Straight Hole
Classification: Exploratory (X) Development ( ) Oil (X) Gas (X) THIS IS AN
ESTIMATE ONLY AND THERE IS NO GUARANTEE, EITHER EXPRESS OR IMPLIES, THAT THE
ACTUAL COSTS WILL BE EQUAL TO, LESS OR GREATER THAN THOSE ESTIMATED.
<S> <C> <C> <C> <C> <C>
---------------- ---------------- ---------------
TANGIBLE LEASE & WELL EQUIP. DRILLING COMPLETION TOTAL REMARKS
---------------- ---------------- ---------------
---------------- ---------------- ---------------
1. Surface Csg. & Cond. $28,000 $28,000 800' of 16", 65#, H-40, ST&C
----------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
2. Inter. Csg. & Lng. $130,000 $130,000 6000" of 8-5/8", 40#, 43.5#, 47#, J&N
-------------------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
3. Production Csg. & Lnr. $85,000 $85,000 8500" of 5-1/2" 17#, N-80 & P-110
---------------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
4. Tubing $34,000 $34,000 8500" of 2-7/8", 6.5#, J-55, EUE, tubing
----------------------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
5. Wellhead $30,000 $30,000 10,000# WP
----------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
6. Flow Line $10,000 $10,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
7. Process & Storage Equip. $50,000 $50,000 Heater/Separator/Dehy/Tank
--------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
8. Packers, Anchors, Misc. $10,000 $10,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
Total Lease & Well Equip. $158,000 $219,000 $377,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
Intangibles
---------------- ---------------- ---------------
---------------- ---------------- ---------------
1.a. Footage ft. @ $ $0
---------------- ---------------- ---------------
---------------- ---------------- ---------------
b. Mobilization $100,000 $100,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
c. Daywork 32 Days @ $7000 $224,000 $224,000 Including abandonment or running casing
---------------------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
d. Service Rig - Compl. $20,000 $20,000 8 days @ $2,500/day
-------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
e. Water $6,000 $6,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
f. Mud & Chemicals $150,000 $15,000 $165,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
g. Mud Conditioning $21,000 $21,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
2.a. Operators Overhead $0
---------------- ---------------- ---------------
---------------- ---------------- ---------------
b. Engineering Supervision $29,000 $9,000 $38,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
c. Mud Log $24,000 $24,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
d. Wireline Surveys $50,000 $5,000 $55,000 AIT/Sonic/Neutron/Density: CBL/NL
---------------------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
f. County Use Permits $3,000 $3,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
g. Legal,Insurance,DOG Bond $35,000 $35,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
3.a. Cement & Service $60,000 $25,000 $85,000 Including abandonment
---------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
b. Floating Equipment $5,000 $2,000 $7,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
c. Welding $3,000 $1,000 $4,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
d. Handling Csg. & D.P. $25,000 $10,000 $35,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
4. Perforating $30,000 $30,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
5.a. Location & Roads $50,000 $10,000 $60,000 Wet weather location
--------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
b. Transp. & Freight $50,000 $8,000 $58,000 Including mud disposal
----------------------
---------------- ---------------- ---------------
---------------- ---------------- ---------------
c. Roustabout Labor $5,000 $1,000 $6,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
d. Lodging & Meals $3,000 $2,000 $5,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
6.a. Bits $80,000 $2,000 $82,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
b. Rental Tools $30,000 $8,000 $38,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
c. Coring $30,000 $30,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
d. Contingencies $100,000 $97,000 $197,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
Total Intangibles $1,083,000 $245,000 $1,328,000
---------------- ---------------- ---------------
---------------- ---------------- ---------------
Total $1,241,000 $464,000 $1,705,000
---------------- ---------------- ---------------
Grand Total - $1,705,000 to Salesline, not including pipeline.
</TABLE>
IRANI ENGINEERING
Exhibit 10.51
December 20, 1997
Belridge Road/Railroad Grade Prospect Areas Farmout
Portions of 29/21, 29/22, 30/22 and 30/23, Kern County, California
Chevron FOA #032566
NNG SABA EXPLORATION COMPANY
4700 Stockdale Highway 3201 Skyway Drive
Suite 150 Suite 201
Bakersfield, California 93309 Santa Maria, California 93455
Attention: Rod Nahama Attention: Ilyas Chaudhary
Gentlemen:
NAHAMA NATURAL GAS (NNG), a California corporation, and SABA EXPLORATION
COMPANY, a wholly owned subsidiary of Saba Petroleum Company, a Delaware
corporation (collectively "Farmee"), desire to farm in from Chevron U.S.A.
Production Company, a division of Chevron U.S.A. Inc., hereinafter "Chevron",
the named prospect areas and certain rights in Chevron lands located therein.
When fully executed and delivered, this letter, together with its exhibits, all
of which are attached hereto and incorporated herein by this reference,
constitutes the agreement of the parties with respect to said prospect areas and
lands.
1. Subject to the terms and conditions of this agreement, Farmee shall have
the right to undertake seismic and oil and gas drilling and development
operations relating to the prospect areas and Chevron lands depicted on
Exhibit "A" and described in Exhibit "B". Farmee's exercise of such rights
shall be subject to the terms and conditions of that certain data license
and confidentiality agreement attached as Exhibit "C" and the form of oil
and gas lease attached as Exhibit "D".
2. On or about January 15, 1998, Chevron shall deliver to Farmee digital
copies of Chevron's proprietary final migrated volume from its Belridge
Road and Railroad Grade 3D seismic data sets. Such data shall be furnished
to Farmee under the terms and conditions of Exhibit "C".
On or about February 1, 1998, Chevron shall deliver to a geophysical data
processing contractor mutually acceptable to both Chevron and Farmee,
Chevron's proprietary fields tapes and other digital and non-digital data
necessary for such vendor's reprocessing and merging of the Belridge Road
and Railroad Grade 3D seismic survey data sets, pursuant to the provisions
of this agreement AND Exhibit "C". Farmee shall promptly reimburse Chevron
for all of its costs of retrieving and copying such data, which such costs
are estimated to be less than $300.00. Such data shall be deemed to have
been furnished by Chevron directly to Farmee (and to such contractor by
Farmee) and, therefore, all such data shall be subject to the terms and
conditions of this agreement and Exhibit "C". Farmee shall contract with
such contractor for its prompt commencement and diligent completion of
those seismic data merging and reprocessing operations provided for in
Exhibit "C" and shall promptly pay to contractor all charges invoiced under
such contract. In addition, Farmee shall promptly reimburse Chevron for any
in-house costs or out of pocket expenses it may have incurred in the
retrieval and copying of such data for Farmee/contractor, which such costs
and expenses are estimated to be $20,000.00.
Promptly after the completion of such data reprocessing and merging
operations, but in no event later than May 1, 1998, Farmee shall furnish to
Chevron a true and complete copy of the final stack and migration data and
tapes of the reprocessed/merged data, all in standard industry format (but
not Farmee's interpretive products), and shall otherwise adhere to the
terms and conditions of Exhibit "C". Farmee's failure to timely and
satisfactorily perform its obligations under this Paragraph "2" shall
result in termination of Farmee's rights under this agreement, effective
May 1, 1998.
3. In the event Farmee timely and satisfactorily performs all of its seismic
obligations under Paragraph "2", it shall have a limited option to drill
one or more test wells within the prospect areas, the actual drilling of
the first of such wells to be commenced, if at all, no later than August 1,
1998. If Farmee elects to drill such a well, it shall give Chevron written
notice thereof by July 1, 1998. Such notice shall state the location, depth
and geotechnical objectives of such well and shall describe the Chevron
acreage block to be leased to Farmee in support of the well. The well shall
be designed to fully penetrate and test the Stevens sands (equivalents)
formations or to such other predetermined formation and/or depth as may at
that time be mutually agreeable to Chevron and Farmee. Farmee's notice
shall include its proposed formation/depth and Chevron shall promptly
advise, in writing, of its approval or non-approval thereof. Promptly after
its receipt of such notice, Chevron shall promptly execute and deliver to
Farmee an oil and gas lease covering such available acreage in the form of
that lease attached as Exhibit "D". The following shall constitute the
principal terms of the lease:
Acreage: 2 sections plus 10% (maximum of
approximately 1400 contiguous acres,
all to be located within no more
than three contiguous governmental
sections). Except as otherwise noted
on Exhibit "B", Chevron's grant of
an elected lease shall be without
depth restriction. Notwithstanding,
Farmee acknowledges that Chevron is
engaged in negotiations with a third
party, as of the date of this
agreement, for a farmout or lease to
that party of deep rights (generally
lying below base Stevens [+/-15,000'
measured depth]) in certain Cal
Canal area acreage. In the event
Chevron consummates an agreement
with such party for such rights
before Farmee has elected a lease on
such acreage, this agreement shall
on the date of such third-party
agreement be deemed to have been
amended to exclude such depths in
such acreage from this agreement;
Primary term: 4 months
Bonus: Waived;
Delay Rental: Inapplicable; Royalty: 20% of 100% through payout of all
drilling, testing, completion and casing of the first lease well; 25%
thereafter. Chevron may elect to take its royalty share in kind;
Development: 1:10 (oil down through Etchegoin), 1:40 (oil below Etchegoin);
1:160 (gas down through Etchegoin), 1:320 (gas below Etchegoin); 180-day
string between first and
second wells; 120-days between subsequent wells;
Offsets: 660' oil and 1320' gas;
Pooling: Lessee may pool Chevron acreage with outside acreage, subject to
the above development obligations and provided that a minimum of 50% of the
production is allocated to the Chevron lease;
Back-in Rights: Chevron is retaining no back-in rights.
If Farmee shall fail to timely notify Chevron of its election to drill
under this Paragraph "3" or thereafter fail to timely commence and
diligently prosecute the drilling of such well to completion or
abandonment, all of Farmee's rights under this agreement shall forthwith
terminate.
4. In the event Farmee has timely and satisfactorily drilled a test well under
Paragraph "3" hereof and is not then in default of its obligations under
this agreement and such lease, Farmee shall have a limited option to drill
one or more additional test wells within the prospect areas, the actual
drilling of the first of such additional wells to be commenced, if at all,
no later than February 1, 1999. If Farmee elects to drill such a well, it
shall give Chevron written notice thereof by December 1, 1998. Such notice
shall contain all information prescribed in Paragraph "3" hereof and upon
its receipt, Chevron shall promptly execute and deliver to Farmee an oil
and gas lease in the same form and with the same terms as provided in
Paragraph "3". If Farmee shall fail to timely notify Chevron of its
election to drill under this Paragraph "4" or thereafter fail to timely
commence and diligently prosecute the drilling of such well to completion
or abandonment, all of Farmee's rights to earn additional Chevron leases
under this agreement shall forthwith terminate.
5. In the event Farmee has timely and satisfactorily drilled a test well under
Paragraph "4" hereof and is not then in default of its obligations under
this agreement and such lease, Farmee shall have a limited option to drill
one or more additional test wells within the prospect areas, the actual
drilling of the first of such additional wells to be commenced, if at all,
no later than August 1, 1999. If Farmee elects to drill such a well, it
shall give Chevron written notice thereof by July 1, 1999. Such notice
shall contain all information prescribed in Paragraph "3" hereof and upon
its receipt, Chevron shall promptly execute and deliver to Farmee an oil
and gas lease in the same form and with the same terms as provided in
Paragraph "3". If Farmee shall fail to timely notify Chevron of its
election to drill under this Paragraph "5" or thereafter fail to timely
commence and diligently prosecute the drilling of such well to completion
or abandonment, all of Farmee's rights to earn additional Chevron leases
under this agreement shall forthwith terminate.
6. In the event Farmee has timely and satisfactorily drilled a test well under
Paragraph "5" hereof and is not then in default of its obligations under
this agreement and the leases granted under the provisions of Paragraphs
"3", "4" and "5", Farmee shall have a limited option to drill one final
test well within the prospect areas, the actual drilling of such well to be
commenced, if at all, no later than December 31, 1999. If Farmee elects to
drill such a well, it shall give Chevron written notice thereof by November
1, 1999. Such notice shall contain all information prescribed in Paragraph
"3" hereof and upon its receipt, Chevron shall promptly execute and deliver
to Farmee an oil and gas lease in the same form and with the same terms as
provided in Paragraph "3". In addition, Farmee's notice of election to
drill under this Paragraph "6" shall include Farmee's payment to Chevron of
$50,000.00. If Farmee shall fail to timely notify Chevron of its election
to drill under this Paragraph "6", if Farmee shall fail to timely make the
prescribed $50,000.00 payment therewith or if Farmee shall thereafter fail
to timely commence and diligently prosecute the drilling of such well to
completion or abandonment, all of Farmee's rights to earn additional
Chevron leases under this agreement shall forthwith terminate.
7. If during the term of this agreement, Farmee shall drill a well or wells on
prospect lands not leased to it by Chevron ("third party leases and
lands"), Farmee shall furnish to Chevron all data and information related
to such wells, pursuant to the terms of Exhibit "B" to Exhibit "D", as if
such well were drilled on Chevron lands under said Exhibit "D". In
addition, Farmee shall execute and record a grant to Chevron of an
overriding royalty interest equal to the difference between 25% of 100% and
the burdens of record applicable to such third party leases and lands, but
in no event less than 5% of 100%, on all production from such third party
leases and lands.
8. All of Farmee's operations and obligations under or related to this
agreement shall be performed by or on behalf of Farmee at its sole risk,
cost and expense and all such operations and their products shall be
undertaken and completed in accordance with: (a) current industry practice
and standards for California; (b) all exhibits to this agreement; and (c)
all applicable laws, rules, orders and regulations.
9. Upon the termination of Farmee's rights to drill and earn additional
acreage under this agreement, which shall in no event be later than
December 31, 1999, Farmee's continuing operations upon Chevron lands, if
any, and all of Farmee's obligations with respect all such lands shall be
governed by the terms and conditions of Exhibit "C" and, in the event a
lease is, or leases are granted to Farmee hereunder, the terms and
conditions of such lease(s).
10. Chevron has long been engaged in negotiations with the U.S. Fish and
Wildlife Service, the California Department of Fish and Game, the County of
Kern, the Bureau of Land Management and the California Division of Oil, Gas
and Geothermal Resources for a habitat conservation plan ("HCP") for the
"Lokern" area, an area within which the subject acreage lies. A copy of the
current draft of the Chevron Lokern HCP is attached hereto as Exhibit "E"
and made a part hereof by this reference. As you can see from your review
of the exhibit, the HCP is designed to provide for accelerated permitting
of oil and gas operations and for protection of threatened and endangered
species and their habitats.
We estimate that the Chevron Lokern HCP will not be finalized for another
six to twelve months but one important tenet of the plan seems already to
be set; that is, acreage compensation for `permanent' surface disturbance
on Chevron properties within the Lokern area (disturbance for which surface
restoration is not begun within two years and completed within a reasonable
length of time thereafter) will be made at the rate of 3:1 (three acres of
compensation for each acre of surface disturbed). If Farmee undertakes
actual operations on the subject Chevron lands under this agreement, Farmee
will be responsible for the `payment' of the requisite compensation. It is
also important to note that in light of the fact that the Chevron Lokern
HCP has not yet been finalized, Farmee will be required to consult with the
U.S. Fish and Wildlife Service, the California Department of Fish and Game,
the California Department of Conservation, Division of Oil, Gas and
Geothermal Resources, and possibly others regarding permits currently
necessary for operating in the Lokern area.
This letter, including all of its Exhibits, constitutes the agreement of the
parties with respect to the matters herein contained.
Nahama Natural Gas (NNG) Saba Exploration Company
By: By:
Its: Its:
Chevron U.S.A. Production Company
By:
Its: Assistant Secretary
Table of Exhibits
"A" Prospect plat (BelRRGxA.doc)
"B" Description of Chevron lands (BLRRGacr.doc)
"C" Data License and Confidentiality Agreement (BelCnfdC.doc)
"D" Chevron fee lease form (NngSabaBelRdRRGradeLongLse.doc, LeasexA.doc,
LeasexB.doc)
"E" Lokern HCP (Draft #3) and Implementation Agreement (Draft dated
10/20/97)
"F" Additional Terms and Conditions (AddTerms.doc)
Exhibit "A"
Attached to and made a part of that certain Belridge/Railroad Grade Prospect
Area Farmout, dated December 20, 1997, by and between NNG and Saba Exploration
Company (collectively "Farmee") and Chevron U.S.A. Production Company.
[graphic omitted]
EXHIBIT "B"
Attached to and made a part of that certain Belridge Road/Railroad
Grade Prospect Areas Farmout, dated December 20, 1997, by and between NNG and
Saba Exploration Company (collectively "Farmee") and Chevron U.S.A. Production
Company.
<TABLE>
<S> <C> <C> <C> <C>
T/R/S (Chev #) Chev Interest N/G Acr Comments
2822031 (001497) Fee Simple 0 All rights burdened by O&G lease
Absolute ("FSA") (no interest available for earning).
292111 None 0 Chevron has given a non-exclusive license
of its 3D data to a competitor (014929)
292113 " 0 " " " " "
292114 " 0 " " " " "
292115 " 0 " " " " "
292123 " 0 " " " " "
292124 " 0 " " " " "
292125 (003046) FSA 0 " " " " "
292136 (003855) FSA 0 No interest available for earning.
292205 (001500) FSA 0 All rights burdened by O&G lease
(no interest available for earning).
292207(001501) FSA 644 Grazing lease.
292209 (001502) FSA (N/2) 0 All rights burdened by O&G lease
(no interest available for earning).
292215 (001505) FSA 640 Grazing lease; designated drillsites only.
292216 (003647) FSA 600 " " "
292217 (001507) FSA 640 "
292219 (001508) FSA 642 Chevron has given a non-exclusive license of its 3D
data [and an O&G lease of
the S/2 of the section -
top Olig to base of Upper
Antelope] to a competitor
(limited depths available
for earning).
Also, grazing lease.
292221 (001509) FSA 640 Grazing lease.
292222 (003023) FSA 160 "
292223 (001510) FSA 631 "
292225 (001511) FSA 629 "
292227 (001512) FSA 640 "
292229 (001513) FSA 640 "
292230 (003025) FSA (NE/4) 160 Chevron has given a non-exclusive license of
its 3D data [and an O&G
lease of the NE/4 of the
section - top Olig to
base of Upper Antelope]
to a competitor (limited
depths available for
earning).
Also, grazing lease.
292230 (001571) FSA (S/2 SESE) 0 No interest available for earning.
292231 (001514) FSA 0 Chevron has given a non-exclusive license of its 3D
data [and an O&G lease of
the N/2 and the NE/4 of the
SE/4 of the section top
Olig to base of Upper
Antelope] to a competitor.
No interest available for
earning.
292232 (001572) FSA (N/2 NE/4) 80 Grazing lease.
292233 (001515) FSA 640 "
292235 (001518) FSA (exc lease) 612 Chevron's "SP#42" O&G lease (136840)
(300' wide strip) not available for earning.
Also, grazing lease.
292331 (001562) FSA (S/2) 320 Grazing lease.
302201 (001519) FSA 0 No interest available for earning.
302203 (001521) FSA 640 Grazing lease.
302205 (001523) FSA 0 No interest available for earning.
302209 (001525) FSA 0 " "
302211 (001526) FSA 0 " "
302215 (001529) FSA 0 " "
302305 (001567) FSA 0 " "
302307 (001584) FSA 0 " "
--------
8,958
</TABLE>
Exhibit "C"
Attached to and made a part of that certain Belridge Road/Railroad Grade
Prospect Areas Farmout, dated December 20, 1997, by and between NNG and Saba
Exploration Company (collectively "Farmee" and Reviewing Party") and Chevron
U.S.A. Production Company.
DATA LICENSE and
CONFIDENTIALITY AGREEMENT
(Belridge Road/Railroad Grade Prospect Areas)
This Agreement is made this 20th day of December, 1997, by and between
Nahama Natural Gas ("NNG") and Saba Exploration Company (collectively "Reviewing
Party") and Chevron U.S.A. Production Company ("Licensor").
1. Background and Purpose of Agreement. Licensor owns certain
proprietary 3D seismic data ("Data"), described in Exhibit "B", attached hereto
and made a part hereof, relating to the Belridge Road/Railroad Grade Prospect
Areas, Kern County, California, which said prospect areas are shown on Exhibit
"A". Reviewing Party wishes to merge and reprocess and otherwise use the Data
exclusively in connection with its evaluation of the prospect (all of such
merged and reprocessed Data and all tapes, notes, interpretations and other
products derived therefrom, whether or not through Reviewing Party's efforts,
are hereinafter collectively referred to as the "Data Package"). Reviewing Party
and Licensor agree that the Data shall remain exclusively proprietary to
Licensor and that the Data Package shall be owned severally by Licensor and by
Reveiwing Party, as more fully provided in Paragraph "12". Licensor is agreeable
to making limited, non-exclusive disclosure of the Data to Reviewing Party and
permitting Reviewing Party to use the Data and Data Package exclusively for the
purposes set forth herein, in consideration of the execution of this License by
Reviewing Party and of the payment to Licensor by Reviewing Party of a one-time
data licensing fee of Three Hundred Thirty Thousand Dollars ($330,000.00), which
such payment shall be made on or before March 1, 1998. Reviewing Party is
willing to limit its use of the Data and Data Package to the stated purposes and
to be bound by the terms and conditions of this Agreement.
2. Access to Data. Upon the full execution and delivery of this
License, Licensor will promptly provide a digital copy of the Data, as described
in Exhibit "B", to Reviewing Party's (NNG's) offices at 4700 Stockdale Highway,
Suite 150, Bakersfield, California (Phone: 805-323-6546) or to Reviewing Party's
geophysical data processing contractor. Reviewing Party shall reimburse Licensor
for all of its reasonable and documented costs and expenses of retrieving,
reproducing and transmitting the Data to Reviewing Party within thirty (30) days
of Licensor's presentation to Reviewing party of an itemized invoice therefor.
3. Limited Disclosure of Data. Reviewing Party is expressly authorized
to disclose the Data and Data Package to Reviewing Party's employees,
consultants and agents directly engaged in the work referred to in Paragraph
"1", provided all such persons to whom such disclosure is to be made agree in
writing, in advance, to hold the same confidential in accordance with the terms
and conditions of this agreement. Within thirty (30) days of disclosure,
Reviewing Party shall advise Licensor, in writing, of the full names of each
third party to whom such disclosure is made. Reviewing Party will make necessary
and appropriate efforts to safeguard the Data and Data Package from disclosure
to any person or entity other than as expressly permitted herein. In the event
Reviewing Party or any person or entity to whom Reviewing Party transmits the
Data or Data Package becomes legally compelled to disclose any of the same,
Reviewing Party will provide Licensor with prompt written notice thereof so that
Licensor may seek a protective order or other appropriate remedy. In the event
that such protective order is not obtained, Reviewing Party will furnish only
that portion of the Data or Data Package which is legally required and it will
exercise its best efforts to obtain reliable assurance that confidential
treatment will be accorded the Data and Data Package. Subject only to such
limited exceptions as are herein expressed, Reviewing Party shall not publish or
otherwise disclose any of the Data or Data Package to any party.
4. Reproduction and/or Removal of Data. The Reviewing Party shall not
make, nor allow to be made, copies of the Data, nor more than one original and
one copy of the Data Package, or otherwise reproduce any of the Data or the Data
Package, except as Licensor may specifically authorize in writing.
5. Termination of Access to Data. Subject to the provisions of the
agreement to which this License is attached, Licensor or Reviewing Party may
elect at any time to terminate further access to, and review of, the Data and as
soon as practicable after such termination, Reviewing Party shall return to
Licensor the original and all copies of the Data. Such termination shall not
affect or eliminate Reviewing Party's obligations of confidentiality and limited
use hereunder.
6. Confidentiality. The foregoing obligations of confidentiality shall
not extend to Data or any part of the Data Package which, by the date hereof:
a. is part of the public domain;
b. is rightfully in the Reviewing Party's possession.
7. Equitable Relief. Reviewing Party acknowledges and agrees that
Licensor would not have an adequate remedy at law and would be irreparably
harmed in the event that any of the provisions of this License were not fully
and faithfully performed in accordance with its terms or were otherwise
breached. It agrees that Licensor shall be entitled to injunctive relief to
prevent breaches of this License, in addition to any other remedy to which
Licensor may be entitled, at law or in equity.
8. Breach. Reviewing Party agrees to be responsible for any breach
of this License by any of its employees, officers, consultants,
agents or others to whom it discloses the Data or any part of the
------
Data Package.
9. Representations and Warranties. This License shall be governed by
and construed in accordance with the law of the State of California. REVIEWING
PARTY UNDERSTANDS AND AGREES THAT LICENSOR MAKES NO REPRESENTATION OR WARRANTY,
EXPRESS OR IMPLIED, WITH RESPECT TO THE DATA OR THE DATA PACKAGE, ALL SUCH
REPRESENTATIONS OR WARRANTIES BEING HEREBY SPECIFICALLY DENIED AND DISCLAIMED,
AND REVIEWING PARTY AND ALL OTHERS SHALL RELY ON THE DATA AND THE DATA PACKAGE
AT ITS AND THEIR SOLE RISK, COST AND EXPENSE.
10. Liability. Licensor shall have no liability to Reviewing Party or
others for any loss or injury which results from or relates to
the selection or use of the Data or any part of the Data Package
by ---------
Reviewing Party or others.
11. Area of Mutual Interest. There is no AMI provision in this License.
12. Ownership and Use of Data Package. As provided in Paragraph "1"
hereof, Licensor and Reviewing Party shall severally own all merged and
reprocessed Data, all tapes and notes relating thereto and, excepting Reviewing
Party's interpretations thereof, all other products derived from the merged and
reprocessed Data. Notwithstanding, Licensor agrees that during the term of
Reviewing Party's rights (as "Farmee") to earn interests in the
Belridge/Railroad Grade Prospect Area under the provisions of the farmout
agreement to which this License is attached (which such term shall not extend
beyond December 31, 1999), Licensor will not disclose any of the Data Package to
third parties, except prospective purchasers or assignees of the subject Chevron
lands or any of them, in confidence. After December 31, 1999, Licensor and
Reviewing Party will each be entitled to freely use, disclose, sell, otherwise
deal with or dispose of the Data Package, without limitation.
13. Termination of Agreement. Except as provided in Paragraph "12"
hereof, this License shall terminate on December 31, 2000 (or as soon thereafter
as Reviewing Party, in the exercise of good faith and due diligence, can
assemble and return all of the Data and Data Package to Licensor at its
Bakersfield, California offices). Notwithstanding the foregoing provision, this
License shall terminate on such earlier date as Reviewing Party's rights (as
Farmee) terminate, with respect to the Belridge Road/Railroad Grade Prospect
Areas, under the provisions of the agreement to which this License is attached
(or as soon thereafter as Reviewing Party, in the exercise of good faith and due
diligence, can assemble and return all of the Data to Licensor at its
Bakersfield, California offices).
/ / / / / / /
14. Facsimile Execution. The execution and facsimile transmission of
this License shall be considered the same as the execution and delivery of an
original hereof. At the request of either party, the parties will confirm
facsimile transmitted signatures by signing an original document for delivery
between the parties.
Executed and effective as of the date first above written.
Reviewing Party Reviewing Party
Nahama Natural Gas (NNG) Saba Exploration Company
By: By:
Title: Title:
Licensor
Chevron U.S.A. Production Company
By:
Title: Assistant Secretary
EXHIBIT "A"
Attached to and made a part of Exhibit "C" to the BelridgeRoad/Railroad Grade
Prospect Areas Farmout, dated December 20, 1997, by and between NNG and Saba
Exploration Company (collectively "Farmee" and "Reviewing Party") and Chevron
U.S.A. Production Company.
(PLAT OF PROSPECT AREAS)
[graphic omitted]
EXHIBIT "B"
Attached to and made a part of Exhibit "C" to that certin Belridge Road/Railroad
Grade Prospect Areas, dated December 20, 1997, by and between NNG and Saba
Exploration Company (collectively "Farmee" and "Reviewing Party") and Chevron
U.S.A. Production Company.
Identification/Description of Data Item Format
<TABLE>
<S> <C>
Belridge Road 3D Data:
________________________________ SEG-Y 8mm tapes
- - -------------------------------- "
- - -------------------------------- "
Railroad Grade 3D Data:
- - -------------------------------- "
- - -------------------------------- "
- - -------------------------------- "
</TABLE>
*************** END OF EXHIBIT ***************
EXHIBIT "D"
Attached to and part a part of that certain Belridge Road/Railroad Grade
Prospect Areas Farmout , dated December 20, 1997, by and between NNG and Saba
Exploration Company (collectively "Farmee") and Chevron U.S.A. Production
Company.
OIL AND GAS LEASE
THIS OIL AND GAS LEASE, made and entered into this ____ day of
__________, 199__, by and between CHEVRON U.S.A. Inc., a corporation
(hereinafter called "Lessor"), and (hereinafter called "Lessee").
W I T N E S S E T H:
For and in consideration of the covenants and agreements hereinafter
contained on the part of Lessee to be kept and performed, Lessor hereby grants,
lets and leases unto Lessee the land hereinafter described (herein sometimes
called the "leased land") for the purposes and with the exclusive right of
prospecting, exploring, mining, drilling and operating the leased land for oil,
gas, other hydrocarbons (hereinafter collectively called "substances"), and
producing, taking, treating, storing, removing and disposing of such substances
from the leased land, and Lessor hereby grants to Lessee all rights, privileges
and easements useful or convenient for Lessee's operations on the leased land,
subject to the covenants, conditions and provisions hereinafter set forth,
including but not limited to, the right to construct, install, maintain, repair,
use, replace, and remove therefrom, roads, bridges, pipelines, tanks, pump and
power stations, power and communication facilities and lines, facilities for
surface and subsurface disposal of produced water and other substances, plants,
structures to treat, process and transport said substances and products
manufactured therefrom; and the right to drill wells to inject gas, water, air
or other substances into the subsurface zones. Lessor reserves the right to
occupy and use the leased land in any manner and to any extent not inconsistent
with Lessee's rights granted herein including, but not limited to, the use of
the surface and subsurface of the leased land to explore for and produce said
substances from lands and depths not subject to this lease, and Lessee shall so
conduct its operations so as to interfere as little as reasonably necessary with
Lessor's herein reserved rights to use said premises for surface operations and
operations in zones or formations not subject to this lease. The leased land is
situated in the County of Kern, State of California, and is described as
follows:
Township South, Range East, MDBM
Section:
Section:
and containing _______ gross acres (_______ net mineral acres), more or less.
TO HAVE AND TO HOLD the same for a term ending _______________________,
and so long thereafter as any of said substances is produced from the leased
land in paying quantities ("paying quantities" being defined as production in
sufficient quantities to yield a return in excess of the operating cost of the
well) or so long as Lessee shall conduct drilling operations or continue
development (including, without limitation, drilling, redrilling, deepening,
repairing and reworking) or producing operations on the leased land as
hereinafter provided without cessation for more than ninety (90) consecutive
days, or be excused therefrom as hereinafter provided. Wherever used in this
lease, drilling operations shall mean, in addition to actual drilling, any work
undertaken or commenced in good faith if followed diligently and in due course
by the construction of a derrick or other necessary structures for the drilling
of an oil or gas well, and by the actual operations of drilling in the ground.
In consideration of the premises, the parties hereby agree as follows:
1. Lessee has paid to Lessor upon the execution of this lease the
rental in full hereunder for a period ending ______________________.
/
/
/
1a. All payments required to be made by Lessee hereunder shall be made
or tendered by its check issued and made payable to:
Chevron U.S.A. Inc. Production Company
P. O. Box 840672
Dallas, Texas 75284-0672
(with a copy, referring to Lse #_______, to Chevron's notice address)
A waiver by Lessee of the provisions of this paragraph in the making of
any payment or payments shall not be deemed a waiver thereof with respect to
subsequent payments.
2. Any notice to be given by either party to the other hereunder shall
be delivered in person or by registered or certified mail, postage prepaid,
return receipt requested, addressed to the party for whom intended as follows:
Chevron U.S.A. Inc.
P. O. Box 1392
Bakersfield, CA 93302
Attention: Manager, California Land Division
Lessee:
Attention:
Either party may from time to time, by written notice to the other, designate a
different address which shall be substituted for the one above specified.
3. (a) If substances are discovered in commercial quantities in any
well drilled by Lessee on the leased land (such quantities being sufficient to
return to Lessee a profit after deducting all costs of drilling, testing,
completing, equipping and operating such well), then Lessee shall, within one
hundred twenty (120) days after the release of the drilling rig, commence the
drilling on the leased land of another well and thereafter Lessee shall keep at
least one (1) string of tools employed continuously with not more than one
hundred twenty (120) days intervening between the release of the drilling rig of
one well and the commencement of drilling of another well, in diligently
drilling wells to completion on the leased land until there shall have been
drilled thereon a number of oil wells (or oil and gas wells) equal to the number
of acres then subject to this lease divided by ten (if the deepest production
therefrom is established from zones down through the Etchegoin formation) or by
forty (40) (if the deepest production therefrom is established from zones below
the Etchegoin formation); or, in the case of gas wells, one hundred sixty (160)
(if the deepest production therefrom is established from zones down through the
Etchegoin formation) or by three hundred twenty (320) (if the deepest production
therefrom is established from zones below the Etchegoin formation) unless Lessee
gives written notice to Lessor of Lessee's election to cease drilling and
surrender down to the developed area of the lease land pursuant to paragraph 13
of this lease.
Notwithstanding the one hundred twenty (120) day period
between wells provided above, the allowable period shall be one hundred eighty
(180) days between the first and second wells drilled hereunder, provided the
first such well is the first well in such prospect.
(b) The requirements set forth above constitute a minimum
development program only, and Lessee shall in any event drill and complete on
the leased land whatever additional producing wells may be necessary from time
to time to provide proper development, consistent with good oil field practice,
of the leased land for the production of substances from all zones remaining
subject to this lease. Lessee may drill on the leased land to subsurface
portions thereof remaining subject to this lease as many wells as it may desire
to drill in addition to those required by the provisions of this lease.
(c) In the event that the zone to be produced from is shown to
be a part of a pool which includes an area outside the leased land, the drilling
requirements under this paragraph may be fulfilled by the drilling of wells
anywhere within the pool, provided that any well drilled within the offset
distance under paragraph 4 is unitized with Lessor's land as provided in
paragraph 23.
4. If, during or after the primary term hereof, a well is drilled upon
adjacent property, whether by Lessee or by another party, and the Lessor has no
interest in the production therefrom and the well is located within six hundred
sixty feet (660') of the exterior boundaries of the land at that time included
in this lease and is completed as a producer of oil in commercial quantities (or
the well is located within thirteen hundred twenty feet [1320'] of the exterior
boundaries of the land at that time included in this lease and is completed as a
producer of gas in commercial quantities) and causes the migration of oil or gas
from said land, then Lessee shall (provided it is not then drilling or has not
theretofore drilled an offset well on said land) within ninety (90) days from
the date the owner of such well commences marketing production therefrom, either
commence operations for the drilling of an offset well on said land or surrender
and terminate this lease, in the manner provided in paragraph 13 hereof, as to a
portion of said land, the dimensions of which said portion shall be equal to the
distance of such well from said exterior boundary. Such surrender shall be
limited to the zone or zones being drained by the well on the adjacent property.
Lessee shall never be required to drill (or surrender in lieu thereof) any
offset well which, in Lessee's opinion, would be incapable of producing said
substances in quantities sufficient to yield a return which, after deducting the
value of all said substances to be drained into said land from such zone or
zones by existing wells thereon, would exceed the drilling and operating costs
of such offset well.
5. Except as herein otherwise provided, Lessee shall drill each well
and operate each completed well continuously, consistent with securing
ultimately the maximum production from the leased land, and in accordance with
good oil field practice so long as such well shall be capable of producing oil
or gas in paying quantities but in conformity with any conservation or
curtailment program which may be imposed by law or by any appropriate
governmental agency. After the completion of the first oil well, drilling or
producing operations hereunder (except of offset wells when wells offset or to
be offset are being operated) may be suspended while either: a) for an oil well,
the price generally offered to producers in the same field or, if none, the same
vicinity for oil of the quality produced from the leased land is Five Dollars
($5.00) or less per barrel at the well, and for a gas well, the price generally
offered to producers in the same field or, if none, the same vicinity is less
than One Dollar ($1.00) per thousand cubic feet, or when there is no available
market for the oil or gas at the well above said prices; or b) when the well
would be incapable of producing oil or gas in quantities sufficient to yield a
return which, after deducting the value of all substances to be drained from
such zone or zones by existing wells thereon, would exceed the operating costs
of recovery. In such case, an annual advance royalty proportionate to the amount
paid in paragraph 1 will be paid by Lessee to Lessor. In the event operations
are suspended under "b)" above, Lessee shall suspend operations for no longer
than two (2) years at any given time, and at the end of the period of
suspension, Lessee must operate continuously for at least six (6) months. In any
event, Lessee is not required to resume operations for ninety (90) days after
the reason for suspension ceases to exist.
5.1 Lessee shall, to the fullest extent permitted by applicable law,
indemnify and hold Lessor harmless of and from all liens, liability, claims,
demands, damages, or costs of every kind, on account of injury to or death of
persons and damage to real or personal property, arising out of or in connection
with operations and activities conducted or caused by Lessee under or pursuant
to this Oil and Gas Lease, except to the extent that those liabilities that
arise due to the gross negligence and/or willful misconduct of Lessor.
/
/
6. (a) The term "royalty share" as used herein means twenty-five
percent (25% of 100%); provided, however, that the royalty share shall be
reduced on the first well only to twenty percent (20% of 100%) until payout of
such first well. Within thirty (30) days of completion of such first well,
Lessee shall furnish to Lessor monthly payout statements, in standard industry
format, related to such well.
(b) Lessee shall pay Lessor as royalty on oil the value of the royalty
share of all oil produced and removed from the leased land after making the
customary adjustments for temperature, water and b.s. at the average of the
three highest posted prices in
the field, but in no event lower than the price actually received, in which the
well is located for oil of like gravity and quality on the day the oil is so
removed or, at Lessor's option, in lieu of such payment Lessee shall deliver the
royalty share of said oil, free of cost, into Lessor's tanks on the leased land
or into pipeline thereon designated by Lessor. A change from payment in cash to
delivery in kind, or vice versa, may not be made more often than once in any
calendar year and then only on 60 days prior written notice to Lessee. If
royalty on oil is payable in cash, Lessee may deduct therefrom a reasonable
charge for dehydration, cleaning and treating such oil and a reasonable charge
for transportation to the treating plant. Nothing herein contained shall be
construed as obligating Lessee to treat oil. If Lessor shall elect to receive
the royalty on oil in kind, it shall be of the same quality as the oil removed
from the leased land for Lessee's own account, and if Lessee's own oil shall be
treated before such removal, Lessor's oil will be treated therewith before
delivery to Lessor, and Lessor, in such event, shall pay a proportionate part of
the cost of treatment. No royalty shall be due Lessor for or on account of oil
used by Lessee in operations on the leased land or lost through evaporation,
leakage, fire or other casualty prior to the removal of the same or prior to
delivery to Lessor if royalty shall be delivered in kind.
(c) Lessee shall pay Lessor as royalty on natural gas the royalty
share of the value of such natural gas which shall be the sum of the
following:
(i) The net proceeds received by Lessee from the sale of gas produced
from wells on the leased land (whether such gas be sold by Lessee
in its natural state or as residual dry gas after extracting
gasoline and other content therefrom). Gas treated at a gasoline
extraction plant not owned or operated by Lessee and for which
Lessee receives in return for processing such gas a percentage of
the gas from the operator of such plant shall be deemed sold in
its natural state for an amount equal to the amount realized by
the Lessee for the sale of said percentage of gas. Except as
otherwise provided herein, gas used or consumed by Lessee in
operations other than under this lease shall be deemed sold for
the market value thereof. The value of gas and products extracted
therefrom, used or consumed in the operation of a gasoline
extraction plant (to the extent that it is so used for processing
gas from the leased land), or in operations on the leased land,
or in repressuring any oil bearing formation from which a well or
wells on the leased land is producing, shall not be included. The
cost of processing, treating, compressing, handling and
transporting gas in connection with the sale thereof shall be
deducted in determining net proceeds of sale.
"Market Value" as used herein shall mean (1) the value received under a
prudently negotiated contract for the sale and purchase of gas, gasoline or
other liquid hydrocarbons between Lessee and non-affiliated buyer in arm's
length negotiations, or (2) in the absence of such a contract, it shall be
determined from the weighted average prices paid under contracts, which are
available to the Lessee, for production of like kind and quality in the field in
which the leased land is located, and which contracts were made or entered into
(or the price is renegotiated or redetermined in accordance with the contracts)
at or near the time that the sale of gas or other liquid hydrocarbons produced
hereunder is made to the affiliated buyer, and if there is no such contract in
the field, then in the county or area, or (3) if no such contracts are available
to the Lessee, it shall be based on the arithmetic average of the arm's length
spot market price reported in reliable publications for the pipeline or
pipelines to which the leased land or field is physically connected, adjusted
for the transportation differential between the leased land and the spot market
location based on pipeline tariffs approved by the Federal Energy Regulatory
Commission or applicable state regulatory agency.
(ii) The market value at the extraction plant of all gasoline and
other liquid hydrocarbons extracted and saved from natural gas
from the leased land as a result of processing such gas at a
plant owned or operated by Lessee, less the cost of such
processing.
(iii)The amount realized by the Lessee, at the plant where extracted,
of all gasoline and other liquid hydrocarbons received by Lessee
as a result of the processing of natural gas from the leased land
at a plant not owned or operated by Lessee (if such processing is
not on a royalty basis) less the cost to Lessee of such
processing.
Nothing herein contained shall obligate Lessee to
treat or process natural gas nor shall Lessee be obligated to save, sell or
otherwise dispose of natural gas or residual dry gas, as the case may be, unless
there is a market therefor at the well or processing plant at a price and under
conditions which Lessee believes to be for the best interests of both parties
hereto, or to pay royalty on any gas which is neither sold nor used.
(d) Lessee shall pay Lessor as royalty on hydrocarbons
produced from the lease other than oil, gas and gasoline, and other products
extracted at a gasoline extraction plant, the royalty share of the market value
of such substances.
(e) If at any time or from time to time there is on the leased
land a well capable of producing gas in paying quantities, but gas is not being
produced therefrom, this lease shall terminate, unless otherwise maintained
under other applicable provisions hereof, as to the Well Tract associated with
said well unless Lessee, prior to six (6) months following cessation of
production (or completion in the case of a new well), pays or tenders to Lessor
as shut-in royalty the sum of $25 per net acre for the acreage in the Well Tract
associated with the shut-in well. If Lessee tenders such payment to Lessor in
the allotted time, the lease shall continue in full force and effect as to the
Well Tract in question for a period of two (2) years from the date of cessation
of production (or completion in the case of a new well). Thereafter this lease
shall terminate unless maintained in accordance with other applicable provisions
herein.
7. Settlement shall be made by Lessee on or before the last day of each
calendar month for all royalties which accrued during the preceding month and
Lessee shall furnish Lessor monthly statements showing the computation of
royalties. Lessor agrees to examine promptly each and all statements and
remittances forwarded by Lessee to it hereunder and promptly advise Lessee of
any objection thereto. Notwithstanding anything to the contrary contained in
this Paragraph 7, in the case of settlement for gas, the time period for
settlement provided for herein shall be extended by an additional thirty (30)
days.
8. Lessee shall pay all taxes levied upon or assessed against its
improvements, fixtures and personal property on the leased land, including
Lessee's oil stored thereon. Taxes levied upon or assessed against the minerals
and mineral rights subject to this lease, (or, if same shall not be separately
assessed, such part of the taxes on the leased land as are due to the discovery
of oil, gas or any of the above-mentioned other substances on the leased land or
lands adjacent thereto) shall be paid as follows: The royalty share thereof by
Lessor and the remainder thereof by Lessee. Any severance tax or other tax
assessment, or license now or hereafter levied or imposed, measured by the
quantity or value of oil, natural gasoline, gas or said other substances
produced from the leased land, or any thereof, shall be borne by the parties in
the same ratio as taxes on minerals and mineral rights. Lessee shall not be
liable for any special assessment for local improvements or benefits.
9. Except as otherwise provided for, Lessee, at its own cost and
expense, shall pay for all labor performed and materials furnished in the
operations of Lessee hereunder and Lessor shall not be chargeable with, or
liable for, any part thereof. Lessee shall protect the leased land from liens of
every character arising from its operations. Lessor may post and keep posted on
the leased land notices to protect the same from liens.
10. Lessee shall conduct all of its operations on the leased land in
accordance with and in all respects shall perform and observe all of the
provisions of Exhibits "A" and "B", attached hereto and by this reference made a
part hereof. Without in any way limiting Lessee's obligations, Lessee shall use
its best efforts to assure that field personnel in charge of its operations on
the leased land are familiar with and actively enforcing all of the terms of
this lease and the requirements of its Exhibits "A" and "B".
11. Lessee shall pay the amount of all damages to livestock, crops,
fruit or nut trees, timber, fences, ditches, buildings and other improvements
caused by Lessee's operations on the leased land, which payments shall be made
to Lessor or Lessor's tenant, whichever shall sustain such damage. If Lessor is
not the owner of such surface, Lessee will hold Lessor harmless from all claims
and demands arising out of Lessee's operations hereunder which may be asserted
by the owner of the surface or by any tenant of such owner.
12. Lessor, at all reasonable times and upon reasonable notice, may
inspect the leased land and the work done and in progress thereon, and the
production therefrom. Lessor may also examine the books kept by Lessee in
relation to the amount and character of the production from the leased land and
disposition thereof. Lessee shall promptly furnish to Lessor data from all wells
drilled by Lessee on the leased land, as is listed on Exhibit "B", attached
hereto.
13. (a) Except as otherwise specifically provided herein, Lessee shall
have the right, at any time or times, to give written notice of and surrender to
Lessor (i) all of the leased land, (ii) any portion of the leased land, or (iii)
all of the rights of Lessee as to any subsurface portion or portions of the
leased land underlying all of the leased land or any such portion thereof.
Thereupon the lands or the subsurface portion or portions of the leased land, as
the case may be, so surrendered, shall cease to be subject to this lease and all
rights, obligations and liabilities of Lessee hereunder, except obligations or
liabilities theretofore accrued, shall cease and terminate with respect thereto.
(b) Promptly after giving written notice to Lessor of an
election to cease drilling and surrender down to the developed area pursuant to
this paragraph 13, Lessee shall surrender to Lessor (i) all of the leased land
except each Well Tract containing a well which produced or was capable of
producing substances hereunder in paying quantities at some time during the
period of 6 months next preceding the giving of such notice, and (ii) all
subsurface portions of the leased land underlying each Well Tract below the base
of the stratigraphic equivalent of the formation of deepest production from
which substances were produced or capable of production hereunder in paying
quantities at some time during said period of 6 months. Whenever used in this
lease, Well Tract shall mean the amount of acreage specified in paragraph 3.A,
provided that each respective tract of land shall be as nearly as possible in
the shape of a square with the earning well situated in the center thereof, with
sides paralleling the section boundaries. In instances where a well is slant
drilled with a surface location on one Well Tract and opened for production
under a different Well Tract, the well shall be deemed drilled on the Well Tract
under which such well is opened for production.
(c) From time to time after Lessee's original surrender to a
developed area under paragraph 13(b), then, except as provided in paragraph 6
(e), (i) whenever there shall have been no production of substances in paying
quantities hereunder from a Well Tract retained by Lessee under paragraph 13(b)
for a continuous period of 6 months, Lessee shall promptly surrender such Well
Tract to Lessor, and (ii) in the case of Well Tracts with respect to which
Lessee retained more than one zone under paragraph 13(b), whenever there shall
have been no production of substances hereunder in paying quantities from any
zone so retained by Lessee for a period of 6 months, Lessee shall promptly
surrender such zone to Lessor; provided, that during the first year of the term
hereof the foregoing provisions of this paragraph shall be suspended during any
period in which Lessee keeps at least one (1) string of tools employed
continuously, with not more than 60 days intervening between the completion of
one well and the commencement of drilling of another well, in diligently
drilling wells on the leased land to completion, or in which Lessee's drilling
obligations are suspended pursuant to paragraph 14, or paragraph 5.
(d) Whenever any lands constituting all or any part of the
leased land or whenever any subsurface portion or portions of the leased land
underlying lands remaining subject hereto, or any portion thereof, shall cease
to be subject to this lease by surrender, lapse of time, termination or
otherwise, all rights of Lessee under this lease with respect to such lands or
subsurface portion or portions thereof shall forthwith cease and be at an end,
and Lessor shall have and is hereby given the right to re-enter such lands and
repossess itself thereof as of its former estate therein, removing all persons
and property therefrom, and Lessee shall promptly and peaceably surrender up the
possession of such lands to Lessor and shall duly and promptly execute,
acknowledge and deliver to Lessor a good, sufficient and recordable release,
covering all rights of Lessee in or to such lands or such subsurface portion or
portions thereof. Whenever any subsurface portion or portions of the leased land
shall so cease to be subject to this lease while an underlying portion of the
leased land remains subject hereto, Lessee shall have the right to conduct such
drilling and other operations in and through the subsurface portion or portions
so ceasing to be subject to this lease as may be necessary or convenient for its
operations in the retained subsurface portion or portions.
(e) Whenever any part of the leased land shall cease to be
subject to this lease by surrender, lapse of time, termination or otherwise
while other lands remain subject to this lease, Lessee shall, at the request of
Lessor and upon receipt of the release provided for in paragraph 13(d), deliver
to Lessee a license covering existing roads, water, oil and other pipe lines,
telephone and electric power lines, oil, gas and water wells and other
facilities which are located on the lands so ceasing to be subject to this lease
and which are still needed for the operations of Lessee hereunder on the lands
remaining subject hereto. The license shall be executed by both Lessor and
Lessee and shall be effective for so long as such facilities are needed for the
operations of Lessee hereunder.
(f) Lessee may at any time with respect to a designated part
or all of the leased land, (i) surrender its right to produce oil, or (ii)
surrender its right to produce gas. A surrender of the right to produce oil
shall include a surrender of the right to produce the gas which will necessarily
be produced therewith. A surrender of oil rights in all the leased land will
relieve Lessee of further obligation to drill oil wells. A surrender of oil
rights in a part only of the leased land will reduce the number of required oil
wells to a number determined by the acreage as to which oil rights are retained
by Lessee. A surrender of oil rights shall have no effect on obligations to
drill for gas and a surrender of gas rights shall have no effect on obligations
to drill for oil.
14. Performance of covenants and conditions imposed upon Lessee
hereunder shall be excused while, and to the extent that, Lessee is hindered in
or prevented from complying therewith, in whole or in part, by war, riots,
strikes, lockouts, action of the elements, accidents, inability to obtain
materials in the open market or to obtain transportation therefor, laws, rules
and regulations of any federal, state, municipal or other governmental agency or
any other cause beyond the control of the Lessee, whether similar or dissimilar
to those herein specifically enumerated and without regard to whether such cause
exists at the date hereof or hereafter arises.
15. (a) If Lessee shall fail to pay promptly any installment of
royalty, and if such default shall continue for a period of 15 days after
written demand therefor, then at the option of Lessor, this lease shall
forthwith terminate as to the Well Tract for the applicable well; provided,
however, that if there be a bona fide dispute as to the amount due, and all
undisputed amounts are paid, said 15 day period shall be extended until 5 days
after such dispute is settled by final court decree, arbitration or mutual
agreement.
(b) In case of default by Lessee with respect to any other
condition or covenant hereof and continuance of such default for 30 days after
written notice from Lessor to Lessee to perform such condition or covenant, then
at the option of Lessor this lease shall forthwith cease and terminate except
that if any well or wells have theretofore been drilled or is then being drilled
and Lessee is not in default in connection therewith, this lease shall
nevertheless continue in effect as to an area or areas as provided in paragraph
13.B. Lessee shall not, however, be deemed to be in default while work is in
progress in good faith which when completed will constitute compliance with such
condition or covenant. A termination of this lease as to a part only of the
leased land or as to a part only of Lessee's rights shall not affect such rights
of way and easements as may be necessary in Lessee's operations on the part of
the leased land as to which no such termination shall have occurred.
16. Lessor agrees that if Lessee shall make any payment on account of
any tax not required to be paid by it under the conditions hereof or any
mortgage or other lien on or against any of the lands subject to this lease, it
shall , in addition to the right of subrogation, have the right to reimburse
itself out of any royalty or rentals accruing hereunder.
17. The Lessee's interest under this Oil and Gas Lease may not be
sold, assigned or otherwise conveyed without the prior written consent of
Lessor. Any attempted sale, assignment or other conveyance of Lessee's
interest without such consent shall be null and void.
18. In the event that Lessee drills a water well on the leased land for
the production of water for its operations on the leased land, Lessee agrees
that if said well is no longer desired by Lessee or upon the termination of this
lease it will remove the pump, tubing and power plant from said water well and
will cap the surface casing and otherwise leave same in such condition as may be
required by any law or regulation, but otherwise will leave said well in such
condition that Lessor may subsequently equip the well for the production of
water for Lessor's own use.
19. This Oil and Gas Lease is made without warranty of any kind as to
title. Lessor shall cooperate with Lessee, without any expense to Lessor, in any
defense of the title thereto. Lessee shall pay all taxes levied against Lessee's
plants, machinery and personal property and all taxes (except those payable on
Lessor's royalty share) assessed upon mineral rights or assessed upon or
measured by production from or allocated to the leased land. Lessor shall pay
all other taxes assessed against the leased land and its royalty share of taxes
assessed upon mineral rights and assessed upon or measured by production from or
allocated to the leased land. If Lessor shall fail to pay any taxes, assessments
or charges required to be paid by Lessor, Lessee may, at its option, pay the
same and reimburse itself therefor out of any future royalties or rentals
accruing hereunder.
20. Regardless of whether or not Lessor's interest is specified in this
Oil and Gas Lease, Lessor shall be entitled to royalties and rentals payable
hereunder with respect to any of said substances only in the proportion which
Lessor's actual interest in the respective substances bears to the entire
undivided and unqualified fee simple estate herein.
21. Lessee shall furnish to Lessor the data and other information
provided in Exhibit "B", attached hereto and by this reference made a part
hereof, in the manner provided in said exhibit. Should Lessee perform other
tests, take other samples or run other logs or otherwise perform operations to
obtain information related to the type contemplated by the requirements of said
exhibit, Lessee shall provide copies thereof or otherwise make available such
information to Lessor.
22. Time and specific performance are of the essence of this Oil and
Gas Lease. Where this Oil and Gas Lease provides that certain periods of time
are to commence upon the completion or abandonment of a well, such completion or
abandonment shall be deemed to occur when the rig then on such well is released
therefrom.
23. Subject to the following terms and conditions, Lessee is hereby
granted the right to unitize or pool the leased land or any part thereof with
any other land, lease, leases, mineral estates or parts thereof for the
production of substances when, in Lessee's good faith judgment, unitization or
pooling are required to comply with applicable laws, to promote or encourage the
conservation of natural resources or the efficient and economical location and
spacing of wells or to join in any cooperative or unit plan of development or
operation approved by state or federal authorities. Furthermore, Lessee may, in
accordance with the following terms and conditions and in the exercise of its
good faith judgment, change the size or shape of any such unit to permit more
efficient and economical operation, to include acreage believed to be productive
and to exclude acreage believed to be unproductive or which is not committed to
the unit, but any increase or decrease in Lessor's royalty resulting from any
such change in any such unit shall not be retroactive. Any such unit may be
established or changed, and in the absence of production therefrom may be
abolished and dissolved, by filing for record an instrument so declaring, a copy
of which, as recorded, shall be delivered to Lessor. Drilling or other
operations (as defined in this lease) upon, or production of any one of said
substances from any part of such unit shall be treated and considered for all
purposes of this lease as such operations upon or production from the leased
land. Lessee shall allocate to the portion of the leased land included in any
such unit a fractional part of all production from any part of such unit on the
same basis as is provided in the agreement between Lessee and others whereby
such unit is established or, in the absence of such an agreement or of a method
of allocation therein, Lessee shall elect one of the following bases: (a) the
ratio between the surface acreage in this lease included in such unit and the
total of all surface acreage included in such unit; or (b) the ratio between the
value, as estimated by Lessee, of recoverable production within the portion of
the leased land included in such unit and the total value, as estimated by
Lessee, of recoverable production within such unit.
No offset obligation shall accrue under this lease as a result
of any well drilled within any such unit.
In addition to the foregoing terms and conditions:
(a) Units formed for the production of oil hereunder shall not
exceed ten (10) acres for oil produced from the Etchegoin or any shallower
formation or forty (40) acres for oil produced from zones lying deeper than the
Etchegoin formation, such units being sometimes referred to hereinafter as
("allowable units").
(b) Units formed for the production of gas hereunder shall not
exceed one hundred sixty (160) acres for gas produced from the Etchegoin or any
shallower formation or one hundred sixty (160) acres for gas produced from zones
lying deeper than the Etchegoin formation, such units being sometimes referred
to hereinafter as "allowable units".
(c) For any allowable unit, the leased land shall comprise a minimum
of fifty percent (50%) of the total thereof.
24. This lease and all its terms, conditions and stipulations shall
extend to and be binding upon the successors and assigns of said
Lessor and Lessee.
25. In addition to Lessor's right to elect to take its royalty share in
kind, Lessor shall have the right to elect to purchase all or any part of the
production attributable to this Oil and Gas Lease in accordance with the
provisions of the agreement to which this lease (Exhibit "D") is attached.
LESSOR LESSEE
CHEVRON U.S.A. INC.
By: _____________________ By: _____________________________
Assistant Secretary Title:
EXHIBIT "A"
Attached to and made a part of that certain Oil & Gas Lease, dated
______________, 199__, by and between Chevron U.S.A. Inc., as Lessor, and
_________________________, as Lessee.
MANNER OF OPERATION AND CLEAN-UP REQUIREMENTS
1. General. In drilling, equipping and operating wells and in all other
operations on the leased land, Lessee shall use reasonable care and diligence
and shall perform all work in a proper and workmanlike manner and so as to
interfere as little as possible with agricultural, grazing, surface development
or any other uses to which the land may be put. Lessee shall locate its
structures in groups and shall avoid unnecessary scattering of such structures
and unnecessary occupancy of the leased land. Lessee shall keep the premises
around all of its facilities free from brush, weeds and rubbish and in a neat
and clean condition, and shall use extraordinary care to prevent fires on the
leased land or adjoining lands. Lessee shall plow for a width of at least 8 feet
such parts of the leased land as it shall be necessary or proper to plow to
prevent the spread of any fire which might originate at any place in the control
of Lessee.
2. No Earthen Sump. Lessee shall not construct or utilize earthen
sumps for any purpose, including, but not limited to percolation
or drilling or production operations.
3. Notice of Surface Use. Lessee shall give ___________________,
Lessor's ______ Area Production Manager (805-________) and ___________________,
Lessor's California Division Pipe Line Manager (805-________) at least 5 days'
advance notice, either in writing or by telephone, before commencing any
operations on any portion of the leased land not then being used or occupied by
Lessee and shall specify in such notice the approximate time of commencement and
location of its intended operations, to the end that said Manager may take such
steps as he may deem appropriate to minimize interference with other operations
on the surface of the leased lands.
4. Surface Drillsite. The surface area and location of Lessee's
drillsite shall be subject to the prior written approval of Lessor's designated
Production Manager and Lessor's Pipe Line Manager. Such surface drillsite(s)
shall be constructed in compliance with all applicable federal, state, county
and municipal laws and applicable rules, orders and regulations and in
accordance with specifications current in use by Lessor for its own operations.
(These specifications may be obtained from said Production Manager.)
5. Pipelines, Roads and Fences. The location of Lessee's pipelines and
access roads shall be confined to section lines or mid-section lines and subject
to the prior written approval of Lessor's designated Production Manager and
Lessor's Pipe Line Manager. To the extent practicable Lessee shall confine its
travel to established roads in order to avoid interference with agricultural or
any of Lessor's other operations and, in the case of hilly or mountainous
country, in order to avoid gullying which would result in erosion. Lessee shall
keep all of its pipelines and access roads in good and safe condition at all
times. All gates used by Lessee in any fences of Lessor now or hereafter
existing on the leased land or elsewhere shall be kept closed and locked by
Lessee at all times except when necessarily open for actual passage. Upon
written request of Lessor, Lessee shall install and maintain substantial cattle
guards at all points where roads used by Lessee pass through any such fences.
Upon similar request Lessee shall erect and maintain substantial fences with
proper gates or cattle guards (as directed by Lessor) around all wells, sump
holes, buildings and other structures erected or used by Lessee upon the leased
land. All such fences, gates and cattle guards shall be constructed in
compliance with all applicable federal, state, county and municipal laws and
applicable rules, orders and regulations and in accordance with specifications
currently in use by Lessor for its own operations. (These specifications may be
obtained from said Production Manager.)
<PAGE>
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6. Burying of Pipes. Upon written request of Lessor, Lessee shall
promptly bury and thereafter maintain all pipe lines on the leased land, or on
such portion thereof as Lessor may designate, so that the top of the pipe shall
be not less than thirty-six (36) inches below the surface of the ground, and
Lessee shall promptly fill in all trenches dug in the course of burying any such
pipe line.
7. Irrigation, Water Storage and Flood Control. Lessee shall never under
any circumstances obstruct or interfere with the free flow of water in any
canal, ditch, stream or other watercourse or interfere with any levee, dam,
embankment or other works or structures for the control, diversion, storage or
carriage of water, whether now existing or hereafter constructed or established
on the leased land, or interfere with the construction, maintenance or operation
of any of them. Subject to the foregoing limitations, Lessee may construct and
maintain such separate embankments around its individual wells and other
structures as may be necessary to protect them from flood waters, but Lessee
shall not construct or maintain any other embankments or any levees or other
works to control, divert or ward off any flood waters or other water flowing
upon the leased land. Should it become necessary for any of Lessee's access
roads or pipe lines to cross any canal, ditch, stream or other watercourse, the
crossing shall be constructed by Lessee at the time and in the manner specified
by Lessor's designated Production Manager and Lessor's Pipe Line Manager.
8. Locating Oil Wells etc. Adjacent to Canals, Buildings, Pole Lines
etc. Lessee shall not drill any well or place or erect any derrick, sump,
building or other structure upon the leased land in the bed of, nor within 100
feet of the outside toe of the bank of, any canal, ditch, stream or other
watercourse, nor within 100 feet of any power transmission line, nor within 150
feet of any building, corral or water well, nor within 1,000 feet of any cattle
watering trough or station. Any corral or cattle watering trough or station may
be relocated by Lessee at any time at its own cost and expense at a new location
approved by Lessor's designated Production Manager and Lessor's Pipe Line
Manager, so as to permit Lessee to erect buildings and other structures at the
location desired.
9. Protection of Water Sources. Lessee shall use all reasonable means to
shut off all water that may be encountered in drilling any well on the leased
land and in the event of the abandonment of any such well Lessee shall leave
therein sufficient casing or other material permanently to shut off all such
water. Lessee shall make adequate provision in a manner approved by Lessor's
designated Production Manager and Lessor's Pipe Line Manager to handle and
dispose of all oil, oily substances, tailings, water and liquid refuse so as to
prevent the pollution of the fresh water strata underlying the leased land and
also prevent the escape of any such material into any canal, ditch, stream or
other watercourse.
10. Abandonment of Oil and Gas Wells. If Lessee proposes the abandonment
of any well, it shall give written notice thereof to Lessor. Within thirty (30)
days' of Lessor's receipt of such notice (except in the case of a well whose
drilling rig is on location and in such case, such advance notice period shall
be twenty-four [24] hours, excluding weekends and holidays), Lessor may elect to
take over the well by affirmative notice to Lessee, whereupon Lessor shall
thereafter own the well, pay to Lessee the net salvage value of the well (value
of salvable equipment and materials in the well minus the estimated costs of
salvaging the same) and thereafter bear all risk, cost and expense related to
the same. Lessor and Lessee shall cooperate to promptly secure the approval of
appropriate governmental agencies of the transfer of the well's
ownership/operatorship. Lessor's failure to timely notify Lessee of Lessor's
election to take over the well shall be deemed to be an election not to take it
over.
Subject to Chevron's right to take over wells as provided herein,
any oil or gas well in which producing operations are suspended for 180 days,
for which Lessee is not actively pursuing the restoration of production
therefrom, and which is not authorized to remain suspended pursuant to the terms
of paragraph 6(e) of the Oil and Gas Lease to which this Exhibit "A" is
attached, shall be promptly abandoned by Lessee upon demand by Lessor. Whenever
Lessee shall abandon any oil or gas well upon the leased land, Lessee shall
promptly remove all tanks, pipes, structures and equipment used solely by Lessee
in connection with drilling or operating said well, clean out and fill all sumps
appurtenant thereto, remove and haul away all sludge and oil-soaked earth, dig
out and remove all foundations, pipes and other objects installed by Lessee
within 4 feet of the surface of the ground, clean and smooth out the surface of
the ground, and leave the ground surrounding the well site in as near the
condition existing at the date of this lease as is reasonably practicable.
Furthermore, Lessee shall take whatever additional actions as are required to
plug and abandon the well in accordance with applicable laws, rules, orders and
regulations. Except for wells taken over by Lessor hereunder, Lessee shall bear
the sole risk, cost and expense of the abandonment of all wells.
11. Removal of Facilities and Restoration of Land. Whenever any lands
constituting all or any part of the leased land shall cease to be subject to
this lease, Lessee shall upon written notice from Lessor promptly commence the
removal from such lands of all facilities placed or constructed on such lands by
or for Lessee in connection with its operations under this lease, excepting any
facilities specified by Lessor. Lessee's obligation to remove facilities shall
include the obligation to obliterate such of Lessee's roads as Lessor shall
specify in its written notice to Lessee and the obligation to remove and haul
away all sludge and oil-soaked earth, dig out and remove all foundations, pipes
and other objects within 4 feet of the surface of the ground and clean and
smooth out the surface of the ground; provided, however, that such obligations
shall apply only to those facilities and conditions which exist on or after the
effective date of this oil and gas lease. In obliterating roads Lessee shall
break up and remove all paving, gravel and other surfacing and shall break down
and smooth out all fills, cuts and embankments appurtenant to such roads. Lessee
shall diligently continue the work of such removal until it is completed, shall
restore such lands to as near their original condition as is practicable and
shall leave such lands in a neat, clean and orderly condition.
12. Maps of Foundations, etc. Not Removed. Whenever Lessee shall abandon
any oil or gas well and whenever any lands shall cease to be subject to this
lease, Lessee shall promptly thereafter prepare and deliver to Lessor in
duplicate a detailed map showing the exact location of all foundations, pipes
and other objects installed and left by Lessee.
EXHIBIT "B"
Attached to and made a part of that certain Oil & Gas Lease, dated
______________, by and between Chevron U.S.A. Production Company, as Lessor, and
___________________, as Lessee.
I. GEOLOGIC AND FORMATION EVALUATION REQUIREMENTS:
A. Mudlogging Unit: 24-hour coverage, minimum two man crew.
Conventional unit equipment plus chromatograph. Logged from
shoe of surface casing to total depth. Collect minimum 30'
composite unwashed wet and minimum 30' composite washed and
dried samples from shoe of surface casing to T.D.
B. Minimum Open Hole Wireline Logging: Base of surface casing to
T.D. run: Dual Induction Log, Digital Sonic Log, Compensated
Density/Compensated Neutron/Gamma Ray Logs, Dipmeter/Dipmeter
processing (optional with Lessee), sidewall samples, as dictated
by prudent oilfield practices. LIS tapes of all wireline logs are
required, if such logs are run. -------
C. Coring and Testing: As dictated by prudent oilfield practices
for oil and gas shows.
II. DRILLING AND CASING REQUIREMENTS:
A. Casing: Casing depths and sizes to be in accordance with city,
county, state or federal regulations and good oil field
practices.
B. Drilling Fluid: High quality for minimum formation damage and
optimum formation evaluation.
III. PERMITS AND WELL PROGRAM:
Two weeks prior to spudding the well, provide the following:
A. Two (2) copies of any notices or permits required by governmental
regulatory agencies.
B. Two (2) copies of the drilling program, formation evaluation
program, and any proposed directional plat map.
The above material should be addressed to:
Chevron U.S.A. Production Company
P. O. Box 1392
(or 5001 California Ave.)
Bakersfield, CA 93302 (or 93309)
Attn: W. C. Kempner
IV. DAILY REPORTING, FIELD PRINTS, CUTTING SAMPLES:
A. During well operations, provide the following:
1. A drilling progress report, daily mudlog and mudloggers
report before 8:00 a.m. by FAX to Chevron's Bakersfield office.
FAX Number: (805) 395-6304
Attn: W. C. Kempner
2. One set each of unwashed wet and washed and dried samples and a
one-quart sample of each hydrocarbon based fluid additive are to
shipped on a weekly basis to:
Chevron U.S.A. Production Company
Geology Warehouse
100 Castro Street
Richmond, CA 94801
Attn: Don Gibson
3. Advance notice (of no less than 48 hours) of wireline logging
runs, coring, testing operations, or of completion or abandonment
operations must be given to Chevron. 4. Send daily or as soon as
available, two (2) copies of the
following to:
Chevron U.S.A. Production Company
P. O. Box 1392
(or 5001 California Ave.)
Bakersfield, CA 93302 (or 93309)
Attn: W. C. Kempner
a. Daily mudlog (blueline).
b. Field prints of all wireline logs.
c. Directional survey.
d. Survey plat showing final well surface location.
e. DST summaries, if any, including tracing or copy of pressure
charts.
f. Descriptions, photographs and analyses (including data diskette)
of any conventional or sidewall cores taken. Minimum analyses to
include porosity, permeability, and fluid saturations.
5. One copy of all wireline log digital acquisition (or
equivalent) tapes, including dipmeter (raw data and answer tape), of each log
run.
6. One copy of all check shot or VSP data, including digital
tape, if run.
B. Notify Chevron if hydrocarbons are added to the mud system, annotate
same on mudlog.
C. Furnish a minimum one gallon sample of any formation liquids
recovered on each drillstem test. Also furnish a sample of any
gas recovered. If insufficient sample is recovered to provide
a separate Chevron sample, minimum analyses on group samples
will include standard oil field brine analysis on any
formation water; gravity and viscosity on any oil recovered;
gas BTU on any gas recovered.
D. Chevron's earth scientist for the property is:
Office Phone Home Phone
W. C. Kempner (805) 395-6312 (805) 664-8331
V. FINAL WELL DATA, COMPLETION/ABANDONMENT REPORTS, WELL HISTORY:
After completion or abandonment of the well, provide final well data as
indicated below to the following address:
Chevron U.S.A. Production Company
P. O. Box 1392
(or 5001 California Ave.)
Bakersfield, CA 93302 (or 93309)
Attn: W. C. Kempner
A. Two (2) reproducible copies of all wireline logs, including
computed dipmeter, and two (2) blueline prints.
B. Two (2) reproducible copies of the final mudlog (and auxiliary
logs), two (2) blueline prints, two copies of the final report,
and if applicable one copy of the mudlog digital tape.
C. Two (2) copies of the completion report and history, including
reports filed with any governmental agencies.
D. Two (2) copies of the final directional report.
E. Two (2) copies of the final drillstem test reports.
F. Two (2) copies of any reports prepared by the drilling contractor
or service companies not specified above.
G. If completed as a producing well, furnish daily testing and
production reports for the first 30 days of production and
monthly reports for the following period of one year.
H. Detailed completion and stimulation data to include depths, rates,
volume amounts, etc.
EXHIBIT "E"
Attached to and made a part of that certain Belridge Road/Railroad Grade
Prospect Areas Farmout, dated December 20, 1997, by and between NNG and
Saba Exploration Company (collectively "Farmee") and Chevron U.S.A.
Production Company-
Exhibit "E" consists of the two attached parts:
Revised Draft #3 of the "Chevron Lokern Habitat Conservation Plan/Natural
Community Conservation Plan"; and
Working Draft of the "Implementation Agreement" for the Lokern Natural Community
Conservation Plan/Habitat Conservation Plan, dated October 20, 1997, together
with cover letter re "Chevron/Lokern HCP", dated October 20, 1997, from
Nossaman, Guthner, Knox & Elliot.
EXHIBIT "F"
Attached to and made a part of that certain Belridge Road/Railroad Grade
Prospect Areas Farmout, dated December 20, 1997, by and between NNG, Saba
Exploration Company (collectively "Farmee) and Chevron U.S.A. Production
Company.
Additional Terms and Conditions
1. Chevronb. No Warrantiesb. No Warranties makes no representations or
warranties of title of any kind or character, express or implied, as to
ownership or validity of rights and interests purportedly covered by the farmout
lands or leases, and any interest in such farmout lands or leases earned by
Farmee shall expressly or impliedly be leased or assigned with disclaimers of
warranties consistent with the foregoing. Consequently, acting as a reasonably
prudent operator, Farmee shall satisfy itself as to title to the subject lands
and leases by conducting adequate title research. Farmee shall make available to
Chevron, on request, any abstracts and other title information owned or
controlled by Farmee and covering the farmout area, and shall furnish Chevron,
without warranty, a copy of all title opinions and curative data obtained by
Farmee covering or affecting title to lands or leases subject to the agreement
to which this exhibit is attached ("said agreement"), and shall mail same to
"Chevron / Attention: Land Manager" at the address provided for below.
2. Farmee shall not create, incur or allow to be incurred any lien, encumbrance
or claim against the land, leases or other rights affected by said agreement.
Should any such lien or encumbrance attach without Chevron's express written
consent, and if Farmee does not fully satisfy same within thirty (30) days
thereafter, then Chevron may, at its sole option, terminate said agreement and
Farmee's rights thereunder. Notwithstanding any termination hereof, Farmee shall
defend and indemnify Chevron against all such liens, claims of liens, suits
and/or all other proceedings pertaining thereto, including such costs and
attorneys' fees.
3. Farmee shall pay, currently when due, all costs and expenses for work
and labor performed and materials furnished in connection with Farmee's
operations pursuant to said agreement.
4. Chevron shall retain a right to purchase or to designate a purchaser for
Chevron's royalty share and for Farmee's share (hereinafter referred to as
"Farmee's share") of the "crude oil" (including condensate and other liquid
hydrocarbons) hereafter produced from or attributable to the farmout lands and
leases. Farmor may exercise its right according to the following procedures:
a. At least thirty (30) days prior to the commencement of a given "call
period", Chevron shall notify Farmee that Chevron elects to purchase or
to designate a purchaser for Farmee's share of the crude oil produced
from or attributable to the farmout lands and leases for a specified
period of time ("call period"), which call period shall in no event be
less than thirty (30) days. Upon the commencement of such call period,
Farmee shall deliver reserved crude oil only to Chevron or to its
designated purchaser until such call period has ended. For such
deliveries of crude oil, Farmee shall be paid market price, determined
for the time when such crude oil is produced and for crude oil of like
gravity and quality produced in the field wherein the farmout lands and
leases are situated.
b. Chevron's failure to notify Farmee of its election regarding a
proposed sale within the time allowed shall be deemed an election by
Chevron not to purchase or to designate a purchaser. In the event that
Chevron expressly or impliedly waives its right to purchase or
designate a purchaser under this provision, Chevron shall be deemed to
have consented to Farmee's sale of such crude oil under terms and
conditions no more favorable to the purchaser thereof than those
submitted to Chevron in such notice.
c. Nothing in this provision shall prevent Chevron from exercising its
call from time to time and at any time on crude oil production from or
attributable to the farmout lands or leases which is or will be
produced following expiration of the term of a third party sale
completed pursuant to the above provision, or on such crude oil
production not sold or committed thereby.
d. Chevron's exercise of its right to purchase or designate a purchaser
for crude oil shall not alter or diminish Farmee's responsibility to
administer the farmout area and farmout lands and leases, or to
maintain associated division orders.
e. Chevron shall have the right to take in kind and separately dispose
of its share of oil produced from or attributable to the farmout lands
and leases, either as a working interest owner or as an overriding
royalty owner.
f. Farmee shall bear any severance taxes owing on its share of
production.
g. This provision shall include and apply separately to not only
Chevron but also any one of its subsidiaries or affiliates.
5. Chevron hereby retains a right to purchase or to designate a purchaser for
Farmee's share (hereinafter referred to as "Farmee's share") of the gas
hereafter produced from or attributable to the leased land. Chevron may exercise
its right according to the following procedures:
a. At least thirty (30) days prior to the commencement of the "call
period" specified, Chevron shall notify Farmee that Chevron wishes to
purchase or to designate a purchaser for Farmee's share of the gas
produced from or attributable to the leased land for a specified period
of time ("call period"), which call period shall in no event be less
than thirty (30) days, and of the price Chevron or its designated
purchaser is willing to pay for such gas. Within ten (10) days
following receipt of Chevron's offer, Farmee shall either notify
Chevron that it accepts such price for the call period, or shall
negotiate with Chevron a mutually acceptable price. After acceptance of
a price by Farmee, upon the commencement of such call period, Farmee
shall deliver reserved gas only to Chevron or to its designated
purchaser until such call period has ended. If the parties are unable
to agree on a price, then Farmee shall be free to dispose of such gas
for a period not to exceed the call period specified by Chevron,
subject to Chevron's right to match any third party offer under Section
"b(i)" below.
b. At least ten (10) days prior to the proposed effective date thereof,
Farmee shall notify Chevron of the terms and conditions of any proposed
sale to a party other than Chevron of Farmee's share of gas produced
from or attributable to the leased land which is not already subject to
a call by Chevron or Chevron's designated purchaser. Within seven (7)
days following receipt of such notice, Chevron shall notify Farmee in
writing which of the following it elects:
. To purchase or to designate a purchaser for such gas under terms no less
favorable to Farmee than those described in such notice; or . To waive its
right of first refusal as set forth in Section "b", and thereby to consent
to Farmee's sale of such gas under terms and conditions no more favorable
to Farmee than those submitted to Chevron in such notice.
Chevron's failure to notify Farmee of its election regarding a proposed
sale within the time allowed shall be deemed an election by Chevron
under Section "b(ii)" hereof. Nothing in this Section "b" shall prevent
Chevron from exercising its call from time to time and at any time, in
accordance with Section "a", on gas production from or attributable to
the leased land which is or will be produced following expiration of
the term of a third party sale completed pursuant to this Section "b",
or on any gas production not sold or committed thereby.
iii. c. Chevron's exercise of its right to purchase or designate a
purchaser for gas shall not alter or diminish Farmee's responsibility to
administer the leased land or to maintain associated division orders.
-----------------
d. Chevron shall have the right to take in kind and separately
dispose of its royalty share of gas produced from or attributable
to the leased land.
e. Farmee shall bear any severance taxes owing on its share of
production.
f. This provision shall include and apply separately to not only
Chevron but also any one of its subsidiaries or affiliates.
6. In the event Chevron so elects, Farmee agrees to accommodate Chevron in
effecting a tax-deferred exchange under Internal Revenue Code Section 1031, as
amended. Chevron shall have the right to elect such a tax-deferred exchange at
any time prior to the closing of this transaction. If Chevron so elects, Farmee
agrees to execute such escrow instructions, documents, agreements or instruments
to effect an exchange as Chevron may reasonably request, it being understood
that Farmee shall not be required to incur additional costs, expenses, fees or
liabilities, not reimbursed or indemnified by Chevron, as a result of or
connected with an exchange.
Chevron may assign its rights and delegate its duties under this agreement in
whole or in part to a third party in order to effect such an exchange; provided
that Chevron shall remain responsible to Farmee for the full and prompt
performance of any delegated duties. Chevron shall indemnify and hold Farmee
harmless from and against all claims, expenses (including reasonable attorneys'
fee), loss and liability resulting from Farmee's participation in any exchange
undertaken pursuant to this provision.
7. If any operation permitted or required under said agreement, or the
performance by any party of any requirement thereof, is delayed or interrupted
directly or indirectly by any past or future acts, orders, regulations,
environmental permits or requirements of the Government of the United States or
any State or other governmental body, or any agency, officer, representative or
any agency, officer, representative or authority of any of them, or because of
delay or inability to get materials, labor, equipment or supplies, or on account
of any other similar or dissimilar cause beyond the control of that party, the
period of such delay or interruption shall not be counted against that party,
and the term of any provision herein shall automatically be extended so long as
the cause or causes for such delays or interruptions continue. No party shall
not be liable to the other party or parties in damages for failure to perform
any operation permitted or required hereunder or to comply with any requirement
or agreement hereof during the time such non-performing party is relieved from
the obligations to comply with such requirement or agreement. Notwithstanding
the above, no force majeure shall relieve any party of its obligation to pay
money hereunder.
In the event any party chooses to rely upon this provision to excuse its
failure to perform, or to timely perform, an obligation on its part to be
performed, it shall promptly notify the the other parties, in writing, of the
existence and detailed nature of the alleged force majeure. Such notice shall
also advise of the proposed course of action the party intends to take to seek
to overcome the force majeure and an estimate of time within which such course
of action will be completed. If the parties fail to agree that the alleged force
majeure exists or that its existence is a significant cause for the
non-performing party's failure to perform or to timely perform as alleged, the
dispute will be promptly settled by arbitration. The party seeking arbitration
shall set forth the particulars of its claim and the identity of its arbitrator
in a notice to be given in writing to the other party. Within fifteen (15) days
after receipt of such notice, the other party shall designate its arbitrator in
a written notice to the party requesting arbitration. The two arbitrators so
selected shall then mutually agree upon a third arbitrator (hereinafter referred
to as "neutral arbitrator"). Should the two initial arbitrators fail to so agree
within fifteen (15) days, the neutral arbitrator shall be designated pursuant to
California Code of Civil Procedure, Section 1281.6, as that section may from
time to time be amended or redesignated by number. A majority of the three
arbitrators or, when agreed to by the parties, the neutral arbitrator acting
alone, shall make a determination which shall be final and binding upon the
parties to the proceeding. Notwithstanding the foregoing, pending the final
determination of the arbitrators, the parties may continue such operations as
they may in the interim deem advisable.
8. Farmee shall observe and comply with all farmout lease obligations (express,
implied or otherwise) and with all laws, orders, rules and regulations of all
governmental authorities having, or asserting, jurisdiction. Upon abandonment,
each well shall be promptly plugged, equipment removed, pits treated and
backfilled, trash and debris removed and surface cleaned and restored as nearly
as practicable to its original condition. Farmee agree to defend, indemnify and
hold Chevron harmless from all claims, demands, losses, fines, penalties,
damages and liability resulting from or arising out of the breach of any such
lease obligation or the violation of any such law, rule, regulation or order.
Additionally, in the event that the transfer of any interest in a farmout
lease requires approval of the lessor or of any federal, state or local agency
having jurisdiction, Chevron's obligation to transfer an interest to Farmee
shall be subject to Farmee's obtaining the pertinent approval.
9. Unless said agreement is exempted by law, rule, regulation or order, Farmee
shall comply with the following clauses contained in the Code of Federal
Regulations (including any revision or redesignation thereof), which are
incorporated herein by reference, the full text of which will be made available
upon request:
48.C.F.R. ss.52.222-35 (Disabled and Vietnam Veterans);
48.C.F.R. ss.52.222-36 (Handicapped Workers);
48.C.F.R. ss.52.222-26 (Equal Opportunity);
48.C.F.R. ss.52.219-8 and -9 (Utilization of Small and Small
Disadvantaged Business Concerns); and
48.C.F.R. ss.52.219-13 (Utilization of Women-Owned Small Businesses).
Where required by law and unless previously provided, Farmee shall provide a
Certificate of Non-Segregated Facilities to Chevron and Farmee shall require
Farmee's contractors and subcontractors to provide the same to Farmee. Farmee
agrees and covenants that none of Farmee's employees or employees of Farmee's
contractors or subcontractors who provide services pursuant to said agreement
are unauthorized aliens as defined in the Immigration Reform and Control Act of
1986.
10. Farmee agree to defend, protect, indemnify and save Chevron harmless from
any and all claims, demands, liabilities, injuries, losses, damages, costs
(including attorneys' fees), causes of action and expenses arising out of,
incident to or resulting directly or indirectly in connection with Farmee's
operations under or related to said agreement.
Farmee shall secure and maintain adequate insurance protection against all risks
occasioned by its operations under said agreement. Farmee shall commence no
operations hereunder before Chevron receives from Farmee's insurer a certificate
or other evidence of insurance which shall describe the type, policy, limits,
deductibles, and period of coverage of and state the party insured by Farmee's
insurance. All such insurance shall name Chevron U.S.A. Production Company, its
parent and affiliates and its and their directors, officers, employees and
agents as primary insureds with respect to all activities conducted under or
Farmee agrees to require its insurer to insert a provision in any such policy to
cover all of the obligations assumed by Farmee under said agreement.
all operations under said agreement, Farmee is acting independently of Chevron
and in no case as Chevron's agent. All such operations shall be under Farmee's
exclusive control and at Farmee's sole risk, cost and expense. The liabilities
of the parties hereunder shall be several, not joint or collective. It is not
the purpose or intention of said agreement to create any partnersip, mining
partnership, or association, and neither said agreement nor the operations under
it agreement shall be construed or considered as creating any such relationship.
It is understood and agreed that any transfer by Chevron of the farmout leases
hereinabove provided for shall be considered only as a contribution by Chevron
to the pool of capital for the development of the mineral interests by the
parties.
As to all operations hereunder, the parties shall be subject to the tax
election provisions set out in Exhibit "F-1" to this Exhibit "F".
13. Farmee shall have neither the right nor the power to assign, in whole or in
part, said agreement or any interest earned thereunder to another party without
Chevron's prior written consent, which such consent shall not be unreasonably
withheld. Chevron may withhold Farmor's consent to any such proposed or
attempted assignment for any reason related to the prospective assignee's poor
operating or financial performance or for its substandard or ethically poor
business practices, all to be determined in Chevron's sole discretion. Any
attempted assignment made in contravention of this provision shall be, at
Chevron's sole option (and in addition to any other remedy available to Chevron
at law or in equity), voidable and of no force and effect. The granting of
Chevron's consent to any such assignment shall be effective only as to the
specific assignment then the express subject of such consent, and all subsequent
assignments which may be proposed or attempted shall likewise be expressly
subject to the hereinabove stated rights, power and authority reserved by
Chevron.
If at any time the interest of Chevron or Farmee is divided among or is
assigned to and owned by four or more co-owners or an entity in which equity
ownership is held by four or more co-owners, any party hereto may, at its
discretion, require such co-owners to designate in writing a trustee, mandatary
or agent with full authority and all rights necessary to settle, compromise,
dismiss, or release on behalf of such co-owners any loss, expense, claim,
damage, penalty, fine, lawsuit, or similar matter arising from operations
hereunder, including full authority to act for all said co-owners as insureds
under or with respect to any policy of insurance relevant to such matters.
14. Unless otherwise provided herein, all notices provided for hereunder shall
be deemed properly given to a party when sent by certified or registered mail
(return receipt requested) or by overnight courier, telex, telegram or confirmed
facsimile, with all postage or other charges fully prepaid, to the party at the
address set out below:
Farmee Chevron
<TABLE>
<S> <C>
NNG Chevron U.S.A. Production Company
Attention: Rod or Joe Nahama Attention: Land Manager
4700 Stockdale Highway, Suite 150 4900 California Avenue (P.O. Box 1392)
Bakersfield CA 93309 Bakersfield CA 93309 (93302)
Phone: 805-323-6546 Phone: 805-633-4530
Fax: 805-323-0540 Fax: 805-633-4545
</TABLE>
15. Notwithstanding anything herein to the contrary, termination of said
agreement shall not relieve any party hereto from any liability, duty or
obligation which accrued, attached or arose prior to such termination, nor shall
such termination preclude Chevron from asserting its right to specific
performance, damages or any other rights or remedies to which it may be
entitled. Nonenforcement by Chevron of any remedy for any particular violation
of the provisions of this agreement is not a waiver of such remedy, nor shall
nonenforcement of a remedy for one violation prevent Chevron from enforcing any
remedies for other violations, or for the same violation occurring at any other
time.
16. Neither Farmee nor any director, officer, employee or agent of Farmee, its
contractors, subcontractors or vendors, shall give or receive from any director,
officer, employee or agent of Chevron or any affiliate of Chevron any gift or
entertainment of significant cost or value or any commission, fee or rebate in
connection with said agreement. In addition, neither Farmee nor any director,
officer, employee or agent of Farmee, its contractors, subcontractors or
vendors, shall enter into any business arrangement with any director, employee
or agent of Chevron or any affiliate of Chevron who is not acting as a
representative of Chevron or its affiliate without prior written notification
thereof to Chevron. Any representatives authorized by Chevron may audit any and
all records of Farmee and any contractor, subcontractor or vendor of Farmee for
the sole purpose of determining whether there has been compliance with this
provision.
Farmee and its contractors, subcontractors and vendors shall maintain true and
correct books and records in connection with this agreement and all transactions
related thereto and shall retain all such books and records for at least 24
months after the end of the calendar year in which the transactions occur. In
the event costs are to be charged to the credit owed Chevron under this
agreement or if costs are to be reimbursed by Chevron, Chevron may from time to
time and at any time during the foregoing period of record retention conduct an
audit of all books and records of Farmee and its contractors, subcontractors and
vendors relating to such costs.
17. Time is of the essence of each and every provision of said agreement.
18. Said agreement represents the entire agreement between the parties with
respect to the matters covered and affected thereby, and all prior discussions,
correspondence, agreements, and related matters are merged into and superseded
by said agreement. Said agreement shall not be modified or amended except by
mutual agreement of the parties in writing, and no action or failure to act on
the part of either party hereto shall be construed as a modification or
amendment to, or a waiver of, any of the provisions of said agreement.
19. The terms and conditions of said agreement, including its exhibits,
shall be binding upon the parties hereto, their respective heirs,
successors, legal representatives and assigns.23. Indemnity23.
----------------- -
Indemnity
- - ---------
Chevron _______ (Farmee) ______________
EXHIBIT "F-1"
Attached to and made a part of Exhibit "E" to that certain Belridge
Road/Railroad Grade Prospect Areas Farmout, dated December 20, 1997, by and
between NNG and Saba Exploration Company, Inc. (collectively "Farmee") and
Chevron U.S.A. Production Company.
INTERNAL REVENUE CODE ELECTION
A. Liability of Parties. The liability of the parties hereunder shall be
several, not joint or collective. Each party shall be responsible only
for its obligations set forth in the Agreement. It is not the purpose
or intention of this Exhibit to create any partnership, mining
partnership, tax partnership or association, and neither this Exhibit
nor the operations under this Agreement shall be construed or
considered as creating any such relation.
B. Income Tax Election. Notwithstanding any provision herein that
the rights and liabilities hereunder are several and not joint or
collective, or that this agreement and operations hereunder shall
not ------------------- constitute a partnership, if, for federal
income tax purposes, this agreement and the operations hereunder
are regarded as a partnership, each party hereby affected elects
to be excluded from the application of all of the provisions of
Subchapter "K", Chapter 1, Subtitle "A", of the Internal Revenue
Code of 1986, as permitted and authorized by Section 761 of the
Code and the regulations promulgated thereunder. Operator is
authorized and directed to execute on behalf of each party hereby
affected such evidence of this election as may be required by the
Secretary of the Treasury of the United States or the Federal
Internal Revenue Service, including specifically, but not by way
of limitation, all of the returns, statements, and the data
required by Treasury Regulations 1.761-1 and 1.761-2. Should
there be any requirement that each party hereby affected give
further evidence of this election, each such party shall execute
such documents and furnish such other evidence as may be required
by the Federal Internal Revenue Service or as may be necessary to
evidence this election. No such party shall give any notices or
take any other action inconsistent with the election made hereby.
If any present or future income tax laws of the state or states
in which the farmout area is located or any future income tax
laws of the United States contain provisions similar to those in
Subchapter "K", Chapter 1, Subtitle "A", of the Internal Revenue
Code of 1986, under which an election similar to that provided by
Section 761 of the Code is permitted, each party hereby affected
shall make such election as may be permitted or required by such
laws. In making the foregoing election, each such party states
that the income derived by such party from operations hereunder
can be adequately determined without the computation of
partnership taxable income.
In case of any conflict between the terms of this exhibit and those of the
agreement to which it is attached, the terms of this agreement shall prevail.
Exhibit 10.52
(exchange.doc)
EXCHANGE AGREEMENT
This Agreement (the "Agreement") for the exchange of the properties listed on
Exhibit "A," attached hereto, (the "Properties") is entered into on March 6,
1998 (herein called the "Contract Date") by and between ENERGY ASSET MANAGEMENT
COMPANY, L.L.C. (EAMC), an Arkansas limited liability company, wholse address is
P.O. Box 1714, El Dorado, Arkansas 71731 and SABA ENERGY OF TEXAS, INCORPORATED
(SABA), a Texas Corporation whose address is 1603 SE 19th Street, Suite 203,
Edmond, Oklahoma 73013 and SABA PETROLEUM COMPANY (SPC), a California
Corporation whose address is 3201 Airpark Drive, Suite 201, Santa Maria,
California 93455. Pursuant to the following terms and conditions, EAMC shall
convey to SABA all of EAMC's right, title and interest in and to the Properties
in exchange for Two Hundred Thousand (200,000) shares of Common Stock of SPC,
which stock is traded on the American Stock Exchange under the Symbol SAB.
1. Effective Date and Time of Sale and Purchase Agreement. Unless otherwise
agreed to in writing by EAMC and SABA, the effective date and time
("Effective Date") of this exchange of Properties is January 1, 1998 at
7:00 A.M.C.S.T.
2. Closing. Upon satisfaction of all the terms and conditions contained
herein, EAMC and SABA shall close this exchange on March 6, 1998 (the
"Closing Date") unless otherwise agreed to by both parties in writing.
Closing shall take place at SABA's office, or via mail and facsimile. A one
time extension to the closing date of no more than 10 days shall not be
unreasonably withheld, if requested in writing. At closing, the following
shall occur:
a. EAMC, SABA and SPC shall provide an executed original of this agreement,
each to the other.
b. EAMC and SABA shall execute additional documents, as reasonably required
by SABA for the transfer of assets, or Partnership interests.
c. SPC shall tender one certificate for 200,000 shares of common stock,
free of all restrictions, except as otherwise provided in Article 4g
hereinbelow, to EAMC.
d. SABA shall produce a final closing statement setting forth the final
cash amount due SABA as of the agreed closing and effective dates. In
the event there is a material difference (defined as $50,000) between
$2,615,000.00 and the actual amount due SABA, then SABA shall pay to
EAMC (or EAMC shall pay to SABA) within 45 days of closing the cash
difference, less $50,000.
3. Exchange. This is an exchange of equity interest in the properties for
common stock in SPC. The number of shares of stock set forth in Article 2c
shall constitute the adjusted number of shares with no further increase, or
reduction in the number of shares exchanged pursuant to this Agreement,
except as provided in Article 6b hereinbelow. There shall be no
post-closing adjustments between the parties, except as provided in Article
6b hereinbelow. Adjustments made at closing pursuant to Article 2d are
inclusive of the following considerations: i) The unpaid balance owed by
EAMC for principal and interest payments per prior acquisition agreements,
participation agreements and financing agreements through the date of
closing; ii) The unpaid balance owed by EAMC for operating expenses and
capital expenditures incurred prior to the effective date; iii) Unpaid
Partnership obligations; iv) Revenue paid to EAMC for post effective date
occurences; v) EAMC's share of escrow accounts; vi) EAMC's net share of
value for oil in the tanks as of the effective date; vii) Any other
accounts jointly held between EAMC and SABA, or SPC.
4. Representations with Respect to the Common Stock. EAMC represents to SPC
that:
a. Investment Purpose. As of the date hereof, EAMC is acquiring the
Common Stock for its own account for investment only and not with a
present view towards the public sale or distribution thereof, except
pursuant to sales registered or exempted from registration under the
1933 Act.
b. Accredited Investor Status. EAMC is an "accredited investor" as
that term is defined in Rule 501 (a) of Regulation D.
-------------------------------------
<PAGE>
c. Reliance on Exemptions. EAMC understands that the Common Stock are
being offered and sold to it in reliance upon specific exemptions from
the registration requirements of United States federal and state
securities laws and that SABA and SPC are relying upon the truth and
accuracy of, and EAMC's compliance with, the representations,
agreements, acknowledgments and understandings of EAMC set forth herein
in order to determine the availability of such exemptions and the
eligibility of the EAMC to acquire the Common Stock.
d. Information. EAMC and its advisors, if any, have been furnished with
all materials relating to the business, finances and operations of SPC
and the Common Stock which have been requested by EAMC or its advisors.
EAMC and its advisors, if any, have been afforded the opportunity to
ask questions of SPC and have received what EAMC believes to be
satisfactory answers to any such inquires. EAMC understands that its
investment in the Common Stock involves a significant degree of risk.
e. Governmental Review. EAMC understands that no United States
federal or state agency or any other government or governmental
agency has passed upon or made any recommendation or endorsement
of the ------------------------------- Common Stock.
f. Transfer or Resale. EAMC understands that (i) the Common Stock has
not been registered under the Securities Act of 1933 or any applicable
state securities laws, and may not be transferred unless (a)
subsequently included in an effective registration statement
thereunder, or (b) EAMC shall have delivered to SPC an opinion of
counsel (which opinion shall be reasonably acceptable to SPC) to the
effect that the Securities to be sold or transferred may be sold or
transferred pursuant to an exemption from such registration or (c) sold
or transferred to an "affiliate" (as defined under Rule 144) or EAMC,
or (d) sold pursuant to Rule 144 promulgated under the 1933 Act (or a
successor rule); (ii) any sale of such Securities made in reliance on
Rule 144 may be made only in accordance with the terms of said Rule and
further, if said Rule is not applicable, any resale of such Securities
under circumstances in which the seller (or the person through whom the
sale is made) may be deemed to be an underwriter (as that term is
defined in the 1933 Act) may require compliance with some other
exemption under the 1933 Act or the rules and regulations of the SEC
thereunder; and (iii) neither SPC nor any other person is under any
obligation to register such Common Stock under the 1933 Act or any
state securities laws or to comply with the terms and conditions of any
exemption thereunder (in each case, other than as set forth in the
agreement).
g. Legends. EAMC understands that the Common Stock, until such time
as it shall have been registered under the 1933 Act as
contemplated herein, may bear a restrictive legend in
substantially the following ------------- form (and a
stop-transfer order may be placed against transfer of the
certificates for such securities):
"The securities represented by this certificate have not been
registered under the Securities Act of 1933, as amended. The securities have
been acquired for investment and may not be sold, transferred or assigned in the
absence of an effective registration statement for the securities under said
Act, or an opinion of counsel, in form, substance and scope reasonably
acceptable to SPC, that registration is not required under said Act or unless
sold pursuant to Rule 144 under said Act."
5. Certain Agreements to Register. SPC will file a registration statement with
the Securities and Exchange Commission within sixty (60) days of the
closing of the transaction contemplated hereby, covering the sale of the
Common Stock by EAMC. SPC will use its best efforts to cause the Securities
and Exchange Commission to accept the registration statement. EAMC will, as
a condition to the filing and the effectiveness of such registration
statement, furnish SPC with such information concerning EAMC's intention to
sell the Common Stock as SPC may reasonably request for inclusion in the
registration statement and will indemnify and hold each of SABA and SPC
harmless from and against any loss or liability (including reasonable
attorneys fees and fees of experts) arising out of any claim that such
information is incorrect in any material respect.
6 Organization and Authority Relative to this Agreement.
a. EAMC is a limited liability corporation, duly organized, validly
existing and in good standing as a domestic corporation under the laws
of the State of Arkansas and has full power and authority to enter
into, deliver and perform this Agreement and to consummate the
transaction contemplated hereby. The execution and delivery of this
Agreement by EAMC and the consummation by EAMC of the transaction
contemplated hereby have been duly authorized by all requisite action,
and no other corporate proceedings on the part of EAMC are necessary to
authorize this Agreement or the transaction contemplated hereby. This
Agreement has been duly executed and delivered by EAMC and constitutes
a legally valid and binding obligation of EAMC, enforceable in
accordance with its terms.
b. Notwithstanding the items listed below, there are no suits, judgements,
actions, proceedings, liens, or investigation pending or, to the
knowledge of EAMC, threatened, against or affecting EAMC, its
respective businesses or any of the Properties, in any court or before
or by any governmental or regulatory authority or agency, domestic or
foreign, or any arbitration, which could adversely affect the
Properties or SABA's use of the same, or the ability of EAMC to perform
its obligations under this Agreement, or any instrument to be delivered
pursuant hereto.
1) Docket number 0518643F: Lewis England & Associates, Inc., v.
EAMC, L.L.C. in the 24th Judicial District Court of Jefferson
Parish, Louisiana.
2) Investigations by the British Columbia Financial Institutions
Commission and the British Columbia Securities Commission of Eron
Mortgage Corp., Capital Productions, Inc., Brian Slobogian and
Frank Biller.
EAMC shall indemnify and hold harmless SABA and SPC, its officers,
directors and agents, from and against any and all loss, liability,
cost and expense (including reasonable costs of investigation and
defense) arising out of, or in any way connected with the matters
described in 1) or 2) above, which indemnity shall include attorneys
fees, the costs of experts and other consultants. Should any claim be
asserted against SABA, SPC, or the assets acquired hereunder which
arises out of or is connected with either of the aforementioned
matters, EAMC shall, upon request, advance to, or for the account of
SABA and SPC, the costs of investigating and defending said claim.
Until each of said matters is resolved to the satisfaction of and
without expense to SABA and SPC, SPC shall withhold 10,000 shares of
the commons stock, which shall be held to secure payment sums which may
become due SABA and SPC hereunder. Subject to mutual consent, which
will not be unreasonably withheld by either party, SPC is authorized to
cancel from time to time the number of shares as may be required to
indemnify SABA and SPC under this paragraph. Shares cancelled shall be
deemed to have been reacquired by SPC at the average bid price for the
common stock during the five trading days preceding the date of
cancellation. The foregoing right shall not constitute a limitation on
the indemnity contained in this paragraph.
Until such time as item number 1 above is dismissed, or upon written
agreement by both parties, SPC shall reserve 10,000 shares from the exchange
described in Article 3 hereinabove.
c. SABA is a corporation, is duly organized, validly existing and in good
standing as a corporation under the laws of the State of Texas and has
full corporate power and authority to enter into, deliver and perform
this Agreement and to consummate the transaction contemplated hereby;
the execution and delivery of this Agreement by SABA and the
consummation by SABA of the transaction contemplated hereby have been
duly authorized by all requisite action and no other corporate
proceedings on the part of SABA are necessary to authorize this
Agreement and the transaction contemplated hereby. This agreement has
been duly executed and delivered by SABA and constitutes a legally
valid and binding obligation of SABA, enforceable in accordance with
its terms.
d. SPC is a corporation, is duly organized, validly existing and in good
standing as a corporation under the laws of the State of California
and has full corporate power and authority to enter into, deliver and
perform this Agreement and to consummate the transaction contemplated
hereby; the execution and delivery of this Agreement by SPC and the
consummation by SPC of the transaction contemplated hereby have been
duly authorized by all requisite action and no other corporate
proceedings on the part of SPC are necessary to authorize this
Agreement and the transaction contemplated hereby. This agreement has
been duly executed and delivered by SPC and constitutes a legally
valid and binding obligation of SPC, enforceable in accordance with
its terms.
e. There are no suits, judgements, actions, proceedings, liens, or
investigation pending, or to the knowledge of SABA, or SPC, threatened,
against or affecting SABA, or SPC, its respective businesses or any of
the Properties, in any court or before or by any governmental or
regulatory authority or agency, domestic or foreign, or any
arbitration, which could adversely the ability of SABA, or SPC to
perform its obligations under this Agreement, or any instrument to be
delivered pursuant hereto.
7. Other Documents and Contracts. This Agreement will be made subject to any
and all existing operating agreements, unit agreements, gas purchase or
sale contracts, as well as any and all other agreements to which the
Properties are subject, including, but not limited to, any applicable
farmin agreements. SABA shall assume and be responsible for all obligations
accruing under such agreements as of the Effective Date.
By execution of this Agreement, EAMC and SABA hereby agree to cancel, void,
annul, dissolve, disclaim and forever waive the following agreements:
That certain agreement dated October 4, 1996 by and between
the parties hereto regarding the acquisition of MV Ventures, G.P. and all assets
and liabilities associated with MV Ventures, G.P.
That certain agreement dated September 5, 1997 by and between
the parties hereto regarding the acquisition of the Potash Field from Statoil
Exploration (U.S.), Inc.
That certain Operating Agreement dated September 2, 1997 by
and between the parties regarding the operation of the Potash Field.
By execution of this Agreement, EAMC hereby sets over, conveys and forever
disclaims any interest in, or rights to the following agreements and shall
forever waive any remedy available through the following agreements:
That certain Purchase and Sale Agreement dated October 8, 1996 by and
between DuBose Ventures, Inc., Rockbridge Oil & Gas, Inc., Saba Energy of
Texas, Incorporated and Energy Asset Management Corporation regarding the
sale of MV Ventures, G.P.
That certain Partnership Agreement dated November 1, 1995
regarding the creation of MV Ventures, G.P.
EAMC and SABA shall execute additional documents, either at closing, or
at anytime after closing, as reasonably required by SABA, to document
the transfer of equity, or Partnership interests. EAMC will cooperate
with SABA in perfecting SABA's title.
8. Notices. All communications required or permitted under this Agreement
shall be in writing. Any communication or delivery hereunder shall be
deemed to have been fully made if actually delivered, sent by facsimile
machine, or if mailed by registered or certified mail, postage prepaid, to
the applicable address indicated above.
9. Further Assurances. Each of the parties shall execute acknowledge and
deliver to the other such further instruments, and take such other actions
as may be reasonably necessary to carry out the provisions of this
Agreement.
10. Entire Agreement. This Agreement constitutes the entire understanding
between the parties and it may not be amended nor any rights hereunder
waived except by an instrument in writing signed by the party to be charged
with such amendment or waiver and delivered by such party to the party
claiming the benefit of such amendment or waiver.
If any provision of this Agreement, or the application thereof to any
person or circumstances, shall, to any extent, be held in any proceeding to
be invalid or unenforceable, the remainder of this Agreement, and the
application of such provisions to persons or circumstances other than those
to which it is held to be invalid or unenforceable, shall not be affected
thereby, and shall be valid and enforceable to the fullest extend permitted
by law, but only if and to the extend such enforcement would not materially
and adversely frustrate the parties' essential objectives as expressed
herein.
No party to this Agreement may assign its rights or obligations hereunder
without the written consent of all parties hereto. Subject to the
foregoing, this Agreement shall be binding upon the parties hereto, their
respective successors and assigns, and nothing contained in this Agreement,
express or implied, is intended to confer upon any other person or entity
any benefits, rights, or remedies.
11. Venue and Exclusive Jurisdiction. The parties agree that any dispute
arising out of or relating to this Agreement, shall be adjudicated solely
in the Superior Court for the County of Santa Barbara, or the U.S. District
Court for the Southern District of California. Each party consents to the
jurisdiction of each such court.
12. Costs. Except as otherwise agreed upon, each party shall pay its own
costs, including fees and expenses of its own counsel and accountants, in
connection with this Agreement
13. Breech of Contract. Any breech of contract, or inability of any party
to fulfill the terms of this agreement shall cause this agreement to become
null and void and all property, cash and common stock will be restored to
the holders of such rights at the time of execution of this Agreement.
14. Term. Except with respect to Article 6, which shall survive for the period
of the applicable statute of limitations, this Agreement shall expire upon
delivery of the common stock, as agreed in Article 2c, removal of
restrictions to the common stock and upon satisfaction of all terms and
obligations provided for herein, or mutual agreement.
15. Counterparts. This Agreement may be executed by SABA, SPC and EAMC in
any number of counterparts, each of which shall be deemed an original
instrument, but all of which together shall constitute but one and the same
instrument.
AGREED AND ACCEPTED
<TABLE>
<S> <C>
WITNESS: ENERGY ASSET MANAGEMENT COMPANY, L.L.C.
- - -----------------------------------
___________________________________ By: Name: Robert M. Thomasson
-------------------------------------------------- Title: Vice President
WITNESS: SABA ENERGY OF TEXAS, INCORPORATED
- - -----------------------------------
___________________________________ By:
Name: Bradley T. Katzung
Title: President
WITNESS: SABA PETROLEUM COMPANY
- - -----------------------------------
___________________________________ By:
Name: Ilyas Chaudhary
Title: President
</TABLE>
<PAGE>
STATE OF OKLAHOMA )
)ss
COUNTY OF OKLAHOMA )
Before me, a Notary Public in and for said County and State, on this 9th day of
March, 1998, personally appeared Robert M. Thomasson, to me know to be the
identical person who subscribed the name of the maker thereof to the foregoing
instrument as its Vice President and acknowledged to me that he executed the
same of his free and voluntary act and deed and of the free and voluntary act
and deed of the corporation, for the uses and purposes therein set forth.
Given under my hand and seal of office the day and year last above written.
--------------------------------
Notary Public
My commission expires August 17, 1998
STATE OF OKLAHOMA )
)ss
COUNTY OF OKLAHOMA )
Before me, a Notary Public in and for said County and State, on this 9th day of
March, 1998, personally appeared Bradley T. Katzung, to me know to be the
identical person who subscribed the name of the maker thereof to the foregoing
instrument as its President and acknowledged to me that he executed the same of
his free and voluntary act and deed and of the free and voluntary act and deed
of the corporation, for the uses and purposes therein set forth.
Given under my hand and seal of office the day and year last above written.
--------------------------------
Notary Public
My commission expires August 17, 1998
STATE OF OKLAHOMA )
)ss
COUNTY OF OKLAHOMA )
Before me, a Notary Public in and for said County and State, on this 9th day of
March, 1998, personally appeared Ilyas Chaudhary, to me know to be the identical
person who subscribed the name of the maker thereof to the foregoing instrument
as its President and acknowledged to me that he executed the same of his free
and voluntary act and deed and of the free and voluntary act and deed of the
corporation, for the uses and purposes therein set forth.
Given under my hand and seal of office the day and year last above written.
--------------------------------
Notary Public
My commission expires August 17, 1998
EXHIBIT "A"
Attached to and made a part of that certain Exchange Agreement dated March 6,
1998, by and between ENERGY ASSET MANAGEMENT COMPANY, L.L.C., SABA ENERGY OF
TEXAS, INCORPORATED and SABA PETROLEUM COMPANY
A) LA001: That certain Lease for Oil, Gas and Other Liquid or Gaseous
Minerals dated August 16, 1982, by and between the State Mineral Board of the
State of Louisiana (State Lease No. 10394), as Lessor, and James A. Whitson,
Jr., as Lessee, filed for record in Entry No. 1027740, Mineral Book 38, Folio
436 of the records of Jefferson Parish, Louisiana; and as amended by that
certain Correction of State Mineral Lease No. 10394 dated March 17, 1983, filed
for record in Entry No. 83-22790 of the records of Jefferson Parish, Louisiana.
[CCHC #171480A]
B) LA002: That certain Oil and Gas Lease dated May 1, 1982, by
and between The Louisiana Land and Exploration Company, as
Lessor, and James A. Whitson, Jr., as Lessee, to which a
recording memorandum entitled Declaration has been filed for
record in Entry No. 1015347, Mineral Book 38, Folio 255 of the
records of Jefferson Parish, Louisiana. [CCHC #171480B]
C) LA003: That certain Lease for Oil, Gas and Other Liquid or
Gaseous Minerals dated June 13, 1983, by and between the State
Mineral Board of the State of Louisiana (State Lease No.
10808), as Lessor, and Primary Fuels, Inc., as Lessee, filed
for record in Mineral Book 39, Folio 576 of the records of
Jefferson Parish, Louisiana and in COB Book 571, Folio 664 of
the records of Plaquemines Parish, Louisiana [CCHC #171481]
D) LA004: That certain Oil and Gas Lease dated April 15, 1983, by
and between The Louisiana Land and Exploration Company, as
Lessor, and James A. Whitson, Jr., as Lessee, to which a
recording memorandum entitled Declaration has been filed for
record in Entry No. 8318074, Mineral Book 39, Folio 146 of the
records of Jefferson Parish, Louisiana and in COB Book 565,
Folio 941 of the records of Plaquemines Parish, Louisiana.
[CCHC #171482]
E) LA005: That certain Oil, Gas and Other Hydrocarbon Standard
Development Lease dated November 7, 1990, by and between
Frederick E. Purcell, et al., as Lessor, and Wm. Bullen, Inc.,
as Lessee, filed for record in Entry No. 9104193, COB Book
2930, Folio 213 of the records of Jefferson Parish, Louisiana,
as amended by that certain Lease Amendment and Extension
Agreement dated August 11, 1994 filed for record in Entry NO.
09449744, COB Book 2902, Folio 396 of the records of Jefferson
Parish, Louisiana. [CCHC #171634]
F) LA006: That certain Oil and Gas Lease dated July 1, 1991, by
and between The Louisiana Land and Exploration Company, as
Lessor, and Corpus Christi Hydrocarbons Company, as Lessee, to
which a recording memorandum entitled Declaration has been
filed for record in Entry No. 9138700, Mineral Book 119, Folio
323 of the records of Jefferson Parish, Louisiana. [CCHC
#171647]
<PAGE>
G) LA016: That certain oil, gas and mineral lease effective
November 8, 1928, granted by the Board of Levee Commissions of
the Orleans Levee District in favor of Humble Oil & Refining
Company, recorded in COB 66, Folio 518, LESS AND EXCEPT land
lying within the surface boundaries of the Pengo Petroleum,
Inc. Voluntary Unit "B" created by instrument dated effective
July 1, 1978, recorded in COB 482, Folio 429, Entry No. 76
containing 132.846 acres, more or less, from the surface down
to the stratigraphic equivalent of the base of the TEXT W Sand
seen at a depth of 13,500 feet measured depth on the ISF-Sonic
Log, Run No. 1, for the Orleans Levee Board B-1 Well, dated
November 10, 1975, but not less and except the MIO 10 Sand as
found at 9,500 feet to 10,240 feet measured depth on the
ISF-Sonic Log, Run No. 1 for the Orleans Levee Board B-1 Well,
dated November 10, 1975.
H.) LA017: That certain oil, gas and mineral lease granted by the
State of Louisiana to W. T. Burton, effective January 23, 1936,
recorded in COB 81, Folio 4, designated State Lease 335, as to
all land covered thereby lying in Townships 17 and 18 South,
Range 15 East LESS AND ECEPT (1) lands and depths released
therefrom on November 1, 1943, July 30, 1974, February 5, 1986
and September 7, 1989 and (2) all land lying within the surface
boundaries of the Pengo Petroleum, Inc. Voluntary Unit "B"
created by instrument dated effective July 1, 1978, recorded in
COB 482, Folio 429, Entry No. 76, containing 132.846 acres more
or less, from the surface to the stratigraphic equivalent of
the base of the TEXT W Sand seen at a depth of 13,500 feet
measured depth on the ISF-Sonic Log, Run No. 1, for the Orleans
Levee Board B-1 Well, dated November 10, 1975, but not less and
except the Mio10 Sand as found at 9,500 feet to 10,240 feet
measured depth on the ISF-Sonic Log, Run No. 1 for the Orleans
Levee Board B-1 Well, dated November 10, 1975.
I.) LA018: That certain oil, gas and mineral lease dated effective
November 21, 1941, granted by the State of Louisiana in favor
of Humble Oil & Refining Company, recorded in COB 105, Folio
392, designated State Lease 508, LESS AND EXCEPT (1) forty
acres surrounding the State Lease 508 No. 13 Well described as
beginning at the point X-2,517,580.06 and Y-307,462.15, then
South 36(degree) 36' 35" East 1,320 feet, then south 53(degree)
23' 25" West 1,320 feet, then North 36(degree) 36' 35" West
1,320 feet, then North 53(degree) 23' 25" East 1,320 feet to
the point of beginning as to all depths from the surface to 100
feet below the stratigraphic equivalent of the base of the MIO
12F Sand seen at 11,818 feet (log depth) on the electric log
for the Humble State Lease 508 No. 5 Well, (2) forty acres
surrounding the State Lease 508 No. 15/15-D Wells described as
beginning at the point X-2,517,715.00 and Y=307,443.15, then
North 60(degree) East 1,320 feet, then South 30(degree) East
1,320 feet, then South 60(degree) West 1,320 feet, then North
30(degree) West 1,320 feet to the point of beginning as to all
depths from the surface to 100 feet below the stratigraphic
equivalent of the base of the MIO 12F Sand seen at 11,818 feet
(log depth) in the State Lease 508 No. 5 Well and (3) all land
and depths released therefrom on May 6, 1971, September 9,
1983, September 5, 1991, and July30, 1992.
<PAGE>
J) (LA019) That certain oil, gas and mineral lease effective March
11, 1947 granted by Board of Levee Commissioners of the Orleans
Levee District to The Superior Oil Company, recorded in COB
130, Folio 556, LESS AND EXCEPT (1) land and depths released on
March 18, 1985, (2) the 160 acres of the lease in Sections 3
and 10, Township 18 South, Range 15 East reserved by The
Superior Oil Company from the sublease to Gulf Oil Corporation
and Humble Oil & Refining Company on December 2, 1959 (3) land
lying within the surface boundaries of the Pengo Petroleum,
Inc. Voluntary Unit "B" created by instrument effective July 1,
1978, recorded in COB 482, Folio 429, Entry No. 76, containing
132.846 acres from the surface to the stratigraphic equivalent
of the base of the TEXT W Sand seen at a depth of 13,500 feet
measured depth on the ISF-Sonic Log, Run No. 1, for the Orleans
Levee Board B-1 Well, dated November 10, 1975, but not less and
except the MIO 10 Sand as found at 9,500 feet to 10,240 feet
measured depth on the ISF-Sonic Log, Run No. 1 for the Orleans
Levee Board B-1 Well, dated November 10, 1975.
1) Any and all leasehold interests in oil, gas, or other minerals, including
working interests, carried working interests, rights of assignment and
reassignment, reversionary interests, and other interests under or in oil, gas
or mineral leases and interests in rights to explore for and produce oil, gas,
and other minerals;
2) Any and all rights and interests in or derived from unit agreements, orders
and decisions of state and federal regulatory authorities establishing units,
joint operating agreements, enhanced recovery and injection agreements, farmout
agreements and farmin agreements, options, drilling agreements, product sales
agreements, exploration agreements, assignments of operating rights, working
interests, subleases, and any and all other agreements to the extent they
pertain to the Assigned Premises (excluding, however, any contracts or
agreements that by their own terms are not transferable);
3) Any and all rights-of-way, easements, servitudes and franchises acquired or
used in connection with operations for the exploration and production of oil,
gas, or other minerals from the Assigned Premises, including those which may be
off the Assigned Premises but are attributable to the production and operation
of the Assigned Premises;
4) Any and all permits and licenses of any nature owned, held, or
operated in connection with operations for the exploration and production
of oil, gas or other minerals, to the extent such permits and licenses are
transferable;
5) Any and all producing, non-producing, shut-in and temporarily
abandoned oil and gas wells, salt water disposal wells and water wells.
6) Any and all surface and down-hole equipment, fixtures, related inventory,
gathering and treating facilities, production barges, crew boats, pipe, tubing,
casing and equipment, used in connection with the properties described in
Exhibit 10.54
AMERICAN INDUSTRIAL REAL ESTATE ASSOCIATION
STANDARD INDUSTRIAL/COMMERCIAL SINGLE-TENANT LEASE-NET
(Do not use this form for Multi-Tenant Property)
1. Basic Provisions ("Basic Provisions")
1.1 Parties: This Lease ("Lease"), dated for reference purposes only, January
9th, 1998 is made by and between Reza Zandian, ("Lessor") and Saba Petroleum, A
Delaware Corporation ("Lessee") Delaware Corporation
(collectively the "Parties" or individually a "Party"). ,
1.2 Premises: That certain real property, including all improvements therein or
to be provided by Lessor under the terms of this Lease, and commonly known by
the street address of 17526 Von Karmen Ave., Ste. 200, Irvine located in the
County of Orange, State of California and generally described as (describe
briefly the nature of the property) Approximatley 1930 square feet of office
space
("Premises"). (See Paragraph 2 for further provisions.)
See Addendum
1.4 Early Possession: ("Early Possession Date").
(See Paragraphs 3.2 and 3.3 for further provisions.)
1.5 Base Rent: $1351.00 ** per month ("Base Rent"), payable on the 1st day of
each month commencing (** .70(cent) per square foot) - January 9, 1998
($1,002.00 transferred from sub-lease for rents owed through .January 31, 1998)
(See Paragraph 4 for further provisions.)
If this box is checked, there are provisions in this Lease for the Base Rent to
be adjusted.
1.6 Base Rent Paid Upon Execution: $ as Base Rent for the period
---------------------------------------------------
1.7 Security Deposit:$1500.00*** ("Security Deposit").(See Paragraph
5 for further provisions.) ------------
1.8 Permitted Use: Genera1 Office (*** 1410.00 transferred from sub-lease) (See
Paragraph 6 for further provisions.)
1.9 Insuring Party: Lessor is the "Insuring Party" unless otherwise stated
herein. (See Paragraph 8 for further provisions.)
1.10 Real Estate Brokers: The following real estate brokers
(collectively, the "Brokers") and brokerage relationships exist
in this transaction and are consented to by the Parties (check
applicable boxes): represents
Lessor exclusively ("Lessor's Broker"); both Lessor and Lessee, and
represents
Lessee exclusively ("Lessee's Broker"); both Lessee and Lessor. (See
Paragraph 15 for further provisions.)
1.11 Guarantor:The obligations of the Lessee under this Lease are to
be guaranteed by ("Guarantor"). (See Paragraph 37 for further
provisions.) --------------------------------------
1.12 Addenda. Attached hereto is an Addendum or Addenda consisting of Paragraphs
1.3 XXXXXand XXX 49 through 57, inclusive, all of which constitute a part of
this Lease.
2. Premises.
2,1 Letting. Lessor hereby leases to Lessee, and Lessee hereby leases from
Lessor, the Premises, for the term, at the rental, and upon all of the terms,
covenants and conditions set forth in this Lease. Unless otherwise provided
herein, any statement of square footage set forth in this Lease, or that may
have been used in calculating rental, is an approximation which Lessor and
Lessee agree is reasonable and the rental based thereon is not subject to
revision whether or not the actual square footage is more or less.
2.2 Condition. Lessor shall deliver the Premises to Lessee clean and free of
debris on the Commencement Date and warrants to Lessee that the existing
plumbing, fire sprinkler system, lighting, air conditioning, heating, and
loading doors, if any, in the Premises, other than those constructed by Lessee,
shall be in good operating condition on the Commencement Date. If a
non-compliance with said warranty exists as of the Commencement Date, Lessor
shall, except as otherwise provided in this Lease, promptly after receipt of
written notice from Lessee setting forth with specificity the nature and extent
of such non-compliance, rectify same at Lessor's expense. If Lessee does not
give Lessor written notice of a non-compliance with this warranty within thirty
(30) days after the Commencement Date, correction of that non-compliance shall
be the obligation of Lessee at Lessee's sole cost and expense.
2.3 Compliance with Covenants, Restrictions and Building Code. Lessor warrants
to Lessee that the improvements on the Premises comply with all applicable
covenants or restrictions of record and applicable building codes, regulations
and ordinances in effect on the Commencement Date. Said warranty does not apply
to the use to which Lessee will put the Premises or to any Alterations or
Utility Installations (as defined in Paragraph 7.3(a)) made or to be made by
Lessee. If the Premises do not comply with said warranty, Lessor shall, except
as otherwise provided in this Lease, promptly after receipt of written notice
from Lessee setting forth with specificity the nature and extent of such
non-compliance, rectify the same at Lessor's expense. If Lessee does not give
Lessor written notice of a non-compliance with this warranty within six (6)
months following the Commencement Date, correction of that non-compliance shall
be the obligation of Lessee at Lessee's sole cost and expense.
2.4 Acceptance of Premises. Lessee hereby acknowledges: (a) that it has been
advised by the Brokers to satisfy itself with respect to the condition of the
Premises (including but not limited to the electrical and fire sprinkler
systems, security, environmental aspects, compliance with Applicable Law as
defined in Paragraph 6.3) and the present and future suitability of the Premises
for Lessee's intended use, (b) that Lessee has made such investigation as it
deems necessary with reference to such matters and assumes all responsibility
therefor as the same relate to Lessee's occupancy of the Premises and/or the
term of this Lease, and (c) that neither Lessor, nor any of Lessor's agents, has
made any oral or written representations or warranties with respect to the said
matters other than as set forth in this Lease.
2.5 Lessee Prior Owner/Occupant. The warranties made by Lessor in this Paragraph
2 shall be of no force or effect if immediately prior to the date set forth in
Paragraph 1.1 Lessee was the owner or occupant of the Premises. In such event,
Lessee shall, at Lessee's sole cost and expense, correct any non-compliance of
the Premises with said warranties.
3. Term.
3.1 Term. The Commencement Date, Expiration Date and Original Term of this Lease
are as specified in Paragraph 1.3.
3.2 Early Possession. If Lessee totally or partially occupies the Premises prior
to the Commencement Date, the obligation to pay Base Rent shall be abated for
the period of such early possession. All other terms of this Lease, however,
(including but not limited to the obligations to pay Real Property Taxes and
insurance premiums and to maintain the Premises) shall be in effect during such
period. Any such early possession shall not affect nor advance the Expiration
Date of the Original Term.
NET PAGE 1
<PAGE>
3.3. Delay In Possession. If for any reason Lessor cannot deliver possession of
the Premises to Lessees agreed herein by the Early Possession Date, if one is
specified in Paragraph 1.4, or, if no Early Possession Date is specified, by the
Commencement Date, Lessor shall not be subject to any liability therefor, nor
shall such failure affect the validity of this Lease, or the obligations of
Lessee hereunder, or extend the term hereof, but in such case, Lessee shall not,
except as otherwise provided herein, be obligated to pay rent or perform any
other obligation of Lessee under the terms of this Lease until Lessor delivers
possession of the Premises to Lessee. If possession of the Premises is not
delivered to Lessee within sixty (60) days after the Commencement Date, Lessee
may, at its option, by notice in writing to Lessor within ten (10) days
thereafter, cancel this Lease, in which event the Parties shall be discharged
from all obligations hereunder; provided, however, that if such written notice
by Lessee is not received by Lessor within said ten (10) day period, Lessee's
right to cancel this Lease shall terminate and be of no further force or effect.
Except as may be otherwise provided, and regardless of when the term actually
commences, if possession is not tendered to Lessee when required by this Lease
and Lessee does not terminate this Lease, as aforesaid, the period free of the
obligation to pay Base Rent, if any, that Lessee would otherwise have enjoyed
shall run from the date of delivery of possession and continue for a period
equal to what Lessee would otherwise have enjoyed under the terms hereof, but
minus any days of delay caused by the acts, changes or omissions of Lessee.
4. Rent.
4.1 Base Rent. Lessee shall cause payment of Base Rent and other rent or
charges, as the same may be adjusted from time to time, to be received by Lessor
in lawful money of the United States, without offset or deduction, on or before
the day on which it is due under the terms of this Lease. Base Rent and all
other rent and charges for any period during the term hereof which is for less
than one (1) lull calendar month shall be prorated based upon the actual number
of days of the calendar month involved. Payment of Base Rent and other charges
shall be made to Lessor at its address stated herein or to such other persons or
at such other addresses as Lessor may from time to time designate in writing to
Lessee.
5. Security Deposit. Lessee shall deposit with Lessor upon execution hereof the
Security Deposit set forth in Paragraph 1.7 as security for Lessee's faithful
performance of Lessee's obligations under this Lease. If Lessee fails to pay
Base Rent or other rent or charges due hereunder, or otherwise Defaults under
this Lease (as defined in Paragraph 13.1), Lessor may use, apply or retain all
or any portion of said Security Deposit for the payment of any amount due Lessor
or to reimburse or compensate Lessor for any liability, cost, expense, loss or
damage (including attorneys' fees) which Lessor may suffer or incur by reason
thereof. If Lessor uses or applies all or any portion of said Security Deposit,
Lessee shall within ten (10) days after written request therefor deposit moneys
with Lessor sufficient to restore said Security Deposit to the full amount
required by this Lease. Any time the Base Rent increases during the term of this
Lease, Lessee shall, upon written request from Lessor, deposit additional moneys
with Lessor sufficient to maintain the same ratio between the Security Deposit
and the Base Rent as those amounts are specified in the Basic Provisions. Lessor
shall not be required to keep all or any part of the Security Deposit separate
from its general accounts. Lessor shall, at the expiration or earlier
termination of the term hereof and after Lessee has vacated the Premises, return
to Lessee (or, at Lessor's option, to the last assignee, if any, of Lessee's
interest herein), that portion of the Security Deposit not used or applied by
Lessor. Unless otherwise expressly agreed in writing by Lessor, no part of the
Security Deposit shall be considered to be held in trust, to bear interest or
other increment for its use, or to be prepayment for any moneys to be paid by
Lessee under this Lease.
6. Use.
6.1 Use. Lessee shall use and occupy the Premises only for the purposes set
forth in Paragraph 1.8, or any other use which is comparable thereto, and for no
other purpose. Lessee shall not use or permit the use of the Premises in a
manner that creates waste or a nuisance, or that disturbs owners and/or
occupants of, or causes damage to, neighboring premises or properties. Lessor
hereby agrees to not unreasonably withhold or delay its consent to any written
request by Lessee. Lessees assignees or subtenants, and by prospective assignees
and subtenants of the Lessee, its assignees and subtenants, for a modification
of said permitted purpose for which the premises may be used or occupied, so
long as the same will not impair the structural integrity of the improvements on
the Premises, the mechanical or electrical systems therein, is not significantly
more burdensome to the Premises and the improvements thereon, and is otherwise
permissible pursuant to this Paragraph 6. If Lessor elects to withhold such
consent, Lessor shall within five (5) business days give a written notification
of same, which notice shall include an explanation of Lessor's reasonable
objections to the change in use.
6.2 Hazardous Substances.
(a) Reportable Uses Require Consent. The term "Hazardous Substance" as used in
this Lease shall mean any product, substance, chemical material or waste whose
presence, nature, quantity and/or intensity of existence, use, manufacture,
disposal, transportation, spill, release or effect, either by itself or in
combination with other materials expected to be on the Premises, is either: (i)
potentially injurious to the public health, safety or welfare, the environment
or the Premises, (ii) regulated or monitored by any governmental authority, or
(iii) a basis for liability of Lessor to any governmental agency or third party
under any applicable statute or common law theory Hazardous Substance shall
include. but not be limited to, hydrocarbons, petroleum, gasoline, crude oil or
any products, by-products or fractions thereof. Lessee shall not engage in any
activity in, on or about the Premises which constitutes a Reportable Use (as
hereinafter defined) of Hazardous Substances without the express prior written
consent of Lessor and compliance in a timely manner (at Lessee's sole cost and
expense) with all Applicable Law (as defined in Paragraph 6.3). "Reportable Use"
shall mean (i) the installation or use of any - above or below ground-storage
tank, (ii) the generation, possession, storage, use, transportation, or disposal
of a Hazardous Substance that requires a permit from, or with respect to which a
report, notice, registration or business plan is required to be filed with, any
governmental authority. Reportable Use shall also include Lessee's being
responsible for the presence in, on or about the Premises of a Hazardous
Substance with respect to which any Applicable Law requires that a notice be
given to persons entering or occupying the Premises or neighboring properties.
Notwithstanding the foregoing, Lessee may, without Lessor's prior consent, but
in compliance with all Applicable Law, use any ordinary and customary materials
reasonably required to be used by Lessee in the normal course of Lessee's
business permitted on the Premises, so long as such use is not a Reportable Use
and does not expose the Premises or neighboring properties to any meaningful
risk of contamination or damage or expose Lessor to any liability therefor. In
addition, Lessor may (but without any obligation to do so) condition its consent
to the use or presence of any Hazardous Substance, activity or storage tank by
Lessee upon Lessee's giving Lessor such additional assurances as Lessor, in its
reasonable discretion, deems necessary to protect itself, the public, the
Premises and the environment against damage, contamination or injury and/or
liability therefrom or therefor, including, but not limited to, the installation
(and removal on or before Lease expiration or earlier termination) of reasonably
necessary protective modifications to the Premises (such as concrete
encasements) and/or the deposit of an additional Security Deposit under
Paragraph 5 hereof.
(b) Duty to Inform Lessor. If Lessee knows, or has reasonable cause to believe,
that a Hazardous Substance, or a condition involving or resulting from same, has
come to be located in, on, under or about the Premises, other than as previously
consented to by Lessor, Lessee shall immediately give written notice of such
fact to Lessor. Lessee shall also immediately give Lessor a copy of any
statement, report, notice, registration, application, permit, business plan,
license, claim, action or proceeding given to, or received from, any
governmental authority or private party, or persons entering or occupying the
Premises, concerning the presence, spill, release, discharge of, or exposure to,
any Hazardous Substance or contamination in, on, or about the Premises,
including but not limited to all such documents as may be involved in any
Reportable Uses involving the Premises.
(c) Indemnification. Lessee shall indemnify, protect, defend and hold Lessor,
its agents, employees, lenders and ground lessor, if any, and the Premises,
harmless from and against any and all bass of rents and/or damages, liabilities,
judgments, costs, claims, liens, expenses, penalties, permits and attorney's and
consultant's fees arising out of or involving any Hazardous Substance or storage
tank brought onto the Premises by or for Lessee or under Lessee's control.
Lessee's obligations under this Paragraph 6 shall include, but not be limited
to, the effects of any contamination or injury to person, property or the
environment created or suffered by Lessee, and the cost of investigation
(including consultant's and attorney's fees and testing), removal, remediation,
restoration and/or abatement thereof, or of any contamination therein involved,
and shall survive the expiration or earlier termination of this Lease. No
termination, cancellation or release agreement entered into by Lessor and Lessee
shall release Lessee from its obligations under this Lease with respect to
Hazardous Substances or storage tanks, unless specifically so agreed by Lessor
in writing at the time of such agreement.
6.3 Lessee's Compliance with Law. Except as otherwise provided in this Lease,
Lessee, shall, at Lessee's sole cost and expense, fully, diligently and in a
timely manner, comply with all "Applicable Law," which term is used in this
Lease to include all laws, rules, regulations, ordinances, directives,
covenants, easements and restrictions of record, permits, the requirements of
any applicable fire insurance underwriter or rating bureau, and the
recommendations of Lessor's engineers and/or consultants, relating in any manner
to the Premises (including but not limited to matters pertaining to (i)
industrial hygiene, (ii) environmental conditions on, in, under or about the
Premises, including soil and groundwater conditions, and (iii) the use,
generation, manufacture, production, installation, maintenance, removal,
transportation, storage, spill or release of any Hazardous Substance or storage
tank), now in effect or which may hereafter come into effect, and whether or not
reflecting a change in policy from any previously existing policy. Lessee shall,
within five (5) days after receipt of Lessor's written request, provide Lessor
with copies of all documents and information, including, but not limited to,
permits, registrations, manifests, applications, reports and certificates,
evidencing Lessee's compliance with any Applicable Law specified by Lessor, and
shall immediately upon receipt, notify Lessor in writing (with copies of any
documents involved) of any threatened or actual claim, notice, citation,
warning, complaint or report pertaining to or involving failure by Lessee or the
Premises to comply with any Applicable Law.
6.4 Inspection; Compliance. Lessor and Lessor's Lender(s) (as defined in
Paragraph 8.3(a)) shall have the right to enter the Premises at any time, in the
case of an emergency, and otherwise at reasonable times, for the purpose of
inspecting the condition of the Premises and for verifying compliance by Lessee
with this Lease and all Applicable Laws (as defined in Paragraph 6.3), and to
employ experts and/or consultants in connection therewith and/or to advise
Lessor with respect to Lessee's activities, including but not limited to the
installation, operation, use, monitoring, maintenance, or removal of any
Hazardous Substance or storage tank on or from the Premises. The costs and
expenses of any such inspections shall be paid by the party requesting same,
unless a Default or Breach of this Lease, violation of Applicable Law, or a
contamination, caused or materially contributed to by Lessee is found to exist
or be imminent, or unless the inspection is requested or ordered by a
governmental authority as the result of any such existing or imminent violation
or contamination. In any such case, Lessee shall upon request reimburse Lessor
or Lessor's Lender, as the case may be, for the costs and expenses of such
inspections.
7. Maintenance; Repairs; Utility Installations; Trade Fixtures and Alterations.
7.1 Lessee's Obligations.
(a) Subject to the provisions of Paragraphs 2.2 (Lessor's warranty as to
condition), 2.3 (Lessor's warranty as to compliance with covenants,etc),
NET
PAGE 2
<PAGE>
7.2 (Lessor's obligations to repair), 9 (damage and destruction), and 14
(condemnation), Lessee shall, at Lessee's sole cost and expense and at all
times, keep the Premises and every part thereof in good order, condition and
repair, structural and non-structural (whether or not such portion of the
Premises requiring repairs, or the means of repairing the same, are reasonably
or readily accessible to Lessee, and whether or not the need for such repairs
occurs as a result of use, any prior use, the elements or the age of such
portion of the Premises), including, without limiting the generality of the
foregoing, all equipment or facilities serving the Premises, such as plumbing,
heating, air conditioning, ventilating, electrical, lighting facilities,
boilers, fired or unfired pressure vessels, fire sprinkler and/or standpipe and
hose or other automatic fire extinguishing system, including fire alarm and/or
smoke detection systems and equipment, fire hydrants, fixtures, walls (interior
and exterior), foundations, ceilings, roofs, floors, windows, doors, plate
glass, skylights landscaping, driveways, parking lots, fences, retaining walls,
signs, sidewalks and parkways located in, on, about, or adjacent to the
Premises. Lessee shall not cause or permit any Hazardous Substance to be spilled
or released in, on, under or about the Premises (including through the plumbing
or sanitary sewer system) and shall promptly, at Lessee's expense; take all
investigatory and/or remedial action reasonably recommended, whether or not
formally ordered or required, for the cleanup of any contamination of, and for
the maintenance, security and/or monitoring of the Premises, the elements
surrounding same, or neighboring properties, that was caused or materially
contributed to by Lessee, or pertaining to or involving any Hazardous Substance
and/or storage tank brought onto the Premises by or for Lessee or under its
control. Lessee, in keeping the Premises in good order, condition and repair,
shall exercise and perform good maintenance practices. Lessee's obligations
shall include restorations, replacements or renewals when necessary to keep the
Premises and all improvements thereon or a part thereof in good order, condition
and state of repair. If Lessee occupies the Premises for seven (7) years or
more, Lessor may require Lessee to repaint the exterior of the buildings on the
Premises as reasonably required, but not more frequently than once every seven
(7) years.
<deleted items>
7.2 Lessor's Obligations. Except for the warranties and agreements of Lessor
contained in Paragraphs 2.2 (relating to condition of the Premises), 2.3
(relating to compliance with covenants, restrictions and building code), 9
(relating to destruction of the Premises) and 14 (relating to condemnation of
the Premises), it is intended by the Parties hereto that Lessor have no
obligation, in any manner whatsoever, to repair and maintain the Premises, the
improvements located thereon, or the equipment therein, whether structural or
non structural, all of which obligations are intended to be that of the Lessee
under Paragraph 7.1 hereof. It is the intention of the Parties that the terms of
this Lease govern the respective obligations of the Parties as to maintenance
and repair of the Premises. Lessee and Lessor expressly waive the benefit of any
statute now or hereafter in effect to the extent it is inconsistent with the
terms of this Lease with respect to, or which affords Lessee the right to make
repairs at the expense of Lessor or to terminate this Lease by reason of any
needed repair'.
7.3 Utility Installations; Trade Fixtures; Alterations.
(a) Definitions; Consent Required. The term "Utility Installations" is used in
this Lease to refer to all carpeting, window coverings, air lines, power panels,
electrical distribution, security, fire protection systems, communication
systems, lighting fixtures, heating, ventilating, and air conditioning
equipment, plumbing, and fencing in, on or about the Premises. The term "made
Fixtures" shall mean Lessee's machinery and equipment that can be removed
without doing material damage to the Premises. The term "Alterations" shall mean
any modification of the improvements on the Premises from that which are
provided by Lessor under the terms of this Lease, other than Utility
Installations or Trade Fixtures, whether by addition or deletion. "Lessee Owned
Alterations and/or Utility Installations" are defined as Alterations and/or
Utility Installations made by lessee that are not yet owned by Lessor as defined
in Paragraph 7.4(a). Lessee shall not make any Alterations or Utility
Installations in, on, under or about the Premises without Lessor's prior written
consent. Lessee may, however, make non-structural Utility Installations to the
interior of the Premises (excluding the roof), as long as they are not visible
from the outside, do not involve puncturing, relocating or removing the roof or
any existing walls, and the cumulative cost thereof during the term of this
Lease as extended does not exceed $25,000.
(b) Consent. Any Alterations or Utility Installations that Lessee shall desire
to make and which require the consent of the Lessor shall be presented to Lessor
in written form with proposed detailed plans. All consents given by Lessor,
whether by virtue of Paragraph 7.3(a) or by subsequent specific consent, shall
be deemed conditioned upon: (i) Lessee's acquiring all applicable permits
required by governmental authorities, (ii) the furnishing of copies of such
permits together with a copy of the plans and specifications for the Alteration
or Utility Installation to Lessor prior to commencement of the work thereon, and
(iii) the compliance by Lessee with all conditions of said permits in a prompt
and expeditious manner Any Alterations or Utility Installations by Lessee during
the term of this Lease shall be done in a good and workmanlike manner, with good
and sufficient materials, and in compliance with all Applicable Law. Lessee
shall promptly upon completion thereof furnish Lessor with as-built plans and
specifications therefor. Lessor may (but without obligation to do so) condition
its consent to any requested Alteration or Utility Installation that costs
S10,000 or more upon Lessee's providing Lessor with a lien and completion bond
in an amount equal to one and one-half times the estimated cost of such
Alteration or Utility Installation and/or upon Lessee's posting an additional
Security Deposit with Lessor under Paragraph 36 hereof.
(c) Indemnification. Lessee shall pay, when due, all claims for labor or
materials furnished or alleged to have been furnished to or for Lessee at or for
use on the Premises, which claims are or may be secured by any mechanic's or
materialmen's lien against the Premises or any interest therein. Lessee shall
give Lessor not less than ten (10) days' notice prior to the commencement of any
work in, on or about the Premises, and Lessor shall have the right to post
notices of non-responsibility in or on the Premises as provided by law. If
Lessee shall, in good faith, contest the validity of any such lien, claim or
demand, then Lessee shall, at its sole expense defend and protect itself, Lessor
and the Premises against the same and shall pay and satisfy any such adverse
judgment that may be rendered thereon before the enforcement thereof against the
Lessor or the Premises. If Lessor shall require, Lessee shall furnish to Lessor
a surety bond satisfactory to Lessor in an amount equal to one and one-half
times the amount of such contested lien claim or demand, indemnifying Lessor
against liability for the same, as required by law for the holding of the
Premises free from the effect of such lien or claim. In addition, Lessor may
require Lessee to pay Lessor's attorney's fees and costs in participating in
such action if Lessor shall decide it is to its best interest to do so.
7.4 Ownership; Removal; Surrender; and Restoration.
(a) Ownership. Subject to Lessor's right to require their removal or become the
owner thereof as hereinafter provided in this Paragraph 7.4, all Alterations and
Utility Additions made to the Premises by Lessee shall be the property of and
owned by Lessee, but considered a part of the Premises. Lessor may, at any time
and at its option, elect in writing to Lessee to be the owner of all or any
specified part of the Lessee Owned Alterations and Utility Installations. Unless
otherwise instructed per subparagraph 7.4(b) hereof, all Lessee Owned
Alterations and Utility Installations shall, at the expiration or earlier
termination of this Lease, become the property of Lessor and remain upon and be
surrendered by Lessee with the Premises.
(b) Removal. Unless Otherwise agreed in writing, Lessor may require that any or
all Lessee Owned Alterations or Utility Installations be removed by me
expiration or earlier termination of this Lease, notwithstanding their
installation may have been consented to by Lessor. Lessor may require the
removal at any time of all or any part of any Lessee Owned Alterations or
Utility Installations made without the required consent of Lessor.
(c) Surrender/Restoration. Lessee shall surrender the Premises by me end of the
last day of the Lease term or any earlier termination date, with all of the
improvements, parts and surfaces thereof clean and free of debris and in good
operating order, condition and state of repair, ordinary wear and tear excepted.
"Ordinary wear and tear" shall not include any damage or deterioration met would
have been prevented by good maintenance practice or by Lessee performing all of
its obligations under this Lease. Except as otherwise agreed or specified in
writing by Lessor, the Premises, as surrendered, shall include the Utility
Installations. The obligation of Lessee shall include the repair of any damage
occasioned by the installation, maintenance or removal of Lessee's Trade
Fixtures, furnishings, equipment, and Alterations and/or Utility Installations,
as well as me removal of any storage tank installed by or for Lessee, and the
removal, replacement, or remediation of any soil, material or ground water
contaminated by Lessee, all as may then be required by Applicable Law and/or
good service practice. Lessee's Trade Fixtures shall remain the property of
Lessee and shall be removed by Lessee subject to its obligation to repair and
restore the Premises per His Lease.
a Insurance; Indemnity.
8.1 Payment for Insurance. Paragraph 8 except to the extent of the cost
attributable to liability insurance carried hy ~ Dolor in o,~cc_. of ~ I,~,uuv
per occurrence. Premiums for policy periods commencing Drior to Or ~ViDr~r~l ~3
b ~ _ ~' '/: Lease term shall be prorated to correspond to me Lease term.
Payment shall be made by Ld~ Loooor within ton (10) days following o cecipt of
an invoice for any amount due.
8.2 Liability Insurance.
(a) Carried by Lessee. Lessee shall obtain and keep in force during the term of
this Lease a Commercial General Liability policy of insurance protecting Lessee
and Lessor (as an additional insured) against claims for bodily injury, personal
injury and property damage based upon, involving or arising out of the
ownership, use, occupancy or maintenance of the Premises and all areas
appurtenant thereto. Such Insurance shall be on an occurrence basis providing
single limit coverage in an amount not less than $1,000,000 per occurrence with
an "Additional Insured-Managers or Lessors of Premises" Endorsement and contain
the "Amendment of the Pollution Exclusions for damage caused by heat, smoke or
fumes from a hostile fire. The policy shall not contain any intra-insured
exclusions as between insured persons or organizations, but shall include
coverage for liability assumed under this Lease as an "insured contract" for the
performance of Lessee's indemnity obligations under this Lease. The limits of
said insurance required by this Lease or as carried by Lessee shall not,
however, limit the liability of Lessee nor relieve Lessee of any obligation
hereunder. All insurance to be carried by Lessee shall be primary to and not
contributory with any similar insurance canted by Lessor, whose insurance shall
be considered excess insurance only.
(b) Carried By Lessor. In me event Lessor is the Insuring Party, Lessor
shall also maintain liability insurance described in Paragraph 8.2(a),
above, in addition to, and not in lieu of, the insurance required to be
maintained by Lessee. Lessee shall not be named as an additional insured
therein.
PAGE 3
<PAGE>
8.3 Proporty Insuranoo Etulidtng, l~omonta and Rental V lua. V
(a) Duliding and Impravomonta. The Insuring Party shall obtain and laptop in
forgo during the term of this Loeco D policy or poliolos in the no .` of Lessor,
with loss payable to Lessor and to the holders of any mortgages, deeds of trust
or ground leases on the Premises ("Lender(s)"), insur~oss or damage to the
Premises. The amount of such insurance shall be equal to the full replacement
cost of the Premises, as the same shall exj*tfoilh time to time, or the amount
required by Lenders, but in no event more than the commercially reasonable and
available insurable value th~if, by reason of the unique nature or age of the
improvements involved, such latter amount is less than full replacement cost. If
Lessor is the]neafing Party, however, Lessee Owned Alterations and Utility
Installations shall be insured by Lessee under Paragraph 8.4 rather than by
Lessor. If Coverage is available and commercially appropriate, such policy or
policies shall insure against all risks of direct physical loss or damage
(except tendrils of flood and/or earthquake unless required by a Lender),
including coverage for any additional costs resulting from debris removal and
Enable amounts of coverage for the enforcement of any ordinance or law
regulating the reconstruction or replacement of any undamaged sects me Premises
required to be demolished or removed by reason of the enforcement of any
building, zoning, safety or land use laws as the rest covered cause of loss.
Said policy or policies shall also contain an agreed valuation provision in lieu
of any coinsurance clause, waiver of subrogation, and inflation guard protection
causing an increase in the annual property insurance coverage amount by a factor
of not less man the adjusted. Department of Labor Consumer Price Index for All
Urban Consumers for the city nearest to where the Premises are located. If such
Insuranc~verage has a deductible clause, the deductible amount shalt not exceed
$1,000 per occurrence, and Lessee shall be liable for such deductible A - unt in
the event of an Insured Loss, as defined in Paragraph 9.1(c).
(b) Rental Value. The Insuring Party shall, in addition, obtain ag~ep in force
during the term of this Lease a policy or policies in the name of Lessor, with
loss payable to Lessor and Lender(s), insuring the log the full rental and other
charges payable by Lessee to Lessor under this Lease for one (1) year (including
all real estate taxes, insurance cost, and any scheduled rental increases). Said
insurance shall provide that in the event the Lease is terminated by reason of
an insured loss, th~iod of indemnity for such coverage shall be extended beyond
the date of the completion of repairs or replacement of the Premises, to prove
one full year's loss of rental revenues from the date of any such loss. Said
insurance shall contain an agreed valuation provision in lieu of any Assurance
clause, and me amount of coverage shall be adjusted annually to reflect the
projected rental income, property taxes, insurance premJ~costs and other
expenses, If any, otherwise payable by Lessee, for the next twelve (12) month
period. Lessee shall be liable for any deductible pint in the event of such
loss.
(c) Adiacant Pray. If the Premises are part of s larger building, or If the
Premises are part of a group of buildings owned by Lessor which are adjacent to
the Uses, the Lessee shall pay for any Increase In the premiums for the property
insurance of such building or buildings if said increase is cagey Lessee's acts,
omissions, use or occupancy of the Premises.
(d~nant's Improvements. If the Lessor is the Insuring Party, me Lessor
shall not be required to Insure Lessee Owned Alterations and Utility
Ins~ons unless the item in question has become the property of Lessor under
me terms of this Lease. It Lessee is the Insuring Party, the policy carried
j ~__A o ~ ~ ~ n ~ al I _A ~ A AA ~ ._AA A a--Al ALA ALA ~ ~ --.~ ~A_~AtlA~
A_A _J ~ unuOF t..lS . arG9rGp _._ O G nou._ __oo__ am..__ _._ _ _ _ _
a....., ..._....._.._.
8.4 Lessee's Property Insurance. Subject to the requirements of Paragraph 8.5,
Lessee at its cost shall either by separate policy or, at Lessor's option, by
endorsement to a policy already carried, maintain insurance coverage on all of
Lessee's personal property, Lessee Owned Alterations and Utility Installations
in, on, or about the Premises similar in coverage to that carried by the
Insuring Party under Paragraph 8.3. Such insurance shall be full replacement
cost coverage with a deductible of not to exceed $1,000 per occurrence. The
proceeds from any such insurance shall be used by Lessee for the replacement of
personal property or the restoration of Lessee Owned Alterations and Utility
Installations. Lessee shall be the Insuring Party with respect to the insurance
required by this Paragraph 8.4 and shall provide Lessor with written evidence
that such insurance is in force.
8.5 Insurance Policies. Insurance required hereunder shall be in companies duly
licensed to transact business in the state where the Premises are located, and
maintaining during the policy term a "General Policyholders Rating" of at least
B +, V, or such other rating as may be required by a Lender having a lien on the
Premises, as set forth in the most current issue of "Best's Insurance Guide."
Lessee shall not do or permit to be done anything which shall invalidate the
insurance policies referred to in this Paragraph 8. If Lessee is me Insuring
Party, Lessee shall cause to be delivered to Lessor certified copies of policies
of such insurance or certificates evidencing the existence and amounts of such
insurance with the insured and loss payable clauses as required by this Lease.
No such policy shall be cancellable or subject to modification except after
thirty (30) days prior written notice to Lessor. Lessee shall at least thirty
(30) days prior to the expiration of such policies, furnish Lessor with evidence
of renewals or "insurance binders" evidencing renewal thereof, or Lessor may
order such Insurance and charge the cost thereof to Lessee, which amount shall
be payable by Lessee to Lessor upon demand. If the Insuring Party shall fail to
procure and maintain the insurance required to be carried by me Insuring Party
under this Paragraph 8, the other Party may, but shall not be required to,
procure and maintain the same, but at Lessee's expense.
8.6 Waiver of Subrogation. Without affecting any other rights or remedies,
Lessee and Lessor ("Waiving Party") each hereby release and relieve the other,
and waive their entire right to recover damages (whether in contract or in tort)
against the other, for loss of or damage to the Waiving Party's property arising
out of or incident to the perils required to be insured against under Paragraph
8. The effect of such releases and waivers of the right to recover damages shall
not be limited by the amount of insurance carried or required, or by any
deductibles applicable thereto.
8.7 Indemnity. Except for Lessor's negligence and/or breach of express
warranties, Lessee shall indemnify, protect, defend and hold harmless the
Premises, Lessor and its agents, Lessor's master or ground lessor, partners and
Lenders, from and against any and all claims, loss of rents and/or damages,
costs, liens, judgments, penalties, permits, attorney's and consultant's fees,
expenses and/or liabilities arising out of, involving, or in dealing with, me
occupancy of the Premises by Lessee, the conduct of Lessee's business, any act,
omission or neglect of Lessee, its agents, contractors, employees or invitees,
and out of any Default or Breach by Lessee in the performance in a timely manner
of any obligation on Lessee's part to be performed under this Lease. The
foregoing shall include, but not be limited to, the defense or pursue of any
claim or any action or proceeding involved therein, and whether or not (in the
case of claims made against Lessor) litigated and/or reduced to judgment, and
whether well founded or not. In case any action or proceeding be brought against
Lessor by reason of any of the foregoing matters, Lessee upon notice from Lessor
shall defend the same at Lessee's expense by counsel reasonably satisfactory to
Lessor and Lessor shall cooperate with Lessee in such defense. Lessor need not
have first paid any such claim in order to be so indemnified.
8.8 Exemption of Lessor from Liability. Lessor shall not be liable for injury or
damage to the person or goods, wares, merchandise or other properly of Lessee,
Lessee's employees, contractors, invitees, customers, or any other person in or
about the Premises, whether such damage or injury is caused by or results from
fire, steam, electricity, gas, water or rain, or from the breakage, leakage,
obstruction or other defects of pipes, fire sprinklers, wires, appliances,
plumbing, air conditioning or lighting fixtures, or from any other cause,
whether the said injury or damage results from conditions arising upon the
Premises or upon other portions of the building of which the Premises are a
part, or from other sources or places, and regardless of whether the cause of
such damage or injury or me means of repairing the same is accessible or not.
Lessor shall not be liable for any damages arising from any act or neglect of
any other tenant of Lessor. Notwithstanding Lessor's negligence or breach of
this Lease, Lessor shall under no circumstances be liable for injury to Lessee's
business or for any loss of income or profit therefrom.
9. Damage or Destruction.
9.1 Definitions.
(a) "Premises Partial Damage" shall mean damage or destruction to me
improvements on me Premises, other than Lessee Owned Alterations and Utility
Installations, the repair cost of which damage or destruction is less than 50%
of the then Replacement Cost of the Premises immediately prior to such damage or
destruction, excluding from such calculation the value of the land and Lessee
Owned Alterations and Utility Installations.
(b) "Premises Total Destruction" shall mean damage or destruction to the
Premises, other than Lessee Owned Alterations and Utility Installations the
repair cost of which damage or destruction is 50% or more of the then
replacement Cost of the Premises immediately prior to such damage or
destruction, excluding from such calculation the value of the land and Lessee
Owned Alterations and Utility Installations.
(c) "Insured Loss" shall mean damage or destruction to improvements on the
Premises, other than Lessee Owned Alterations and Utility Installations, which
was caused by an event required to be covered by the insurance described in
Paragraph 8.3(a), irrespective of any deductible amounts or coverage limits
involved.
(d) "Replacement Cost" shall mean the cost to repair or rebuild the improvements
owned by Lessor at the time of the occurrence to their condition existing
immediately prior thereto, including demolition, debris removal and upgrading
required by the operation of applicable building codes, ordinances or laws, and
without deduction for depreciation.
(e) "Hazardous Substance Condition" shall mean the occurrence or discovery of a
condition involving the presence of, or a contamination by, a Hazardous
Substance as defined in Paragraph 6.2(a), in, on, or under the Premises.
9.2 Partial Damage-Insured Loss. If a Premises Partial Damage that is an Insured
Loss occurs, then Lessor shall, at Lessor's expense, repair such damage (but not
Lessee's Trade Fixtures or Lessee Owned Alterations and Utility Installations)
as soon as reasonably possible and this Lease shall continue in full force and
effect; provided, however, that Lessee shall, at Lessor's election, make the
repair of any damage or destruction the total cost to repair of which is $10,000
or less, and, in such event, Lessor shall make the insurance proceeds available
to Lessee on a reasonable basis for that purpose. Notwithstanding the foregoing,
if the required insurance was not in force or the insurance proceeds are not
sufficient to effect such repair, the Insuring Party shall promptly contribute
the shortage in proceeds (except as to the deductible which is Lessee's
responsibility) as and when required to complete said repairs. In the event,
however, the shortage in proceeds was due to the fact that, by reason of the
unique nature of the improvements, full replacement cost insurance coverage was
not commercially reasonable and available, Lessor shall have no obligation to
pay for the shortage in insurance proceeds or to fully restore the unique
aspects of the Premises unless Lessee provides Lessor with the funds to cover
same, or adequate assurance thereof, within ten (10) days following receipt of
written notice of such shortage and request therefor. If Lessor receives said
funds or adequate assurance thereof within said ten (10) day period, the party
responsible for making the repairs shall complete them as soon as reasonably
possible and this Lease shall remain in full force and effect. If Lessor does
not receive such funds or assurance within said period, Lessor may nevertheless
elect by written notice to Lessee within ten (10) days thereafter to make such
restoration and repair as is commercially reasonable with Lessor paying any
shortage in proceeds, in which case this Lease shall remain in full force and
effect. If in such case Lessor does not so elect, then this Lease shall
terminate sixty (60) days following the occurrence of the damage or destruction.
Unless otherwise agreed, Lessee shall in no event have any right to
reimbursement from Lessor for
NET
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any funds contributed by Lessee to repair such damage or destruction. Premises
Partial Damage due to flood or earthquake shall be subject to Paragraph 9.3
rather than Paragraph 9.2, notwithstanding that there may be some insurance
coverage but the net proceeds of any such insurance shall be made available for
the repairs if made by either Party.
9.3 Partial Damage-Uninsured Loss If a Premises Partial Damage that is not an
Insured Loss occurs, unless caused by a negligent or willful act of Lessee (in
which event Lessee shall make the repairs at Lessee's expense and this Lease
shall continue in full force and effect, but subject to Lessor's rights under
Paragraph 13), Lessor may at Lessor's option, either: (i) repair such damage as
soon as reasonably possible at Lessor's expense, in which event this Lease shall
continue in full force and effect, or (ii) give written notice to Lessee within
thirty (30) days after receipt by Lessor of knowledge of the occurrence of such
damage of Lessor's desire to terminate this Lease as of the date sixty (60) days
following the giving of such notice. In the event Lessor elects to give such
notice of Lessor's intention to terminate this Lease, Lessee shall have the
right within ten (10) days after the receipt of such notice to give written
notice to Lessor of Lessee's commitment to pay for the repair of such damage
totally at Lessee's expense and without reimbursement from Lessor. Lessee shall
provide Lessor with the required funds or satisfactory assurance thereof within
thirty (30) days following Lessee's said commitment. In such event this Lease
shall continue in full force and effect, and Lessor shall proceed to make such
repairs as soon as reasonably possible and the required funds are available. If
Lessee does not give such notice and provide the funds or assurance thereof
within the times specified above, this Lease shall terminate as of the date
specified in Lessor's notice of termination.
9.4 Total Destruction. Notwithstanding any other provision hereof, if a Premises
Total Destruction occurs (including any destruction required by any authorized
public authority), this Lease shall terminate sixty (60) days following the date
of such Premises Total Destruction, whether or not the damage or destruction is
an Insured Loss or was caused by a negligent or willful act of Lessee. In the
event, however, that the damage or destruction was caused by Lessee, Lessor
shall have the right to recover Lessor's damages from Lessee except as released
and waived in Paragraph 8.6.
9.5 Damage Near End of Term. If at any time during the last six (6) months of
the term of this Lease there is damage for which the cost to repair exceeds one
(1) month's Base Rent, whether or not an Insured Loss, Lessor may, at Lessor's
option, terminate this Lease effective sixty (60) days following the date of
occurrence of such damage by giving written notice to Lessee of Lessor's
election to do so within thirty (30) days after the date of occurrence of such
damage. Provided, however, if Lessee at that time has an exercisable option to
extend this Lease or to purchase the Premises, then Lessee may preserve this
Lease by, within twenty (20) days following the occurrence of the damage, or
before the expiration of the time provided in such option for its exercise
whichever is earlier ("Exercise Period"), (i) exercising such option and (ii)
providing Lessor with any shortage in insurance proceeds (or adequate assurance
thereof) needed to make the repairs. If Lessee duly exercises such option during
said Exercise Period and provides Lessor with funds (w adequate assurance
thereof) to cover any shortage in insurance proceeds, Lessor shall, at Lessor's
expense repair such damage as soon as reasonably possible and this Lease shall
continue In full force and effect. If Lessee fails to exercise such option and
provide such funds or assurance during said Exercise Period, then Lessor may at
Lessor's option terminate this Lease as of the expiration of said sixty (60) day
period following the occurrence of such damage by giving written notice to
Lessee of Lessor's election to do so within ten (10) days after the expiration
of the Exercise Period, notwithstanding any term or provision in the grant of
option to the contrary.
9.6 Abatement of Rent; Lessee's Remedies.
(a) In the event of damage described in Paragraph 9.2 (Partial Damage-Insured),
whether or not Lessor or Lessee repairs or restores the Premises, the Base Rent,
Real Property Taxes, insurance premiums, and other charges, if any, payable by
Lessee hereunder for the period during which such damage, its repair or the
restoration continues (not to exceed the period for which rental value insurance
is required under Paragraph 8.3(b)), shall be abated in proportion to the degree
to which Lessee's use of the Premises is impaired. Except for abatement of Base
Rent, Real Property Taxes, insurance premiums, and other charges, if any, as
aforesaid, all other obligations of Lessee hereunder shall be performed by
Lessee, and Lessee shall have no claim against Lessor for any damage suffered by
reason of any such repair or restoration.
(b) If Lessor shall be obligated to repair or restore the Premises under the
provisions of this Paragraph 9 and shall not commence, in a substantial and
meaningful way, the repair or restoration of the Premises within ninety (90)
days after such obligation shall accrue, Lessee may, at any time prior to the
commencement of such repair or restoration, give written notice to Lessor and to
any Lenders of which Lessee has actual notice of Lessee's election to terminate
this Lease on a date not less than sixty (60) days following the giving of such
notice. If Lessee gives such notice to Lessor and such Lenders and such repair
or restoration is not commenced within thirty (30) days after receipt of such
notice, this Lease shall terminate as of the date specified in said notice. If
Lessor or a Lender commences the repair or restoration of the Premises within
thirty (30) days after receipt of such notice, this Lease shall continue in full
force and effect. "Commence" as used in this Paragraph shall mean either the
unconditional authorization of the preparation of the required plans, or the
beginning of the actual work on the Premises, whichever first occurs.
9.7 Hazardous Substance Conditions. If a Hazardous Substance Condition occurs,
unless Lessee Is legally responsible therefor (in which case Lessee shall make
the investigation and remediation thereof required by Applicable Law and this
Lease shall continue in full force and effect, but subject to Lessor's rights
under Paragraph 13), Lessor may at Lessor's option either (i) investigate and
remediate such Hazardous Substance Condition, if required, as soon as reasonably
possible at Lessor's expense, in which event this Lease shall continue in full
force and effect, or (ii) if the estimated cost to investigate and remediate
such condition exceeds twelve (12) times the then monthly Base Rent or S100,000,
whichever is greater, give written notice to Lessee within thirty (30) days
after receipt by Lessor of knowledge of the occurrence of such Hazardous
Substance Condition of Lessor's desire to terminate this Lease as of the date
sixty (60) days following the giving of such notice. In the event Lessor elects
to give such notice of Lessor's intention to terminate this Lease, Lessee shall
have the right within ten (10) days after the receipt of such notice to give
written notice to Lessor of Lessee's commitment to pay for the investigation and
remediation of such Hazardous Substance Condition totally at Lessee's expense
and without reimbursement from Lessor except to the extent of an amount equal to
twelve (12) times the then monthly Base Rent or S100,000, whichever is greater.
Lessee shall provide Lessor with the funds required a! Lessee w satisfactory
assurance thereof within thirty (30) days following Lessee's said commitment. In
such event this Lease shall continue in full force and effect, and Lessor shall
proceed to make such investigation and remediation as soon as reasonably
possible and the required funds are available. If Lessee does not give such
notice and provide the required funds or assurance thereof within the times
specified above, this Lease shall terminate as of the date specified in Lessor's
notice of termination. If a Hazardous Substance Condition occurs for which
Lessee is not legally responsible there shall be abasement of Lessee's
obligations under this Lease to the same extent as, worded in Paragraph 9.6(a)
for a period of not to exceed twelve (12) months.
9.8 Termination-Advance Payments. Upon termination of this Lease pursuant to
this Paragraph 9, an equitable adjustment shall be made concerning advance Base
Rent and any other advance payments made by Lessee to Lessor. Lessor shall, in
addition, return to Lessee so much of Lessee's Security Deposit as has not been,
or is not then required to be, used by Lessor under the terms of this Lease.
9.9 Waive Statutes. Lessor and Lessee agree that the terms of this Lease
shall govern the effect of any damage to or destruction of the Premises
with respect to the termination of this Lease and hereby waive the
provisions of any present or future statute to the extent inconsistent
herewith.
10. Real Property Taxes.
~ (a) Poymont at Saxon Losooo oRd pay the Real property Taxoo, as donned in
Paragraph 10.3, applbablo to the Fromicoc during the term of this Lease. Subject
to Paragraph 10.1(b), all such payments shall be made at least ten (10) days
prior to the delinquency date of the applicable instaJl~nt. Lessee shall
promptly furnish Lessor with satisfactory evidence that such taxes hwe been
paid. If any such taxes to be paid by Lessee shiver any period of time prior to
or after the expiration or earlier termination of the term hereof, Lessee's
share of such taxes shall be equitably Drafated to cover only the period of time
within the tax fiscal year this Lease is in effect, and Lessor shall reimburse
Lessee for any overpayme~er such proration. If Lessee shall fail to pay any Real
Property Taxes required by this Lease to be paid by Lessee, Lessor shall hwe the
right ~ the same, and Lessee shall reimburse Lessor therefor upon demand. ~
(b) Advance Payment. In order to insure payment when due and before delinquency
of any or all Real PsDp~ty Taxes, Lessor reserves the right, at Lessor's option,
to estimate the current Real Property Taxes applicable to the Premises, and to
require ~cunent year's Real Property Taxes to be paid in advance to Lessor by
Lessee, either: (i) in a lump sum amount equal to the installment due~fleast
twenty (20) days prior to the applicable delinquency date, or (ii) monthly in
advance with the payment of the Base Rent. If Lessor elec~require payment
monthly in advance, the monthly payment shall be that equal monthly amount
which, over the number of months remaining _~ofe the month in which the
applicable tax installment would become delinquent (and without interest
thereon), would provide a fund large enoug_to~ully discharge before delinquency
the estimated installment of taxes to be paid. When the actual amount of the
applicable tax bill is known, th~arfiount of such equal monthly advance payment
shall be adjusted as required to provide the fund needed to pay the applicable
taxes before deli~ncy. If the amounts paid to Lessor by Lessee under the
provisions of this Paragraph are insufficient to discharge the obligations of
Lessee to p_ - ch Real Property Taxes as the same become due, Lessee shall pay
to Lessor, upon Lessor's demand, such additional sums as are necessary~ay such
obligations. All moneys paid to Lessor under this Paragraph may be intermingled
with other moneys of Lessor and shall not bear interest In the event of a Breach
by Lessee in the performance of the obligations of Lessee under this Lease, then
any balance of funds paid to Lessors the provisions of this Paragraph may,
subject to proration as provided in Paragraph 10.1(a), at the option of Lessor,
be treated as an additio - Security Deposit under Paragraph 5.
10.2 Dethithn d "Real Property Taxers used herein, the term "Real Property
Taxes" shalUnclude any Arm of real estate tax or assessment, general special,
ordinary or extraordinary, an~y license fee, commercial rental tax, improvement
bond or bonds, levy or tax (other than inheritance, personal income or estate
taxes) impo~pon the Premises by any authority having the direct or indirect
power to tax, including any city, state or federal government, or any school -
ricultural, sanitary, fire, street, drainage or other improvement district
thereof, levied against any legal or equitable interest of Lessor in the Preps
or in the real property of which the Premises are a part, Lessor's right to rent
or other income therefrom, and/or Lessor's business of lathe Premises. The term
"Reat Property T xes" shall also include any tax, fee, levy, assessment or
charge, or any increase therein, imposed Mason of events occurring, or changes
in applicable law taking effect, during the term of this Lease, including but
not limited to a change in th~nership of the Premises or in the improvements
thereon, the execution of this Lease, or any modification, amendment or transfer
thereof, and h*~r~ not oontomplatod by the Partiso.
10.3 Joint Assessment. If the Premises are not separately assessed, Lessee's
liability shall be an equitable proportion of the Real Property Taxes for all of
the land and improvements included within the tax parcel assessed, such
proportion to be determined by Lessor from the respective valuations
PAGE 5
<PAGE>
assigned In the assessor's work sheets or other information as may be reasonably
available. Lessor's reasonable determination thereof, in good faith shall be
conclusive.
10.4 Personal Property Taxes. Lessee shall pay prior to delinquency all taxes
assessed against and levied upon Lessee Owned Alterations, Utility
Installations, Trade Fixtures, furnishings, equipment and all personal property
of Lessee contained in the Premises or elsewhere. When possible, Lessee shall
cause its Trade Fixtures, furnishings, equipment and all other personal property
to be assessed and billed separately from the real property of Lessor. If any of
Lessee's said personal property shall be assessed with Lessor's real property,
Lessee shall pay Lessor the taxes attributable to Lessee within ten (10) days
after receipt of a written statement setting forth the taxes applicable to
Lessee's property or, at Lessor's option, as provided in Paragraph 10.1(b).
11. Utilities Lasses shall pay for all water, gas, heat, light, power,
tclephone, trash disposal end other utilities and services supplied to the
Premises, together with any taxes thereon. If any such services are not
separately, metered to Lossoe, Lessee shall pay reasonable proportion, to be
determined by Lessor,
12. Assignment and Subletting.
12.1 Lessor's Consent Required.
(a) Lessee shall not voluntarily or by operation of law assign, transfer,
mortgage or otherwise transfer or encumber (collectively, "assignment") or
sublet all or any part of Lessee's interest in this Lease or in the
Premises without Lessor's prior written consent given under and subject to
the terms of Paragraph 36. (b) A change in the control of Lessee shall
constitute an assignment requiring Lessor's consent. The transfer, on a
cumulative basis, of twenty-five percent (25%) or more of the voting
control of Lessee shall constitute a change in control for this purpose.
(c) The involvement of Lessee or its assets in any transaction, or series of
transactions (by way of merger, sale, acquisition, financing, refinancing,
transfer, leveraged buy-out or otherwise), whether or not a formal assignment or
hypothecation of this Lease or Lessee's assets occurs, which results or will
result in a reduction of the Net Worth of Lessee, as hereinafter defined, by an
amount equal to or greater than twenty-five percent (25%) of such Net Worth of
Lessee as it was represented to Lessor at the time of the execution by Lessor of
this Lease or at the time of the most recent assignment to which Lessor has
consented, or as it exists immediately prior to said transaction or transactions
constituting such reduction, at whichever time said Net Worth of Lessee was or
is greater, shall be considered an assignment of this Lease by Lessee to which
Lessor may reasonably withhold its consent. "Net Worth of Lessee" for purposes
of this Lease shall be the net worth of Lessee (excluding any guarantors)
established under generally accepted accounting principles consistently applied.
(d) An assignment or subletting of Lessee's Interest in this Lease without
Lessor's specific prior written consent shall, at Lessor's option, be a Default
curable after notice per Paragraph 13.1(c), or a nondurable Breach without the
necessity of any notice and grace period. If Lessor elects to treat such
unconsented to assignment or subletting as a nondurable Breach, Lessor shall
have the right to either: (i) terminate this Lease, or (ii) upon thirty (30)
days written notice ("Lessor's Notice"), increase the monthly Base Rent to fair
market rental value or one hundred ten percent (110%) of the Base Rent then in
effect, whichever is greater. Pending determination of the new fair market
rental value, if disputed by Lessee, Lessee shall pay the amount set forth in
Lessor's Notice, with any overpayment credited against the next installment(s)
of Base Rent coming due, and any underpayment for the period retroactively to
the effective date of the adjustment being due and payable immediately upon the
determination thereof. Further, in the event of such Breach and market value
adjustment, (i) the purchase price of any option to purchase the Premises held
by Lessee shall be subject to similar adjustment to the then fair market value
(without the Lease being considered an encumbrance or any deduction for
depreciation or obsolescence, and considering the Premises at its highest and
best use and in good condition), or one hundred ten percent (110%) of the price
previously in effect, whichever is greater, (ii) any index-oriented rental or
price adjustment formulas contained in this Lease shall be adjusted to require
that the base index be determined with reference to the index applicable to the
time of such adjustment, and (iii) any fixed rental adjustments scheduled during
the remainder of the Lease term shall be increased in the same ratio as the new
market rental bears to the Base Rent in effect immediately prior to the market
value adjustment.
(e) Lessee's remedy for any breach of this Paragraph 12.1 by Lessor shall be
limited to compensatory damages and injunctive relief.
12.2 Terms and Conditions Applicable to Assignment and Subletting.
(a) Regardless of Lessor's consent, any assignment or subletting shall not: (i)
be effective without the express written assumption by such assignee or
subleases of the obligations of Lessee under this Lease, (ii) release Lessee of
any obligations hereunder, or (iii) alter the primary liability of Lessee for
the payment of Base Rent and other sums due Lessor hereunder or for the
performance of any other obligations to be performed by Lessee under this Lease.
(b) Lessor may accept any rent or performance of Lessee's obligations from any
person other than Lessee pending approval or disapproval of an assignment.
Neither a delay in the approval or disapproval of such assignment nor the
acceptance of any rent or performance shall constitute a waiver or estoppel of
Lessor's right to exercise its remedies for the Default or Breach by Lessee of
any of the terms, covenants or conditions of this Lease.
(c) The consent of Lessor to any assignment or subletting shall not constitute a
consent to any subsequent assignment or subletting by Lessee or to any
subsequent or successive assignment or subletting by the sublessee. However,
Lessor may consent to subsequent sublettings and assignments of the sublease or
any amendments or modifications thereto without notifying Lessee or anyone else
liable on the Lease or sublease and without obtaining their consent, and such
action shall not relieve such persons from liability under this Lease or
sublease.
(d) In the event of any Default or Breach of Lessee's obligations under this
Lease, Lessor may proceed directly against Lessee, any Guarantors or any one
else responsible for the performance of the Lessee's obligations under this
Lease, including the sublessee, without first exhausting Lessor's remedies
against any other person or entity responsible therefor to Lessor, or any
security held by Lessor or Lessee.
(e) Each request for consent to an assignment or subletting shall be in writing,
accompanied by information relevant to Lessor's determination as to the
financial and operational responsibility and appropriateness of the proposed
assignee or sublessee, including but not limited to the intended use and/or
required modification of the Premises, if any, together with a non-refundable
deposit of $1,000 or ten percent (10%) of the current monthly Base Rent,
whichever is greater, as reasonable consideration for Lessor's considering and
processing the request for consent. Lessee agrees to provide Lessor with such
other or additional information and/or documentation as may be reasonably
requested by Lessor.
(f) Any assignee of, or sublessee under, this Lease shall, by reason of
accepting such assignment or entering into such sublease, be deemed, for the
benefit of Lessor, to have assumed and agreed to conform and comply with each
and every term, covenant, condition and obligation herein to be observed or
performed by Lessee during the term of said assignment or sublease, other than
such obligations as are contrary to or inconsistent with provisions of an
assignment or sublease to which Lessor has specifically consented in writing.
(g) The occurrence of a transaction described in Paragraph 12.1 (c) shall give
Lessor the right (but not the obligation) to require that the Security Deposit
be increased to an amount equal to six (6) times the then monthly Base Rent, and
Lessor may make the actual receipt by Lessor of the amount required to establish
such Security Deposit a condition to Lessor's consent to such transaction.
(h) Lessor, as a condition to giving its consent to any assignment or
subletting, may require that the amount and adjustment structure of the
rent payable under this Lease be adjusted to what is then the market value
and/or adjustment structure for property similar to the Premises is then
constituted.
12.3 Additional Terms and Conditions Applicable to Subletting. The
following terms and conditions shall apply to any subletting by Lessee of
all or any part of the Premises and shall be deemed included in all
subleases under this Lease whether or not expressly incorporated therein:
(a) Lessee hereby assigns and transfers to Lessor all of Lessee's interest in
all rentals and income arising from any sublease of all or a portion of the
Premises heretofore or hereafter made by Lessee, and Lessor may collect such
rent and income and apply same toward Lessee's obligations under this Lease;
provided, however, that until a Breach (as defined in Paragraph 13.1) shall
occur in the performance of Lessee's obligations under this Lease, Lessee may,
except as otherwise provided in this Lease, receive, collect and enjoy the rents
accruing under such sublease. Lessor shall not, by reason of this or any other
assignment of such sublease to Lessor, nor by reason of the collection of the
rents from a sublessee, be deemed liable to the sublessee for any failure of
Lessee to perform and comply with any of Lessee's obligations to such sublessee
under such sublease. Lessee hereby irrevocably authorizes and directs any such
sublessee, upon receipt of a written notice from Lessor stating that a Breach
exists in the performance of Lessee's obligations under this Lease, to pay to
Lessor the rents and other charges due and to become due under the sublease.
Sublessee shall rely upon any such statement and request from Lessor and shall
pay such rents and other charges to Lessor without any obligation or right to
inquire as to whether such Breach exists and notwithstanding any notice from or
claim from Lessee to the contrary. Lessee shall have no right or claim against
said sublessee, or, until the Breach has been cured, against Lessor, for any
such rents and other charges so paid by said sublessee to Lessor
(b) In the event of a Breach by Lessee in the performance of its obligations
under this Lease, Lessor, at its option and without any obligation to do so, may
require any sublessee to attorn to Lessor, in which event Lessor shall undertake
the obligations of the sublessor under such sublease from the time of the
exercise of said option to the expiration of such sublease; provided, however,
Lessor shall not be liable for any prepaid rents or security deposit paid by
such sublessee to such sublessor or for any other prior Defaults or Breaches of
such sublessor under such sublease.
(c) Any matter or thing requiring the consent of the sublessor under a sublease
shall also require the consent of Lessor herein.
(d) No sublessee shall further assign or sublet all or any part of the Premises
without Lessor's prior written consent.
(e) Lessor shall deliver a copy of any notice of Default or Breach by Lessee to
the sublessee, who shall have the right to cure the Default of Lessee within the
grace period, if any, specified in such notice. The sublessee shall have a right
of reimbursement and offset from and against Lessee for any such Defaults cured
by the sublessee.
13. Default; Breach; Remedies.
13.1 Default Breach. Lessor and Lessee agree that if an attorney is consulted by
Lessor in connection with a Lessee Default or Breach (as hereinafter defined),
$350.00 is a reasonable minimum sum per such occurrence for legal services and
costs in the preparation and service of a notice of Default, and that Lessor may
include the cost of such services and costs in said notice as rent due and
payable to cure said Default. A "Default" is defined as a failure by the Lessee
to observe, comply with or perform any of the terms, covenants, conditions or
rules applicable to Lessee under this Lease. A "Breach"
PAGE 6
<PAGE>
is defined as the occurrence of any one or more of the following Defaults, and,
where a grace period for cure after notice is specified herein, the failure .by
Lessee to cure such Default prior to the expiration in the applicable grace
period, shall entitle Lessor to pay the remedies set forth in Paragraphs 13.2
and/or 13.3:
(a) The vacating of the Premises without the intention to reoccupy same, or the
abandonment of the Premises.
(b) Except as expressly otherwise provided in this Lease, the failure by Lessee
to make any payment of Base Rent or any other monetary payment required to be
made by Lessee hereunder, whether to Lessor or to a third party, as and when
due, the failure by Lessee to provide Lessor with reasonable evidence of
insurance or surety bond required under this Lease, or the failure of Lessee to
fulfill any obligation under this Lease which endangers or threatens life or
property, where such failure continues for a period of three (3) days following
written notice thereof by or on behalf of Lessor to Lessee.
(c) Except as expressly otherwise provided in this Lease, the failure by Lessee
to provide Lessor with reasonable written evidence (in duly executed original
form, if applicable) of (i) compliance with Applicable Law per Paragraph 6.3,
(ii) the inspection, maintenance and service contracts required under Paragraph
7.1 (b), (iii) the recission of an unauthorized assignment or subletting per
Paragraph 12.1 (b), (iv) a Tenancy Statement per Paragraphs 16 or 37, (v) the
subordination or non-subordination of this Lease per Paragraph 30, (vi) the
guaranty of the performance of Lessee's obligations under this Lease if required
under Paragraphs 1.11 and 37, (vii) the execution of any document requested
under Paragraph 42 (easements), or (viii) any other documentation or information
which Lessor may reasonably require of Lessee under the terms of this Lease,
where any such failure continues for a period of ten (10) days following written
notice by or on behalf of Lessor to Lessee.
(d) A Default by Lessee as to the terms, covenants, conditions or provisions of
this Lease, or of the rules adopted under Paragraph 40 hereof, that are to be
observed, complied with or performed by Lessee, other than those described in
subparagraphs (a), (b) or (c), above, where such Default continues for a period
of thirty (30) days after written notice thereof by or on behalf of Lessor to
Lessee; provided, however, that if the nature of Lessee's Default is such that
more than thirty (30) days are reasonably required for its cure, then it shall
not be deemed to be a Breach of this Lease by Lessee if Lessee commences such
cure within said thirty (30) day period and thereafter diligently prosecutes
such cure to completion.
(e) The occurrence of any of the following events: (i) The making by lessee of
any general arrangement or assignment for the benefit of creditors (ii) Lessee's
becoming a "debtor" as defined in 11 U.S.C. ss.101 or any successor statute
thereto (unless, in the case of a petition filed against Lessee, the same is
dismissed within sixty (60) days); (iii) the appointment of a trustee or
receiver to take possession of substantially all of Lessee's assets located at
the Premises or of Lessee's interest in this Lease, where possession is not
restored to Lessee within thirty (30) days, or (iv) the attachment, execution or
other judicial seizure of substantially all of Lessee's assets located at the
Premises or of Lessee's interest in this Lease, where such seizure is not
discharged within thirty (30) days; provided, however, In the event that any
provision of this subparagraph (e) is contrary to any applicable law, such
provision shag be of no force or effect, and not affect the validly of the
remaining provisions.
(f) The discovery by Lessor that any financial statement given to Lessor by
Lessee or any Guarantor of Lessee's obligations hereunder was materially false.
(g) If the performance of Lessee's obligations under this Lease is guaranteed:
(I) the death of a guarantor, (ii) the termination of a guarantor's liability
with respect to this Lease other than in accordance with the terms of such
guaranty, (iii) a guarantor's becoming insolvent or the subject of a bankruptcy
filing, (iv) a guarantor's refusal to honor the guaranty, or (v) a guarantor's
breach of its guaranty obligation on an anticipatory breach basis, and Lessee's
failure, within sixty (60) days following written notice by or on behalf of
Lessor to Lessee of any such event, to provide Lessor with written alternative
assurance or security, which, when coupled with the then existing resources of
Lessee, equals or exceeds the combined financial resources of Lessee and the
guarantors that existed at the time of execution of this Lease.
13.2 Remedies. If Lessee fails to perform any affirmative duty or obligation of
Lessee under this Lease, within ten (10) days after written notice to Lessee (or
in case of an emergency, without notice) Lessor may at its option (but without
obligation to do so), perform such duty or obligation on Lessee's behalf,
including but not limited to the obtaining of reasonably required bonds,
insurance policies, or governmental licenses, permits or approvals. The costs
and expenses of any such performance by Lessor shall be due and payable by
Lessee to Lessor upon invoice therefor. If any check given to Lessor by Lessee
shall not be honored by the bank upon which it is drawn, Lessor, at its option,
may require all future payments to be made under this Lease by Lessee to be made
only by cashier's check. In the event of a Breach of this Lease by Lessee, as
defined in Paragraph 13.1, with or without further notice or demand, and without
limiting Lessor In the exercise of any right or remedy which Lessor may have by
reason of such Breach, Lessor may
(a) Terminate Lessee's right to possession of the Premises by any lawful means,
in which case this Lease and the term hereof shall terminate and Lessee shall
immediately surrender possession of the Premises to Lessor. In such event Lessor
shall be entitled to recover from Lessee: (i) the worth at the time of the award
of the unpaid rent which had been earned at the time of termination; (ii) the
worth at the time of award of the amount by which the unpaid rent which would
have been earned after termination until the time of award exceeds the amount of
such rental loss that the Lessee proves could have been reasonably avoided;
(iii) the worth at the time of award of the amount by which the unpaid rent for
the balance of the term after the time of award exceeds the amount of such
rental loss that the Lessee proves could be reasonably avoided; and (iv) any
other amount necessary to compensate Lessor for all the detriment proximately
caused by the Lessee's failure to perform its obligations under this Lease or
which in the ordinary course of things would be likely to result therefrom,
including but not limited to the cost of recovering possession of the Premises,
expenses of reletting, including necessary renovation and alteration of the
Premises, reasonable attorneys' fees, and that portion of the leasing commission
paid by Lessor applicable to the unexpired term of this Lease. The worth at the
time of award of the amount referred to in provision (iii) of the prior sentence
shall be computed by discounting such amount at the discount rate of the Federal
Reserve Bank of San Francisco et the time of award plus one percent (1%).
Efforts by Lessor to mitigate damages caused by Lessee's Default or Breach of
this Lease shall not waive Lessor's right to recover damages under this
Paragraph. If termination of this Lease is obtained through the provisional
remedy of unlawful detainer, Lessor shall have the right to recover in such
proceeding the unpaid rent and damages as are recoverable therein, or Lessor may
reserve therein the right to recover all or any part thereof in a separate suit
for such rent and/or damages. If a notice and grace period required under
subparagraphs 13.1(b), (c) or (d) was not previously given, a notice to pay rent
or quit, or to perform or quit, as the case may be, given to Lessee under any
statute authorizing the forfeiture of leases for unlawful detainer shall also
constitute the applicable notice for grace period purposes required by
subparagraphs 13.1 (b), (c) or (d). In such case, the applicable grace period
under subparagraphs 13.1 (b), (c) or (d) and under the unlawful detainer statute
shall run concurrently after the one such statutory notice, and the failure of
Lessee to cure the Default within the greater of the two such grace periods
shall constitute both an unlawful detainer and a Breach of this Lease entitling
Lessor to the remedies provided for in this Lease and/or by said statute.
(b) Continue the Lease and Lessee's right to possession in effect (in California
under California Civil Code Section 1951.4) after Lessee's Breach and
abandonment and recover the rent as it becomes due, provided Lessee has the
right to sublet or assign, subject only to reasonable limitations. See
Paragraphs 12 and 36 for the limitations on assignment and subletting which
limitations Lessee and Lessor agree are reasonable. Acts of maintenance or
preservation, efforts to relet the Premises, or the appointment of a receiver to
protect the Lessor's interest under the Lease, shall not constitute a
termination of the Lessee's right to possession.
(c) Pursue any other remedy now or hereafter available to Lessor under the laws
w judicial decisions of the state wherein the Premises are located.
(d) The expiration or termination of this Lease and/or the termination of
Lessee's right to possession shall not relieve Lessee from liability under any
indemnity provisions of this Lease as to matters occurring or accruing during
the term hereof or by reason of Lessee's occupancy of' the, Premises.
13.3 Inducement Recapture In Event Of Breach. Any agreement by Lessor for free
or abated rent or other charges applicable to the Premises, or for the giving or
paying by Lessor to or for Lessee of any cash or other bonus, inducement or
consideration for Lessee's entering into this Lease, all of which concessions
are hereinafter refined to as "Inducement Provisions," shall be deemed
conditioned upon Lessee's full and faithful performance of all of the terms,
covenants and conditions of this Lease to be performed or observed by Lessee
during the term hereof as the same may be extended. Upon the occurrence of a
Breach of this Lease by Lessee, as defined in Paragraph 13.1, any such
inducement Provision shall automatically be deemed deleted from this Lease and
of no further force or effect, and any rent, other charge, bonus, inducement or
consideration theretofore abated, given or paid by Lessor under such an
Inducement Provision shall be immediately due and payable by Lessee to Lessor,
and recoverable by Lessor as additional rent due under this Lease,
notwithstanding any subsequent cure of said Breach by Lessee. The acceptance by
Lessor of rent or the cure of the Breach which initiated the operation of this
Paragraph shall not be deemed a waiver by Lessor of the provisions of this
Paragraph unless specifically so stated in writing by Lessor at the time of such
acceptance.
13.4 Late Charged Lessee hereby acknowledges that late payment by Lessee to
Lessor of rent and other sums due hereunder will cause Lessor to incur costs not
contemplated by this, Lease, the exact amount of which will be extremely
difficult to ascertain. Such costs include, but are not limited to, processing
and accounting charges, and late charges which may be imposed upon Lessor by the
terms of any ground lease, mortgage or trust deed covering the Premises.
Accordingly, if any installment of rent or any other sum due from Lessee shall
not be received by Lessor or Lessor's designee within five (5) days after such
amount shall be due, then, without any requirement for notice to Lessee, Lessee
shall pay to Lessor a late charge equal to six percent (6%) of such overdue
amount. The parties hereby agree that such late charge represents a fair and
reasonable estimate of the costs Lessor will incur by reason of late payment by
Lessee. Acceptance of such late charge by Lessor shall in no event constitute a
waiver of Lessee's Default or Breach with respect to such overdue amount, nor
prevent Lessor from exercising any of the other rights and remedies granted
hereunder. In the event that a late charge is payable hereunder, whether or not
collected, for three (3) consecutive installments of Base Rent, then
notwithstanding Paragraph 4.1 or any other provision of this Lease to the
contrary, Base Rent shall, at Lessor's option, become due and payable quarterly
in advance.
13.5 Breach by Lessor. Lessor shall not be deemed in breach of this Lease unless
Lessor fails within a reasonable time to perform an obligation required to be
performed by Lessor. For purposes of this Paragraph 13.5, a reasonable time
shall in no event be less than thirty (30) days after receipt by Lessor, and by
the holders of any ground lease, mortgage or deed of trust covering the Premises
whose name and address shall have been furnished Lessee in writing for such
purpose, of written notice specifying wherein such obligation of Lessor has not
been performed; provided, however, that if the nature of Lessor's obligation is
such that more than thirty (30) days after such notice are reasonably required
for its performance, then Lessor shall not be in breach of this Lease if
performance is commenced within such thirty (30) day period and thereafter
diligently pursued to completion.
14. Condemnation. If the Premises or any portion thereof are taken under
the power of eminent domain or sold under the threat of the exercised said
power (all of which are herein called "condemnation"), this Lease shall
terminate as to the part so taken as of the date the condemning authority
takes
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title or possession, whichever first occurs. If more than ten percent (10%) of
the floor area of the Premises or more than twenty-five percent (25%) of the
land area not occupied by any building, is taken by condemnation, Lessee may, at
Lessee's option, to be exercised in writing within ten (10) days after Lessor
shall have given Lessee written notice of such taking (or in the absence of such
notice, within ten (10) days after the condemning authority shall have taken
possession) terminate this Lease as of the date the condemning authority takes
such possession. If Lessee does not terminate this Lease in accordance with the
foregoing, this Lease shall remain in full force and effect as to the portion of
the Premises remaining, except that the Base Rent shall be reduced in the same
proportion as the rentable floor area of the Premises taken bears to the total
rentable floor area of the building located on the Premises. No reduction of
Base Rent shall occur if the only portion of the Premises taken is land on which
there is no building. Any award for the taking of all or any part of the
Premises under the power of eminent domain or any payment made under threat of
the exercise of such power shall be the property of Lessor, whether such award
shall be made as compensation for diminution in value of the leasehold or for
the taking of the fee, or as severance damages provided, however that Lessee
shall be entitled to any compensation separately awarded to Lessee for Lessee's
relocation expenses and/or loss of Lessee's Trade Fixtures. In the event that
this Lease is not terminated by reason of such condemnation, Lessor shall to the
extent of its net severance damages received, over and above the legal and other
expenses incurred by Lessor in the condemnation matter, repair any damage to the
Premises caused by such condemnation, except to the extent that Lessee has been
reimbursed therefor by the condemning authority. Lessee shall be responsible for
the payment of any amount in excess of such net severance damages required to
complete such repair.
<deleted items>
16. Tenancy Statement.
16.1 Each Party (as "Responding Party") shall within ten (10) days after written
notice from the other Party (the "Requesting Party") execute, acknowledge and
deliver to the Requesting Party a statement in writing in form similar to the
then most current "Tenancy Statement" form published by the American Industrial
Real Estate Association, plus such additional information, confirmation and/or
statements as may be reasonably requested by the Requesting Party.
16.2 If Lessor desires to finance, refinance, or sell the Premises, any part
thereof, or the building of which the Premises are a part, Lessee and all
Guarantors of Lessee's performance hereunder shall deliver to any potential
lender or purchaser designated by Lessor such financial statements of Lessee and
such Guarantors as may be reasonably required by such lender or purchaser,
including but not limited to Lessee's financial statements for the past three
(3) years. All such financial statements shall be received by Lessor and such
lender or purchaser in confidence and shall be used only for the purposes herein
set forth.
17. Lessor's Liability. The term "Lessor" as used herein shall mean the owner or
owners at the time in question of the fee title to the Premises, or, if this is
a sublease, of the Lessee's interest in the prior lease. In the event of a
transfer of Lessor's title or interest in the Premises or in this Lease, Lessor
shall deliver to the transferee or assignee (in cash or by credit) any unused
Security Deposit held by Lessor at the time of such transfer or assignment.
Except as provided in Paragraph 15, upon such transfer or assignment and
delivery of the Security Deposit, as aforesaid, the prior Lessor shall be
relieved of all liability with respect to the obligations and/or covenants under
this Lease thereafter to be performed by the Lessor. Subject to the foregoing,
the obligations and/or covenants in this Lease to be performed by the Lessor
shall be binding only upon the Lessor as hereinabove defined.
18. Severability. The invalidity of any provision of this Lease, as determined
by a court of competent jurisdiction, shall in no way affect the validity of any
other provision hereof.
19. Interest on Past Due Obligations. Any monetary payment due Lessor hereunder,
other then late charges, not received by Lessor within thirty (30) days
following the date on which it was due, shall bear interest from the
thirty-first (31st) day after it was due at the rate of 12% per annum, but not
exceeding the maximum rate allowed by law, in addition to the late charge
provided for in Paragraph 13.4.
20. Time of Essence. Time is of the essence with respect to the performance of
all obligations to be performed or observed by the Parties under this Lease.
21: Rent Defined. All monetary obligations of Lessee to Lessor under the
terms of this Lease are deemed to be rent.
22. No Prior or Other Agreements; Broker Disclaimer. This Lease contains all
agreements between the Parties with respect to any matter mentioned herein, and
no other prior or contemporaneous agreement or understanding shall be
effective.. Lessor and Lessee each represents and warrants to the Brokers that
it has made, and is relying solely upon, its own investigation as to the nature,
quality, character and financial responsibility of the other Party to this Lease
and as to the nature, quality and character of the Premises. Brokers have no
responsibility with respect thereto or with respect to any default or breach
hereof by either Party.
23. Notices.
23.1 All notices required or permitted by this Lease shall be in writing and may
be delivered in person (by hand or by messenger or courier service) or may be
sent by regular, certified or registered mail or U.S. Postal Service Express
Mail, with postage prepaid, or by facsimile transmission, and shall be deemed
sufficiently given if served in a manner specified in this Paragraph 23. The
addresses noted adjacent to a Party's signature on this Lease shall be that
Party's address for delivery or mailing of notice purposes. Either Party may by
written notice to the other specify a different address for notice purposes,
except that upon Lessee's taking possession of the Premises, the Premises shall
constitute Lessee's address for the purpose of mailing or delivering notices to
Lessee. A copy of all notices required or permitted to be given to Lessor
hereunder shall be concurrently transmitted to such party or parties at such
addresses as Lessor may from time to time hereafter designate by written notice
to Lessee.
23.2 Any notice sent by registered or certified mail, return receipt requested,
shall be deemed given on the date of delivery shown on the receipt card, or if
no delivery date is shown, the postmark thereon. If sent by regular mail the
notice shall be deemed given forty-eight (48) hours after the same is addressed
as required herein and mailed with postage prepaid. Notices delivered by United
States Express Mail or overnight courier that guarantees next day delivery shall
be deemed given twenty-four (24) hours after delivery of the same to the United
States Postal Service or courier. If any notice is transmitted by facsimile
transmission or similar means, the same shall be deemed served or delivered upon
telephone confirmation of receipt of the transmission thereof, provided a copy
is also delivered via delivery or mail. If notice is received on a Sunday or
legal holiday, it shall be deemed received on the next business day.
24. Waivers. No waiver by Lessor of the Default or Breach of any term, covenant
or condition hereof by Lessee, shall be deemed a waiver of any other term,
covenant or condition hereof, or of any subsequent Default or Breach by Lessee
of the same or of any other term, covenant or condition hereof. Lessor's consent
to, or approval of, any act shall not be deemed to render unnecessary the
obtaining of Lessor's consent to, or approval of, any subsequent or similar act
by Lessee, or be construed as the basis of an estoppel to enforce the provision
or provisions of this Lease requiring such consent. Regardless of Lessor's
knowledge of a Default or Breach at the time of accepting rent, the acceptance
of rent by Lessor shall not be a waiver of any preceding Default or Breach by
Lessee of any provision hereof, other than the failure of Lessee to pay the
particular rent so accepted. Any payment given Lessor by Lessee may be accepted
by Lessor on account of moneys or damages due Lessor, notwithstanding any
qualifying statements or conditions made by Lessee in connection therewith,
which such statements and/or conditions shall be of no force or effect
whatsoever unless specifically agreed to in writing by Lessor at or before the
time of deposit of such payment.
25. Recording. Either Lessor or Lessee shall, upon request of the other,
execute, acknowledge and deliver to the other a short form memorandum of this
Lease for recording purposes. The Party requesting recordation shall be
responsible for payment of any fees or taxes applicable thereto.
26 No Right To Holdover. Lessee has no right to retain possession of the
Premises or any part thereof beyond the expiration or earlier termination of
this Lease.
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27. Cumulative Remedies. No remedy or event hereunder shall be deemed exclusive
but shall, whenever possible, be cumulative with all other remedies at law or in
equity.
28. Covenants and Conditions. All provisions of this Lease to be observed or
performed by Lessee are both covenants and conditions.
29. Binding Effect; Choice of Law. This Lease shall be binding upon the parties,
their personal representatives, successors and assigns and be governed by the
laws of the State in which the Premises are located. Any litigation between the
Parties hereto concerning this Lease shall be initiated in the county in which
the Premises are located.
30. Subordination; Attornment; Non-Disturbance.
30.1 Subordination. This Lease and any Option granted hereby shall be subject
and subordinate to any ground lease, mortgage. deed of trust, or other
hypothecation or security device (collectively, "Security Device"), now or
hereafter placed by Lessor upon the real property of which the Premises are a
part, to any and all advances made on the security thereof, and to all renewals,
modifications, consolidations, replacements and extensions thereof. Lessee
agrees that the Lenders holding any such Security Device shall have no duty,
liability or obligation to perform any of the obligations of Lessor under this
Lease, but that in the event of Lessor's default with respect to any such
obligation, Lessee will give any Lender whose name and address have been
furnished Lessee in writing for such purpose notice of Lessor's default and
allow such Lender thirty (30) days following receipt of such notice for the cure
of said default before invoking any remedies Lessee may have by reason thereof.
If any Lender shall elect to have this Lease and/or any Option granted hereby
superior to the lien of its Security Device and shall give written notice
thereof to Lessee, this Lease and such Options shall be deemed prior to such
Security Device, notwithstanding the relative dates of the documentation or
recordation thereof.
30.2 Attornment. Subject to the non-disturbance provisions of Paragraph 30.3,
Lessee agrees to attorn to a Lender or any other party who acquires ownership of
the Premises by reason of a foreclosure of a Security Device, and that in the
event of such foreclosure, such new owner shall not: (i) be liable for any act
or omission of any prior lessor or with respect to events occurring prior to
acquisition of ownership, (ii) be subject to any offsets or defenses which
Lessee might have against any prior lessor, or (iii) be bound by prepayment of
more than one (1) month's rent.
30.3 Non-Disturbance. With respect to Security Devices entered into by Lessor
after the execution of this Lease, Lessee's subordination of this Lease shall be
subject to receiving assurance (a "non-disturbance agreement") from the Lender
that Lessee's possession and this Lease, including any options to extend the
term hereof, will not be disturbed so long as Lessee is not in Breach hereof and
attorns to the record owner of the Premises.
30.4 Self-Executing. The agreements contained in this Paragraph 30 shall be
effective without the execution of any further documents; provided, however,
that, upon written request from Lessor or a Lender in connection with a sale,
financing or refinancing of the Premises, Lessee and Lessor shall execute such
further writings as may be reasonably required to separately document any such
subordination or non-subordination, attornment and/or non-disturbance agreement
as is provided for herein.
31. Attorney's Fees. It any Party or Broker brings an action or proceeding to
enforce the terms hereof or declare rights hereunder, the Prevailing Party (as
hereafter defined) or Broker in any such proceeding, action, or appeal thereon,
shall be entitled to reasonable attorney's fees. Such fees may be awarded in the
same suit or recovered in a separate suit, whether or not such action or
proceeding is pursued to decision or judgment. The term "Prevailing Party" shall
include, without limitation, a Party or Broker who substantially obtains or
defeats the relief sought, as the case may be, whether; by compromise,
settlement, judgment, or the abandonment by the other Party or Broker of its
claim or defense. The attorney's fees award shall not be computed in accordance
with any court fee schedule, but shall be such as to fully reimburse all
attorney's fees reasonably incurred. Lessor shall be entitled to attorney's
fees, costs and expenses incurred in the preparation and service of notices of
Default and consultations in connection therewith, whether or not a legal action
is subsequently commenced in connection with such Default or resulting Breach.
32. Lessor's Access; Showing Premises; Repairs. Lessor and Lessor's agents shall
have the right to enter the Premises at any time, in the case of an emergency,
and otherwise at reasonable times for the purpose of showing the same to
prospective purchasers, lenders, or lessees, and making such alterations,
repairs, improvements or additions to the Premises or to the building of which
they are a part, as Lessor may reasonably deem necessary. Lessor may at any time
place on or about the Premises or building any ordinary "For Sale" signs and
Lessor may at any time during the last one hundred twenty (120) days of the term
hereof place on or about the Premises any ordinary "For Lease" signs. All such
activities of Lessor shall be without abatement of rent or liability to Lessee.
33. Auctions. Lessee shall not conduct, nor permit to be conducted, either
voluntarily or involuntarily, any auction upon the Premises without first having
obtained Lessor's prior written consent. Notwithstanding anything to the
contrary in this Lease, Lessor shall not be obligated to exercise any standard
of reasonableness in determining whether to grant such consent.
34. Signs. Lessee shall not place any sign upon the Premises, except that Lessee
may, with Lessor's prior written consent, install (but not on the roof) such
signs as are reasonably required to advertise Lessee's own business. The
installation of any sign on the Premises by or for Lessee shall be subject to
the provisions of Paragraph 7 (Maintenance, Repairs, Utility Installations,
Trade Fixtures and Alterations). Unless otherwise expressly agreed herein,
Lessor reserves all rights to the use of the roof and the right to install, and
all revenues frown the installation of, such advertising signs on the Premises,
including the roof, as do not unreasonably interfere with the conduct of
Lessee's business.
35. Termination; Merger. Unless specifically stated otherwise in writing by
Lessor, the voluntary or other surrender of this Lease by Lessee, the mutual
termination or cancellation hereof, or a termination hereof by Lessor for Breach
by Lessee, shall automatically terminate any sublease or lesser estate in the
Premises; provided, however, Lessor shall, in the event of any such surrender,
termination or cancellation, have the option to continue any one or all of any
existing subtenancies. Lessor's failure within ten (10) days following any such
event to make a written election to the contrary by written notice to the holder
of any such lesser interest, shall constitute Lessor's election to have such
event constitute the termination of such interest.
36. Consents.
(a) Except for Paragraph 33 hereof (Auctions) or as otherwise provided herein,
wherever in this Lease the consent of a Party is required to an act by or for
the other Party, such consent shall not be unreasonably withheld or delayed.
Lessor's actual reasonable costs and expenses (including but not limited to
architects', attorneys', engineers' or other consultants' fees) incurred in the
consideration of, or response to, a request by Lessee for any Lessor consent
pertaining to this Lease or the Premises, including but not limited to consents
to an assignment, a subletting or the presence or use of a Hazardous Substance,
practice or storage tank, shall be paid by Lessee to Lessor upon receipt of an
invoice and supporting documentation therefor. Subject to Paragraph 1 2.2(e)
(applicable to assignment or subletting), Lessor may, as a condition to
considering any such request by Lessee, require that Lessee deposit with Lessor
an amount of money (in addition to the Security Deposit held under Paragraph 5)
reasonably calculated by Lessor to represent the cost Lessor will incur in
considering and responding to Lessee's request. Except as otherwise provided,
any unused portion of said deposit shall be refunded to Lessee without interest.
Lessor's consent to any act, assignment of this Lease or subletting of the
Premises by Lessee shall not constitute an acknowledgement that no Default or
Breach by Lessee of this Lease exists, nor shall such consent be deemed a waiver
of any then existing Default or Breach, except as may be otherwise specifically
stated in writing by Lessor at the time of such consent.
(b) All conditions to Lessor's consent authorized by this Lease are acknowledged
by Lessee as being reasonable. The failure to specify herein any particular
condition to Lessor's consent shall not preclude the imposition by Lessor at the
time of consent of such further or other conditions as are then reasonable with
reference to the particular matter for which consent is being given.
<deleted items>
38. Quiet Possession. Upon payment by Lessee of the rent for the Premises and
the observance and performance of all of the covenants, conditions and
provisions on Lessee's part to be observed and performed under this Lease,
Lessee shall have quiet possession of the Premises for the entire term hereof
subject to all of the provisions of this Lease.
39. Options.
39.1 Definition. As used in this Paragraph 39 the word "Option" has the
following meaning: (a) the right to extend the term of this Lease or to renew
this Lease or to extend or renew any lease that Lessee has on other property of
Lessor; (b) the right of first refusal to lease the Premises or the right of
first offer to lease the Premises or the right of first refusal to lease other
property of Lessor or the right of first offer to lease other property of
Lessor; (c) the right to purchase the Premises, or the right of first refusal to
purchase the Premises, or the right of first offer to purchase the Premises, or
the right to purchase other property of Lessor, or the right of first refusal to
purchase other property of Lessor, or the right of first offer to purchase other
property of Lessor.
39.2 Options Personal To Original Lessee. Each Option granted to Lessee in this
Lease is personal to the original Lessee named in Paragraph 1.1 hereof, and
cannot be voluntarily or involuntarily assigned or exercised by any person or
entity other than said original Lessee while the original Lessee is in full and
actual possession of the Premises and without the intention of thereafter
assigning or subletting. The Options, if any, herein granted to Lessee are not
assignable, either as a part of an assignment of this Lease or separately or
apart therefrom, and no Option may be separated from this Lease in any manner,
by reservation or otherwise. //
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39.3 Multiple Options. In the event that Lease has any Multiple Options to
extend or renew this Lease a later Option cannot be exercised unless the prior
Options to extend or renew this Lease have been validly exercised.
39.4 Effect of Default on Options.
(a) Lessee shall have no right to exercise an Option, notwithstanding any
provision in the grant of Option to the contrary: (i) during the perioed
commencing with the giving of any notice of Default under Paragraph 13.1 and
continuing until the noticed Default is cured, or (ii) during the period of time
any monetary obligation due Lessor from Lessee is unpaid (without regard to
whether notice thereof is given Lessee), or (iii) during the time Lessee is in
Breach of this Lease, or (iv) in the event that Lessor has given to Lessee three
(3) or more notices of Default under Paragraph 13.1, whether or not the Defaults
are cured, during the twelve (12) month period immediately preceding the
exercise of the Option.
(b) The period of time within which an Option may be exercised shall not be
extended or enlarged by reason of Lessee's inability to exercise an Option
because of the provisions of Paragraph 39.4(a).
(c) All rights of Lessee under the provisions of an Option shall terminate and
be of no further force or effect, notwithstanding Lessee's due and timely
exercise of the Option, if, after such exercise and during the term of this
Lease, (i) Lessee fails to pay to Lessor a monetary obligation of Lessee for a
period of thirty (30) days after such obligation becomes due (without any
necessity of Lessor to give notice thereof to Lessee), or (ii) Lessor gives to
Lessee three (3) or more notices of Default under Paragraph 13.1 during any
twelve (12) month period, whether or not the Defaults are cured, or (iii) if
Lessee commits a Breach of this Lease.
40. Multiple Buildings. If the Premises are part of a group of buildings
controlled by Lessor, Lessee agrees that it will abide by, keep and observe all
reasonable rules and regulations which Lessor may make from time to time for the
management, safety, care, and cleanliness of the grounds, the parking and
unloading of vehicles and the preservation of good order, as well as for the
convenience of other occupants or tenants of such other buildings and their
invitees, and that Lessee will pay its fair share of common expenses incurred in
connection therewith.
4t. Security Measures. Lessee hereby acknowledges that the rental payable to
Lessor hereunder does not include the cost of guard service or other security
measures, and that Lessor shall have no obligation whatsoever to provide same.
Lessee assumes all responsibility for the protection of the Premises, Lessee, as
agents and Invitees and their property from the acts of third parties.
42. Reservations. Lessor reserves to itself the right, from time to time, to
grant, without the consent or Joinder of Lessee, such easements, rights and
dedications that Lessor deems necessary, and to cause the recordation of parcel
maps and restrictions, so long as such easements, rights, dedications, maps and
restrictions do not unreasonably interfere with the use of the Premises by
Lessee. Lessee agrees to sign any documents reasonably requested by Lessor to
effectuate any such easement rights, dedication, map or restrictions.
43. Performance Under Protest. If at any time a dispute shall arise as to any
amount or sum of money to be paid by one Party to the other under the provisions
hereof, the Party against whom the obligation to pay the money is asserted shall
have the right to make payment "under protest" and such payment shall not be
regarded as a Voluntary payment and there shall survive the right on the part of
said Party to institute suit for recovery of such sum. If it shall be adjudged
that there was no legal obligation on the part of said Party to pay such sum or
any part thereof, said Party shall be entitled to recover such sum or so much
thereof as was not legally required to pay under the provisions of this Lease.
44. Authority. If either Party hereto is a corporation, trust, or general or
limited partnership, each individual executing this Lease on behalf of such
entity represents and warrants that he or she is duly authorized to execute and
deliver this Lease on its behalf. If Lessee is a corporation, trust or
partnership, Lessee shall, within thirty (30) days after request by Lessor,
deliver to Lessor evidence satisfactory to Lessor of such authority
45. Conflict. Any conflict between the printed provisions of this Lease and the
typewritten or handwritten provisions shall be controlled by the typewritten or
handwritten provisions.
46. Offer. Preparation of this Lease by Lessor or Lessor's agent and
submission of same to Lessee shall not be deemed an offer to lease to
Lessee. This Lease is not intended to be binding until executed by all
Parties hereto.
47. Amendments. This Lease may be modified only in writing, signed by the
Parties in interest at the time of the modification. The parties shall amend
this Lease from time to time to reflect any adjustments that are made to the
Base Rent or other rent payable under this Lease. As long as they do not
materially change Lessee's obligations hereunder, Lessee agrees to make such
reasonable non-monetary modifications to this Lease as may be reasonably
required by an Institutional, insurance company, or pension plan Lender in
connection with the obtaining of normal financing or refinancing of the property
of which the Premises are a part.
48. Multiple Parties. Except as otherwise expressly provided herein, if
more than one person or entity is named herein as either Lessor or Lessee,
the obligations of Such Multiple Parties shall be the joint and several
responsibility of all persons or entities named herein as such Lessor or
Lessee.
LESSOR AND LESSEE HAVE CAREFULLY READ AND REVIEWED THIS LEASE AND EACH TERM AND
PROVISION CONTAINED HEREIN, AND BY THE EXECUTION OF THIS LEASE SHOW THEIR
INFORMED AND VOLUNTARY CONSENT THERETO. THE PARTIES HEREBY AGREE THAT, AT THE
TIME THIS LEASE IS EXECUTED, THE TERMS OF THIS LEASE ARE COMMERCIALLY REASONABLE
AND EFFECTUATE THE INTENT AND PURPOSE OF LESSOR AND LESSEE WITH RESPECT TO THE
PREMISES.
IF THIS LEASE HAS BEEN FILLED IN, IT HAS BEEN PREPARED FOR SUBMISSION TO YOUR
ATTORNEY FOR HIS APPROVAL. FURTHER, - EXPERTS SHOULD BE CONSULTED TO EVALUATE
THE CONDITION OF THE PROPERTY AS TO THE POSSIBLE PRESENCE OF ASBESTOS, STORAGE
TANKS OR HAZARDOUS SUBSTANCES. NO REPRESENTATION OR RECOMMENDATION IS MADE BY
THE AMERICAN INDUSTRIAL REAL ESTATE ASSOCIATION OR BY THE REAL ESTATE BROKER(S)
OR THEIR AGENTS OR EMPLOYEES AS TO THE LEGAL SUFFICIENCY, LEGAL EFFECT OR TAX
CONSEQUENCES OF THIS LEASE OR THE TRANSACTION TO WHICH IT RELATES; THE PARTIES
SHALL RELY SOLELY UPON THE ADVICE OF THEIR OWN COUNSEL AS TO THE LEGAL AND TAX
CONSEQUENCES OF THIS LEASE. IF THE SUBJECT PROPERTY IS LOCATED IN A STATE OTHER
THAN CALIFORNIA, AN ATTORNEY FROM THE STATE WHERE THE PROPERTY IS LOCATED SHOULD
BE CONSULTED.
The parties hereto have executed this Lease at the place on the dates specified
above by their respective signatures.
Executed at Paris
on 3/7/98
by LESSOR: Reza Zandian
PO Box 5506
Irvine, CA 92716
Executed at Santa Maria, California
on 2-16-98
LESSEE: Saba Petroleum Company
A. Delaware Corporation
By
Name Printed: Ilyas Chaudhary
The: Chief Executive Officer
3201 Airpark Drive, Suite 201
Santa Maria, CA 93455
(805)347-8700
(805)347-1072
PAGE 10
<PAGE>
OFFICE / INDUSTRIAL LEASE ADDENDUM
EFFECT OF THIS ADDENDUM
This addendum to the office / industrial lease ("Lease"), dated this 9th day of
January, 1998, between Reza Zandian ("Lessor") and Saba Petroleum Company
("Lessee"), relating to the real property located at 17526 Von Karman Avenue,
Suite 200, Irvine, California ("Premises"), shall constitute additional
agreements between the parties and shall provide Lessee with notice of certain
conditions which may affect Lessee's use and occupation of the Premises.
1.3 Term of the Lease.
This paragraph shall replace paragraph 1.3 of the original Lease document. The
Premises will be leased to Lessee, commencing on January 9, 1998, ("Commencement
Date") on a "month-to-month" rental basis. This month to month lease may be
canceled by Lessee at any time or by Lessor only after September 30, 1998, by
providing written notice, thirty (30) days prior to the date that the party
wishes to terminate the lease. However, this lease may be canceled by Lessor at
any time (a) the City of Irvine mandates that Lessee vacate the premises, (b)
Lessor is required to make repairs to the Premises which cannot be commenced
until Lessee vacates the Premises, or (c) if Lessee fails to pay rent due to
Lessor in a timely manner. (See paragraph 3 of the Lease for further
provisions.)
1
NOTIFICATION OF CONDITION OF PREMISES
49. Lessor Wishes to Inform Lessee of the Following:
A) Excluding the portion of the premises leased hereunder, certain
portions of the real property located at 17526 Von Karman Avenue, Suite 200,
Irvine, California, have not been granted building and/or occupancy permits by
the City of Irvine.
B) The City of Irvine has issued a notice that certain portions of the
real property located at 17526 Von Karman Avenue, Suite 200, Irvine, California,
excluding the portion of the premises leased hereunder, are unsafe and that the
City of Irvine may take legal action to vacate any and all occupants of the
Premises. Such remedial action, if taken by the City of Irvine, may negatively
affect Lessee's quiet enjoyment of the Premises.
Lessor does not have a permit for the mezzanine area of the Premises.
Consequently, it is possible that Lessor may be required to destroy the
mezzanine area of the Premises to comply with Irvine City regulations. Any such
construction, demolition or repair may adversely affect Lessee's quiet use and
enjoyment of the Premises.
50. BASE RENT
The base rent of $ 1351.00 per month shall include all utilities and association
dues, except for telephone service. All telephone service(s) and janitorial
service(s) shall be paid by Lessee.
51. PARKING
Lessor shall provide eight (8) reserved parking spaces, free for the Lease term,
subject to Community Association and/or management company's approval.
52. UTILITIES
Lessor shall be responsible for all utilities, with the exception of telephone
service. All telephone service(s) shall be paid by Lessee.
53. LESSOR'S OBLIGATION
Lessor shall be responsible for repairs and maintenance of the Premises,
including plumbing, heating, air conditioning, electrical, lighting (except for
light bulbs), fire extinguishing system, landscaping, driveways, parking lot and
sidewalks. Lessee shall be responsible for replacing all light bulbs and/or
flourescent bulbs.
54. TENANT IMPROVEMENTS
Lessee shall accept the Premises in its current condition, subject to the
following conditions:
(a) All mechanical, electrical, HVAC systems, and plumbing systems are to be in
good working order.
(b) Any and all notices regarding the condition of the property issued by the
City of Irvine, including but not limited to that certain prior "Notice of
Dangerous Condition" and "Notice to Vacate."
55. OPERATING EXPENSES
Lessee shall not be responsible for any pass through of operating expenses
during its Lease term, including but not limited to common area maintenance
expenses, or Lessor's capital improvements to the Premises.
56. SIGNAGE
Lessee shall, at Lessee's expense, have the right to place a sign at its
entrance to the Premises, subject to Association approval and guidelines.
57. HVAC (HEATING, VENTILATING AND AIR CONDITIONING)
Lessor shall supply HVAC, per industry standards, pertaining to a hill
service gross lease. The standard hours of operation shall be 8:00 a.m. to
6:00 p.m. Monday through Friday and 9:00 a.m. to 1:00 p.m. on Saturday,
except for national holidays. Lessor reserves the right to place a timer on
the thermostats.
I ACCEPT AND AGREE TO THE FOREGOING:
Date 3/7/98 Reza Zandian (Lessor)
Date:2-16-98 Saba Petroleum Company (Lessee)
Exhibit 10.60
FINDER agreement
This FINDER AGREEMENT ("Agreement") is entered into this 31st day of
December, 1997, by and between Saba Petroleum Company, a Delaware
corporation ("Company") and Aberfoyle Capital Limited, an Irish corporation
("Finder"). RECITALS
A. Finder has introduced Company to RGC International Investors, LDC
("Investor"). Company and Investor have executed a Securities Purchase
Agreement, of even date herewith, ("Securities Purchase Agreement") pursuant to
which Investor has purchased from Company, and Company has sold to Investor,
shares of Company Series A Convertible Preferred Stock, par value $0.001 per
share, and Warrants to purchase shares of Company Common Stock, par value $0.001
per share ("Common Stock"), and pursuant to which Company and Investor have
executed certain other agreements, instruments and documents (collectively, the
"Financing").
B. As compensation for Finder's services in connection with the
Financing, and pursuant to the Final Summary of Offering dated December 15,
1997, Company has agreed to pay to Finder a placement fee as set forth herein,
and to grant Finder certain rights with respect to certain future transactions
of Company, also as set forth herein.
AGREEMENT
NOW THEREFORE, in consideration of the mutual covenants contained herein,
and for other good and valuable consideration, the receipt and adequacy of
which are hereby acknowledged, the parties hereto agree as follows:
1. Placement Fee.
As consideration for Finder's services in connection with the
Financing, Company is delivering herewith the following (the "Placement Fee"):
1.1 an executed copy of the Stock Purchase Warrant (Finder's Warrant),
of even date herewith, in the form attached as Exhibit A (the "Warrants"),
pursuant to which Finder shall have the right to purchase 44,944 shares of
Common Stock, as adjusted therein (the "Warrant Shares" and with the
Warrants, the "Securities").
1.2 a wire transfer in the amount of Four Hundred Thousand Dollars
($400,000) to the account of Finder listed in Exhibit B, the receipt of
which is hereby acknowledged by Finder.
2. Exclusive Rights.
Company covenants that from the date hereof until December 15, 1998,
Company will not consummate an additional financing with Investor without
payment to Finder upon such consummation of an additional Placement Fee,
calculated in the same proportion as the current Placement Fee bears to the
Financing; viz, a cash payment of 4% of the funded amount, and warrants to
purchase 4% of the shares of Common Stock which would be issuable to Investor
upon conversion of the preferred stock issued, if any, at 120% of the
then-current Market Price (as defined in the Warrant) for such Common Stock as
of the closing date of such additional financing).
3. Finders Representations and Warranties
Finder represents and warrants to Company as follows:
3.1 Broker/Dealer Status. Finder is either (i) duly registered as a
broker/dealer under the Securities Exchange Act of 1934, as amended, and any
applicable state Blue Sky laws, or (ii) exempt from such registration as a
result of the type and extent of services rendered in connection with the
Financing.
3.2 Investment Intent. Finder is purchasing the Warrants with for its
own account for investment only and not with a view towards the sale or
distribution thereof, except pursuant to a registration statement filed with and
declared effective by the Securities and Exchange Commission, or in a
transaction exempt from registration under the Securities Act of 1933, as
amended (the "Act").
3.3 Accredited Investor Status. Finder is an "accredited investor" as that
term is defined in Rule 5019(a) of Regulation D promulgated under the Act.
--------------------------
3.4 Reliance on Exemptions. Finder understands that the Securities are
being offered and sold to it in reliance upon specific exemptions from the
registration requirements of United States federal and state securities laws and
that the Company is relying upon the truth and accuracy of, and Finder
compliance with, the representations, warranties, agreements, acknowledgments
and understandings of the Finder set forth herein in order to determine the
availability of such exemptions and the eligibility of the Finder to acquire the
Securities.
3.5 Information. Finder and its advisors, if any, have been furnished
with all materials relating to the business, finances and operations of Company
and materials relating to the offer and sale of the Securities which have been
requested by Finder or its advisors. Finder and its advisors, if any, have been
afforded the opportunity to ask questions of Company and have received what
Finder believes to be satisfactory answers to any such inquiries. Finder
understands that its investment in the Securities involves a significant degree
of risk.
3.6 Governmental Review. Finder understands that no United States federal
or state agency or any other government or governmental agency has passed
upon or made any recommendation or endorsement of -------------------- the
Securities.
3.7 Transfer or Resale. Finder understands that (i) the Securities have
not been and are not being registered under the Act or any applicable state
securities laws, and may not be transferred unless (a) subsequently included in
an effective registration statement thereunder, or (b) Finder shall have
delivered to the Company an opinion of counsel (which counsel and the form,
substance and scope of such opinion shall be acceptable to the Company in its
reasonable judgment) to the effect that the Securities to be sold or transferred
may be sold or transferred pursuant to an exemption from such registration (c)
sold or transferred to an "affiliate" (as defined under Rule 144) of the Buyer,
or (d) sold pursuant to Rule 144 promulgated under the Act (or a successor
rule); (ii) any sale of such Securities made in reliance on Rule 144 may be made
only in accordance with the terms of said Rule and further, if said Rule is not
applicable, any resale of such Securities under circumstances in which the
seller (or the person through whom the sale is made) may be deemed to be an
underwriter (as that term is defined in the Act) may require compliance with
some other exemption under the Act or the rules and regulations of the SEC
thereunder; and (iii) neither the Company nor any other person is under any
obligation to register such Securities under the Act or any state securities
laws or to comply with the terms and conditions of any exemption thereunder.
Finder further understands and acknowledges that the Warrants and Warrant Shares
may be transferred only in whole and only with the prior written consent of
Company, which consent will not be unreasonably withheld.
3.8 Legends. Finder understands that the Warrants and Warrant Shares,
may bear a restrictive legend in substantially the following form (and a
stop-transfer order may be placed against transfer of the certificates for such
Securities):
"The securities represented by this certificate have not been
registered under the Securities Act of 1933, as amended. The securities
have been acquired for investment any may not be sold, transferred or
assigned in the absence of an effective registration statement for the
securities under said Act, or an opinion of counsel, in form, substance
and scope reasonably acceptable to the Company, that registration is
not required under said Act or unless sold pursuant to Rule 144 under
said Act. In addition, transfer of these securities is subject to
limitations as set forth in the Finder Agreement dated as of December
31, 1997."
The legend set forth above shall be removed and Company shall issue a
certificate without such legend to the holder of any Security upon which it is
stamped, if, unless otherwise required by applicable state securities laws, (a)
such Security is registered for sale under an effective registration statement
filed under the Act, or (b) such holder provides the Company with an opinion of
counsel (which counsel and the form, substance and scope of such opinion shall
be acceptable to the Company in its reasonable judgment), to the effect that a
public sale or transfer of such Security may be made without registration under
the Act and such sale or transfer is effected or (c) such holder provides
Company with reasonable assurances that such Security can be sold pursuant to
Rule 144 under the Act (or a successor rule thereto) without any restriction as
to the number of Securities acquired as of a particular date that can then be
immediately sold. Finder agrees to sell all Securities, including those
represented by a certificate(s) from which the legend has been removed, in
compliance with applicable prospectus delivery requirements, if any.
4. Registration Rights with Respect to Warrant Shares
Company will include all of the Warrant Shares in the registration
statement required to be filed by Company in connection with the Securities
Purchase Agreement. Finder will provide customary indemnification to Company for
any information provided by Finder and included by Company in such registration
statement. Finder shall have no rights under the Registration Rights Agreement,
dated as of December 31, 1997, by and among Company and the parties signatory
thereto.
5. Miscellaneous
5.1 Notices. All notices and other communications hereunder shall be in
writing and shall be deemed given on the date of delivery, if delivered
personally or faxed during normal business hours of the recipient, or three days
after deposit in the U.S. Mail, postage prepaid, if mailed by registered or
certified mail (return receipt requested) as follows:
(a) if to Company:
Saba Petroleum Company
3201 Airpark Drive, Suite 201
Santa Maria, CA 93455
Attention: General Counsel
(b) if to Finder
Aberfoyle Capital Limited
c/o Loughran & Co.
38 Hertford Street
London W1Y 7TG England
Attention: Mr. Pierce Loughran
or to such other Persons or addresses as may be designated in writing by the
party to receive such notice as provided above.
5.2 Choice of Law; Jury Trial
(a) THIS AGREEMENT SHALL BE DEEMED TO BE MADE IN AND IN ALL RESPECTS
SHALL BE INTERPRETED, CONSTRUED AND GOVERNED BY AND IN ACCORDANCE WITH THE LAW
OF THE STATE OF CALIFORNIA WITHOUT REGARD TO THE CONFLICT OF LAW PRINCIPLES
THEREOF. The parties hereby irrevocably submit to the jurisdiction of the courts
of the State of California located in the County of Santa Barbara ("State
Court") and the Federal courts of the United States of America located in the
Central District of the State of California ("Federal Court") solely in respect
of the interpretation and enforcement of the provisions of this Agreement and of
the documents referred to in this Agreement, and in respect of the transactions
contemplated hereby, and hereby waive, and agree not to assert, as a defense in
any action, suit or proceeding for the interpretation or enforcement hereof or
of any such document, that it is not subject thereto or that such action, suit
or proceeding may not be brought or is not maintainable in said courts or that
the venue thereof may not be appropriate or that this Agreement or any such
document may not be enforced in or by such courts, and the parties hereto
irrevocably agree that all claims with respect to such action or proceeding
shall be heard and determined in such a State Court or Federal Court. The
parties hereby consent to and grant any such court jurisdiction over the person
of such parties and over the subject matter of such dispute and agree that
mailing of process or other papers in connection with any such action or
proceeding in the manner provided herein in such other manner as may be
permitted by applicable law, shall be valid and sufficient service thereof.
(b) The parties agree that irreparable damage would occur and that the
parties would not have any adequate remedy at law in the event that any of the
provisions of this Agreement were not performed in accordance with their
specific terms or were otherwise breached. It is accordingly agreed that the
parties are entitled to an injunction or injunctions to prevent breaches of this
Agreement and to enforce specifically the terms and provisions of this Agreement
in any Federal Court or State Court, this being in addition to any other remedy
to which they are entitled at law or in equity.
(c) EACH PARTY ACKNOWLEDGES AND AGREES THAT ANY CONTROVERSY WHICH MAY
ARISE UNDER THIS AGREEMENT IS LIKELY TO INVOLVE COMPLICATED AND DIFFICULT
ISSUES, AND THEREFORE EACH SUCH PARTY HEREBY IRREVOCABLY AND UNCONDITIONALLY
WAIVES ANY RIGHT SUCH PARTY MAY HAVE TO A TRIAL BY JURY AND TO PUNITIVE DAMAGES
IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF OR RELATING
TO THIS AGREEMENT OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. EACH PARTY
CERTIFIES AND ACKNOWLEDGES THAT (I) NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY
OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD
NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER, (II) EACH
SUCH PARTY UNDERSTANDS AND HAS CONSIDERED THE IMPLICATIONS OF THIS WAIVER, (III)
EACH SUCH PARTY MAKES THIS WAIVER VOLUNTARILY, AND (IV) EACH SUCH PARTY HAS BEEN
INDUCED TO ENTER INTO THIS AGREEMENT BY, AMONG OTHER THINGS, THE INITIAL WAIVERS
AND CERTIFICATIONS IN THIS SECTION.
5.3. Counterparts. This Agreement may be executed in two or more
counterparts, each of which being deemed an original, but all of which
together shall constitute one and the same agreement. ------------
5.4 Entire Agreement. This Agreement, together with the exhibits
hereto, embodies the entire agreement and understanding of the parties in
respect of the subject matter contained herein and, with respect to Company and
Finder only, supersedes all prior agreements and understandings among them with
respect to such subject matter, including without limitation the Final Summary
of Offering, dated December 15, 1997.
5.5 No Personal Liability. This Agreement shall not create or be
deemed to create any personal liability or obligation on the part of any
direct or indirect stockholder of Finder or Company, or any of
---------------------- their respective officers, directors, employees,
agents or representatives.
5.6 Expenses. All costs and expenses incurred in connection with this
Agreement, the Financing, and the other transactions contemplated hereby
shall be paid by the party incurring such expenses. ---------
5.7 Termination. This Agreement shall terminate and be of no further
force and effect on December 15, 1998. -----------
[signatures follow]
<PAGE>
IN WITNESS WHEREOF, the parties have caused this Agreement to be executed as of
the date first above written.
<TABLE>
<S> <C>
COMPANY FINDER
Saba Petroleum Company Aberfoyle Capital Limited
By: ________________________ By: ________________________
Name: ________________________ Name: ________________________
Title: ________________________ Title: ________________________
</TABLE>
EA973640.038/10+
Exhibit 10.61
485798.001(B&F)
<PAGE>
THIS WARRANT AND THE SHARES ISSUABLE UPON THE EXERCISE OF THIS WARRANT
HAVE NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED.
NEITHER THIS WARRANT NOR ANY OF SUCH SHARES MAY BE SOLD, OFFERED FOR
SALE, ASSIGNED, TRANSFERRED, OR OTHERWISE DISPOSED OF IN THE ABSENCE OF
REGISTRATION UNDER SUCH ACT OR AN OPINION OF COUNSEL THAT REGISTRATION
IS NOT REQUIRED UNDER SUCH ACT OR UNLESS SOLD PURSUANT TO RULE 144
UNDER SUCH ACT. ANY SUCH SALE, ASSIGNMENT OR TRANSFER MUST ALSO COMPLY
WITH APPLICABLE STATE SECURITIES LAWS. IN ADDITION, THIS WARRANT IS
SUBJECT TO LIMITATIONS AS SET FORTH IN THE FINDER AGREEENT DATED AS OF
DECEMBER 31, 1997.
Right to
Purchase
44,944
Shares of
Common Stock, par value $.001 per share
STOCK PURCHASE WARRANT (FINDER WARRANT)
THIS CERTIFIES THAT, for value received, ABERFOYLE CAPITAL LIMITED, is
entitled to purchase from SABA PETROLEUM COMPANY, a Delaware corporation (the
"Company"), at any time or from time to time during the period specified in
Paragraph 2 hereof, Forty-four Thousand, Nine Hundred Forty-four (44,944) fully
paid and nonassessable shares of the Company's Common Stock, par value $.001 per
share (the "Common Stock"), at an exercise price of $10.68 per share (the
AExercise Price@). The term "Warrant Shares," as used herein, refers to the
shares of Common Stock purchasable hereunder. The Warrant Shares and the
Exercise Price are subject to adjustment as provided in Paragraph 4 hereof. The
term Warrants means this Warrant and the other warrants issued or to be issued
pursuant to that certain Securities Purchase Agreement dated December 31, 1997,
by and among the Company and the Buyers listed on the execution page thereof
(the "Securities Purchase Agreement").
This Warrant is subject to the following terms, provisions, and
conditions:
<PAGE>
-283-
1. Manner of Exercise; Issuance of Certificates; Payment for Shares.
Subject to the provisions hereof, this Warrant may be exercised by the holder
hereof, in whole or in part, by the surrender of this Warrant, together with a
completed exercise agreement in the form attached hereto (the "Exercise
Agreement"), to the Company during normal business hours on any business day at
the Company's principal executive offices (or such other office or agency of the
Company as it may designate by notice to the holder hereof), and upon (i)
payment to the Company in cash, by certified or official bank check or by wire
transfer for the account of the Company of the Exercise Price for the Warrant
Shares specified in the Exercise Agreement or (ii) if the resale of the Warrant
Shares by the holder is not then registered pursuant to an effective
registration statement under the Securities Act of 1933, as amended (the
ASecurities Act@), delivery to the Company of a written notice of an election to
effect a ACashless Exercise@ (as defined in Section 11(c) below) for the Warrant
Shares specified in the Exercise Agreement. The Warrant Shares so purchased
shall be deemed to be issued to the holder hereof or such holder's designee, as
the record owner of such shares, as of the close of business on the date on
which this Warrant shall have been surrendered, the completed Exercise Agreement
shall have been delivered, and payment shall have been made for such shares as
set forth above. Certificates for the Warrant Shares so purchased, representing
the aggregate number of shares specified in the Exercise Agreement, shall be
delivered to the holder hereof within a reasonable time, not exceeding three (3)
business days, after this Warrant shall have been so exercised. The certificates
so delivered shall be in such denominations as may be requested by the holder
hereof and shall be registered in the name of such holder or such other name as
shall be designated by such holder. If this Warrant shall have been exercised
only in part, then, unless this Warrant has expired, the Company shall, at its
expense, at the time of delivery of such certificates, deliver to the holder a
new Warrant representing the number of shares with respect to which this Warrant
shall not then have been exercised.
Notwithstanding anything in this Warrant to the contrary, in
no event shall the Holder of this Warrant be entitled to exercise a number of
Warrants (or portions thereof) in excess of the number of Warrants (or portions
thereof) upon exercise of which the sum of (i) the number of shares of Common
Stock beneficially owned by the Holder and its affiliates (other than shares of
Common Stock which may be deemed beneficially owned through the ownership of the
unexercised Warrants and unconverted shares of Series A Preferred Stock (as
defined in the Securities Purchase Agreement) and (ii) the number of shares of
Common Stock issuable upon exercise of the Warrants (or portions thereof) with
respect to which the determination described herein is being made, would result
in beneficial ownership by the Holder and its affiliates of more than 4.9% of
the outstanding shares of Common Stock. For purposes of the immediately
preceding sentence, (a) beneficial ownership shall be determined in accordance
with Section 13(d) of the Securities Exchange Act of 1934, as amended, and
Regulation 13D-G thereunder, except as otherwise provided in clause (i) hereof
and (b) the holder of this Warrant may waive the limitations set forth therein
by written notice to the Company upon not less than sixty-one (61) days prior
notice (with such waiver taking effect only upon the expiration of such 61-day
notice period).
2. Period of Exercise. This Warrant is exercisable at any time or from
time to time on or after the date on which this Warrant is issued and delivered
pursuant to the terms of the Finder Agreement and before 5:00 p.m., New York
City time on the third (3rd) anniversary of the date of issuance (the "Exercise
Period").
3. Certain Agreements of the Company. The Company hereby covenants and
agrees as follows:
(a) Shares to be Fully Paid. All Warrant Shares will, upon issuance in
accordance with the terms of this Warrant, be validly issued, fully paid,
and nonassessable and free from all taxes, liens, -----------------------
and charges with respect to the issue thereof.
(b) Reservation of Shares. During the Exercise Period, the Company
shall at all times have authorized, and reserved for the purpose of
issuance upon exercise of this Warrant, a sufficient number
--------------------- of shares of Common Stock to provide for the exercise
of this Warrant.
(c) Listing. The Company shall promptly secure the listing of
the shares of Common Stock issuable upon exercise of the Warrant upon each
national securities exchange or automated quotation system, if any, upon which
shares of Common Stock are then listed (subject to official notice of issuance
upon exercise of this Warrant) and shall maintain, so long as any other shares
of Common Stock shall be so listed, such listing of all shares of Common Stock
from time to time issuable upon the exercise of this Warrant; and the Company
shall so list on each national securities exchange or automated quotation
system, as the case may be, and shall maintain such listing of, any other shares
of capital stock of the Company issuable upon the exercise of this Warrant if
and so long as any shares of the same class shall be listed on such national
securities exchange or automated quotation system.
(d) Certain Actions Prohibited. The Company will not, by
amendment of its charter or through any reorganization, transfer of assets,
consolidation, merger, dissolution, issue or sale of securities, or any other
voluntary action, avoid or seek to avoid the observance or performance of any of
the terms to be observed or performed by it hereunder, but will at all times in
good faith assist in the carrying out of all the provisions of this Warrant and
in the taking of all such action as may reasonably be requested by the holder of
this Warrant in order to protect the exercise privilege of the holder of this
Warrant against dilution or other impairment, consistent with the tenor and
purpose of this Warrant. Without limiting the generality of the foregoing, the
Company (i) will not increase the par value of any shares of Common Stock
receivable upon the exercise of this Warrant above the Exercise Price then in
effect, and (ii) will take all such actions as may be necessary or appropriate
in order that the Company may validly and legally issue fully paid and
nonassessable shares of Common Stock upon the exercise of this Warrant.
(e) Successors and Assigns. This Warrant will be binding upon any
entity succeeding to the Company by merger, consolidation, or acquisition
of all or substantially all the Company's assets. ----------------------
4. Antidilution Provisions. During the Exercise Period, the Exercise
Price and the number of Warrant Shares shall be subject to
adjustment from time to time as provided in this Paragraph 4.
-----------------------
In the event that any adjustment of the Exercise Price as required
herein results in a fraction of a cent, such Exercise Price shall be rounded up
to the nearest cent.
(a) Adjustment of Exercise Price and Number of Shares upon
Issuance of Common Stock. Except as otherwise provided in Paragraphs 4(c) and
4(e) hereof, if and whenever on or after the date of issuance of this Warrant,
the Company issues or sells, or in accordance with Paragraph 4(b) hereof is
deemed to have issued or sold, any shares of Common Stock for no consideration
or for a consideration per share (before deduction of reasonable expenses or
commissions or underwriting discounts or allowances in connection therewith)
less than the Market Price (as hereinafter defined) on the date of issuance (a
"Dilutive Issuance"), then immediately upon the Dilutive Issuance, the Exercise
Price will be reduced to a price determined by multiplying the Exercise Price in
effect immediately prior to the Dilutive Issuance by a fraction, (i) the
numerator of which is an amount equal to the sum of (x) the number of shares of
Common Stock actually outstanding immediately prior to the Dilutive Issuance,
plus (y) the quotient of the aggregate consideration, calculated as set forth in
Paragraph 4(b) hereof, received by the Company upon such Dilutive Issuance
divided by the Market Price in effect immediately prior to the Dilutive
Issuance, and (ii) the denominator of which is the total number of shares of
Common Stock Deemed Outstanding (as defined below) immediately after the
Dilutive Issuance.
(b) Effect on Exercise Price of Certain Events. For purposes of
determining the adjusted Exercise Price under Paragraph 4(a) hereof, the
following will be applicable: ------------------------------------------
(i) Issuance of Rights or Options. If the Company in any manner
issues or grants any warrants, rights or options, whether or not
immediately exercisable, to subscribe for or to
-----------------------------
purchase Common Stock or other securities convertible into or exchangeable for
Common Stock ("Convertible Securities") (such warrants, rights and options to
purchase Common Stock or Convertible Securities are hereinafter referred to as
"Options") and the price per share for which Common Stock is issuable upon the
exercise of such Options is less than the Market Price on the date of issuance
or grant of such Options, then the maximum total number of shares of Common
Stock issuable upon the exercise of all such Options will, as of the date of the
issuance or grant of such Options, be deemed to be outstanding and to have been
issued and sold by the Company for such price per share. For purposes of the
preceding sentence, the "price per share for which Common Stock is issuable upon
the exercise of such Options" is determined by dividing (i) the total amount, if
any, received or receivable by the Company as consideration for the issuance or
granting of all such Options, plus the minimum aggregate amount of additional
consideration, if any, payable to the Company upon the exercise of all such
Options, plus, in the case of Convertible Securities issuable upon the exercise
of such Options, the minimum aggregate amount of additional consideration
payable upon the conversion or exchange thereof at the time such Convertible
Securities first become convertible or exchangeable, by (ii) the maximum total
number of shares of Common Stock issuable upon the exercise of all such Options
(assuming full conversion of Convertible Securities, if applicable). No further
adjustment to the Exercise Price will be made upon the actual issuance of such
Common Stock upon the exercise of such Options or upon the conversion or
exchange of Convertible Securities issuable upon exercise of such Options.
(ii) Issuance of Convertible Securities. If the Company in any manner
issues or sells any Convertible Securities, whether or not immediately
convertible (other than where the same are
---------------------------------- issuable upon the exercise of Options)
and the price per share for which Common Stock is issuable upon such
conversion or exchange is less than the Market Price on the date of
issuance, then the maximum total number of shares of Common Stock issuable
upon the conversion or exchange of all such Convertible Securities will, as
of the date of the issuance of such Convertible Securities, be deemed to be
outstanding and to have been issued and sold by the Company for such price
per share. For the purposes of the preceding sentence, the "price per share
for which Common Stock is issuable upon such conversion or exchange" is
determined by dividing (i) the total amount, if any, received or receivable
by the Company as consideration for the issuance or sale of all such
Convertible Securities, plus the minimum aggregate amount of additional
consideration, if any, payable to the Company upon the conversion or
exchange thereof at the time such Convertible Securities first become
convertible or exchangeable, by (ii) the maximum total number of shares of
Common Stock issuable upon the conversion or exchange of all such
Convertible Securities. No further adjustment to the Exercise Price will be
made upon the actual issuance of such Common Stock upon conversion or
exchange of such Convertible Securities.
(iii) Change in Option Price or Conversion Rate. If there is a change
at any time in (i) the amount of additional consideration payable to the
Company upon the exercise of any Options;
----------------------------------------- (ii) the amount of additional
consideration, if any, payable to the Company upon the conversion or
exchange of any Convertible Securities; or (iii) the rate at which any
Convertible Securities are convertible into or exchangeable for Common
Stock (other than under or by reason of provisions designed to protect
against dilution), the Exercise Price in effect at the time of such change
will be readjusted to the Exercise Price which would have been in effect at
such time had such Options or Convertible Securities still outstanding
provided for such changed additional consideration or changed conversion
rate, as the case may be, at the time initially granted, issued or sold.
(iv) Treatment of Expired Options and Unexercised Convertible
Securities. If, in any case, the total number of shares of Common Stock
issuable upon exercise of any Option or upon
-----------------------------------------------------------------------
conversion or exchange of any Convertible Securities is not, in fact,
issued and the rights to exercise such Option or to convert or exchange
such Convertible Securities shall have expired or terminated, the Exercise
Price then in effect will be readjusted to the Exercise Price which would
have been in effect at the time of such expiration or termination had such
Option or Convertible Securities, to the extent outstanding immediately
prior to such expiration or termination (other than in respect of the
actual number of shares of Common Stock issued upon exercise or conversion
thereof), never been issued.
(v) Calculation of Consideration Received. If any Common Stock,
Options or Convertible Securities are issued, granted or sold for cash, the
consideration received therefor for ---------------------------------------
purposes of this Warrant will be the amount received by the Company
therefor, before deduction of reasonable commissions, underwriting
discounts or allowances or other reasonable expenses paid or incurred by
the Company in connection with such issuance, grant or sale. In case any
Common Stock, Options or Convertible Securities are issued or sold for a
consideration part or all of which shall be other than cash, the amount of
the consideration other than cash received by the Company will be the fair
value of such consideration, except where such consideration consists of
securities, in which case the amount of consideration received by the
Company will be the Market Price thereof as of the date of receipt. In case
any Common Stock, Options or Convertible Securities are issued in
connection with any acquisition, merger or consolidation in which the
Company is the surviving corporation, the amount of consideration therefor
will be deemed to be the fair value of such portion of the net assets and
business of the non-surviving corporation as is attributable to such Common
Stock, Options or Convertible Securities, as the case may be. The fair
value of any consideration other than cash or securities will be determined
in good faith by the Board of Directors of the Company.
(vi) Exceptions to Adjustment of Exercise Price. No adjustment to the
Exercise Price will be made (i) upon the exercise of any warrants, options
or convertible securities granted,
------------------------------------------- issued and outstanding on the
date of issuance of this Warrant or issued pursuant to the Finder
Agreement; (ii) upon the grant or exercise of any stock or options which
may hereafter be granted or exercised under any employee benefit plan of
the Company now existing or to be implemented in the future, so long as the
issuance of such stock or options is approved by a majority of the
independent members of the Board of Directors of the Company or a majority
of the members of a committee of independent directors established for such
purpose; or (iii) upon the exercise of the Warrants.
(c) Subdivision or Combination of Common Stock. If the Company
at any time subdivides (by any stock split, stock dividend, recapitalization,
reorganization, reclassification or otherwise) the shares of Common Stock
acquirable hereunder into a greater number of shares, then, after the date of
record for effecting such subdivision, the Exercise Price in effect immediately
prior to such subdivision will be proportionately reduced. If the Company at any
time combines (by reverse stock split, recapitalization, reorganization,
reclassification or otherwise) the shares of Common Stock acquirable hereunder
into a smaller number of shares, then, after the date of record for effecting
such combination, the Exercise Price in effect immediately prior to such
combination will be proportionately increased.
(d) Adjustment in Number of Shares. Upon each adjustment of
the Exercise Price pursuant to the provisions of this Paragraph 4, the number of
shares of Common Stock issuable upon exercise of this Warrant shall be adjusted
by multiplying a number equal to the Exercise Price in effect immediately prior
to such adjustment by the number of shares of Common Stock issuable upon
exercise of this Warrant immediately prior to such adjustment and dividing the
product so obtained by the adjusted Exercise Price.
(e) Consolidation, Merger or Sale. In case of any
consolidation of the Company with, or merger of the Company into any other
corporation, or in case of any sale or conveyance of all or substantially all of
the assets of the Company other than in connection with a plan of complete
liquidation of the Company, then as a condition of such consolidation, merger or
sale or conveyance, adequate provision will be made whereby the holder of this
Warrant will have the right to acquire and receive upon exercise of this Warrant
in lieu of the shares of Common Stock immediately theretofore acquirable upon
the exercise of this Warrant, such shares of stock, securities or assets as may
be issued or payable with respect to or in exchange for the number of shares of
Common Stock immediately theretofore acquirable and receivable upon exercise of
this Warrant had such consolidation, merger or sale or conveyance not taken
place. In any such case, the Company will make appropriate provision to insure
that the provisions of this Paragraph 4 hereof will thereafter be applicable as
nearly as may be in relation to any shares of stock or securities thereafter
deliverable upon the exercise of this Warrant. The Company will not effect any
consolidation, merger or sale or conveyance unless prior to the consummation
thereof, the successor corporation (if other than the Company) assumes by
written instrument the obligations under this Paragraph 4 and the obligations to
deliver to the holder of this Warrant such shares of stock, securities or assets
as, in accordance with the foregoing provisions, the holder may be entitled to
acquire.
(f) Distribution of Assets. In case the Company shall declare
or make any distribution of its assets (including cash) to holders of Common
Stock as a partial liquidating dividend, by way of return of capital or
otherwise, then, after the date of record for determining stockholders entitled
to such distribution, but prior to the date of distribution, the holder of this
Warrant shall be entitled upon exercise of this Warrant for the purchase of any
or all of the shares of Common Stock subject hereto, to receive the amount of
such assets which would have been payable to the holder had such holder been the
holder of such shares of Common Stock on the record date for the determination
of stockholders entitled to such distribution.
(g) Notice of Adjustment. Upon the occurrence of any event
which requires any adjustment of the Exercise Price, then, and in each such
case, the Company shall give notice thereof to the holder of this Warrant, which
notice shall state the Exercise Price resulting from such adjustment and the
increase or decrease in the number of Warrant Shares purchasable at such price
upon exercise, setting forth in reasonable detail the method of calculation and
the facts upon which such calculation is based. Such calculation shall be
certified by the chief financial officer of the Company.
(h) Minimum Adjustment of Exercise Price. No adjustment of the
Exercise Price shall be made in an amount of less than 1% of the Exercise Price
in effect at the time such adjustment is otherwise required to be made, but any
such lesser adjustment shall be carried forward and shall be made at the time
and together with the next subsequent adjustment which, together with any
adjustments so carried forward, shall amount to not less than 1% of such
Exercise Price.
(i) No Fractional Shares. No fractional shares of Common Stock
are to be issued upon the exercise of this Warrant, but the Company shall pay a
cash adjustment in respect of any fractional share which would otherwise be
issuable in an amount equal to the same fraction of the Market Price of a share
of Common Stock on the date of such exercise.
(j) Other Notices. In case at any time:
(i) the Company shall declare any dividend upon the Common Stock
payable in shares of stock of any class or make any other
distribution (including dividends or distributions payable in
cash out of retained earnings) to the holders of the Common
Stock;
(ii) the Company shall offer for subscription pro rata to the holders
of the Common Stock any additional shares of stock of any class
or other rights;
(iii)there shall be any capital reorganization of the Company, or
reclassification of the Common Stock, or consolidation or merger
of the Company with or into, or sale of all or substantially all
its assets to, another corporation or entity; or
(iv) there shall be a voluntary or involuntary dissolution,
liquidation or winding-up of the Company;
then, in each such case, the Company shall give to the holder of this Warrant
(a) notice of the date on which the books of the Company shall close or a record
shall be taken for determining the holders of Common Stock entitled to receive
any such dividend, distribution, or subscription rights or for determining the
holders of Common Stock entitled to vote in respect of any such reorganization,
reclassification, consolidation, merger, sale, dissolution, liquidation or
winding-up and (b) in the case of any such reorganization, reclassification,
consolidation, merger, sale, dissolution, liquidation or winding-up, notice of
the date (or, if not then known, a reasonable approximation thereof by the
Company) when the same shall take place. Such notice shall also specify the date
on which the holders of Common Stock shall be entitled to receive such dividend,
distribution, or subscription rights or to exchange their Common Stock for stock
or other securities or property deliverable upon such reorganization,
reclassification, consolidation, merger, sale, dissolution, liquidation, or
winding-up, as the case may be. Such notice shall be given at least 30 days
prior to the record date or the date on which the Company's books are closed in
respect thereto. Failure to give any such notice or any defect therein shall not
affect the validity of the proceedings referred to in clauses (i), (ii), (iii)
and (iv) above.
(k) Certain Events. If any event occurs of the type
contemplated by the adjustment provisions of this Paragraph 4 but not expressly
provided for by such provisions, the Company will give notice of such event as
provided in Paragraph 4(g) hereof, and the Company's Board of Directors will
make an appropriate adjustment in the Exercise Price and the number of shares of
Common Stock acquirable upon exercise of this Warrant so that the rights of the
Holder shall be neither enhanced nor diminished by such event.
(l) Certain Definitions.
(i) "Common Stock Deemed Outstanding" shall mean the number of shares
of Common Stock actually outstanding (not including shares of
Common Stock held in the treasury of the Company),
-------------------------------- plus (x) pursuant to Paragraph
4(b)(i) hereof, the maximum total number of shares of Common
Stock issuable upon the exercise of Options, as of the date of
such issuance or grant of such Options, if any, and (y) pursuant
to Paragraph 4(b)(ii) hereof, the maximum total number of shares
of Common Stock issuable upon conversion or exchange of
Convertible Securities, as of the date of issuance of such
Convertible Securities, if any.
(ii) AMarket Price,@ as of any date, (i) means the average of the last
reported sale prices for the shares of Common Stock on the
American Stock Exchange (the "AMEX") for the five (5)
------------- trading days immediately preceding such date as
reported by Bloomberg, L.P. ("Bloomberg"), or (ii) if the AMEX is
not the principal trading market for the shares of Common Stock,
the average of the last reported sale prices on the principal
trading market for the Common Stock during the same period as
reported by Bloomberg, or (iii) if market value cannot be
calculated as of such date on any of the foregoing bases, the
Market Price shall be the fair market value as reasonably
determined in good faith by (a) the Board of Directors of the
Corporation or, at the option of a majority-in-interest of the
holders of the outstanding Warrants by (b) an independent
investment bank of nationally recognized standing in the
valuation of businesses similar to the business of the
corporation. The manner of determining the Market Price of the
Common Stock set forth in the foregoing definition shall apply
with respect to any other security in respect of which a
determination as to market value must be made hereunder.
(iii)"Common Stock," for purposes of this Paragraph 4, includes the
Common Stock, par value $.001 per share, and any additional class
of stock of the Company having no preference as to
-----------dividends or distributions on liquidation, provided
that the shares purchasable pursuant to this Warrant shall
include only shares of Common Stock, par value $.001 per share,
in respect of which this Warrant is exercisable, or shares
resulting from any subdivision or combination of such Common
Stock, or in the case of any reorganization, reclassification,
consolidation, merger, or sale of the character referred to in
Paragraph 4(e) hereof, the stock or other securities or property
provided for in such Paragraph.
5. Issue Tax. The issuance of certificates for Warrant Shares upon the
exercise of this Warrant shall be made without charge to the holder of this
Warrant or such shares for any issuance tax or other costs in respect thereof,
provided that the Company shall not be required to pay any tax which may be
payable in respect of any transfer involved in the issuance and delivery of any
certificate in a name other than the holder of this Warrant.
6. No Rights or Liabilities as a Shareholder. This Warrant shall not
entitle the holder hereof to any voting rights or other rights as a shareholder
of the Company. No provision of this Warrant, in the absence of affirmative
action by the holder hereof to purchase Warrant Shares, and no mere enumeration
herein of the rights or privileges of the holder hereof, shall give rise to any
liability of such holder for the Exercise Price or as a shareholder of the
Company, whether such liability is asserted by the Company or by creditors of
the Company.
7. Transfer, Exchange, and Replacement of Warrant.
(a) Restriction on Transfer. This Warrant and the rights
granted to the holder hereof are transferable, in whole or in part, upon
surrender of this Warrant, together with a properly executed assignment in the
form attached hereto, at the office or agency of the Company referred to in
Paragraph 7(e) below, provided, however, that any transfer or assignment shall
be subject to the conditions set forth in Paragraph 7(f) hereof and to the
applicable provisions of the Finder Agreement. Until due presentment for
registration of transfer on the books of the Company, the Company may treat the
registered holder hereof as the owner and holder hereof for all purposes, and
the Company shall not be affected by any notice to the contrary. Notwithstanding
anything to the contrary contained herein, the registration rights described in
Paragraph 8 are not assignable.
(b) Warrant Exchangeable for Different Denominations. This
Warrant is exchangeable, upon the surrender hereof by the holder hereof at the
office or agency of the Company referred to in Paragraph 7(e) below, for new
Warrants of like tenor representing in the aggregate the right to purchase the
number of shares of Common Stock which may be purchased hereunder, each of such
new Warrants to represent the right to purchase such number of shares as shall
be designated by the holder hereof at the time of such surrender.
(c) Replacement of Warrant. Upon receipt of evidence
reasonably satisfactory to the Company of the loss, theft, destruction, or
mutilation of this Warrant and, in the case of any such loss, theft, or
destruction, upon delivery of an indemnity agreement reasonably satisfactory in
form and amount to the Company (including the posting of a bond, if reasonably
requested by the Company), or, in the case of any such mutilation, upon
surrender and cancellation of this Warrant, the Company, at its expense, will
execute and deliver, in lieu thereof, a new Warrant of like tenor.
(d) Cancellation; Payment of Expenses. Upon the surrender of
this Warrant in connection with any transfer, exchange, or replacement as
provided in this Paragraph 7, this Warrant shall be promptly canceled by the
Company. The Company shall pay all taxes (other than securities transfer taxes)
and all other expenses (other than legal expenses, if any, incurred by the
Holder or transferees or any expenses incurred in connection with the posting of
a bond pursuant to Paragraph 7(c) above) and charges payable in connection with
the preparation, execution, and delivery of Warrants pursuant to this Paragraph
7.
(e) Register. The Company shall maintain, at its principal
executive offices (or such other office or agency of the Company as it may
designate by notice to the holder hereof), a register for this Warrant, in which
the Company shall record the name and address of the person in whose name this
Warrant has been issued, as well as the name and address of each transferee and
each prior owner of this Warrant.
(f) Exercise or Transfer Without Registration. If, at the time
of the surrender of this Warrant in connection with any exercise, transfer, or
exchange of this Warrant, this Warrant (or, in the case of any exercise, the
Warrant Shares issuable hereunder), shall not be registered under the Securities
Act of 1933, as amended (the "Securities Act") and under applicable state
securities or blue sky laws, the Company may require, as a condition of allowing
such exercise, transfer, or exchange, (i) that the holder or transferee of this
Warrant, as the case may be, furnish to the Company a written opinion of
counsel, which opinion and counsel are acceptable to the Company, to the effect
that such exercise, transfer, or exchange may be made without registration under
said Act and under applicable state securities or blue sky laws, (ii) that the
holder or transferee execute and deliver to the Company an investment letter in
form and substance acceptable to the Company and (iii) that the transferee be an
Aaccredited investor@ as defined in Rule 501(a) promulgated under the Securities
Act; provided that no such opinion, letter or status as an Aaccredited investor@
shall be required in connection with a transfer pursuant to Rule 144 under the
Securities Act. The first holder of this Warrant, by taking and holding the
same, represents to the Company that such holder is acquiring this Warrant for
investment and not with a view to the distribution thereof.
8. Registration Rights. The initial holder of this Warrant is
entitled to the benefit of such registration rights in respect of
the Warrant Shares as are set forth in the Finder Agreement.
-------------------
9. Notices. All notices, requests, and other communications required or
permitted to be given or delivered hereunder to the holder of this Warrant shall
be in writing, and shall be personally delivered, or shall be sent by certified
or registered mail or by recognized overnight mail courier, postage prepaid and
addressed, to such holder at the address shown for such holder on the books of
the Company, or at such other address as shall have been furnished to the
Company by notice from such holder. All notices, requests, and other
communications required or permitted to be given or delivered hereunder to the
Company shall be in writing, and shall be personally delivered, or shall be sent
by certified or registered mail or by recognized overnight mail courier, postage
prepaid and addressed, to the office of the Company at 3201 Airpark Drive, Suite
201, Santa Maria, California 93455, Attention: Chief Executive Officer, or at
such other address as shall have been furnished to the holder of this Warrant by
notice from the Company. Any such notice, request, or other communication may be
sent by facsimile, but shall in such case be subsequently confirmed by a writing
personally delivered or sent by certified or registered mail or by recognized
overnight mail courier as provided above. All notices, requests, and other
communications shall be deemed to have been given either at the time of the
receipt thereof by the person entitled to receive such notice at the address of
such person for purposes of this Paragraph 9, or, if mailed by registered or
certified mail or with a recognized overnight mail courier upon deposit with the
United States Post Office or such overnight mail courier, if postage is prepaid
and the mailing is properly addressed, as the case may be.
10. Governing Law. THIS WARRANT SHALL BE GOVERNED BY AND CONSTRUED
AND ENFORCED IN ACCORDANCE WITH THE INTERNAL LAWS OF THE STATE OF
DELAWARE WITHOUT REGARD TO THE BODY OF LAW CONTROLLING CONFLICTS
OF ------------- LAW.
11. Miscellaneous.
(a) Amendments. This Warrant and any provision hereof may only be
amended by an instrument in writing signed by the Company and the
holder hereof. ----------
(b) Descriptive Headings. The descriptive headings of the several
paragraphs of this Warrant are inserted for purposes of reference
only, and shall not affect the meaning or construction of
--------------------- any of the provisions hereof.
(c) Cashless Exercise. Notwithstanding anything to the
contrary contained in this Warrant, if the resale of the Warrant Shares by the
holder is not then registered pursuant to an effective registration statement
under the Securities Act, this Warrant may be exercised by presentation and
surrender of this Warrant to the Company at its principal executive offices with
a written notice of the holder=s intention to effect a cashless exercise,
including a calculation of the number of shares of Common Stock to be issued
upon such exercise in accordance with the terms hereof (a ACashless Exercise@).
In the event of a Cashless Exercise, in lieu of paying the Exercise Price in
cash, the holder shall surrender this Warrant for that number of shares of
Common Stock determined by multiplying the number of Warrant Shares to which it
would otherwise be entitled by a fraction, the numerator of which shall be the
difference between the then current Market Price per share of the Common Stock
and the Exercise Price, and the denominator of which shall be the then current
Market Price per share of Common Stock.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]
<PAGE>
IN WITNESS WHEREOF, the Company has caused this Warrant to be signed by
its duly authorized officer.
SABA PETROLEUM COMPANY
By: ________________________________
Ilyas Chaudhary
Chief Executive Officer
Dated as of December 31, 1997
<PAGE>
FORM OF EXERCISE AGREEMENT
Dated: ________, ____.
To:_____________________________
The undersigned, pursuant to the provisions set forth in the within
Warrant, hereby agrees to purchase ________ shares of Common Stock covered by
such Warrant, and makes payment herewith in full therefor at the price per share
provided by such Warrant in cash or by certified or official bank check in the
amount of, or, if the resale of such Common Stock by the undersigned is not
currently registered pursuant to an effective registration statement under the
Securities Act of 1933, as amended, by surrender of securities issued by the
Company (including a portion of the Warrant) having a market value (in the case
of a portion of this Warrant, determined in accordance with Section 11(c) of the
Warrant) equal to $_________. Please issue a certificate or certificates for
such shares of Common Stock in the name of and pay any cash for any fractional
share to:
Name: ___________________________________
Signature: ________________________________
Address: ________________________________
- - --------------------------------
Note: The above signature should correspond exactly with the name on
the face of the within Warrant. and, if said number of shares of Common
Stock shall not be all the shares purchasable under the within Warrant, a
new Warrant is to be issued in the name of said undersigned covering the
balance of the shares purchasable thereunder less any fraction of a share
paid in cash.
<PAGE>
FORM OF ASSIGNMENT
FOR VALUE RECEIVED, the undersigned hereby sells, assigns, and
transfers all the rights of the undersigned under the within Warrant, with
respect to the number of shares of Common Stock covered thereby set forth
hereinbelow, to:
<TABLE>
<S> <C> <C>
Name of Assignee Address No of Shares
</TABLE>
, and hereby irrevocably constitutes and appoints ______________
________________________ as agent and attorney-in-fact to transfer said
Warrant on the books of the within-named corporation, with full power of
substitution in the premises.
Dated: _____________________, ____,
In the presence of
- - ------------------
Name: ___________________________________
Signature: _________________________
Title of Signing Officer or Agent (if any):
- - -----------------------------------
Address: ___________________________
- - ---------------------------
Note: The above signature should correspond exactly with the name on the
face of the within Warrant.
Exhibit 11.1
<TABLE>
<CAPTION>
Computation of Earnings Per Common Share
For the Years Ended December 31, 1995, 1996 and 1997
<S> <C> <C> <C>
1995 1996 1997
---- ---- ----
Basic Earnings
Net income before minority interest
in earnings of consolidated
subsidiary 602,164 4,006,117 2,453,330
Minority interest in earnings of
consolidated subsidiary (55,632) (241,401) (55,883)
------------ ------------- -------------
Net income available to Common 546,532 3,764,716 2,397,447
======= ======== ========
Basic Shares
Weighted average number of Common
Shares outstanding 8,327,495 8,803,941 10,649,766
======== ======== ========
Basic Earnings per Common Share
Net income available to Common 0.07 0.43 0.23
===== ===== =====
Diluted Earnings
Net income before minority interest
in earnings of consolidated
subsidiary 602,164 4,006,117 2,453,330
Minority interest in earnings of
consolidated subsidiary (55,632) (241,401) (55,883)
Plus interest expense attributable
to Debentures, net of related income
taxes 9,059 558,775 202,635
------------ ------------- -------------
Net income available to Common 555,591 4,323,491 2,600,082
======= ======== ========
Diluted Shares
Weighted average number of Common
Shares outstanding 8,327,495 8,803,941 10,649,766
Effect of dilutive securities:
Of shares underlying options 330,407 371,393 350,066
Of shares underlying convertible
Debentures 41,331 2,650,119 1,001,108
------------ ------------- -------------
Diluted Shares 8,699,233 11,825,453 12,000,940
======= ======== ========
Diluted Earnings per Common Share
Net income 0.06 0.37 0.22
===== ===== =====
Dilution factor: diluted EPS/basic EPS 0.9731348 0.854991263 0.962415992
</TABLE>
Exhibit 23.1 Consent of Coopers & Lybrand, LLP
CONSENT OF INDEPENDENT ACCOUNTANTS We consent to the incorporation by
reference in this annual report on Form 10-K of our report, which includes
an explanatory paragraph regarding the Company's ability to continue as a
going concern, dated April ___, 1998, on our audits of the consolidated
financial statements and financial statement schedule of Saba Petroleum
Company and subsidiaries as of December 31, 1997 and 1996, and for each of
the three years in the period ended December 31, 1997, appearing in the
registration statements on Form S-3 (SEC File Nos. 33-71272 and 333-00799)
and Form S-1 (SEC File No. 333-45023) of Saba Petroleum Company filed with
the Securities and Exchange commission pursuant to the Securities Act of
1933.
COOPERS & LYBRAND
Los Angeles, California
April ___, 1998
Exhibit 23.2 Consent of Netherland, Sewell & Associates, Inc.
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
The undersigned
hereby consents to be named as the source for certain oil and gas reserve
information presented in the form 10-K of Saba Petroleum Company (the
"Registrant") as filed with the Securities and Exchange commission pursuant
to the Securities Exchange Act of 1934, as amended. NETHERLAND, SEWELL &
ASSICOATES, INC.
By: /s/ FREDERIC D. SEWELL
Frederic D. Sewell
President
Dallas, Texas April 14, 1998
Exhibit 23.3 Consent of Sproule Associates Limited
April 14, 1998
Saba Petroleum company
3201 Airpark Drive, Suite 201
Santa Maria, CA 93455
Re: Evaluation of the P&NG Reserves of Beaver lake Resources Corporation,
as of January 1, 1998
Dear Sirs:
Sproule Associates Limited hereby consents to being named in the annual
10-K report filed with the SEC and to the reference in this document to the
Sproule Report.
We confirm that we have read excerpts from the draft document and that we
have no reason to believe that there are any misrepresentations in the
information contained therein that is derived from our report.
Sincerely,
/s/ H.J. FIRLA
H.J. Firla, P. Eng.
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
this Schedule contains summary financial information extracted from the
consolidated balance sheet at December 31, 1997 and consolidated statement of
income for year ended December 31, 1997, and is qualified in its entirety by
reference to Form 10-K for the fiscal year ended December 31, 1997.
</LEGEND>
<CIK> 0000312340
<NAME> Saba Petroleum Company
<MULTIPLIER> 1000
<CURRENCY> U.S.dollars
<S> <C>
<PERIOD-TYPE> year
<FISCAL-YEAR-END> Dec-31-1997
<PERIOD-START> Jan-01-1997
<PERIOD-END> Dec-31-1997
<EXCHANGE-RATE> 1.000
<CASH> 1,508
<SECURITIES> 6,528
<RECEIVABLES> (69)
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 12,556
<PP&E> 84,931
<DEPRECIATION> (22,325)
<TOTAL-ASSETS> 77,657
<CURRENT-LIABILITIES> 24,280
<BONDS> 19,610
0
8,514
<COMMON> 11
<OTHER-SE> 23,629
<TOTAL-LIABILITY-AND-EQUITY> 77,657
<SALES> 0
<TOTAL-REVENUES> 35,996
<CGS> 0
<TOTAL-COSTS> 28,997
<OTHER-EXPENSES> 365
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,305
<INCOME-PRETAX> 4,329
<INCOME-TAX> 1,876
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 2,397
<EPS-PRIMARY> 0.23
<EPS-DILUTED> 0.22
</TABLE>
