1
UNITED STATES- --------------------------------------------------------------------------------
FORM 10-K/A
AMENDMENT NO. 1
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT UNDERPURSUANT TO SECTION 13 OR 15(D)
[X]15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1995
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)
[ ]15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 FOR THE
TRANSITION PERIOD FROM[NO FEE REQUIRED]
For the transition period from __________ TOto ___________
COMMISSION FILE NO.: 1-10762Commission file number 1-10727
BENTON OIL AND GAS COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 77-0196707
(STATE OR OTHER JURISDICTION OF (I.R.S. EMPLOYER IDENTIFICATION NUMBER)NO.)
INCORPORATION OR ORGANIZATION)
1145 EUGENIA PLACE, SUITE 200, CARPINTERIA, CALIFORNIACA 93013
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES) (ZIP CODE)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE (805) 566-5600
Securities registered pursuant to SectionSECURITIES REGISTERED PURSUANT TO SECTION 12(b) of the Act:OF THE ACT:
NONE
Securities registered pursuant to SectionSECURITIES REGISTERED PURSUANT TO SECTION 12(g) of the Act:
TITLE OF EACH CLASSTHE ACT:
NAME OF EACH EXCHANGE ON
TITLE OF EACH CLASS WHICH REGISTERED
- ------------------- -----------------------------------------
Common Stock,------------------------
COMMON STOCK, $.01 Par ValuePAR VALUE NASDAQ-NMS
8% Convertible Subordinated Debentures due inCONVERTIBLE SUBORDINATED DEBENTURES DUE 2002 NASDAQ
Common Stock Purchase Warrants,COMMON STOCK PURCHASE WARRANTS, $11.00 exercise price NASDAQ-NMSEXERCISE PRICE NASDAQ - NMS
Indicate by check mark whether the Registrantregistrant (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
Registrantregistrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YESYes X NO
___ ___
On March 28, 1996, theNo
Approximate aggregate market value of the shares of votingcommon stock of
Registrant held by
non-affiliates was approximately $396,063,627 basedof the registrant: $396,100,000, computed on athe basis of $15.69
per share, closing sales price of the common stock on NASDAQ-NMS of $15.69.
As of March 28, 1996,the NASDAQ-NMS.
There were 26,073,161 shares of the Registrant's common stock were
outstanding.
DOCUMENT INCORPORATED BY REFERENCE
Portionsregistrant's Common Stock, $.01
par value, outstanding as of the Registrant's Proxy Statement for the 1996 Annual Meeting of
Stockholders to be filed with the Securities and Exchange Commission, not later
than 120 days after the 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.March 28, 1996.
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K 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.[ ]
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BENTON OIL AND GAS COMPANY
FORM 10-K
TABLE OF CONTENTS
Page
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Part I
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Item 1. Business 1
Item 2. Properties 14
Item 3. Legal Proceedings 14
Item 4. Submission of Matters to a Vote of Security Holders 15
Part II
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Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters 16
Item 6. Selected Consolidated Financial Data 17
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 18
Item 8. Financial Statements and Supplementary Data 23
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 23
PartPART III
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Item 10. Directors and Executive Officers of the Registrant 23
Item 11. Executive Compensation 23
Item 12. Security Ownership of Certain Beneficial
Owners and Management 23
Item 13. Certain Relationships and Related Transactions 23
Part IV
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Item 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K 25
Financial Statements 27
Signatures 51
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PART I
ITEM 1. BUSINESS
GENERAL
Benton Oil and Gas Company (the "Company") is an independent energy company
which has been engaged in the development and production of oil and gas
properties since 1989. Although originally active only in the United States,
the Company has developed significant interests in Venezuela and Russia, and
has recently agreed to sell substantially all of its remaining United States
oil and gas interests. After giving effect to the sale, the Company's existing
operations will be conducted principally through its 80% owned Venezuelan
subsidiary, Benton-Vinccler, C.A. ("Benton-Vinccler"), which operates in the
South Monagas Unit in Venezuela, and its 34% owned Russian joint venture,
GEOILBENT, which operates in the North Gubkinskoye Field in Siberia, Russia.
As of December 31, 1995, the Company had total assets of $214.8 million, total
estimated proved reserves of 96,212 MBOE, and a standardized measure of
discounted future net cash flow, before income taxes, for total proved reserves
of $372.3 million. For the year ended December 31, 1995, the Company had total
revenues of $65.1 million and net income of $10.6 million.
The Company has been successful in increasing reserves, production, revenues
and earnings during the last two years. From year end 1993 through 1995,
estimated proved reserves increased from 42,785 MBOE to 96,212 MBOE and net
production increased from a total of 519 MBOE in 1993 to 6,647 MBOE in 1995.
As production has increased over this period, average lifting costs have
declined from $7.26 per Bbl in Venezuela to $1.19, and in Russia from $16.22
per Bbl to $5.63. Over the same period, earnings per share have increased from
a loss of $0.26 per share in 1993 to income of $0.40 per share for the year
ended December 31, 1995.
BUSINESS STRATEGY
The Company's business strategy is to identify and exploit new oil and gas
reserves in under-developed areas while seeking to minimize the associated risk
of such activities. Specifically, the Company endeavors to minimize risk by
employing the following strategies in its business activities: (i) seek new
reserves in areas of low geologic risk; (ii) use proven advanced technology in
both exploration and development to maximize recovery; (iii) establish a local
presence through joint venture partners and the use of local personnel; (iv)
commit capital in a phased manner to limit total commitments at any one time;
and (v) reduce foreign exchange risks through receipt of revenues in U.S.
currency.
- - Seek new reserves in areas of low geologic risk. The Company has had
significant success in identifying under-developed reserves in the U.S. and
internationally. In particular, the Company has notable experience and
expertise in seeking and developing new reserves in countries where perceived
potential political and operating difficulties have sometimes discouraged other
energy companies from competing. As a result, the Company has established
operations in Venezuela and Russia which have significant reserves that have
been acquired and developed at relatively low costs. The Company is seeking
similar opportunities in other countries and areas which it believes have high
potential.
- - Use of proven advanced technology in both exploration and
development. The Company's use of 3-D seismic technology, in which a three
dimensional image of the earth's subsurface is created through the computer
interpretation of seismic data, combined with its experience in designing the
seismic surveys and interpreting and analyzing the resulting data, allow for a
more detailed understanding of the subsurface than do conventional surveys.
Such technology contributes significantly to field appraisal, development and
production. The 3-D seismic information, in conjunction with subsurface
geologic data from previously drilled wells, is used by the Company's
experienced in-house technical team to identify previously undetected reserves.
The 3-D seismic information can also be used to guide drilling on a real-time
basis, and has been especially helpful in the horizontal drilling done in
Venezuela in order to take advantage of oil-trapping fault lines.
- - Establish a local presence through joint venture partners and the use
of local personnel. The Company has sought to establish a local presence where
it does business to facilitate stronger relationships with local government and
labor through joint venture arrangements with local partners. Moreover, the
Company employs almost exclusively local personnel to run foreign operations
both to take advantage of local knowledge and experience and to minimize cost.
These efforts have created
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an expertise within Company management in forming effective foreign
partnerships and operating abroad. The Company believes that it has gained
access to new development opportunities as a result of its reputation as a
dependable partner.
- - Commit capital in a phased manner to limit total commitments at any
one time. While the Company typically has agreed to a minimum capital
expenditure or development commitment at the outset of new projects,
expenditures to fulfill these commitments are phased over time. In addition,
the Company seeks, where possible, to use internally generated funds for further
capital expenditures and to invest in projects which provide the
potential for an early return to the Company.
- - Reduce foreign exchange risks. The Company seeks to reduce foreign
currency exchange risks by providing for the receipt of revenues by the
Company in U.S. dollars while most operating costs are incurred in local
currency. Pursuant to the operating agreement between the Company's Venezuelan
subsidiary and the state oil company, the operating fees earned by the Company
are paid directly to the Company's bank account in the U.S. in U.S. dollars.
GEOILBENT receives revenues from export sales in U.S. dollars paid to its
account in Moscow. As the Company expands internationally, it will seek to
establish similar arrangements for new operations.
PRINCIPAL AREAS OF ACTIVITY
The following table summarizes the Company's proved reserves, drilling and
production activity, and financial operating data by principal geographic area
at and for each of the years ended December 31:
Venezuela(1) Russia United States
------------ ------ -------------
(dollars in 000's) 1995 1994 1993 1995(2) 1994 1993 1995 1994 1993
---- ---- ---- ---- ---- ---- ---- ---- ----
RESERVE INFORMATION:
Proved Reserves (MBOE) 73,593 60,707 19,389 22,618 17,540 10,121 1(3) 2,913 13,275
Discounted Future Net Cash
Flow Attributable to Proved
Reserves, Before Income Taxes $286,916 $268,830 $72,206 $85,361 $48,833 $24,237 $16 $18,657 $34,970
Standardized Measure of
Future Net Cash Flows $206,545 $172,703 $50,958 $55,434 $32,398 $19,512 $16 $18,286 $32,046
DRILLING AND PRODUCTION
ACTIVITY:
Gross Wells Drilled 21 11 5 21 9 4 5 5 9
Average Daily Production (BOE) 14,949 6,902 440 1,345 806 77 1,917 1,561 907
FINANCIAL DATA:
Oil and Gas Revenues $49,174 $21,472 $1,333 $6,016 $3,513 $324 $7,683 $7,287 $5,565
Expenses:
Lease Operating Costs and
Production Taxes 6,483 3,808 1,165 2,764 2,832 458 1,456 2,891 3,487
Depletion 11,393 4,998 229 1,512 838 99 4,188 4,248 2,142
------- ------- ------ ------ ------ ---- ------ ------ ------
Total Expenses 17,876 8,806 1,394 4,276 3,670 557 5,644 7,139 5,629
------- ------- ------ ------ ------ ---- ------ ------ ------
Results of Operations from Oil
and Gas Producing Activities $31,298 $12,666 $(61) $1,740 $(157) $(233) $2,039 $148 $(64)
======= ======= ====== ====== ====== ===== ====== ====== ======
(1) Includes 100% of the reserve information, drilling and production activity
and financial data, without deduction for minority interest. All
Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and Lagoven, S.A. under which all mineral rights
are owned by the Government of Venezuela. See Item 1. Business--South
Monagas Unit, Venezuela and --Reserves.
(2) The financial information for Russia for the 1995 presentation includes
information for the nine months ended September 30, 1995, the end of the
fiscal period for GEOILBENT. Results of operations in Russia reflect the
twelve months ended December 31, 1993 and 1994 and the nine months ended
September 30, 1995.
(3) The Company has entered into an agreement to sell substantially all its
U.S. reserves and related acreage positions. See Item 1. Business --
Other Properties.
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SOUTH MONAGAS UNIT, VENEZUELA
GENERAL
In July 1992, the Company and Venezolana de Inversiones y Construcciones
Clerico, C.A. ("Vinccler"), a Venezuelan construction and engineering company,
signed a 20-year operating service agreement with Lagoven, S.A. ("Lagoven"), an
affiliate of the national oil company, Petroleos de Venezuela S.A. ("PDVSA"),
to reactivate and further develop the Uracoa, Bombal and Tucupita Fields, which
are a part of the South Monagas Unit (the "Unit"). At that time, the Company
was one of three foreign companies ultimately awarded an operating service
agreement to reactivate existing fields by PDVSA, and was the first U.S.
company since 1976 to be granted such an oil field development contract in
Venezuela.
The oil and gas operations in the Unit are conducted by Benton-Vinccler, the
Company's 80% owned subsidiary. The remaining 20% of the outstanding capital
stock of Benton-Vinccler is owned by Vinccler. The Company, through its
majority ownership of stock in Benton-Vinccler, makes all operational and
corporate decisions related to Benton-Vinccler, subject to certain
super-majority provisions of Benton-Vinccler's charter documents related to
mergers, consolidations, sales of substantially all of its corporate assets,
change of business and similar major corporate events. Vinccler has an
extensive operating history in Venezuela. It provided the Company with initial
financial assistance and continues to provide ongoing assistance with
construction services and governmental and labor relations.
Under the terms of the operating service agreement, Benton-Vinccler is a
contractor for Lagoven and is responsible for overall operations of the South
Monagas Unit, including all necessary investments to reactivate and develop the
fields comprising the Unit. The Venezuelan government maintains full
ownership of all hydrocarbons in the fields. In addition, Lagoven maintains
full ownership of equipment and capital infrastructure following its
installation. Benton-Vinccler invoices Lagoven each quarter based on Bbls of
oil accepted by Lagoven during the quarter, using quarterly adjusted contract
service fees per Bbl, and receives its payments from Lagoven in U.S. dollars
deposited directly into a U.S. bank account. The operating service agreement
provides for Benton-Vinccler to receive an operating fee for each Bbl of crude
oil delivered and a capital recovery fee for certain of its capital
expenditures, provided that such operating fee and capital recovery fee cannot
exceed the maximum total fee per Bbl set forth in the agreement. The operating
fee is subject to periodic adjustments to reflect changes in the special energy
index of the U.S. Consumer Price Index, and the maximum total fee is subject to
periodic adjustments to reflect changes in the average of certain world crude
oil prices. Since commencement of operations, the adjusted maximum total fee
has been cumulatively less than the adjusted operating fee, resulting in no
capital recovery fee. The Company cannot predict the extent to which future
maximum total fee adjustments will provide for capital recovery components in
the fees it receives, and has recorded no income or asset for capital recovery
fees.
Under the terms of the operating service agreement, Benton-Vinccler was
obligated to make certain capital and operating expenditures prior to December
31, 1995. Benton-Vinccler has satisfied all such obligations under the
operating service agreement and no further capital commitments are
contractually required. However, in order to expand operations, the Company
will need to continue to make capital expenditures. See -- Drilling and
Development Activity.
Since 1992, when Venezuela solicited initial calls for indications of interest
related to the reactivation and further development of certain fields in
Venezuela, the country has continued to invite foreign assistance in Venezuelan
oil and gas exploration, development and production. Management believes that
Venezuela continues to provide potential business opportunities for the
Company. See -- Delta Centro Block, Venezuela.
LOCATION AND GEOLOGY
The Unit is located in the southeastern part of the state of Monagas in eastern
Venezuela. The Unit is approximately 51 miles long and eight miles wide and
consists of 157,843 acres, of which the fields comprise approximately one-half.
At December 31, 1995, proved reserves attributable to the Company's Venezuelan
operations were 73,593 MBOE, which represented 76% of the Company's proved
reserves. Benton-Vinccler is currently developing the Oficina sands in the
Uracoa Field, which contain 92.4% of the Unit's proved reserves. The
associated natural gas which is produced is currently being reinjected into the
field, as no ready market exists for the natural gas.
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DRILLING AND DEVELOPMENT ACTIVITY
URACOA FIELD. Benton-Vinccler has been developing the Uracoa Field since 1992.
During March 1996 (through March 28), a total of approximately 50 wells were
producing an average of approximately 31,500 Bbls of oil per day in the Uracoa
Field. The following table sets forth Uracoa drilling activity and production
information for each of the quarters presented:
Wells Drilled Average Daily
------------- -------------
Vertical Horizontal Production from Field (Bbl)
-------- ---------- ---------------------------
1994:
First Quarter . . 5 0 3,400
Second Quarter . 0 0 6,700
Third Quarter . . 3 0 7,200
Fourth Quarter . 0 3 10,200
1995:
First Quarter . . 1 1 11,800
Second Quarter . 1 2 11,300
Third Quarter . . 2 2 15,800
Fourth Quarter . 1 8 20,800
Benton-Vinccler contracts with third parties for drilling and completion of
wells. Currently, Helmerich & Payne International Drilling Co. and Exeter
Drilling Co. are performing drilling services for Benton-Vinccler under
contract. The Company's technical personnel identify drilling locations,
specify the drilling program and equipment to be used and monitor the drilling
activities. To date, 15 previously drilled wells have been reactivated and 42
new wells have been drilled in the Uracoa Field using modern drilling and
completion techniques that had not previously been utilized on the field, with
41, or 98%, completed and placed on production. Two drilling rigs are
currently working in the field. In the Company's recent experience, each
vertical deviated well, drilled to an average depth of 5,600 feet, has been
drilled in approximately 10 days and completed in approximately 6 days. In the
Company's recent experience, each horizontal well, drilled to an average depth
of 6,500 feet, has been drilled in 20 days and completed in 3 days.
Benton-Vinccler plans to drill approximately 7 vertical and 26 horizontal
wells, 2 injection wells and one step-out well adjacent to the Uracoa Field
during 1996, at an anticipated cost to the Company of $35-40 million.
In December 1993, Benton-Vinccler commenced drilling the first horizontal well
in the Uracoa Field. Since the completion of this well, the Company has
successfully integrated modern technology and modern drilling and completion
techniques to improve the ultimate recovery. The Company has conducted a 3-D
seismic survey and interpreted the seismic data over the Uracoa Field. As a
horizontal well is drilled, information regarding formations encountered by the
drill bit is transmitted to the Company. Geologists, engineers and
geophysicists at the Company can determine the location of the drill bit by
comparing the information about the formations being drilled with the 3-D
seismic data. The Company then directs the movement of the drill bit to more
accurately direct the well to the expected reservoir. The Company intends to
continue this method of horizontal drilling in the development of the field.
Once oil is produced in the Uracoa Field, it is transported to production
facilities, which were designed in the United States and installed by
Benton-Vinccler. These production facilities are of the type commonly used in
heavy oil production in the United States, but not previously used extensively
in Venezuela to process crude oil of similar gravity or quality. The current
production facilities are capable of processing 30,000-35,000 Bbls of oil per
day. Benton-Vinccler intends to expand the capacity of the production
facilities in 1996 to a total capacity of 40,000-45,000 Bbls of oil per day.
The Company anticipates capital expenditures of $20 million during 1996 to
complete such expansion.
TUCUPITA AND BOMBAL FIELDS. Before becoming inactive, only Tucupita had been
substantially developed and produced; relatively few wells had been drilled at
Uracoa and Bombal. Benton-Vinccler has completed a 67-square mile 3-D seismic
survey over portions of the Unit and is currently interpreting the data. Based
on the interpretations of the seismic data, Benton-Vinccler may drill one or
more wells to extend the boundaries of the three known fields or to confirm the
existence of additional fields previously undetected in the area. Although
Benton- Vinccler initially planned to begin development of the Bombal Field in
1996, further analysis of the Unit indicates that significant reserves may
remain in the Tucupita Field. Benton-Vinccler intends to evaluate the
potential of the Tucupita Field in 1996 by drilling one oil well, and will
expand existing production facilities in such
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field. Based on the performance of this pilot oil well, and if the Company's
assumptions prove to be correct, the production facilities will be further
expanded, and a pipeline to the Uracoa Field will be installed. The pipeline
will also be used for production from the Bombal Field when it is developed.
Benton-Vinccler currently plans to reactivate and develop the Bombal Field
beginning in 1998. During 1996, the Company expects capital expenditures of
$5-6 million for drilling and construction of facilities in the Tucupita Field.
The Company does not expect to make any capital expenditures in the Bombal
Field during 1996.
CUSTOMERS AND MARKET INFORMATION
Oil produced in Venezuela is delivered to Lagoven under the terms of an
operating service agreement for an operating service fee. Benton- Vinccler has
constructed a 25-mile oil pipeline from its oil processing facilities at Uracoa
to Lagoven's storage facility, which is the custody transfer point. The
service agreement specifies that the oil stream may contain no more than 1%
base sediment and water, and quality measurements are conducted both at
Benton-Vinccler's facilities and at Lagoven's storage facility. A continuous
flow measuring unit is installed at Benton-Vinccler's facility, so that
quantity is monitored constantly. Lagoven provides Benton-Vinccler with a
daily acknowledgment regarding the amount of oil accepted the previous day,
which is reconciled to Benton-Vinccler's measurement. At the end of each
quarter, Benton-Vinccler prepares an invoice to Lagoven for that quarter's
deliveries. Lagoven pays the invoice at the end of the second month after the
end of the quarter. Invoice amounts and payments are denominated in U.S.
dollars. Payments are wire transferred into Benton- Vinccler's account in New
York.
EMPLOYEES; COMMUNITY RELATIONS
Benton-Vinccler seeks to employ nationals rather than bring expatriates into
the country. Presently, there are five full time expatriates working with
Benton-Vinccler and 121 local employees. Benton-Vinccler also conducts ongoing
community relations programs, providing medical care, training, equipment and
supplies, and support for local schools, in both states in which the South
Monagas Unit falls.
DELTA CENTRO BLOCK, VENEZUELA
GENERAL
In February 1996, the Company and its bidding partners, Louisiana Land and
Exploration Company ("LL&E") and Norcen Energy Company ("Norcen"), were awarded
the right to explore and develop the Delta Centro Block in Venezuela. The
contract requires a minimum exploration work program consisting of completing a
1,300-square kilometer seismic survey and drilling three wells to depths of
12,000 to 18,000 feet within five years. PDVSA estimates that this minimum
exploration work program will cost $60 million, and will require that the
Company, LL&E and Norcen each post a performance surety bond or standby letter
of credit for its pro rata share of the estimated work commitment expenditures.
The Company will have a 30% interest in the exploration venture, with LL&E and
Norcen each owning a 35% interest. Under the proposed terms of the operating
agreement, which establishes the management company for the project, LL&E will
be the operator of the field and therefore the Company will not be able to
exercise control of the operations of the venture. It is currently proposed
that Corporacion Venezolana del Petroleo, S.A. ("CVP"), an affiliate of the
national oil company, will have a 35% interest in the management company, which
will dilute the voting power of the partners on a pro rata basis.
If areas within the block are deemed to be commercially viable, then the group
has the right to enter into further agreements with CVP to develop those areas
during the next 20-25 years. CVP would participate in the revenues and costs
with an interest between 1-35%, at CVP's discretion. Any oil and gas produced
at Delta Centro will be sold at market prices and will be subject to the oil
and gas taxation regime in Venezuela and to the terms of a profit sharing
agreement with PDVSA. Under the current oil and gas tax law, a royalty of up
to 16.67% will be paid to the state. Under the contract bid terms, 41% of the
pre-tax income will be shared with PDVSA for the period during which the first
$1 billion of revenues is produced; thereafter, the profit sharing amount may
increase to up to 50% according to a formula based on return on assets.
Currently, the statutory income tax rate for oil and gas enterprises is 66.67%.
Royalties and shared profits are currently deductible for tax purposes.
LOCATION AND GEOLOGY
The Delta Centro block consists of approximately 2,138 square kilometers
(526,000 acres) located in the delta of the Orinoco River in the eastern part
of Venezuela. Although no significant exploratory activity has been conducted
on the block, PDVSA has estimated that the area may contain recoverable
reserves of as much as 820 million barrels, and may be capable of
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producing up to 160,000 barrels of oil per day. The general area of Venezuela
in which the Delta Centro Block is located is known to be a significant source
of hydrocarbons, evidenced by the recently discovered El Furrial light oil
trend to the north and the Orinoco tar sands to the south. Based on its
geological studies of the basins in this area, the Company's technical staff
believes that hydrocarbons have essentially migrated over time from the deeper
Maturin basin area of Venezuela southward toward the shallower Orinoco tar belt
area. If so, then potential trapping structures and/or faults in the path of
the migrating oil would serve as traps for the migrating oil and have the
opportunity to be filled to their spill points. Delta Centro is directly in
line with this migration path, making it an attractive exploration area. The
area is mostly swampy in nature, with terrain ranging from forest in the north
to savannah in the south. The marshlands in the block are similar to the
transition zone areas in the Gulf of Mexico in which the Company has
significant experience in seismic and drilling operations.
DRILLING AND DEVELOPMENT ACTIVITY
The venture intends to conduct a 3-D seismic survey over the southwestern
portion of the Delta Centro Block beginning in 1996, at an expected total cost
to the Company of approximately $6-7 million, of which $2 million is expected
to be spent in 1996. Following the initial interpretation of the seismic data,
the venture intends to drill an initial exploration well during 1997, at a cost
to the Company of approximately $1.5 to 2 million. Seismic and drilling
programs during 1998-2000 will be based on the results of the 1996-1997
activity.
NORTH GUBKINSKOYE, RUSSIA
GENERAL
In December 1991, the joint venture agreement forming GEOILBENT among the
Company (34% interest) and two Russian partners, Purneftegasgeologia and
Purneftegas (each having a 33% interest), was registered with the Ministry of
Finance of the USSR. In November 1993, the agreement was registered with the
Russian Agency for International Cooperation and Development.
Purneftegasgeologia is the official geological body of the government whose
purpose has been to explore for oil and gas in the Purovsky district of Russia.
Purneftegas is the official production agency of the government responsible for
oil and gas production in the area. Although GEOILBENT may only take action
through the unanimous vote of the partners, the Company believes that it has
developed a good relationship with its partners and has not experienced any
disagreement with its partners on major operational matters. Mr. A.E. Benton,
Chief Executive Officer of the Company, serves as Chairman of the Board of
GEOILBENT.
LOCATION AND GEOLOGY
GEOILBENT develops, produces and markets crude oil from the North Gubkinskoye
Field in the West Siberia region of Russia, approximately 2,000 miles northeast
of Moscow. The field, which covers an area approximately 15 miles long and 4
miles wide, has been delineated with over 60 exploratory wells (which tested 26
separate reservoirs) and is surrounded by large proven fields. Before
commencement of GEOILBENT's operations, North Gubkinskoye was one of the
largest oil and gas fields in the region not under commercial production. The
field is a large anticlinal structure with multiple pay sands. The development
to date has focused on the BP 8, 9, 10, 11 and 12 reservoirs. The natural gas
which is produced is currently being flared in accordance with environmental
regulations.
DRILLING AND DEVELOPMENT ACTIVITY
GEOILBENT commenced initial operations in the field during the third quarter of
1992 with the construction of a 37-mile oil pipeline and installation of
temporary production facilities. During March 1996 (through March 28),
approximately 40 wells are producing an average of approximately 8,400 Bbls of
oil per day. The following table sets forth drilling activity and production
information for each of the quarters presented:
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Wells Drilled Average Daily
------------- -------------
Production from Field
---------------------
1994:
First Quarter . . 1 1,000
Second Quarter . 1 2,400
Third Quarter . . 2 2,200
Fourth Quarter . 5 4,900
1995:
First Quarter . . 1 4,300
Second Quarter . 1 5,600
Third Quarter . . 9 7,800
Fourth Quarter . 11 7,900
GEOILBENT contracts with third parties for drilling and completion of wells.
Supervised by a joint American and Russian management team, GEOILBENT
identifies drilling locations, then uses Russian drilling rigs, upgraded by
certain western technology and materials including shaker screens, monitoring
equipment and drilling and completion fluids, to drill and complete a well. To
date, 11 previously drilled wells have been reactivated and 32 wells have been
drilled in the field, with 28, or 88%, completed and placed on production.
Four drilling rigs are currently working on pads in the field, and once all
wells on the pad have been drilled, each such well will be tested for
completion. Each well is drilled to an average depth of approximately 10,000
feet measured depth and 8,000 feet true depth.
Once oil is produced from the North Gubkinskoye Field, it is transported to
production facilities constructed and owned by GEOILBENT. Oil is then
transferred to GEOILBENT's 37-mile pipeline which transports the oil from the
North Gubkinskoye Field south to the main Russian oil pipeline network.
The current production facilities are operating at or near capacity and would
need to be expanded to accommodate any increased production. Subject to
obtaining financing, GEOILBENT has a 1996 capital expenditure budget of
approximately $35 million, of which $21 million would be used to drill
approximately 36 wells in the North Gubkinskoye Field and $14 million for
construction of production facilities. Although no assurance can be given that
such financing will be obtained, GEOILBENT and the Company continue discussions
with the European Bank for Reconstruction and Development ("EBRD") for a
proposed $40 million facility, which would be non-recourse to the Company, to
be used for development of the North Gubkinskoye Field, including the
production facility expansion. If EBRD or other financing is not obtained,
minimal capital expenditures are anticipated and production from the field is
expected to experience a natural decline.
CUSTOMERS AND MARKET INFORMATION
GEOILBENT's 37-mile pipeline runs from the field to the main pipeline in the
area where GEOILBENT transfers the oil to Transneft, the state oil monopoly.
Transneft can transport the oil to the western border of Russia. All oil
production is for export and all oil sales are handled by trading companies
such as Russoil or NAFTA Moscow. During 1995, most of GEOILBENT's crude sales
were made to purchasers in Germany. All sales have been paid in U.S. dollars
into GEOILBENT's account in Moscow.
EMPLOYEES; COMMUNITY AND COUNTRY RELATIONS
Having access to the oilfield labor base in West Siberia, GEOILBENT employs
nationals almost exclusively. Presently, there are three full time expatriates
working with GEOILBENT and over 200 local employees. The Company conducts an
ongoing community relations program in Russia, providing medical care,
training, equipment and supplies in towns in which GEOILBENT personnel reside
and also for the nomadic indigenous population which resides in the area of
oilfield operations.
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ALTERNATIVES FOR NATURAL GAS RESERVES
The Company and GEOILBENT estimate that substantial recoverable associated gas
and condensate reserves exist in the North Gubkinskoye Field. In addition,
there are substantial non-associated natural gas reserves in the field.
Currently, there exists no ready market for these reserves, and therefore there
are no plans to produce these gas and condensate reserves. Associated gas and
condensate are flared in allowable amounts under permits with the Ministry of
Fuel and Energy. If no market develops for the gas and condensate, then over
time GEOILBENT plans to begin reinjecting them back into the reservoirs.
GEOILBENT currently has no rights to develop the gas caps in the field.
However, GEOILBENT has recently entered into discussions with Gazprom, the
state natural gas monopoly, for development and production of the solution gas,
which is estimated by the Company to be 550-600 Bcf. Implementation of such a
development plan would include construction of processing facilities and of a
natural gas pipeline from the field area to the main transmission pipeline.
Feasibility studies are currently in process and anticipated to be completed by
year end 1996. Further development, subject to approval of all parties, will
depend upon available financing.
OTHER PROPERTIES
Prior to 1996, the Company had successfully pursued acquisition and joint
venture opportunities in the United States as major oil and gas companies
continued to consolidate operations and focus exploration and development
activities outside the United States. Substantially all of the Company's
domestic activities had been located in the Louisiana Gulf Coast at the West
Cote Blanche Bay, Rabbit Island and Belle Isle Fields. The Company entered
into agreements with Texaco, Inc. ("Texaco") and Oryx Energy Company ("Oryx")
to produce the fields by using 3-D seismic technology integrated with
subsurface geologic data from previously drilled wells. In addition, the
Company entered into certain agreements with Tenneco Ventures Corporation
("Tenneco") whereby Tenneco purchased certain interests in the Company's
operations in the three fields and was given the right to participate as a 50%
partner in certain of the Company's future activities in the Gulf Coast for the
next five years.
In March 1995, the Company and its affiliates and Tenneco sold to WRT Energy
Corporation a 43.75% working interest in the shallower depths (above
approximately 10,575 feet) in the West Cote Blanche Bay Field for an aggregate
purchase price of $20 million. Of this aggregate purchase price, the Company
received $14.9 million.
In March 1996, the Company entered into an agreement to sell to Shell Offshore
Inc. ("Shell") all of its interests in the West Cote Blanche Bay, Rabbit Island
and Belle Isle Fields effective December 31, 1995, for a purchase price of
$35.4 million. The sale is subject to regulatory approval, and the Company
expects that the sale will be completed in April 1996. Because the properties
are held for sale, the Company's reserve report excludes all reserves
attributable to these properties.
At December 31, 1995, the Company had proved reserves of 1 MBOE in the Scott
Field in Louisiana.
EVALUATION OF ADDITIONAL OPPORTUNITIES
The Company continues to evaluate and pursue additional international
opportunities which fit within the Company's business strategy. The Company is
currently evaluating certain development and/or acquisition opportunities, but
it is not presently known whether, or on what terms, such evaluations will
result in future agreements or acquisitions.
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RESERVES
The following table sets forth information regarding estimates of proved
reserves at December 31, 1995 prepared by the Company and audited by Huddleston
& Co., Inc., independent petroleum engineers:
CRUDE OIL AND CONDENSATE (MBBL) NATURAL GAS(MMCF)
------------------------------------- --------------------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----- --------- ----------- -----
Venezuela(1) 30,032 43,561 73,593 -- -- --
Russia(2) 3,475 19,143 22,618 -- -- --
United States (3) -- -- -- 6 -- 6
------ ------ ------ ------ ------ -------
Total 33,507 62,704 96,211 6 0 6
====== ====== ====== ====== ====== =======
(1) Includes 100% of the reserve information, without deduction for minority
interest. All Venezuelan reserves are attributable to an operating
service agreement between Benton-Vinccler and Lagoven, under which all
mineral rights are owned by the Government of Venezuela. See Item 1.
Business--South Monagas Unit, Venezuela.
(2) Although the Company estimates that there are substantial natural gas
reserves in the North Gubkinskoye Field, no natural gas reserves have been
recorded because of a lack of a ready market.
(3) The Company has entered into an agreement to sell substantially all of its
U.S. reserves and acreage positions. See Item 1. Business -- Other
Properties. The table excludes the reserves to be sold.
There are numerous uncertainties inherent in estimating quantities of proved
reserves and in projecting future rates of production and the timing and amount
of development expenditures, including many factors beyond the control of the
producer. The reserve data set forth above only represent estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
crude oil and natural gas that cannot be measured in an exact manner, and the
accuracy of any reserve estimate is a function of the quality of available data
and of engineering and geological interpretation and judgment. As a result,
estimates of different engineers often vary. In addition, results of drilling,
testing and production subsequent to the date of an estimate may justify
revision of such estimate. Accordingly, reserve estimates are often different
from the quantities of crude oil and natural gas that are ultimately recovered.
The meaningfulness of such estimates is highly dependent upon the accuracy of
the assumptions upon which they were based.
PRODUCTION, PRICES AND LIFTING COST SUMMARY
The following table sets forth by country net production, average sales prices
and average lifting costs of the Company for the years ended December 31, 1995,
1994 and 1993:
YEARS ENDED DECEMBER 31
----------------------------------------------------------
1995 1994 1993
---------- ---------- -------
VENEZUELA
Net Crude Oil Production (Bbl) 5,456,473 2,519,514 160,425
Average Crude Oil Sales Price ($ per Bbl) $9.01 $8.52 $8.31
Average Lifting Costs ($ per Bbl) 1.19 1.51 7.26
RUSSIA (1)
Net Crude Oil Production (Bbl) 490,960 294,364 28,263
Average Crude Oil Sales Price ($ per Bbl) $12.25 $11.93 $11.46
Average Lifting Costs ($ per Bbl) 5.63 9.62 16.22
UNITED STATES
Net Production:
Crude oil and condensate (Bbl) 68,975 225,954 292,266
Natural Gas (Mcf) 3,784,830 2,061,892 232,677
Average Sales Price:
Crude oil and condensate ($ per Bbl) $15.79 $14.46 $17.30
Natural Gas ($ per Mcf) 1.77 1.79 2.19
Average Lifting Costs ($ per BOE) 2.08 5.08 10.53
- ----------------
(1) The 1995 presentation includes information for the nine months ended
September 30, 1995, the end of the fiscal period for GEOILBENT.
9
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REGULATION
GENERAL
The Company's operations are affected by political developments and laws and
regulations in the areas in which it operates. In particular, oil and gas
production operations and economics are affected by price controls, tax and
other laws relating to the petroleum industry, by changes in such laws and by
changing administrative regulations and the interpretations and application of
such rules and regulations. In addition, various federal, state, local and
international laws and regulations covering the discharge of materials into the
environment, the disposal of oil and gas wastes, or otherwise relating to the
protection of the environment, may affect the Company's operations and costs.
Oil and gas industry legislation and agency regulation is periodically changed
for a variety of political, economic, environmental and other reasons.
Numerous governmental departments and agencies issue rules and regulations
binding on the oil and gas industry, some of which carry substantial penalties
for the failure to comply. The regulatory burden on the oil and gas industry
increases the Company's cost of doing business.
In the past, the federal government has regulated the prices at which oil and
gas could be sold. Prices of oil and gas sold by the Company are not currently
regulated and sales may be made at uncontrolled market prices. The Company's
international operations are also subject to political, economic and other
uncertainties including, among others, risks of war, revolution, expropriation,
renegotiation or modification of existing contracts, export and transportation
tariffs, taxation and royalty policies, foreign exchange restrictions,
international monetary fluctuations and other hazards arising out of foreign
government sovereignty over certain areas in which the Company conducts
operations.
VENEZUELA
Venezuela requires environmental and other permits for certain operations
conducted in oil field development, such as site construction, drilling, and
seismic activities. As a contractor to Lagoven, Benton-Vinccler submits
capital and operating budgets to Lagoven for approval. Capital expenditures to
comply with Venezuelan environmental regulations relating to the reinjection of
gas in the field and water disposal are expected to approximate $7.8 million in
1996 and $14.4 million in 1997, respectively. Benton-Vinccler also submits
requests for permits for drilling, seismic and operating activities to Lagoven,
which then obtains such permits from the Ministry of Energy and Mines and
Ministry of Environment, as required. Benton-Vinccler is also subject to
income, municipal and value added taxes, and must file certain monthly and
annual compliance reports to SENIAT (the national tax administration) and to
various municipalities.
RUSSIA
GEOILBENT submits annual production and development plans, which include
information necessary for permits and approvals for its planned drilling,
seismic and operating activities, to local and regional governments and to the
Ministry of Fuel and Energy, Committee of Geology, Ministry of Economy, and
Ministry of Ecology. GEOILBENT also submits annual production targets and
quarterly export nominations for oil pipeline transportation capacity to the
Ministry of Fuel and Energy. GEOILBENT is subject to customs, value added, and
municipal and income taxes. Various municipalities and regional tax
inspectorates are involved in the assessment and collection of these taxes.
GEOILBENT must file operating and financial compliance reports with several
bodies, including the Ministries of Fuel and Energy, Geology, Committee for
Technical Mining Monitoring of the Ministry of Ecology, and the State Customs
Committee.
10
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DRILLING, ACQUISITION AND FINDING COSTS
During the years ended December 31, 1995, 1994 and 1993, the Company spent
approximately $74 million, $53 million, and $26 million, respectively, for
acquisitions of leases and producing properties, development and exploratory
drilling, production facilities and additional development activities such as
workovers and recompletions.
The Company has drilled or participated in the drilling of wells as follows:
YEARS ENDED DECEMBER 31,
-------------------------------------------------------------------
1995 1994 1993
----------------- --------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ------ ----- -----
WELLS DRILLED:
Exploratory:
Crude oil -- -- -- -- 1 0.435
Natural gas 3 .970 2 .875 -- --
Dry holes 1 .375 2 .869 2 0.869
Development:(1)(2)(3)
Crude oil 41 23.140 20 11.860 13 5.693
Natural Gas 1 .220 1 .435 -- --
Dry Holes 1 .800 -- -- 2 0.840
-- ------- --- ------ --- -----
TOTAL 47 25.505 25 14.039 18 7.837
== ======= === ====== === =====
AVERAGE DEPTH OF WELLS (FEET) 7,847 7,266 5,100
PRODUCING WELLS (4):
Crude Oil 77 44.701 112 46.796 106 42.942
Natural Gas 8 2.024 4 .822 6 1.271
(1) In addition to the activities set forth in the table, at the West Cote
Blanche Bay Field during the year ended December 31, 1994, the Company
participated in the successful recompletion of 13 gross (4.2471 net) oil
wells and one gross (.3267 net) gas well. During the year ended December
31, 1993, the Company participated in the recompletion of 13 gross (5.650
net) oil wells, of which 11 gross (4.781 net) were completed as producers,
and one gross (0.435 net) gas well, which was completed as a producer. In
March 1995, the Company sold certain of its interests in the field, a
result of which was to substantially eliminate the Company's future
participation in recompletion and redrilling activities and in March 1996,
the Company entered into an agreement to sell the remainder of its
interests in the field. See Item 1. Business -- Other Properties.
(2) In addition to the activities set forth in the table, the Company has
participated in the successful recompletion of five gross (4.0 net) oil
wells in Venezuela during the year ended December 31, 1994. The Company
participated in the successful reactivation of nine gross (4.5 net) oil
wells in Venezuela during the year ended December 31, 1993.
(3) In addition to the activities set forth in the table, the Company
participated in the successful reactivation of six gross (2.04 net) oil
wells in Russia during the year ended December 31, 1993. There were no
reactivations subsequent to December 31, 1993.
(4) The information related to producing wells reflects wells the Company has
drilled, wells the Company has participated in drilling and producing
wells the Company has acquired.
At December 31, 1995 the Company was participating in the drilling of 2 wells
in Venezuela, and 4 wells in Russia.
All of the Company's drilling activities are conducted on a contract basis with
independent drilling contractors. The Company does not own any drilling
equipment.
From commencement of operations through December 31, 1995, the Company added,
net of production and property sales, approximately 96,180 MBOE of proved
reserves through purchases of reserves-in-place, discoveries of oil and natural
gas reserves, extensions of existing producing fields and revisions of
previously estimated reserves. The Company's finding and development costs for
its proved reserves from inception to December 31, 1995 were $1.75 per BOE.
The Company's estimate
11
14
of future development costs for its undeveloped proved reserves at December 31,
1995 was $1.80 per BOE. The estimated future development costs are based upon
the Company's anticipated cost of developing its non-producing proved reserves,
which costs are calculated using historical costs for similar activities.
ACREAGE
The following table summarizes the developed and undeveloped acreage owned,
leased or under concession as of December 31, 1995. See Item 1. Business --
Other Properties.
DEVELOPED UNDEVELOPED
--------- -----------------
GROSS NET GROSS NET
----- ---- ----- ------
VENEZUELA 7,520 6,016 150,323 120,258
RUSSIA 15,920 5,413 45,580 15,497
UNITED STATES(1) 5,002 1,689 10,000 6,862
------ ------ ------- -------
TOTAL 28,442 13,118 205,903 142,617
====== ====== ======= =======
- -------------
(1) The Company has entered into an agreement to sell substantially all of its
U.S. reserves and related acreage positions. The table excludes the acreage to
be sold. See Item 1.Business -- Other Properties.
COMPETITION
The Company encounters strong competition from major oil and gas companies and
independent operators in acquiring properties and leases for exploration for
crude oil and natural gas. The principal competitive factors in the
acquisition of such oil and gas properties include the staff and data necessary
to identify, investigate and purchase such leases, and the financial resources
necessary to acquire and develop such leases. Many of the Company's
competitors have financial resources, staffs and facilities substantially
greater than those of the Company.
EMPLOYEES AND CONSULTANTS
At December 31, 1995 the Company had 43 employees and one independent
consultant. Benton-Vinccler had 109 employees and GEOILBENT had 220 employees.
TITLE TO DEVELOPED AND UNDEVELOPED ACREAGE
All Venezuelan reserves are attributable to an operating service agreement
between Benton-Vinccler and Lagoven, under which all mineral rights are owned
by the Government of Venezuela. With regard to Russian acreage, GEOILBENT has
obtained certain documentation from appropriate regulatory bodies in Russia
which the Company believes is adequate to establish GEOILBENT's right to
develop, produce and market oil and gas from the North Gubkinskoye Field in
Russia.
At the time of acquisition of undeveloped acreage in the United States, the
Company conducted a limited title investigation. A title opinion from a
qualified law firm was obtained prior to drilling any given U.S. prospect.
Title to presently producing properties had been investigated by a qualified
law firm prior to purchase. The Company believes its method of investigating
the title to these domestic properties was consistent with general practices in
the oil and gas industry and was designed to enable the Company to acquire
title which was generally considered to be acceptable in the oil and gas
industry.
12
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GLOSSARY
When the following terms are used in the text they have the meanings indicated.
MCF. "Mcf" means thousand cubic feet. "Mmcf" means million cubic feet.
"Bcf" means billion cubic feet. "Tcf" means trillion cubic feet.
BBL. "Bbl" means barrel. "MBbl" means thousand barrels. "MMBbl" means
million barrels. "Bbbl" means billion barrels.
BOE. "BOE" means barrels of oil equivalent, which are determined using the
ratio of one barrel of crude oil, condensate or natural gas liquids to six Mcf
of natural gas so that six Mcf of natural gas is referred to as one barrel of
oil equivalent or "BOE". "MBOE" means thousands of barrels of oil equivalent.
"MMBOE" means millions of barrels of oil equivalent.
CAPITAL EXPENDITURES. "Capital Expenditures" means costs associated with
exploratory and development drilling (including exploratory dry holes);
leasehold acquisitions; seismic data acquisitions; geological, geophysical and
land-related overhead expenditures; delay rentals; producing property
acquisitions; and other miscellaneous capital expenditures.
COMPLETION COSTS. "Completion Costs" means, as to any well, all those costs
incurred after the decision to complete the well as a producing well.
Generally, these costs include all costs, liabilities and expenses, whether
tangible or intangible, necessary to complete a well and bring it into
production, including installation of service equipment, tanks, and other
materials necessary to enable the well to deliver production.
DEVELOPMENT WELL. A "Development Well" is a well drilled as an additional
well to the same reservoir as other producing wells on a lease, or drilled on
an offset lease not more than one location away from a well producing from the
same reservoir.
EXPLORATORY WELL. An "Exploratory Well" is a well drilled in search of a new
and as yet undiscovered pool of oil or gas, or to extend the known limits of a
field under development.
FINDING COST. "Finding Cost", expressed in dollars per BOE, is calculated
by dividing the amount of total capital expenditures related to acquisitions,
exploration and development costs (reduced by proceeds for any sale of oil and
gas properties) by the amount of total net reserves added or reduced as a
result of property acquisitions and sales, drilling activities and reserve
revisions during the same period.
FUTURE DEVELOPMENT COST. "Future Development Cost" of proved nonproducing
reserves, expressed in dollars per BOE, is calculated by dividing the amount of
future capital expenditures related to development properties by the amount of
total proved non-producing reserves associated with such activities.
GROSS ACRES OR WELLS. "Gross Acres or Wells" are the total acres or wells,
as the case may be, in which an entity has an interest, either directly or
through an affiliate.
LIFTING COSTS. "Lifting Costs" are the expenses of lifting oil from a
producing formation to the surface, consisting of the costs incurred to operate
and maintain wells and related equipment and facilities, including labor costs,
repair and maintenance, supplies, insurance, production, severance and windfall
profit taxes.
NET ACRES OR WELLS. A party's "Net Acres" or "Net Wells" are calculated by
multiplying the number of gross acres of gross wells in which that party has an
interest by the fractional interest of the party in each such acre or well.
PRODUCING PROPERTIES OR RESERVES. "Producing Reserves" are Proved Developed
Reserves expected to be produced from existing completion intervals now open
for production in existing wells. "Producing Properties" are properties to
which Producing Reserves have been assigned by an independent petroleum
engineer.
PROVED DEVELOPED RESERVES. "Proved Developed Reserves" are Proved Reserves
which can be expected to be recovered through existing wells with existing
equipment and operating methods.
PROVED RESERVES. "Proved Reserves" are the estimated quantities of crude
oil, natural gas and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known oil and
13
16
gas reservoirs under existing economic and operating conditions, that is, on
the basis of prices and costs as of the date the estimate is made and any price
changes provided for by existing conditions.
PROVED UNDEVELOPED RESERVES. "Proved Undeveloped Reserves" are 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.
RESERVES. "Reserves" means crude oil and natural gas, condensate and natural
gas liquids, which are net of leasehold burdens, are stated on a net revenue
interest basis, and are found to be commercially recoverable.
ROYALTY INTEREST. A "Royalty Interest" is an interest in an oil and gas
property entitling the owner to a share of oil and gas production (or the
proceeds of the sale thereof) free of the costs of production.
STANDARDIZED MEASURE OF FUTURE NET CASH FLOWS. The "Standardized Measure of
Future Net Cash Flows" is a method of determining the present value of Proved
Reserves. The future net revenues from Proved Reserves are estimated assuming
that oil and gas prices and production costs remain constant. The resulting
stream of revenues is then discounted at the rate of 10% per year to obtain a
present value.
3-D SEISMIC. "3-D Seismic" is the method by which a three dimensional image
of the earth's subsurface is created through the interpretation of seismic
data. 3-D surveys allow for a more detailed understanding of the subsurface
than do conventional surveys and contribute significantly to field appraisal,
development and production.
UNDEVELOPED ACREAGE. "Undeveloped Acreage" is oil and gas acreage
(including, in applicable instances, rights in one or more horizons which may
be penetrated by existing wellbores, but which have not been tested) to which
Proved Reserves have not been assigned by independent petroleum engineers.
ITEM 2. PROPERTIES
The principal executive offices of the Company are located in leased space in
Carpinteria, California. The lease covering this facility expires in December
2004. The Company also has other offices located in leased space, none of
which individually or in the aggregate are material. For information
concerning the location and character of the Company's oil and gas properties
and interests, see Item 1.
ITEM 3. LEGAL PROCEEDINGS
On June 13, 1994, Charles Agnew and other limited partners in several limited
partnerships formed by the Company brought an action in the Superior Court of
California, County of Ventura, against the Company for alleged actions and
omissions of the Company in operating the partnerships and alleged
misrepresentations made by the Company in selling the limited partnership
interests. The claimants seek an unspecified amount of actual and punitive
damages. On May 17, 1995, the Company agreed to a binding arbitration
proceeding with respect to such claims, which is currently in the discovery
stage. The Company will be forced to spend time and financial resources to
defend or resolve these matters. In January 1996, the Company acquired all of
the interests in three of the limited partnerships which are the subject of the
arbitration, in exchange for shares of, and warrants to purchase shares of, the
Company's common stock. In the arbitration proceeding, if any liability is
found to exist, the arbitrator will determine the amount of any damages, and
may consider all distributions made to the partners, including the
consideration received in the exchange offer, in determining the extent of
damages, if any. However, there can be no assurance that an arbitrator will
consider such factors in his or her determination of damages if the allegations
are found to be true and damages are awarded.
On March 15, 1993, Louis J. Dezseran and other investors sued North Bay
Associates, the Company and others in connection with their investments in
partnerships in which North Bay was the general partner. The suit was filed in
the Superior Court of Los Angeles County, California. The Company was not a
partner, but provided oil and gas prospects and drilled and operated a number
of wells for the partnerships. The plaintiffs claim that the Company aided
North Bay in misrepresentation, fraud, and breach of fiduciary duties. Although
the Company believed that its defenses were meritorious, the Company and the
plaintiffs settled the litigation out of court by an agreement dated December
15, 1995 under which the Company paid an aggregate of $990,000 to the
plaintiffs.
The Company is also subject to ordinary litigation that is incidental to its
business.
14
17
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
During the three month period ended December 31, 1995 no matter was submitted
to a vote of security holders.
15
18
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
The Company's Common Stock is traded on the NASDAQ-National Market System
("NASDAQ-NMS") under the symbol "BNTN." As of December 31, 1995, there were
25,508,605 shares of Common Stock outstanding held of record by approximately
1,050 stockholders. The following table sets forth the high and low sales
prices for the Company's Common Stock reported on the NASDAQ-NMS.
YEAR QUARTER HIGH LOW
---------------------------------------------------------------------------------
1994
First quarter 7.00 4.25
Second quarter 7.63 5.38
Third quarter 7.75 6.50
Fourth quarter 9.13 7.00
1995
First quarter 11.13 8.63
Second quarter 15.13 10.25
Third quarter 13.88 9.50
Fourth quarter 16.13 10.13
1996
First quarter (through March 28) 16.63 11.25
On March 28, 1996, the last sales price for the Common Stock as reported by
NASDAQ-NMS was $15.69 per share.
The Company's policy is to retain its earnings to support the growth of the
Company's business. Accordingly, the Board of Directors of the Company has
never declared cash dividends on its Common Stock. The Company's credit
agreements currently prohibit the declaration of any cash dividends.
16
19
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The following selected consolidated financial data for the Company for each of
the five years in the period ended December 31, 1995, are derived from the
Company's audited consolidated financial statements. The consolidated
financial data below should be read in conjunction with the Company's
Consolidated Financial Statements and related notes thereto and Item 7. --
Management's Discussion and Analysis of Financial Condition and Results of
Operations contained elsewhere in this report.
YEARS ENDED DECEMBER 31,
--------------------------------------------------------------
1995 (5) 1994 1993 1992 1991(3)
----------- -------- ---------- ------- -------
(amounts in thousands, except per share data)
STATEMENT OF OPERATIONS:
Total revenues $ 65,068 $ 34,705 $ 7,503 $ 8,622 $ 11,513
Lease operating costs and production taxes 10,703 9,531 5,110 4,414 4,209
Depletion, depreciation and amortization 17,411 10,298 2,633 3,041 3,058
General and administrative expense 9,411 5,242 2,631 2,245 1,998
Interest expense 7,497 3,888 1,958 1,831 1,736
Litigation settlement expenses 1,673 -- -- -- --
-------- ---------- -------- -------- --------
Income (loss) before income taxes and
minority interest 18,373 5,746 (4,829) (2,909) 512
Income tax expense 2,478 698 - -
--------- ---------- ---------- ---------- ---------
Income (loss) before minority interest 15,895 5,048 (4,829) (2,909) 512
Minority interest 5,304 2,094 -- -- --
--------- --------- ----------- ---------- ---------
Net income (loss) $ 10,591 $ 2,954 $(4,829) $(2,909) $ 512
========= ========= =========== ========== =========
Net income (loss) per common share (1) $ 0.40 $ 0.12 $ (0.26) $ (0.22) $ 0.04
Weighted average common shares
outstanding (1) (2) 26,673 24,851 18,609 12,981 11,838
AT DECEMBER 31,
----------------------------------------------------------------
1995(5) 1994 1993 1992 1991
---------- -------- --------- --------- ----------
BALANCE SHEET DATA: (amounts in thousands)
Working capital (deficit) $ (2,888) $21,785 $26,635 $10,486 $(14,777)
Total assets 214,750 162,561 108,635 68,217 49,386
Long-term obligations, net of current portion 49,486 31,911 11,788 13,463 7,422
Stockholders' equity (4) 103,681 88,259 84,021 50,468 20,209
- -------------------------
(1) The share information for the Company has been adjusted to reflect a
two-for-one stock split in the form of a 100% stock dividend effective
February 26, 1991.
(2) The weighted average common shares outstanding for the Company have been
adjusted for the effect of common stock equivalents for the years ended
December 31, 1995 and 1991.
(3) For the year ended December 31, 1991 the Company recorded income tax
expense of $174,000 and an extraordinary item for the utilization of loss
carryforward for the same amount.
(4) No cash dividends were paid during any period presented.
(5) The financial information related to Russia and included in the 1995
presentation contains information at, and for the nine months ended,
September 30, 1995, the end of the fiscal period for GEOILBENT. See Note
15 to the Consolidated Financial Statements.
17
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
Principles of Consolidation and Accounting Methods
- --------------------------------------------------
The Company has included the results of operations of Benton-Vinccler in its
consolidated statement of operations since January 1, 1994 and has reflected
the 50% ownership interest of Vinccler during January and February 1994 and the
20% ownership interest of Vinccler subsequent thereto as a minority interest.
Prior to 1994, Benton-Vinccler was proportionately consolidated based on the
Company's 50% ownership interest. Beginning in 1995, GEOILBENT has been
included in the consolidated financial statements based on a fiscal period
ending September 30. Results of operations in Russia reflect the twelve months
ended December 31, 1993 and 1994 and the nine months ended September 30, 1995.
The Company's investment in GEOILBENT is proportionately consolidated based on
the Company's ownership interest, and for oil and gas reserve information, the
Company reports its 34% share of the reserves attributable to GEOILBENT.
The Company follows the full-cost method of accounting for its investments in
oil and gas properties. The Company capitalizes all acquisition, exploration,
and development costs incurred. The Company accounts for its oil and gas
properties using cost centers on a country by country basis. Proceeds from
sales of oil and gas properties are credited to the full-cost pools.
Capitalized costs of oil and gas properties are amortized within the cost
centers on an overall unit-of-production method using proved oil and gas
reserves as determined by independent petroleum engineers. Costs amortized
include all capitalized costs (less accumulated amortization), the estimated
future expenditures (based on current costs) to be incurred in developing
proved reserves, and estimated dismantlement, restoration and abandonment
costs. See Note 1 of Notes to Consolidated Financial Statements.
The following discussion of the results of operations and financial condition
for the years ended December 31, 1995 and 1994 and for each of the years in the
three year period ended December 31, 1995, respectively, should be read in
conjunction with the Company's Consolidated Financial Statements and related
notes thereto.
RESULTS OF OPERATIONS
The following table presents the Company's consolidated income statement items
as a percentage of total revenues:
1995 1994 1993
---- ---- ----
Oil and Gas Sales 95.5% 92.0% 96.3%
Net Gain (Loss) on Exchange Rates 1.6 4.2 (2.8)
Investment Earnings 2.7 3.4 5.2
Other 0.2 0.4 1.3
----- ----- -----
Total Revenues 100.0 100.0 100.0
----- ----- -----
Lease Operating Costs and Production Taxes 16.4 27.4 68.1
Depletion, Depreciation and Amortization 26.8 29.7 35.1
General and Administrative 14.5 15.1 35.0
Interest 11.5 11.2 26.1
Litigation Settlement Expenses 2.6 --- ---
----- ----- -----
Total Expenses 71.8 83.4 164.3
----- ------ -----
Income (Loss) Before Income Taxes and Minority Interest 28.2 16.6 (64.3)
Income Tax Expense 3.8 2.0 ---
Minority Interest 8.1 6.1 ---
----- ------ -----
Net Income (Loss) 16.3% 8.5% (64.3)%
===== ====== =====
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21
YEARS ENDED DECEMBER 31, 1995 AND 1994
The Company had revenues of $65.1 million for the year ended December 31, 1995.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $10.7 million, depletion, depreciation and amortization
expense of $17.4 million, general and administrative expense of $9.4 million,
interest expense of $7.5 million, litigation settlement expenses of $1.7
million, income tax expense of $2.5 million and a minority interest of $5.3
million. Net income for the period was $10.6 million or $0.40 per share.
By comparison, the Company had revenues of $34.7 million for the year ended
December 31, 1994. Expenses incurred during the period consisted of lease
operating costs and production taxes of $9.5 million, depletion, depreciation
and amortization expense of $10.3 million, general and administrative expense
of $5.2 million, interest expense of $3.9 million, income tax expense of $0.7
million and a minority interest of $2.1 million. The net income for the period
was $3.0 million or $0.12 per share.
Revenues increased $30.4 million, or 87%, during the year ended December 31,
1995 compared to the corresponding period of 1994 primarily due to increased
oil sales in Venezuela. Sales quantities for the year ended December 31, 1995
from Venezuela and Russia were 5,456,473 and 490,960 Bbl, respectively,
compared to 2,519,514 and 294,364, respectively, for the year ended December
31, 1994. Prices for crude oil averaged $9.01 (pursuant to terms of an
operating service agreement) from Venezuela and $12.25 from Russia for the year
ended December 31, 1995 compared to $8.52 and $11.93 from Venezuela and Russia,
respectively, for the year ended December 31, 1994. Domestic sales quantities
for the year ended December 31, 1995 were 68,975 Bbl of crude oil and
condensate and 3,784,830 Mcf of natural gas compared to 225,954 Bbl of crude
oil and 2,061,892 Mcf of natural gas for the year ended December 31, 1994.
Domestic prices for crude oil and natural gas averaged $15.79 per Bbl and $1.77
per Mcf during the year ended December 31, 1995 compared to $14.46 per Bbl and
$1.79 per Mcf during the year ended December 31, 1994. Revenues for the year
ended December 31, 1995 were reduced by a loss of $0.7 million related to a
commodity hedge agreement compared to $0.3 million in 1994. Revenues for the
year ended December 31, 1995 were increased by a foreign exchange gain of $1.0
million compared to a gain of $1.4 million in 1994.
Lease operating costs and production taxes increased $1.2 million, or 12%,
during the year ended December 31, 1995 compared to 1994 primarily due to the
growth of the Company's Venezuelan operations, partially offset by the sale of
certain of the Company's interest in the West Cote Blanche Bay Field.
Depletion, depreciation and amortization increased $7.1 million, or 69%,
during the year ended December 31, 1995 compared to the corresponding period in
1994 primarily due to the increased oil production in Venezuela. Depletion
expense per barrel of oil equivalent produced from Venezuela, United States and
Russia during the year ended December 31, 1995 was $2.09, $5.98 and $3.08,
respectively, compared to $1.98, $7.46 and $2.85, respectively, during the
previous year. The increase in general and administrative expenses of $4.2
million, or 80%, during the year ended December 31, 1995 compared to 1994 was
primarily due to the Company's increased corporate activity associated with the
growth of the Company's business. The Company incurred litigation settlement
expenses of $1.7 million during the year ended December 31, 1995 as a result of
a settlement agreement reached with investors in partnerships which were
sponsored by a third party. See Note 5 to the Consolidated Financial
Statements. Interest expense increased $3.6 million, or 93%, in 1995 compared
to 1994 primarily due to increased borrowing to fund operations in Venezuela
and Russia. Income tax expense increased $1.8 million, or 255%, during the
year ended December 31, 1995 compared to 1994 primarily due to increased income
taxes in Venezuela and Russia. The net income attributable to the minority
interest increased $3.2 million, or 153%, for 1995 compared to 1994 as a result
of the increased profitability of Benton-Vinccler's operations in Venezuela.
YEARS ENDED DECEMBER 31, 1994 AND 1993
The Company had revenues of $34.7 million for the year ended December 31, 1994.
Expenses incurred during the period consisted of lease operating costs and
production taxes of $9.5 million, depletion, depreciation and amortization
expense of $10.3 million, general and administrative expense of $5.2 million,
interest expense of $3.9 million, income tax expense of $0.7 million, and a
minority interest of $2.1 million. The net income for the period was $3.0
million or $0.12 per share.
By comparison, the Company had revenues of $7.5 million for the year ended
December 31, 1993. Expenses incurred during the period consisted of lease
operating costs and production taxes of $5.1 million, depletion, depreciation
and amortization expense of $2.6 million, general and administrative expense of
$2.6 million and interest expense of $2.0 million. The net loss for the period
was $4.8 million or $0.26 per share.
Revenues increased $27.2 million, or 362%, during the year ended December 31,
1994 compared to the corresponding period of 1993 primarily due to increased
revenues from Benton-Vinccler's operations in Venezuela, the Company's
increased ownership of Benton-Vinccler, the initiation of oil sales in Russia
in late 1993, gain on exchange rates in Venezuela and Russia, gas sales from
19
22
the #831 well in the West Cote Blanche Bay Field and increased investment
earnings. The increase was partially offset by lower oil sales from the West
Cote Blanche Bay Field, lower sales prices and the sale of the Company's
interest in the Pershing property in 1993. Sales quantities for the year ended
December 31, 1994 from Venezuela and Russia were 2,519,514 and 294,364 Bbl,
respectively, compared to 160,425 and 28,263 Bbl, respectively, for the year
ended December 31, 1993. Prices for crude oil averaged $8.52 (pursuant to
terms of an operating service agreement) from Venezuela and $11.93 from Russia
for the year ended December 31, 1994 compared to $8.31 and $11.46 from
Venezuela and Russia, respectively for the year ended December 31, 1993.
Domestic sales quantities for the year ended December 31, 1994 were 225,954 Bbl
of crude oil and condensate and 2,061,892 Mcf of natural gas compared to
292,266 Bbl of crude oil and condensate and 232,677 Mcf of natural gas for the
year ended December 31, 1993. Domestic prices for crude oil and natural gas
averaged $14.46 per Bbl and $1.79 per Mcf during the year ended December 31,
1994 compared to $17.30 per Bbl and $2.19 per Mcf during the year ended
December 31,1993. The Company has realized net foreign exchange gains during
1994 primarily as a result of the decline in the value of the Venezuelan
bolivar and Russian rouble during periods when Benton-Vinccler and GEOILBENT
had substantial net monetary liabilities denominated in bolivares and roubles.
Lease operating costs and production taxes increased $4.4 million, or 87%,
during the year ended December 31, 1994 compared to 1993 primarily due to the
growth of the Company's Venezuelan and Russian operations and were partially
offset by the sale of the Company's interest in certain property in 1993 and
reduced operating costs at the West Cote Blanche Bay Field. Depletion,
depreciation and amortization increased $7.7 million, or 291%, during the year
ended December 31, 1994 compared to 1993 primarily due to increased oil
production in Venezuela, gas sales from the #831 well in the West Cote Blanche
Bay Field and the initiation of oil production in Russia. Depletion expense
per BOE produced from the United States, Venezuela and Russia during the year
ended December 31, 1994 was $7.46, $1.98 and $2.85, respectively, compared to
$6.47, $1.43 and $3.51 during 1993. The increase in general and administrative
expense of $2.6 million, or 99%, in 1994 compared to 1993 was primarily due to
the growth of and the Company's increased ownership of Benton-Vinccler, the
commencement of operations in Russia and increased corporate activity
associated with the growth of the Company's business. Interest expense
increased $1.9 million, or 99%, in 1994 compared to 1993 primarily due to
increased borrowing to fund operations in Venezuela and Russia.
The Company has included the results of operations of Benton-Vinccler in its
consolidated statement of income since January 1, 1994 and has reflected the
50% ownership interest of Vinccler during January and February and the 20%
ownership interest of Vinccler thereafter as a minority interest. For the year
ended December 31, 1994, minority interest expense was $2.1 million.
INTERNATIONAL OPERATIONS
The Company's costs of operations in Venezuela and Russia in 1993, 1994 and
1995 include certain fixed or minimum office, administrative, legal and
personnel related costs and certain start up costs, including short term
facilities rentals, organizational costs, contract services and consultants.
Such costs are expected to grow over time as operations increase. In the last
two years such costs have become less significant on a unit of production
basis, but such costs can be expected to fluctuate in the future based upon a
number of factors. In Venezuela, for the year ended December 31, 1993, the
operating costs and general and administrative expenses were $7.26 and $2.25
per Bbl, respectively. For the year ended December 31, 1995 the operating
costs and general and administrative expenses for Venezuela decreased to $1.19
and $0.63 per Bbl, respectively. The Company's Venezuelan operations grew
considerably during 1994 and 1995, and are expected to continue to grow, and
its operating costs and general and administrative expenses are expected to
increase both in the aggregate and on a per unit basis. In Russia, for the
year ended December 31, 1993, the operating costs and general and
administrative expenses were $16.22 and $12.96 per Bbl, respectively,
decreasing to $5.63 and $1.16 per Bbl, respectively, for the year ended
December 31, 1995. The Company's Russian operations grew less significantly
than the Venezuelan operations during 1994 and 1995. Capital expenditures
through 1993 in both Venezuela and Russia focused on start-up infrastructure
items such as roads, pipelines, and facilities rather than drilling. Beginning
in 1994, a higher proportion of capital expenditures have been and will
continue to be spent on drilling and production activities. See Item
1.Business--South Monagas Unit, Venezuela--Drilling and Development Activity
and --North Gubkinskoye, Russia--Drilling and Development Activity.
As a private contractor, Benton-Vinccler is subject to a statutory income tax
rate of 34%. However, Benton-Vinccler reported significantly lower effective
tax rates for 1994 and 1995 due to significant non-cash tax deductible expenses
resulting from devaluations in Venezuela when Benton-Vinccler had net monetary
liabilities in U.S. dollars. The Company cannot predict the timing or impact
of future devaluations in Venezuela. Any Company operations related to Delta
Centro will be subject to oil and gas industry taxation, which currently
provides for royalties of 16.67% and income taxes of 66.67%. See Item 1.
Business -- Delta Centro Block, Venezuela.
20
23
GEOILBENT is subject to a statutory income tax rate of 35%. GEOILBENT has also
been subject to various other tax burdens, including an oil export tariff. The
export tariff was 30 ECU's per ton through 1995, although GEOILBENT obtained an
exemption from such tariff for 1995. The tariff was reduced to 20 ECU's per
ton in January 1996, and Russia has recently announced that effective July
1996, oil export tariffs will be terminated. The Company anticipates that the
tariff on oil exporters may be replaced by an excise or other duty levied on
all oil producers, but it is currently unclear how such other tax rates and
regimes will be set and administered.
EFFECTS OF CHANGING PRICES, FOREIGN EXCHANGE RATES AND INFLATION
The Company's results of operations and cash flow are affected by changing oil
and gas prices. However, the Company's Venezuelan revenues are based on a fee
adjusted quarterly by the percentage change of a basket of crude oil prices
instead of by absolute dollar changes, which dampens both any upward and
downward effects of changing prices on the Company's Venezuelan revenues and
cash flows. If the price of oil and gas increases, there could be an increase
in the cost to the Company for drilling and related services because of
increased demand, as well as an increase in revenues. Fluctuations in oil and
gas prices may affect the Company's total planned development activities and
capital expenditure program.
Effective May 1, 1994, the Company entered into a commodity hedge agreement
with Morgan Guaranty designed to reduce a portion of the Company's risk from
oil price movements. Pursuant to the hedge agreement, with respect to the
period from May 1, 1994 through the end of 1996, the Company will receive from
Morgan Guaranty $16.82 per Bbl and the Company will pay to Morgan Guaranty the
average price per Bbl of West Texas Intermediate Light Sweet Crude Oil ("WTI")
determined in the manner set forth in the hedge agreement. Such payments will
be made with respect to production of 1,000 Bbl of oil per day for 1994, 1,250
Bbl of oil per day for 1995, and 1,500 Bbl of oil per day for 1996. During the
quarter ended December 31, 1995, the average price per Bbl of WTI was $18.12
and the Company's net exposure for the quarter was $0.1 million. The Company's
total exposure for the year ended December 31, 1995, under the hedge agreement
was $0.7 million. The Company's oil production is not materially affected by
seasonality. The returns under the hedge agreement are affected by world-wide
crude oil prices, which are subject to wide fluctuation in response to a
variety of factors that are beyond the control of the Company.
There are presently no restrictions in either Venezuela or Russia that restrict
converting U.S. dollars into local currency. However, during 1994, Venezuela
implemented exchange controls which significantly limit the ability to convert
local currency into U.S. dollars. Because payments made to Benton-Vinccler are
made in U.S. dollars into its United States bank account, and Benton-Vinccler
is not subject to regulations requiring the conversion or repatriation of those
dollars back into the country, the exchange controls have not had to date a
material adverse effect on Benton-Vinccler or the Company. Currently, there
are no exchange controls in Russia that restrict conversion of local currency
into U.S. dollars.
Within the United States, inflation has had a minimal effect on the Company,
but is potentially an important factor in results of operations in Venezuela
and Russia. With respect to Benton-Vinccler and GEOILBENT, substantially all
of the sources of funds, including the proceeds from oil sales, the Company's
contributions and credit financings, are denominated in U.S. dollars, while
local transactions in Russia and Venezuela are conducted in local currency. If
the exchange controls described above continue in Venezuela, then inflation
could be expected to have an adverse effect on Benton-Vinccler.
During the year ended December 31, 1995, the Company realized net foreign
exchange gains, primarily as a result of the decline in the value of the
Venezuelan bolivar and the Russian rouble during periods when Benton-Vinccler
and GEOILBENT had substantial net monetary liabilities denominated in bolivares
and roubles. During the year ended December 31, 1995, the Company's net
foreign exchange gains attributable to its Venezuelan operations were $1.0
million and net foreign exchange losses attributable to its Russian operations
were $0.1 million. However, there are many factors affecting foreign exchange
rates and resulting exchange gains and losses, many of which are beyond the
influence of the Company. The Company has recognized significant exchange
gains and losses in the past, resulting from fluctuations in the relationship
of the Venezuelan and Russian currencies to the U.S. dollar. It is not
possible to predict the extent to which the Company may be affected by future
changes in exchange rates and exchange controls.
CAPITAL RESOURCES AND LIQUIDITY
The oil and gas industry is a highly capital intensive business. The Company
requires capital principally to fund the following costs: (i) drilling and
completion costs of wells and the cost of production and transportation
facilities; (ii) geological, geophysical and seismic costs; and (iii)
acquisition of interests in oil and gas properties. The amount of available
capital will affect the scope of the Company's operations and the rate of its
growth.
21
24
The net funds raised and/or used in each of the operating, investing and
financing activities for each of the years in the three year period ended
December 31, 1995 are summarized in the following table and discussed in
further detail below:
YEARS ENDED DECEMBER 31,
-------------------------------------------------------
1995 1994 1993
------- ------ -------
Net cash provided by (used in) operating
activities $ 32,349,456 $ 13,462,789 $(1,789,965)
Net cash used in investing activities (53,643,733) (55,078,138) (18,618,794)
Net cash provided by financing activities 13,281,707 19,499,799 43,043,889
------------ ------------ -----------
Net increase (decrease) in cash $ (8,012,570) $(22,115,550) $22,635,130
============ ============ ===========
At December 31, 1995, the Company had current assets of $51.6 million
(including $19.3 million of cash restricted as collateral for a loan to
Benton-Vinccler), and current liabilities of $54.5 million (including a $19.3
million loan collateralized by restricted cash), resulting in a working capital
deficit of $2.9 million and a current ratio of .95:1. This compares to the
Company's working capital of $21.8 million at December 31, 1994. The decrease
of $24.7 million was due primarily to the use of working capital for capital
expenditures in Venezuela.
Cash Flow from Operating Activities. During 1995 and 1994, net cash provided
by operating activities was approximately $32.4 million and $13.5 million,
respectively, and during 1993, net cash used in operating activities was
approximately $1.8 million. Cash flow from operating activities increased by
$18.9 million and $15.3 million in 1995 and 1994, respectively, over the prior
year due primarily to increased oil and gas production in Venezuela.
Cash Flow from Investing Activities. During 1995, 1994 and 1993, the Company
had drilling and production related capital expenditures of approximately $68.3
million, $39.6 million and $26.2 million, respectively. Of the 1995
expenditures, $49.0 million was attributable to the development of the South
Monagas Unit in Venezuela, $12.4 million related to the development of the
North Gubkinskoye Field in Russia, $6.0 million related to drilling activity in
the West Cote Blanche Bay, Rabbit Island and Belle Isle Fields in Louisiana,
and $0.9 million was attributable to other projects. The Company also sold
certain oil and gas properties for net proceeds of approximately $15.4 million,
$5.8 million and $7.8 million in 1995, 1994 and 1993, respectively.
In March 1996, the Company agreed to sell to Shell all of its interests in the
West Cote Blanche Bay, Rabbit Island and Belle Isle Fields for a purchase price
of $35.4 million. Proceeds of the sale will be used to repay debt as described
below and for working capital purposes in Venezuela and other international
activities.
Cash Flow from Financing Activities. On June 30, 1995, the Company issued $20
million in senior unsecured notes due June 30, 2007, with interest at 13% per
annum, payable semi-annually on June 30 and December 31. Annual principal
payments of $4 million are due on June 30 of each year beginning on June 30,
2003. Early payment of the notes would result in a substantial prepayment
premium. The note agreement contains financial covenants including a minimum
ratio of current assets to current liabilities and a maximum ratio of funded
liabilities to net worth and to domestic oil and gas reserves. The note
agreement also provides for limitations on liens, additional indebtedness,
certain capital expenditures, dividends, sales of assets and mergers.
Additionally, in connection with the issuance of the notes, the Company issued
warrants entitling the holder to purchase 125,000 shares of common stock at
$17.09 per share, subject to adjustment in certain circumstances, that are
exercisable on or before June 30, 2007. Upon consummation of the sale of the
U.S. properties to Shell, the Company expects to refinance these senior
unsecured notes and will pay a prepayment premium estimated to be $7.7 million.
The holders of the senior notes have provided consent to the sale of the U.S.
properties and such consent requires payment of the notes on or before June 30,
1996. There can be no assurance that the Company will be able to refinance
such notes prior to June 30, 1996, or the terms of any such financing.
On September 30, 1994, the Company issued $15 million in senior unsecured notes
due September 30, 2002, with interest at 13% per annum. The note agreement
contains financial covenants and provides for limitations on sales of assets.
The holders of the senior unsecured notes have provided consent to the sale of
the U.S. properties to Shell, and such consent requires the prepayment of the
notes at the time of such sale, expected to occur on or prior to April 30,
1996. Upon consummation of the sale of such properties to Shell, the Company
will prepay the outstanding principal and accrued interest on the senior notes,
with a prepayment premium of approximately $3.4 million.
On December 27, 1994, the Company entered into a revolving secured credit
facility with a commercial bank. Under the terms of the credit agreement, the
Company may borrow up to $15 million, with the initial available principal
limited to $10 million. The credit facility is secured by the U.S. properties.
Upon consummation of the sale of the U.S. properties to Shell, the Company will
repay the principal outstanding of approximately $5 million, with accrued
interest, and payment for net profits interest of up to $1.8 million, and the
credit facility will no longer be available to the Company.
22
25
In February 1994, the Company and Benton-Vinccler entered into a six month loan
arrangement with Morgan Guaranty to repay commercial paper and for working
capital requirements, which has subsequently been renewed on a monthly basis.
Under such arrangement, Benton-Vinccler may borrow up to $25 million, of which
$10 million may be borrowed on a revolving basis. Borrowings under this loan
arrangement are secured by cash collateral in the form of a time deposit from
the Company. The loan arrangement contains no restrictive covenants and no
financial ratio requirements. The principal amount of such loan outstanding at
December 31, 1995 was $19.3 million. Benton-Vinccler can borrow an additional
$5.7 million under the loan arrangement if the Company provides a time deposit
to secure such additional borrowings.
On March 14, 1996, the Company accepted a commitment from Morgan Guaranty Trust
Company for a $50 million facility to be provided to Benton-Vinccler and
guaranteed by the Company, secured by payments made under the operating service
agreement with Lagoven. Availability of the facility is subject to agreement
on specific terms and completion of loan documentation. Of the proposed
facility, $18 million will represent a 5-year standby letter of credit for
performance under the Delta Centro exploration agreements. If the facility is
completed, any loans drawn on the $32 million, 12-month credit facility will
bear interest for the first six months of the loan at an annual rate of LIBOR
plus 3% and for the second six months of the loan at an annual rate of LIBOR
plus 3.75%. The loan agreement is expected to contain financial covenants and
limitations customary in similar loan transactions. In connection with the
loan agreement, the Company has agreed to pay to Morgan Guaranty an arrangement
fee.
The Company expects 1996 capital expenditures to be approximately $100 million,
including $12 million in expenditures for Russia (net to the Company's
interest), which is dependent on proposed EBRD or other financing, which may or
may not be obtained. See Item 1.Business--North Gubkinskoye, Russia--Drilling
and Development Activity. Funding is expected to come from the issuance of
debt or equity securities, cash flow from operations, sales of property
interests, or project and trade financing sources. There can be no assurance
that such financing will become available under terms and conditions acceptable
to the Company, which may result in reduced capital expenditures in the
Company's principal areas of operations.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA
The information required by this item is included herein on pages S-1 through
S-23.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
No information is required to be reported under this item.
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
*Information with respect to the directors and executive officers of the
Company is set forth below:
Name Age Position
---- --- --------
A.E. Benton 53 Chairman of the Board, Chief Executive
Officer and Director
Michael B. Wray 59 President, Chief Financial Officer and
Director
William H. Gumma 47 Senior Vice President--Operations, Managing
Director of Benton-Vinccler and Director
David H. Pratt 45 Vice President--International Finance
Joseph C. White 64 Vice President--Operations
Clarence Cottman, III 40 Vice President--Business Development
E. Sven Hagen 38 Vice President--Exploration and Development
Gregory S. Grabar 41 Vice President--Corporate Development and
Administration
Chris C. Hickok 38 Vice President--Controller and Chief
Accounting Officer
Bruce M. McIntyre 67 Director
Richard W. Fetzner 66 Director
Garrett A. Garrettson 52 Director
A.E. BENTON
A.E. Benton, founder of the Company, was first elected Chief Executive Officer
and Chairman of the Board of the Company in September 1988. He has served as
director of the Company since September 1988. From 1986 to October 1988, Mr.
Benton was employed as president and director of Benton Petroleum Company. From
1981 to 1986, Mr. Benton was employed by May Petroleum, Inc., becoming its
senior vice president of exploration. From 1979 to 1981, Mr. Benton was employed
by TransOcean Oil Company and, upon TransOcean's acquisition by Mobil Oil
Corporation, he was employed by another subsidiary of Mobil Oil Corporation as
manager of geophysics. He was employed from 1968 to 1979 by Amoco Oil Company in
various positions, including director of applied geophysical research. Mr.
Benton has a B.S. degree in geophysics from California State University. Mr.
Benton serves as a director of First Seismic Corporation.
MICHAEL B. WRAY
Michael B. Wray was first elected President and Chief Financial Officer of the
Company in January, 1996. He has served as director of the Company since
November 1988. From January 1994 to December 1995, Mr. Wray served as a
consultant to the Company. From January 1992 until July 1993, Mr. Wray served as
vice president -- finance and administration of Del Mar Operating, Inc. From
1985 through 1991, Mr. Wray was an independent financial consultant to oil and
gas exploration and production companies. From 1979 to 1985, Mr. Wray served as
a senior financial officer of Guardian Oil Company, Huffco petroleum Corporation
and May Petroleum, Inc. Prior to that time, Mr. Wray worked for over 15 years in
New York as n investment banker, security analyst and
3
officer in various investment firms including Donaldson, Lufkin & Jenrette,
Inc., Drexel & Co. and L.F. Rothschild & Co. Mr. Wray began his career as an
attorney with Morgan, Lewis & Bockius in Philadelphia. Mr. Wray holds a B.A.
degree from Amherst College and a law degree from Columbia Law School.
WILLIAM H. GUMMA
William H. Gumma was first elected Vice President -- Gulf Coast Operations in
August 1989 and was elected Senior Vice President -Operations of the Company in
September 1990. In December 1995, Mr. Gumma was elected Managing Director of
Benton-Vinccler. In September 1994, Mr. Gumma was appointed a director of the
Company to fill a vacancy on the Board of Directors. From 1988 to 1989, Mr.
Gumma was chief geophysicist-international for Maxus Energy Corp. (formerly
Diamond Shamrock, Inc.), where he directed geophysical exploration in Europe,
South America and North Africa. From 1986 to 1988, Mr. Gumma served as vice
president of exploration for BHP Petroleum, Inc. From 1983 to 1986, Mr. Gumma
served as chief geophysicist and later as Gulf Coast exploration manager for May
Petroleum, Inc. From 1980 to 1983, Mr. Gumma served as chief geophysicist for
Spectrum Oil and Gas Company. From 1978 to 1980, he was district geophysicist
for Inexco Oil Company. From 1972 to 1978, Mr. Gumma was employed by Amoco Oil
Company in various positions. Mr. Gumma received his B.S. from the Colorado
School of Mines and his M.S. in geophysics from Oregon State University.
DAVID H. PRATT
David H. Pratt was first elected Vice President -- International Finance in
January, 1996. From April 1989 to December 1995, Mr. Pratt served as Vice
President Finance, Chief Financial Officer and Treasurer of the Company. From
1987 to 1989, Mr. Pratt was a consultant in the accounting services and systems
industry. From 1982 to 1987, Mr. Pratt was employed by May Petroleum, Inc.,
becoming assistant treasurer. He also served as budget and planning manager, and
managed corporate and partnership investor relations and other administrative
areas. From 1974 to 1982, Mr. Pratt was employed by Arthur Andersen & Co. and he
became a Certified Public Accountant in 1975. Mr. Pratt holds B.S. and M.B.A.
degrees from Texas Christian University.
JOSEPH C. WHITE
Joseph C. White was elected Vice President -- Operations of the Company in
February 1993. Previously, Mr. White was president of J.C. White and Associates,
Inc., an independent consulting firm that prepared the Company's independent
reserve reports from 1988 through 1992. Mr. White was employed by Texaco for 30
years in a variety of engineering and management positions. In 1968, he was
appointed assistant to the vice president for Latin America and Trinidad in
Texaco's New York City executive office and in 1971 was appointed assistant to
the senior vice president for Texaco's worldwide producing operations. In 1972,
he was appointed assistant division manager to Texaco's Denver Division in
Colorado. In this position, he was responsible for all engineering and
operational matters for Texaco's operations in the Rocky Mountain area.
CLARENCE COTTMAN, III
Clarence Cottman, III was first appointed Land Manager in June 1989, was elected
Vice President -- Land of the Company in September 1990 and was elected Vice
President -- Business Development in July 1993. Mr. Cottman, a Certified
Petroleum Landman, was previously employed by Oryx Energy Company (formerly Sun
Exploration and Production Company) from June 1982 to May 1989. Mr. Cottman had
held a variety of exploration and production land positions in Oryx's Dallas,
Houston, and Denver offices. Most recently, he was district landman for Oryx in
Ventura, California, and responsible for all land activity on the West Coast.
Mr. Cottman holds a B.A. degree from Rochester Institute of Technology and an
M.B.A. from the University of Rhode Island. Mr. Cottman is the son-in-law of
Richard W. Fetzner.
E. SVEN HAGEN
E. Sven Hagen was first appointed Gulf Coast Geologist in March 1990 and was
elected Vice President -- Exploration and Development in July 1995. From March
1987 to February 1990, Mr. Hagen was employed by Shell Oil Company as an
exploration geologist responsible for the technical evaluation of the oil and
gas potential of West Africa salt basins including Angola, Congo, Gabon and
Namibia. From December 1985 to February 1987, Mr. Hagen was employed by Standard
Oil Production Company as an
4
Exploration Geologist. Mr. Hagen holds a B.A. degree in geology from the
University of California at Santa Barbara and a Ph.D. in geology from the
University of Wyoming.
GREGORY S. GRABAR
Gregory S. Grabar was first elected Vice President -- Corporate Development and
Administration in April 1993 and was first appointed Manager of Administration
in October 1990. From 1989 to 1990, Mr. Grabar was in the corporate finance
department of Citicorp Real Estate, Inc. From 1988 to 1989, Mr. Grabar was a
consultant in the accounting services industry. From 1981 to 1988, Mr. Grabar
was a vice president in the corporate finance department at Bateman Eichler,
Hill Richards, Inc., a Kemper Securities Inc. company. From 1977 to 1981, Mr.
Grabar was in both the audit and tax departments of Arthur Andersen & Co. and
became a Certified Public Accountant. Mr. Grabar graduated cum laude from
California State University with a B.A. in business administration and received
his M.B.A. from the University of California at Los Angeles.
CHRIS C. HICKOK
Chris C. Hickok was first appointed Controller in November 1991 and was elected
Vice President -- Controller and Chief Accounting Officer in January 1995. From
March 1979 to September 1991, Mr. Hickok was employed by Mission Resources, Inc.
and held various positions in the accounting and finance department including
financial analyst, assistant controller and controller. Mr. Hickok holds a B.S.
degree in business administration from California State University at Hayward
and is a Certified Management Accountant.
BRUCE M. MCINTYRE
Bruce M. McIntyre has served as director of the Company since November 1988. Mr.
McIntyre is a private investor and a consultant in the oil and gas industry, in
which he has been involved since 1952. He also serves in a management capacity
with several small, private companies in the energy field. He currently serves
as a director of MSC Corp., a private company which manages oil wells in
Illinois. From 1981 to 1984, Mr. McIntyre served as president of Rocky Mountain
Exploration Company, ultimately negotiating its merger into Carmel Energy, Inc.,
on whose board of directors he served until March 1986. Prior to that time, Mr.
McIntyre held various management positions with C&K Petroleum, Inc. (now ENSTAR
Petroleum, Inc.), Jenney Oil Company and Sinclair Oil & Gas Company. Mr.
McIntyre is a graduate of Harvard College and the Harvard University Graduate
School of Business Administration.
RICHARD W. FETZNER
Richard W. Fetzner has served as director of the Company since May 1990.
Since 1989, Dr. Fetzner has been an associate professor of business
administration at California Lutheran University in Thousand Oaks,
California. From 1984 to 1989, Dr. Fetzner served in various academic
capacities at the University of Singapore and California Lutheran University
and was a consultant to the World Bank. From 1979 to 1984, Dr. Fetzner served
as group vice president of Sun Company, Inc. and president of Sun Exploration
and Production Company in Dallas, Texas. From 1958 to 1979, he served in
various management and professional positions with Sun Oil Company and its
subsidiaries including president of Sun International, Inc. and Sun Marine
Transport, Inc. Dr. Fetzner holds a B.A. from Augustana College, an M.S. in
geology from the University of Wisconsin, a Ph.D. in geology and economics from
the University of Wisconsin and an M.B.A. from Drexel University. Dr. Fetzner
is the father-in-law of Clarence Cottman, III, an officer of the Company.
GARRETT A. GARRETTSON
Garrett A. Garrettson has served as director of the Company since January 1996.
In 1995, Mr. Garrettson was elected as chairman, chief executive officer and
president of Contract Recording Technology, Inc. In addition, since 1993 he has
served as president and chief executive officer of Censtor Corporation. From
1986 to 1989, Mr. Garrettson served as vice president of Imprimis Technology.
prior to that time, after serving in the United States Navy and Naval Reserves,
Mr. Garrettson held various positions with Hewlett Packard Company, including
laboratory director, department manager, project manager, and research engineer.
Mr. Garrettson graduated from Stanford University with a B.S. and M.S. in
engineering physics, and a Ph.D. in mechanical engineering.
5
ITEM 11.II. EXECUTIVE COMPENSATION
*SUMMARY COMPENSATION TABLE
LONG TERM
COMPENSATION
ANNUAL COMPENSATION AWARDS
----------------------------- ------------
OTHER ALL OTHER
NAME AND SALARY BONUS COMPENSATION OPTIONS/SARS COMPENSATION
PRINCIPAL POSITION YEAR ($) ($) ($) (#) ($)
- --------------------------------- ---------- ----------- ------------- ------------------ ------------------ ------------------
A. E. Benton, 1995 $279,000 $ 50,000 (1) 125,000 $ 460
Chief Executive Officer 1994 250,000 0 250,000 473
1993 165,000 50,000 125,000 448
William H. Gumma 1995 189,000 55,000 (1) 50,000 272
Senior Vice President - 1994 175,000 20,000 100,000 273
Operations 1993 125,000 30,000 50,000 195
Joseph C. White 1995 116,000 20,000 (1) 15,000 902
Vice President - Operations 1994 96,000 0 40,000 902
1993 90,000 10,000 0 489
Clarence Cottman, III 1995 105,000 15,000 (1) 0 174
Vice President - 1994 95,000 0 50,000 118
Business Development 1993 85,000 20,000 10,000 118
E. Sven Hagen 1995 98,000 20,000 (1) 35,000 81
Vice President - Exploration and 1994 84,000 0 40,000 81
Development 1993 65,000 0 0 81
(1) The aggregate amount of prerequisite compensation to be reported herein is
less than the lesser of either $50,000 or 10% of the total of annual salary and
bonus reported for the named executive officer. No other annual compensation was
paid or payable to the named executive officers in the years indicated.
(2) Represents premiums paid by the Company with respect to term life insurance
for the benefit of the named executive officer.
The following table shows information concerning options to purchase
Common Stock granted to certain individuals during 1995.
% OF TOTAL
OPTIONS/SARS
GRANTED TO EXERCISE OR GRANT DATE
OPTIONS/SARS EMPLOYEES IN BASE PRICE EXPIRATION PRESENT VALUE
NAME GRANTED (#) FISCAL YEAR ($/SH) DATE ($)(1)
---------------------- ------------------ ------------------ -------------- ------------- --------------
A.E. Benton 125,000 22.8% 15.25 12/20/05 $803,750
William H. Gumma 50,000 9.1% 15.25 12/20/05 321,500
Joseph C. White 15,000 2.7% 15.25 12/20/05 96,450
E. Sven Hagen 20,000 3.7% 12.69 4/26/05 107,120
E. Sven Hagen 15,000 2.7% 15.25 12/20/05 96,450
6
(1) To calculate the present value of option/SAR grants, the Company has used
the Black-Scholes option pricing model. The actual value, if any, an executive
may realize will depend on the excess of the stock price over the exercise price
on the date the option is exercised, so that there is no assurance the value
realized by an executive will be at or near the value estimated by the
Black-Scholes model. The estimated value under that model for the stock option
granted on April 26, 1995 is based on the assumptions that include (i) a stock
price volatility of 35.0%, (ii) a risk-free rate of return based on a 10-year
U.S. Treasury rate at the time of grant of 7.08%, and (iii) an option exercise
term of ten years. The estimated values under that model for the stock options
granted on December 20, 1995 are based on the assumptions that include (i) a
stock price volatility of 35.0%, (ii) a risk-free rate of return based on a
10-year U.S. Treasury rate at the time of grant of 5.80% and (iii) an option
exercise term of ten years. No adjustments were made for the non-transferability
of the options or to reflect any risk of forfeiture prior to vesting. The
Securities and Exchange Commission requires disclosure of the potential
realizable value or present value of each grant. The Company's use of the
Black-Scholes model to indicate the present value of each grant is not an
endorsement of this valuation, which is based on certain assumptions, including
the assumption that the option will be held for the full ten-year term prior to
exercise.
The following table provides information regarding the exercise of stock
options during 1995 by certain individuals and the year-end value of unexercised
options for certain individuals.
AGGREGATED OPTIONS/SAR EXERCISES IN 1995 AND YEAR-END OPTION/SAR VALUES
NUMBER OF UNEXERCISED VALUE OF UNEXERCISED
SHARES OPTIONS/SARS AT YEAR-END (#) IN-THE-MONEY OPTIONS/SARS ($)
ACQUIRED ON VALUE ----------------------------- -----------------------------
NAME EXERCISE (#) REALIZED ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
- ----------------------- ------------------- --------------- ------------- ----------------- --------------- -----------------
A.E. Benton 0 $ 0 726,667 333,333 $5,823,417 $1,536,458
William H. Gumma 15,000 151,650 276,667 133,333 2,113,517 614,583
Joseph C. White 0 0 63,334 41,666 576,667 203,333
Clarence Cottman, III 80,000 808,000 68,334 36,666 466,042 287,083
E. Sven Hagen 15,000 186,750 88,334 61,666 779,917 249,533
EMPLOYMENT AGREEMENTS
In June 1995, the Board of Directors approved employment agreements
with certain key employees of the Company (the "Employment Agreements"), which
contain severance provisions in the event of a change in control of the Company.
The Company has entered into similar agreements with other officers and key
employees.
Pursuant to each Employment Agreement, in the event of a proposed
change in control (as defined in the Employment Agreement), the employee has
agreed to remain with the Company until the earliest of (a) 180 days from the
occurrence of such proposed change in control, (b) termination of the employee's
employment by reason of death or disability (as defined in the Employment
Agreement), or (c) the date on which the employee first becomes entitled to
receive benefits under the Employment Agreement by reason of disability or
termination of his employment following a change in control. Except for this
agreement by the employee to so remain employed by the Company, the Company or
the employee may terminate the employee's employment prior to or after a change
in control either immediately or after certain notice periods, subject to the
Company's obligation to provide benefits specified in the Employment Agreement.
Each Employment Agreement is for a period of either two or three
years. In the event of a change in control, the term of the Employment
Agreements will continue in effect for an additional 24 months after such change
in control, subject to certain exceptions described therein. Following a change
in control of the Company and for a period of 24 months following such event, if
the employee is terminated without cause (as defined in the Employment
Agreement) or if employment is terminated by the employee for good reason (as
defined in the Employment Agreement), the employee is entitled to a cash
severance payment equal to three times his annual base salary at the rate in
effect prior to termination. The employee, and his dependents, will also be
entitled to participate in all life, accidental death, medical and dental
insurance plans of the Company in which the employee was entitled to participate
at termination for a period of up to two years (and up to seven years in certain
circumstances). However, such amounts will not be payable if termination is due
to death, normal retirement, permanent disability, or voluntary action of the
employee other than for good reason (as defined in the Employment Agreement), or
by the Company for cause (as defined in the Employment Agreement) or if such
payment is not deductible by the Company as a result of the operation of Section
280G of the Internal Revenue Code.
7
Messrs. Benton and Gumma entered into employment agreements for
terms of three years on June 26, 1995. Mr. Cottman entered into an
employment agreement for a term of three years on July 11, 1994. Mr. Hagen
entered into an employment agreement for a term of three years on April 26,
1995. Pursuant to the employment agreements, Mr. Benton's annual base salary
was $300,000, Mr. Gumma's annual base salary was $200,000, Mr. Cottman's
annual base salary was $95,000 and Mr. Hagen's annual base salary was $100,000.
On December 30, 1994, Mr. Cottman's annual base salary was increased to
$105,000. On December 20, 1995, Mr. Cottman's annual base salary was
increased to $125,000 and Mr. Hagen's annual base salary was increased to
$115,000. On January 3, 1996, Mr. Benton's annual base salary was increased
to $425,000 and Mr. Gumma's annual base salary was increased to $275,000. Mr.
Wray entered into an employment agreement for a term of three years on January
3, 1996. Pursuant to the agreement, Mr. Wray will serve as President and
Chief Financial Officer with an annual base salary of $380,000. Salaries are
reviewed annually and bonuses are within the discretion of the Board of
Directors.
REMUNERATION OF DIRECTORS
Directors are elected at the annual stockholders' meeting and hold
office until the next annual stockholders' meeting and until their successors
are elected and qualified. Directors who are not Company officers are paid a fee
of $2,000 for each Board meeting attended, $500 for each committee meeting
attended and $250 for participation in telephonic meetings. Directors are
reimbursed for all travel and related expenses. Beginning July 1995, in addition
to the fees paid per meeting, each director who is not a Company officer is paid
an annual retainer of $20,000.
Additionally, the Company's Director Stock Option Plan provides that
each person who is elected to serve as a non-employee director of the Company is
annually and automatically granted an option to purchase 10,000 shares of Common
Stock at an exercise price equal to the market price on the date of grant.
During 1995, Mr. Wray served as a consultant to the Company to
provide financial advice. In consideration of such services, the Company paid
Mr. Wray an aggregate of $246,000 during 1995 and reimbursed Mr. Wray for all
travel and business related expenses. The Company provided Mr. Wray with use of
a Company car for 1995. See "Certain Relationships and Related Transactions."
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT
The following table sets forth information with respect to each person
known to the Company to be the beneficial owner of more than five percent of the
issued and outstanding Common Stock of the Company as of April 30, 1996, the
directors and nominees, the executive officers named in the Summary Compensation
Table, and the directors and executive officers, as a group. The Common Stock
ownership information includes current shareholdings, Common Stock subject to
warrants which are currently exercisable or exercisable within 60 days, and
Common Stock subject to option under the Company's Stock Option Plans which are
currently exercisable or exercisable within 60 days:
NAME AND ADDRESS OF SHARES BENEFICIALLY PERCENTAGE OF SHARES
BENEFICIAL OWNER OWNED BENEFICIALLY OWNED (1)
------------------------------------------------ ------------------------- ---------------------------
Scudder, Stevens & Clark, Inc. 2,118,600 (2) 7.88%
345 Park Avenue
New York, NY 10154
A.E. Benton 1,410,000 (3) 5.09%
Michael B. Wray 109,300 (4) *
William H. Gumma 260,000 (5) *
Joseph C. White 70,000 (6) *
Clarence Cottman, III 75,967 (7) *
E. Sven Hagen 101,667 (8) *
Bruce M. McIntyre 100,000 (9) *
Richard W. Fetzner 71,667 (10) *
8
Garrett A. Garrettson 10,000 (11) *
All directors and executive officers as a group 2,686,834 (12) 9.32%
(12 persons)
*Less than 1%
(1) The percentage of Common Stock is based upon 26,896,156 shares of Common
Stock outstanding as of May 24, 1996.
(2) The number of shares and the nature of beneficial ownership of Scudder,
Stevens & Clark, Inc. is as of December 31, 1995 and is based upon the Schedule
13G filed with the Securities and Exchange Commission. Pursuant to such Schedule
13G, Scudder, Stevens & Clark, Inc. reported sole dispositive power with respect
to all such shares and disclaimed beneficial ownership.
(3) Includes 810,000 shares subject to options which are currently exercisable
or exercisable within 60 days after May 24, 1996, under the Company's stock
option plans.
(4) Includes 90,000 shares subject to options which are currently exercisable or
exercisable within 60 days after May 24, 1996, under the Company's stock option
plans.
(5) Includes 260,000 shares subject to options which are currently exercisable
or exercisable within 60 days after May 24, 1996, under the Company's stock
option plans.
(6) Includes 70,000 shares subject to options which are currently exercisable or
exercisable within 60 days after May 24, 1996, under the Company's stock option
plans.
(7) Includes 75,967 shares subject to options which are currently exercisable or
exercisable within 60 days after May 24, 1996, under the Company's stock option
plans.
(8) Includes 101,667 shares subject to options which are currently exercisable
or exercisable within 60 days after May 24, 1996, under the Company's stock
option plans.
(9) Includes 90,000 shares subject to options which are currently exercisable or
exercisable within 60 days after May 24, 1996, under the Company's stock option
plans.
(10) Includes 71,667 shares subject to options which are currently exercisable
or exercisable within 60 days after May 24, 1996, under the Company's stock
option plans.
(11) Includes 10,000 shares subject to options which are currently exercisable
or exercisable within 60 days after May 24, 1996, under the Company's stock
option plans.
(12) Includes 1,922,633 shares subject to options which are currently
exercisable or exercisable within 60 days after May 24, 1996, under the
Company's stock option plans.
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Section 16(a) of the Securities Exchange Act of 1934 requires the
Company's executive officers and directors and persons who own more than ten
percent of a registered class of the Company's equity securities to file reports
of ownership and changes in ownership with the Securities and Exchange
Commission and NASDAQ-NMS. Reporting persons are required by SEC regulations to
furnish the Company with copies of Section 16(a) forms they file.
Based solely on its review of the copies of such forms received by the
Company, or written representations from certain reporting persons that no Form
5 was required to be filed, the Company believes that during 1995 all filing
requirements applicable to its executive officers, directors and greater than
ten-percent beneficial owners were complied with, except Mr. McIntyre filed one
Form 4 late which covered transactions related to 2,000 shares of Common Stock.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
*
* Reference is made to information under the captions "Election of
Directors", "Executive Officers", "Executive Compensation", "Security
Ownership of Certain Beneficial Owners and Management", and "Certain
Relationships and Related Transactions" in the Company's Proxy Statement
for the 1996 Annual Meeting of Stockholders.
23
26
INDEPENDENT AUDITORS' REPORT
- ----------------------------
Board of Directors and Stockholders
Benton Oil and Gas Company
Carpinteria, California
We have audited the accompanying consolidated balance sheets of Benton Oil and
Gas Company and subsidiaries (the "Company") as of December 31, 1995 and 1994,
and the related consolidated statements of operations, stockholders' equity,
and cash flows for each of the three years in the period ended December 31,
1995. 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 audit to
obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of Benton Oil and Gas Company and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995 in conformity with generally accepted accounting principles.
Deloitte & Touche LLP
Los Angeles, California
March 20, 1996
S-1
27
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
---------------------------
December 31,
-----------------------------------
1995 1994
---- ----
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents $ 6,179,998 $ 14,192,568
Restricted cash (Note 4) 20,314,000 19,550,000
Accounts receivable:
Accrued oil and gas revenue 22,069,217 9,357,782
Joint interest and other (Note 11) 2,869,962 3,880,808
Property held for sale (Note 2) 14,887,700
Prepaid expenses and other 214,622 563,839
------------ ------------
TOTAL CURRENT ASSETS 51,647,799 62,432,697
OTHER ASSETS (Notes 3 and 11) 3,434,760 1,305,997
PROPERTY AND EQUIPMENT (Notes 2, 3, 5, 10, 14 and 15):
Oil and gas properties (full cost method - costs of
$17,925,371 and $16,695,284 excluded from
amortization in 1995 and 1994, respectively) 177,110,550 117,454,164
Furniture and fixtures 2,539,233 1,439,484
------------ ------------
179,649,783 118,893,648
Accumulated depletion and depreciation (19,982,244) (20,071,223)
----------- -----------
159,667,539 98,822,425
------------ ------------
$214,750,098 $162,561,119
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Accounts payable:
Revenue distribution $ 2,692,751 $ 594,782
Trade and other 19,777,018 11,426,105
Accrued interest payable, payroll and related taxes 1,687,648 1,199,096
Income taxes payable 1,039,166
Short term borrowings (Note 4) 21,905,480 21,035,401
Current portion of long term debt (Notes 3 and 14) 7,433,339 6,392,114
------------ ------------
TOTAL CURRENT LIABILITIES 54,535,402 40,647,498
LONG TERM DEBT (Notes 3 and 14) 49,486,306 31,911,164
MINORITY INTEREST (Note 10) 7,047,791 1,743,660
COMMITMENTS AND CONTINGENCIES (Notes 5, 14 and 15)
STOCKHOLDERS' EQUITY (Notes 2, 3, 7, 8, and 10):
Preferred stock, par value $0.01 a share;
authorized 5,000,000 shares; outstanding, none
Common stock, par value $0.01 a share;
authorized 40,000,000 shares; issued and
outstanding 25,508,605 and 24,899,848 shares at
December 31, 1995 and 1994, respectively 255,086 248,998
Additional paid-in capital 97,745,794 92,921,115
Retained earnings (deficit) 5,679,719 (4,911,316)
------------ -----------
TOTAL STOCKHOLDERS' EQUITY 103,680,599 88,258,797
------------ ------------
$214,750,098 $162,561,119
============ ============
See notes to consolidated financial statements.
S-2
28
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
Years Ended December 31,
---------------------------------------------------
1995 1994 1993
--------- --------- -----------
REVENUES
Oil and gas sales (Notes 13 and 15) $62,156,694 $31,942,810 $ 7,222,310
Net gain (loss) on exchange rates 997,820 1,445,307 (206,481)
Investment earnings 1,770,512 1,180,824 393,843
Other 142,632 135,865 94,124
----------- ----------- -----------
65,067,658 34,704,806 7,503,796
----------- ----------- -----------
EXPENSES
Lease operating costs and production taxes 10,702,797 9,531,264 5,110,264
Depletion, depreciation and amortization 17,411,089 10,298,112 2,632,924
General and administrative 9,410,187 5,241,295 2,631,445
Interest 7,497,187 3,887,961 1,957,753
Litigation settlement expenses (Note 5) 1,673,272
----------- ----------- -----------
46,694,532 28,958,632 12,332,386
----------- ----------- -----------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTEREST 18,373,126 5,746,174 (4,828,590)
2,477,960 697,802
INCOME TAX EXPENSE (Note 6) ---------- ----------- -----------
INCOME (LOSS) BEFORE MINORITY INTEREST 15,895,166 5,048,372 (4,828,590)
MINORITY INTEREST (Note 10) 5,304,131 2,094,211
----------- ----------- -----------
NET INCOME (LOSS) $10,591,035 $ 2,954,161 $(4,828,590)
=========== =========== ===========
NET INCOME (LOSS) PER COMMON SHARE (Note 12) $ 0.40 $ 0.12 $ (0.26)
=========== =========== ===========
See notes to consolidated financial statements.
S-3
29
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
-----------------------------------------------
Years Ended December 31, 1995, 1994 and 1993
COMMON ADDITIONAL RETAINED
SHARES COMMON PAID-IN EARNINGS
ISSUED STOCK CAPITAL (DEFICIT) TOTAL
----------------------------------------------------------------------------
Balance at January 1, 1993 17,441,397 $174,414 $53,330,742 $(3,036,887) $50,468,269
Issuance of common shares:
Exercise of warrants 2,500 25 18,225 18,250
Exercise of stock options 284,211 2,842 540,490 543,332
Sale of common stock 7,000,000 70,000 35,585,406 35,655,406
Redeemable common stock 2,022,323 2,022,323
Retirement of stock (51,260) (513) (513)
Compensation expense
attributed to stock options 142,420 142,420
Net loss for the year (4,828,590) (4,828,590)
------------ ---------- ----------- ----------- ------------
Balance at December 31, 1993 24,676,848 246,768 91,639,606 (7,865,477) 84,020,897
Issuance of common shares:
Exercise of stock options 23,000 230 83,509 83,739
Acquisitions 200,000 2,000 1,198,000 1,200,000
Net income for the year 2,954,161 2,954,161
------------ ---------- ----------- ----------- ------------
Balance at December 31, 1994 24,899,848 248,998 92,921,115 (4,911,316) 88,258,797
Issuance of common shares:
Exercise of warrants 3,155 32 28,663 28,695
Exercise of stock options 272,580 2,726 1,335,330 1,338,056
Conversion of notes and
debentures 333,022 3,330 3,506,713 3,510,043
Securities registration costs (46,027) (46,027)
Net income for the year 10,591,035 10,591,035
------------ ---------- ----------- ----------- ------------
Balance at December 31, 1995 25,508,605 $ 255,086 $97,745,794 $ 5,679,719 $103,680,599
============ ========== =========== =========== ============
See notes to consolidated financial statements.
S-4
30
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
-------------------------------------
Years Ended December 31,
----------------------------------------------
1995 1994 1993
------------- -------------- ---------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (loss) $ 10,591,035 $ 2,954,161 $ (4,828,590)
Adjustments to reconcile net income (loss) to net cash
provided by (used in) operating activities:
Depletion, depreciation and amortization 17,411,089 10,298,112 2,632,924
Compensation expense attributed to stock options 142,420
Net earnings from limited partnerships (57,685) (63,486) (106,230)
Amortization of financing costs 184,447 114,311 139,444
Interest paid in stock 20,145
Loss on disposal of assets 16,211
Minority interest in undistributed earnings of subsidiary 5,304,131 2,094,211
Increase in accounts receivable (12,882,072) (10,384,670) (1,465,725)
(Increase) decrease in prepaid expenses and other 349,217 (84,905) (288,217)
Increase in accounts payable 9,905,365 7,974,335 1,759,747
Increase in accrued interest payable, payroll and related taxes 488,552 560,720 204,117
Increase in income taxes payable 1,039,166
------------ ------------ ------------
TOTAL ADJUSTMENTS 21,758,421 10,508,628 3,038,625
------------ ------------ ------------
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES 32,349,456 13,462,789 (1,789,965)
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Proceeds from sale of property and equipment 15,408,368 5,803,215 7,822,120
Additions of property and equipment (68,288,101) (39,631,547) (26,169,581)
Increase in restricted cash (764,000) (19,250,000) (300,000)
Distributions from limited partnerships 502,167 28,667
Payment for purchase of Benton-Vinccler, net of cash acquired (2,501,973)
------------ ------------ ------------
NET CASH USED IN INVESTING ACTIVITIES (53,643,733) (55,078,138) (18,618,794)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from sale of common stock 36,120,000
Direct offering costs (464,594)
Net proceeds from exercise of stock options and warrants 1,319,767 83,740 561,582
Proceeds from issuance of notes payable 22,157,500 21,360,000
Proceeds from short term borrowings 2,400,000 23,217,775 7,668,588
(Increase) decrease in other assets (596,224) (455,358) 3,460
Payments on short term borrowings and notes payable (11,999,336) (24,706,358) (672,230)
Deficiency payments on redeemable common stock (172,917)
------------ ------------ ------------
NET CASH PROVIDED BY FINANCING ACTIVITIES 13,281,707 19,499,799 43,043,889
------------ ------------ ------------
NET INCREASE (DECREASE) IN CASH (8,012,570) (22,115,550) 22,635,130
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR 14,192,568 36,308,118 13,672,988
------------ ------------ ------------
CASH AND CASH EQUIVALENTS AT END OF YEAR $ 6,179,998 $ 14,192,568 $ 36,308,118
============ ============ ============
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
Cash paid during the year for interest expense $ 7,011,623 $ 3,299,189 $ 1,838,848
============ ============ ============
Cash paid during the year for income taxes $ 1,885,291 $ 715,507
============ ============ ============
S-5
31
SUPPLEMENTAL SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES:
During the year ended December 31, 1995, $1,393,000 of the Company's 8%
convertible notes and $2,118,000 of the Company's 8% convertible debentures
were retired in exchange for 118,785 and 214,237 shares of the Company's common
stock, respectively.
During the year ended December 31, 1995, the Company financed the purchase of
oil and gas equipment and services in the amount of $10,384,809 and leased
office equipment in the amount of $54,473. Also during 1995, the Company
acquired residential real estate for $1,725,000 in exchange for accounts and
notes receivable from an officer of the Company totaling $1,181,483 resulting
in an account payable of $543,517 (See Note 11).
During the year ended December 31, 1994, the Company converted $143,658 of
accounts payable into a note payable, financed the purchase of computer
equipment in the amount of $105,000 and financed the purchase of oil and gas
equipment in the amount of $1,733,675.
On March 4, 1994, the Company acquired capital stock from Vinccler representing
an additional 30% ownership interest in Benton-Vinccler for $3 million in cash,
$10 million in non-interest bearing notes payable (with a present value of $9.2
million assuming a 10% interest rate) and 200,000 shares of the Company's
common stock. The excess of the purchase price over the net book value of
assets acquired was $13,880,100, which was allocated to oil and gas properties.
During the year ended December 31, 1993, the Company converted $2,113,429 of
accounts payable into a note payable and entered into capital lease agreements
for the purchase of furniture and fixtures in the amount of $79,521.
See notes to consolidated financial statements.
S-6
32
BENTON OIL AND GAS COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
------------------------------------------
Years Ended December 31, 1995, 1994 and 1993
Note 1 - Organization and Summary of Significant Accounting Policies
ORGANIZATION
Benton Oil and Gas Company (the "Company") engages in the exploration,
development, production and management of oil and gas properties.
The Company and its subsidiary, Benton Oil and Gas Company of Louisiana,
participated as the managing general partner of three oil and gas limited
partnerships formed during 1989 through 1991. Under the provisions of the
limited partnership agreements, the Company received compensation as stipulated
therein, and functioned as an agent for the partnerships to arrange for the
management, drilling, and operation of properties, and assumed customary
contingent liabilities for partnership obligations. In November 1995, the
Company made an offer to holders of the limited partnership interests to
exchange their interests for an aggregate of 168,362 shares of common stock and
warrants to purchase 587,783 shares of common stock at $11 per share. The
exchange was completed in January 1996 and the partnerships were liquidated
(See Note 14).
The consolidated financial statements include the accounts of the Company and
its subsidiaries. The Company's investments in limited partnerships, the
Russia joint venture ("GEOILBENT") and the Venezuelan joint venture (through
December 31, 1993) are proportionately consolidated based on the Company's
ownership interest. Effective January 1, 1994, the Venezuela joint venture was
incorporated and, as a result of the Company's acquisition of additional
capital stock of such corporation (see Note 10), has been fully consolidated.
Beginning in 1995, GEOILBENT (owned 34% by the Company) has been included in
the consolidated financial statements based on a fiscal period ending September
30. This change was made to provide adequate time for the accumulation and
review of financial information from the joint venture for both quarterly and
annual reporting purposes. This change did not have a material effect on the
consolidated financial statements (see Note 15). All material intercompany
profits, transactions and balances have been eliminated.
CASH AND CASH EQUIVALENTS
Cash equivalents include money market funds and short term certificates of
deposit with original maturity dates of less than three months.
ACCOUNTS RECEIVABLE
The Company's accounts receivable are considered fully collectible; therefore,
no allowance is considered necessary.
OTHER ASSETS
Other assets consist principally of costs associated with the issuance of long
term debt and at December 31, 1995 residential real estate held for sale which
the Company expects to sell in 1996. Debt issuance costs are amortized on a
straight-line basis over the life of the debt.
PROPERTY AND EQUIPMENT
The Company follows the full cost method of accounting for oil and gas
properties. Accordingly, all costs associated with the acquisition,
exploration, and development of oil and gas reserves are capitalized as
incurred, including exploration overhead of $2,282,194, $1,696,330 and
$1,736,678 for the years ended December 31, 1995, 1994 and 1993, respectively.
Only overhead which is directly identified with acquisition, exploration or
development activities is capitalized. All costs related to production,
general corporate overhead and similar activities are expensed as incurred.
The costs of oil and gas properties are accumulated in cost centers on a
country by country basis, subject to a cost center ceiling (as defined by the
Securities and Exchange Commission).
S-7
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
All capitalized costs of oil and gas properties (excluding unevaluated property
acquisition and exploration costs) and the estimated future costs of developing
proved reserves, are depleted over the estimated useful lives of the properties
by application of the unit-of-production method using only proved oil and gas
reserves. Depletion expense attributable to the Venezuelan cost center for the
years ended December 31, 1995, 1994 and 1993 was $11,392,777, $4,998,213 and
$229,080 ($2.09, $1.98 and $1.43 per equivalent barrel), respectively.
Depletion expense attributable to the Russian cost center for the years ended
December 31, 1995, 1994 and 1993 was $1,512,821, $837,818 and $99,207 ($3.08,
$2.85 and $3.51 per equivalent barrel), respectively. Depletion expense
attributable to the United States cost center for the years ended December 31,
1995, 1994 and 1993 was $4,187,440, $4,247,304 and $2,142,133 ($5.98, $7.46 and
$6.47 per equivalent barrel), respectively. Depreciation of furniture and
fixtures is computed using the straight-line method, with depreciation rates
based upon the estimated useful life applied to the cost of each class of
property. Depreciation expense was $310,038, $185,336 and $123,623 for the
years ended December 31, 1995, 1994 and 1993, respectively.
TAXES ON INCOME
Deferred income taxes reflect the net tax effects, calculated at currently
effective rates, of (a) future deductible/taxable amounts attributable to
events that have been recognized on a cumulative basis in the financial
statements and (b) operating loss and tax credit carryforwards. A valuation
allowance is recorded, if necessary, to reduce net deferred income tax assets
to the amount expected to be recoverable.
FOREIGN CURRENCY
The Company has significant operations outside of the United States,
principally in Russia and Venezuela. Both Russia and Venezuela are considered
highly inflationary economies and as a result, operations in those countries
are remeasured in United States dollars and any currency gains or losses are
recorded in the statement of operations. The Company attempts to manage its
operations in a manner to reduce its exposure to foreign exchange losses;
however, there are many factors which affect foreign exchange rates and
resulting exchange gains and losses, many of which are beyond the influence of
the Company. The Company has recognized significant exchange gains and losses
in the past, resulting from fluctuations in the relationship of the Venezuelan
and Russian currencies to the United States dollar. It is not possible to
predict the extent to which the Company may be affected by future changes in
exchange rates.
FAIR VALUE OF FINANCIAL INSTRUMENTS
The Company's financial instruments consist primarily of cash and cash
equivalents, accounts receivable and payable, commercial paper and other
short-term borrowings and debt instruments. In addition, in 1994, the Company entered into a commodity hedgeconsulting agreement (see Note 15). The book values of all
financial instruments, other than debt instruments, are representative of their
fair values due to their short-term maturity. The book valueswith
Mr. Wray, a director of the Company's
debt instruments, except the convertible subordinated debentures and notes, are
consideredCompany, to approximate their fair values because the interest ratesprovide financial advice for a period of
these
instruments are based on current rates offered to the Company. Based on the
last trading sale price on December 31, 1995 and 1994, the convertible
subordinated debentures had a fair valuesix months with compensation of approximately $5,948,000 and
$6,685,000, respectively. As discussed$15,000 per month. Mr. Wray has significant
experience in Note 3, substantially all of the
notes have been converted early in 1996. There was no active market for the
convertible subordinated notes. Based on discounting the future cash flows
related to the notes at interest rates currently offered to the Company,
approximately 13%, the notes would have had a fair value of approximately
$3,600,000 at December 31, 1994. The fair value of the hedge agreement is the
estimated amount the Company would have to pay to terminate the agreement,
taking into account current oil prices and the current creditworthiness of the
hedge counterparties. The estimated termination cost associated with the hedge
agreement at December 31, 1995 and 1994 is approximately $834,000 and
$1,132,000, respectively.
STOCK OPTIONS
Statement of Financial Accounting Standards No. 123 regarding accounting for
stock-based compensation is effective for the Company beginning January 1,
1995. SFAS 123 requires expanded disclosures of stock-based compensation
arrangements and encourages (but does not require) compensation cost to be
measured based on the fair value of the equity instrument awarded. The Company
will continue to apply APB Opinion No. 25 to its stock-based compensation
awards to employees and will disclose the required pro forma effect on net
income and earnings per share.
S-8
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
USE OF ESTIMATES
The preparation ofinvestment banking, 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.
RECLASSIFICATIONS
Certain items in 1994 and 1993 have been reclassified to conform to the 1995
financial statement presentation.
Note 2 - Acquisitions and Sales
In June 1993, the Company sold 50% of its interests in the Belle Isle and
Rabbit Island Fields in exchange for reimbursement of certain expenditures
incurred through the closing date plus the additional reimbursement of certain
future costs as incurred. As of December 31, 1995, $6.6 million of the
Company's costs have been reimbursed. Additionally, in May 1993, the Company
sold its interest in the South Scott Prospect in Lafayette Parish, Louisiana
for $1.5 million. The proceeds from these sales were used for working capital
purposes.
In March 1994, the Company acquired capital stock from Vinccler representing
an additional 30% ownership interest in Benton-Vinccler for $3 million in cash,
$10 million in non-interest bearing notes payable (with a present value of $9.2
million assuming a 10% interest rate) payable in various installments over 24
months and 200,000 shares of the Company's common stock. The excess of the
purchase price over the book value of the 30% interest was allocated to oil and gas
properties.industry and financial consulting. The fees payable pursuant to the consulting
agreement were determined based upon negotiations with Mr. Wray, with
compensation comparable to fees paid to unaffiliated management consultants and
financial consultants. In NovemberMay, 1994, the Company sold a 10.8% working interest (24.9% of the
Company's 43.3% working interest)as amended in the West Cote Blanche Bay Field for
approximately $5.8 million.
In MarchJanuary 1995, the Company sold its 32.5% working interest in certain depths
(above approximately 10,575 feet) in the West Cote Blanche Bay Field for a
purchase price of approximately $14.9 million. The sales price has been
reflected as property held for sale at December 31, 1994.
In March 1996, the Company entered into an agreement to sell to Shell Offshore
Inc. ("Shell") all of its interests in the West Cote Blanche Bay, Rabbit Island
and Belle Isle Fields effective December 31, 1995, for a purchase price of
approximately $35.4 million (see Notes 14 and 15).
S-9
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Note 3 - Long Term Debt
Long term debt consists of the following at December 31:
1995 1994
---------------- ----------------
Senior unsecured notes with interest at 13%.
See description below. $35,000,000 $15,000,000
Revolving secured credit facility. Interest
payments due quarterly beginning
March 31, 1995. Principal payments due
quarterly beginning March 31, 1997.
See description below. 5,000,000 5,000,000
Convertible subordinated debentures with
interest at 8%. See description
below. 4,310,000 6,428,000
Convertible subordinated notes with interest
at 8%. See description below. 3,269,000 4,662,000
Non-interest bearing promissory notes. See Note 10. 1,000,000 5,747,878
Vendor financing with interest ranging from 10.5 - 13.5%.
Principal and interest payments are due in varying
installments through April 1997. Unsecured. 6,234,357
Bank financing with interest at LIBOR plus
7.5%. Secured by certain GEOILBENT
oil export proceeds. See description below. 850,000 1,292,000
Bank financing with interest at 8.875%. Principal
and interest due in monthly installments of $9,156
with the unpaid balance due January 5, 1998. Secured
by residential real estate. 1,137,500
Other--various equipment purchases and
leases with principal and interest
payments due monthly from $180 to $3,381.
Interest rates vary from 10.0% to 16.91%.
Notes and leases mature from March 1996 to
March 2000. 118,788 173,400
------------ -------------
56,919,645 38,303,278
Less current portion 7,433,339 6,392,114
------------ ------------
$49,486,306 $31,911,164
=========== ===========
On June 30, 1995, the Company issued $20 million in senior unsecured notes due
June 30, 2007, with interest at 13% per annum, payable semi- annually on June
30 and December 31. Annual principal payments of $4 million are due on June 30
of each year beginning on June 30, 2003. Early payment of the notes could
result in a substantial prepayment penalty. The note agreement contains
financial covenants including a minimum ratio of current assets to current
liabilities and a maximum ratio of funded liabilities to net worth and to
domestic oil and gas reserves. The note agreement also provides for
limitations on liens, additional indebtedness, certain capital expenditures,
dividends, sales of assets and mergers. Additionally, in connection with the
issuance of the notes, the Company issued warrants entitling the holder to
purchase 125,000 shares of common stock at $17.09 per share, subject to
adjustment in certain circumstances, that are exercisable on or before June 30,
2007. In March 1996, in conjunction with the sale of the Company's Gulf Coast
properties, the Company agreed to prepay the notes and corresponding prepayment
premiums, which are estimated to be approximately $7.7 million (see Note 14).
At December 31, 1995, the Company was in default on certain financial
covenants. The lender has waived any defaults under the financial covenants
until the completion of refinancing arrangements or June 30, 1996, whichever is
earlier.
On September 30, 1994, the Company issued $15 million in senior unsecured notes
due September 30, 2002, with interest at 13% per annum. Interest is payable
semi-annually on March 30 and September 30 beginning March 30, 1995. Annual
principal
S-10
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
payments of $3 million are due on September 30 of each year beginning on
September 30, 1998. Early payment of the notes could result in a substantial
prepayment penalty. The note agreement contains financial covenants including
a minimum ratio of current assets to current liabilities and a maximum ratio of
liabilities to net worth or domestic oil and gas reserves. The note agreement
also provides for limitations on liens, additional indebtedness, certain
capital expenditures, dividends, sales of assets and mergers. Additionally, in
connection with the issuance of the notes, the Company issued warrants
entitling the holder to purchase 250,000 shares of common stock at $9.00 per
share, subject to adjustment in certain circumstances, that are exercisable on
or before September 30, 2002. In March 1996, in conjunction with the sale of
the Company's Gulf Coast properties, the Company agreed to prepay the notes and
corresponding prepayment premiums, which are estimated to be approximately $3.4
million (see Note 14). At December 31, 1995, the Company was in default on
certain financial covenants. The lender has waived any defaults under the
financial covenants until the date of sale of the properties or April 30, 1996,
whichever is earlier.
On December 27, 1994, the Company
entered into a revolving secured credit
facility. Under the creditnew consulting agreement the Company may borrow upwith Mr. Wray pursuant to $15
million, with the initial available principal limited to $10 million, on a
revolving basis for two years, at which time the facility will become a term
loan due December 31, 1999. Borrowings under the credit agreement are secured
in part by mortgages on the Company's U.S. properties and in part by a
guaranteeMr. Wray
provided by the financial institution which arranged the credit
facility. Interest on borrowings under the credit agreement accrues, at the
Company's option, at either a floating rate (higher of prime rate plus 3% or
the Federal Funds Rate plus 5%) or a fixed rate (rate of interest at which
deposits of dollars are available to lender in the interbank eurocurrency
market plus 4.5%). Atadvice through December 31, 1995, and 1994, the rates in effect were
10.2% and 11.1%, respectively. The floating rate borrowings may be prepaid at
any time without penaltywith compensation of $20,000 per
month and the fixed rate borrowings may be repaid onuse of a Company car, with all travel and business related
expenses reimbursed by the last day of an interest period without penalty, or at the optionCompany. The term and compensation arrangement were
modified in recognition of the Company
during an interest period upon payment of a make-whole premium. The credit
agreement contains financial covenants including a minimum ratio of current
assets to current liabilities and maximum ratio of liabilities to net worth or
domestic oil and gas reserves, and also provides for limitations on liens,
dividends, sales of assets and mergers. Additionally, in exchange for the
credit enhancement, the arranging financial institution and commercial bank
received warrants entitling the holder to purchase 50,000 shares of common
stock at $12.00 per share, subject to adjustment in certain circumstances, that
are exercisable on or before December 2004,expertise actually provided by Mr. Wray and the
arranging institution
receives a 5% net profits interestCompany's desire to retain his continued participation and service, as
negotiated with Mr. Wray. Mr. Wray has been instrumental in negotiating and
closing certain financing arrangements entered into by the Company since January
1994, and has provided insight and direction in the Company's properties whose
development is financed by the facility. The Company will repay borrowings
under the credit facility in conjunction with the sale of the Company's Gulf
Coast properties (see Note 14). At December 31, 1995, the Company was in
default on certain financial covenants. The lender has waived any defaults
under the financial covenants until the date of sale of the properties or April
30, 1996, whichever is earlier.
In May 1992, the Company issued $6,428,000 aggregate principal amount of
publicly offered 8% Convertible Subordinated Debentures ("Debentures") due May
1, 2002, convertible at the option of the holder at 101.157 shares per $1,000
principal amount with interest payments due May 1 and November 1. Net proceedsefforts to the Company were approximately $5,711,000 and were used primarily to repay
certain indebtedness. At the Company's option, it may redeem the Debentures in
whole or in part at any time on or after May 1, 1994, at 105% of par plus
accrued interest, declining annually to par on May 1, 1999. The Debentures
also provide that the holders can redeem their debentures following a change in
control (as defined) of the Company. The Company has the option to pay the
repurchase price in cash or shares of its common stock. During 1995, holders
of Debentures with a par value of $2,118,000 elected to convert their
debentures for 214,237 shares of common stock.
In October 1991, the Company issued $4,662,000 aggregate principal amount of
privately placed 8% Convertible Subordinated Notes ("Notes") due October 1,
2001, convertible at the option of the note holder at 85.259 shares per $1,000
principal amount with interest payments due April 1 and October 1. Net
proceeds to the Company were approximately $4,237,000. The Company had the
option to prepay the Notes in whole or in part at any time on or after October
1, 1993 at 105% of the principal amount plus accrued interest declining
annually to the principal amount on October 1, 1998. The Notes also provided
that the holders could redeem their Notes in cash following a change in control
(as defined) of the Company. In December 1995, the holders of the notes were
notified of the Company's intention to prepay the notes on February 12, 1996 at
103% of the principal amount plus accrued interest. As a result, holders of
all except $43,000 principal amount of unconverted notes elected to convert
their notes for shares of common stock and on February 12, 1996, the Company
prepaid the remaining note principal of $43,000 plus premium and accrued
interest. Accordingly, at December 31, 1995, $43,000 is reflected as current
portion of long term debt and the remaining balance of $3,226,000 representing
notes converted to common shares is reflected in long term debt. During 1995,
holders of a total of $1,393,000 of notes elected to convert their notes for
118,785 shares of common stock.
In August 1994, GEOILBENT entered into an agreement with International Moscow
Bank for a $4 million loan with the following terms: 14 monthly payments,
interest at LIBOR plus 7.5%, with interest only payments for the first four
months and monthly principal and interest payments thereafter. In connection
with this agreement, the Company provided to International Moscow Bank a
guarantee of payment under which the Company has agreed to pay such loan in
full if GEOILBENT fails to make
S-11
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
the scheduled payments. In March 1995, GEOILBENT's credit facility with
International Moscow Bank was expanded to $6 million with interest only
payments for three months and monthly principal and interest payments
thereafter. The Company has guaranteed this indebtedness. At December 31,
1995 and 1994, the Company's share of the outstanding balance was $0.9 and $1.3
million, respectively.
The principal requirements for the long term debt outstanding at December 31,
1995 are due as follows for the years ending December 31:
1996 $ 7,433,339
1997 2,467,311
1998 5,800,410
1999 4,679,978
2000 3,002,607
Subsequent Years 30,310,000
-----------
$53,693,645
===========
Note 4 - Short Term Borrowings
In 1994, Benton-Vinccler borrowed $22 million from Morgan Guaranty Trust
Company of New York ("Morgan Guaranty") to repay commercial paper and for
working capital requirements. The credit facility is collateralized in full by
time deposits from the Company, bears interest at LIBOR plus 3/4% (6.5% and
6.7% at December 31, 1995 and 1994, respectively) and is renewed on a monthly
basis. Under the loan arrangement, Benton- Vinccler may borrow up to $25
million, of which $10 million may be borrowed on a revolving basis. The loan
arrangement contains no restrictive covenants and no financial ratio covenants.
Benton-Vinccler made a payment of $2.75 million in September 1994, leaving a
balance of $19.25 million. The Company is presently pursuing several options
for long termpursue
financing for Benton-Vinccler.
During the fourth quarter of 1994 and the year ending December 31, 1995,
Benton-Vinccler acquired approximately $4.1 million of drilling and production
equipment from trading companies and suppliers under terms which include
repayment within a 12-month period in monthly and quarterly installments at
interest rates from 6.7% to 10.75%. At December 31, 1995 and 1994,
approximately $0.7 and $1.5 million related to these loans was outstanding,
respectively.
In June 1994, GEOILBENT entered into a payment advance agreement with NAFTA
Moscow, the export agency which markets GEOILBENT's oil production to
purchasers in Europe. The payment advance of $2.5 million against future oil
shipments, which bore an effective discount rate of 12%, was repaid through
withholdings from oil sales on a monthly basis through December 1994. In March
and August 1995, GEOILBENT received $3.0 million and $2.0 million,
respectively, in production payment advances pursuant to similar agreements
with NAFTA Moscow containing similar terms. At December 31, 1995, the
Company's share of the outstanding liability was approximately $1.0 million.
Additionally, the Company has other short term borrowings which aggregate
approximately $1.0 million at December 31, 1995.
Note 5 - Commitments and Contingencies
The state leases relating to the West Cote Blanche Bay Field, the portion of
the Belle Isle Field owned by Texaco and the Rabbit Island Field, were the
subject of litigation between Texaco and the State of Louisiana. The Company's
interests in the Fields, which include substantially all of the Company's
domestic reserves, were originally owned by Texaco under certain leases granted
by the State. Although the Company was not a party to this litigation, its interests in the Fields were subject to the litigation. In February 1994, the
State and Texaco entered into a Global Settlement Agreement to settle all
disputes related to this litigation. As a result of this agreement, Texaco has
committed to certain acreage development and drilling obligations which may
affect the Company and certain of its Louisiana properties.international projects. The Company believes that the settlement and the subsequent sale of the working interest by
Texacofees
paid to Apache Corporation should have no effect on its proved reserves and
should have no material adverse effect on the Company.
Investors in partnerships which were sponsored by a third party have sued the
Company on the theory that since it provided oil and gas drilling prospects to
those partnerships and operated substantially all of their properties, it was
responsible for alleged violations of securities laws in connection with the
offer and sale of interests, contractual breach of fiduciary duty and fraud.
The Company has entered into a settlement agreement related to these claims,
whereby the Company has paid $990,000 to the
S-12
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
plaintiffs in full settlement of these claims. Legal fees of $683,272 in
addition to the settlement amount have been included in litigation settlement
expenses for the year ended December 31, 1995.
In the normal course of its business, the Company may periodically become
subject to actions threatened or brought by its investors or partners in
connection with the operation or development of its properties or the sale of
securities. Prior to 1992, the Company was engaged in the formation and
operation of oil and gas limited partnership interests. In 1992, the Company
ceased raising funds through such sales. Certain of such limited partners in
the Company's partnerships brought an action against the Company in connection
with the Company's operation of the limited partnerships as managing general
partner. The parties have agreed to submit the claims to binding arbitration.
The arbitration is currently in the discovery stage. The plaintiffs seek
actual and punitive damages for alleged actions and omissions by the Company in
operating the partnerships and alleged misrepresentations made by the Company
in selling the limited partnership interests. The Company intends to
vigorously defend this action and does not believe the claims raised are
meritorious. However, new developments could alter this conclusion at any
time. The Company will be forced to expend time and financial resources to
defend or resolve any such matters. The Company is also subject to ordinary
litigation that is incidental to its business. None of the above matters are
expected to have a material adverse effect on the Company.
The Company's aggregate rental commitments and related sub-leases for
noncancellable agreements at December 31, 1995, are as follows:
Rental Commitments Sub-leases
------------------ ----------
1996 $ 462,409 $(171,224)
1997 315,991
1998 319,160
1999 314,329
2000 308,652
Thereafter 1,234,608
---------- ---------
$2,955,149 $(171,224)
========== ========
Rental expense was $1,981,253, $255,650 and $233,934 for the years ended
December 31, 1995, 1994 and 1993, respectively.
Note 6 - Taxes on Income
The tax effects of significant items comprising the Company's net deferred
income taxes as of December 31, 1995 and 1994 are as follows:
1995 1994
--------------- --------------
Deferred tax assets:
Operating loss carryforwards $ 16,400,000 $ 13,509,000
Foreign tax credit carryforwards 2,500,000 549,000
Valuation allowance (4,000,000) (6,231,000)
------------ ------------
Total 14,900,000 7,827,000
------------ ------------
Deferred tax liabilities:
Difference in basis of property 3,500,000 4,704,000
Undistributed earnings of foreign subsidiaries 11,400,000 3,123,000
------------ ------------
Total 14,900,000 7,827,000
------------ ------------
Net deferred tax liability $ --- $ ---
============ ============
S-13
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
A comparison of the income tax expense at the federal statutory rate to the
Company's provision for income taxes is as follows:
1995 1994 1993
-------------- ------------- ---------------
Income (loss) before income taxes:
United States $ (9,500,000) $ (4,363,000) $ (2,988,000)
Foreign 27,873,000 10,109,000 (1,841,000)
--------------- -------------- ------------
Total $ 18,373,000 $ 5,746,000 $ (4,829,000)
============== ============== ============
Computed tax expense at the statutory rate $ 6,431,000 $ 2,011,000 $ (1,690,000)
State income taxes, net of federal effect 919,000 287,000
Minority interest (2,229,000) (907,000)
Other (412,000) 76,000
Change in valuation allowance (2,231,000) (769,000) 1,690,000
-------------- ---------------- --------------
Provision for income taxes $ 2,478,000 $ 698,000 $ --
============== ============== ============
The provisions for income taxes for 1995 and 1994 consist primarily of foreign
income taxes currently payable. The Company is providing for deferred income
taxes on undistributed earnings of foreign subsidiaries.
The Company has provided a valuation allowance for the excess benefits of
operating loss and tax credit carryforwards. As of December 31, 1995, the
Company had, for federal income tax purposes, operating loss carryforwards of
approximately $41.0 million, expiring in the years 2003 through 2010. If the
carryforwards are ultimately realized, approximately $3.0 million will be
credited to additional paid-in capital for tax benefits associated with
deductions for income tax purposes related to stock options.
Note 7 - Stock Options
The Company adopted its 1988 Stock Option Plan in December 1988 authorizing
options to acquire up to 418,824 shares of common stock. Under the plan,
incentive stock options were granted to key employees and other options, stock
or bonus rights were granted to key employees, directors, independent
contractors and consultants at prices equal to or below market price,
exercisable over various periods.
The Company adopted its 1989 Nonstatutory Stock Option Plan during 1989
covering 2,000,000 shares of common stock which were granted to key employees,
directors, independent contractors and consultants at prices equal to or below
market prices, exercisable over various periods. The plan was amended during
1990 to add 1,960,000 shares of common stock to the plan.
As shares became exercisable under the 1988 and 1989 plans, the Company
recorded compensation expense (a portion of which is associated with
exploration overhead and is therefore capitalized) to the extent that the
market price on the date of grant exceeded the option price. For the year ended
December 31, 1993, compensation expense of $142,420 was recorded.
In September 1991, the Company adopted the 1991-1992 Stock Option Plan and the
Directors' Stock Option Plan. The 1991-1992 Stock Option Plan permits the
granting of stock options to purchase up to 2,500,000 shares of the Company's
common stock in the form of incentive stock options ("ISOs") and nonqualified
stock options ("NQSOs") to officers and employees of the Company. Options may
be granted as ISOs, NQSOs or a combination of each, with exercise prices not
less than the fair market value of the common stock on the date of the grant.
The amount of ISOs that may be granted to any one participant is subject to the
dollar limitations imposed by the Internal Revenue Code of 1986, as amended.
In the event of a change in control of the Company, all outstanding options
become immediately exercisable to the extent permitted by the 1991- 1992 Stock
Option Plan. All options granted to date under the 1991-1992 Stock Option Plan
vest ratably over a three-year period from their dates of grant.
S-14
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
The Directors' Stock Option Plan permits the granting of nonqualified stock
options ("Director NQSOs") to purchase up to 400,000 shares of common stock to
nonemployee directors of the Company. Upon election as a director and annually
thereafter, each individual who serves as a nonemployee director automatically
is granted an option to purchase 10,000 shares of common stock at a price not
less than the fair market value of common stock on the date of grant. All
Director NQSOs vest automatically on the date of the grant of the options.
1989 Nonstatutory
1988 Stock Option Plan Stock Option Plan
---------------------------------------------------------------------------------------------
Option Option Currently Option Option Currently
Prices Shares Exercisable Prices Shares Exercisable
---------------------------------------------------------------------------------------------
Balance at January 1, 1993 $1.17 to $4.89 113,633 113,633 $1.39 to $11.75 1,252,146 852,148
======= =======
Options cancelled $2.55 (40,000)
Options exercised $1.17 (33,633) $1.39 to $ 4.89 (250,579)
-------- --------
Balance at December 31, 1993 80,000 80,000 961,567 951,567
====== =======
Options exercised $2.81 to $ 4.89 (23,000)
-------- -------
Balance at December 31, 1994 $4.89 80,000 80,000 938,567 938,567
====== =======
Options exercised $4.89 (80,000) $1.39 to $ 4.89 (82,900)
-------- -------
Balance at December 31, 1995 0 0 $1.39 to $11.75 855,667 855,667
======== ======= ======= =======
1991 - 1992
Stock Option Plan Directors' Stock Option Plan
---------------------------------------------------------------------------------------------
Option Option Currently Option Option Currently
Prices Shares Exercisable Prices Shares Exercisable
---------------------------------------------------------------------------------------------
Balance at January 1, 1993 $5.25 to $10.125 838,000 109,334 $6.25 to $10.25 80,000 9,999
======= ======
Options granted $8.13 to $ 8.75 345,000 $ 7.00 40,000
Options cancelled $7.75 to $10.125 (70,000)
-------
Balance at December 31, 1993 1,113,000 365,332 120,000 36,667
======= ======
Options granted $5.63 to $ 9.125 825,000 $6.813 40,000
Options cancelled $10.125 (3,000)
-------
Balance at December 31, 1994 1,935,000 733,334 160,000 160,000
======= =======
Options granted $9.00 to $ 15.25 527,500 $11.50 30,000
Options cancelled $5.25 to $ 7.00 (56,667)
Options exercised $5.25 to $10.125 (109,680)
--------
Balance at December 31, 1995 $5.50 to $10.125 2,296,153 1,163,655 $6.25 to $11.50 190,000 190,000
========= ========= ======= =======
In addition to options issuedMr. Wray pursuant to the plans, options for 80,000consulting
9
agreements were comparable to those fees that have been charged by independent
consultants providing similar services. On January 3, 1996, Mr. Wray was elected
President and 135,000 shares of common stock were issued in 1994 and 1993, respectively, to
individuals other than officers, directors or employeesChief Financial Officer of the Company at
prices ranging from $5.63 to $10.25. The options vest over three to four years
and at December 31, 1995, 234,000 options were outstanding of which 140,667
options were vested.
Note 8 - Stock Warrants
During the years ended December 31, 1991, 1992, 1994 and 1995, the Company
issued a total of 690,793, 658,617, 450,000 and 125,000 warrants, respectively.
Each warrant entitles the holder to purchase one share of common stock at the
exercise price of the warrant. Substantially all the warrants are immediately
exercisable upon issuance.
S-15
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
In April 1991, 655,813 warrants were issued in connection with the privately
placed sale of the Company's common stock. In October 1991, the Company issued
34,980 warrants to a placement agent who marketed the Company's 8% convertible
subordinated notes.
In January 1992, 29,841 warrants were issued to a placement agent who sold
shares in the public offering of the Company's stock. In February 1992, 37,118
warrants were issued in connection with the marketing of working interests in a
well the Company drilled. Also in February 1992, 25,000 warrants were issued
in connection with an acquisition of a working interest in a well of which 155
were exercised during the year ended December 31, 1995. In April 1992, 31,400
warrants were issued to a placement agent who marketed the Company's 8%
convertible subordinated debentures and in July 1992, 5,000 warrants were
issued to a consultant to the Company of which 2,500 and 1,000 were exercised
during the years ended December 31, 1993 and 1995, respectively. The Company
was the managing general partner of two limited partnerships that were
liquidated in November 1992. In October 1992, 530,258 warrants were issued to
the partners in these partnerships in connection with the liquidation of which
2,000 were exercised during the year ended December 31, 1995.
In September 1994, 250,000 warrants were issued in connection with the issuance
of $15 million in senior unsecured notes and in December 1994, 50,000 warrants
were issued in connection with a revolving secured credit facility.
In July 1994, the Company issued warrants entitling the holder to purchase a
total of 150,000 shares of common stock at $7.50 per share, subject to
adjustment in certain circumstances, that are exercisable on or before July
2004. 50,000 warrants were immediately exercisable, and 50,000 warrants become
exercisable each July in 1995 and 1996.
In June 1995, 125,000 warrants were issued in connection with the issuance of
$20 million in senior unsecured notes.
The dates the warrants were issued, the expiration dates, the exercise prices
and the number of warrants issued and outstanding at December 31, 1995 were:
Date Issued Expiration Date Exercise Price Issued Outstanding
------------------------------------------------------------------------------------
April 1991 April 1996 $14.41* 592,786 592,786
April 1991 April 1996 11.56* 63,027 63,027
October 1991 October 1996 14.07 34,980 34,980
January 1992 January 1997 12.03 29,841 29,841
February 1992 February 1997 14.63* 37,118 37,118
February 1992 February 1997 9.00 25,000 24,845
April 1992 April 1997 10.30 31,400 31,400
July 1992 July 1997 7.30 5,000 1,500
October 1992 October 1997 10.00 530,258 528,258
July 1994 July 2004 7.50 150,000 150,000
September 1994 September 2002 9.00 250,000 250,000
December 1994 December 2004 12.00 50,000 50,000
June 1995 June 2007 17.09 125,000 125,000
--------- ---------
1,924,410 1,918,755
========= =========
* Price represents weighted average price.
Note 9 - Russian Export Tariff
For the year ended December 31, 1994, the Company recorded an expense for the
Russian export tariff of $1,397,317 which is included in lease operating
expenses and production taxes. GEOILBENT received a waiver from the export
tariff for 1995. Russia has recently announced that, in July 1996, such oil
export tariffs will be terminated in conjunction with a loan agreement with the
International Monetary Fund. It is anticipated that the tariff on oil
exporters may be replaced by an excise or other duty levied on all oil
producers, but it is currently unclear how such other tax rates and regimes
will be set and administered. The Russian regulatory environment continues to
be volatile and the Company is unable to predict the availability of the waiver
for the future.
S-16
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Note 10 - Venezuela Operations
On July 31, 1992, the Company and its partner, Venezolana de Inversiones y
Construcciones Clerico, C.A. ("Vinccler"), signed an operating service
agreement to reactivate and further develop three Venezuelan oil fields with
Lagoven, S.A., an affiliate of the national oil company, Petroleos de
Venezuela, S.A. The operating service agreement covers the Uracoa, Bombal and
Tucupita fields that comprise the South Monagas unit. Under the terms of the
operating service agreement, Benton-Vinccler, a corporation owned 80% by the
Company and 20% by Vinccler, is a contractor for Lagoven and is responsible for
overall operations of the South Monagas unit, including all necessary
investments to reactivate and develop the fields comprising the unit.
Benton-Vinccler receives an operating fee in U.S. dollars deposited into a U.S.
commercial bank account for each barrel of crude oil produced (subject to
periodic adjustments to reflect changes in a special energy index of the U.S.
Consumer Price Index) and is reimbursed according to a prescribed formula in
U.S. dollars for its capital costs, provided that such operating fee and cost
recovery fee cannot exceed the maximum dollar amount per barrel set forth in
the agreement (which amount is periodically adjusted to reflect changes in the
average of certain world crude oil prices). The Venezuelan government
maintains full ownership of all hydrocarbons in the fields.
Pursuant to the original joint venture agreement, the Company and Vinccler each
owned a 50% interest in a joint venture which operated the South Monagas unit.
Effective January 1, 1994, the operating service agreement and the joint
venture assets and liabilities were transferred to Benton-Vinccler, a
corporation in which the Company and Vinccler each owned 50% of the capital
stock. On March 4, 1994, the Company acquired capital stock from Vinccler
representing an additional 30% ownership interest in Benton-Vinccler for $3
million in cash, $10 million in non-interest bearing notes payable (with a
present value of $9.2 million assuming a 10% interest rate) payable in various
installments over 24 months and 200,000 shares of the Company's common stock.
The excess of the purchase price over the book value of the 30% interest was
allocated to oil and gas properties. The final installment on the non-interest
bearing notes of $1 million, originally due in January 1996, has been extended
to July 1996, with interest at 13% during the extension period.
Prior to the acquisition of the additional 30% interest in Benton-Vinccler, the
Company's interest in the Venezuelan joint venture was proportionately
consolidated based on its ownership interest. Effective with the acquisition
of the additional 30% interest in Benton-Vinccler, the Company has included
Benton-Vinccler in its consolidated financial statements, with the 20% owned by
Vinccler reflected as a minority interest.
Note 11 - Related Party TransactionsCompany.
On December 31, 1993, the Company guaranteed a loan made to Mr. A.E.A. E.
Benton, its President and Chief Executive Officer, for $300,000. In January 1994, the Company
loaned $800,000 to Mr. Benton with interest at prime plus 1%1.0%; in September
1994, Mr. Benton made a payment of $207,014 against this loan. In December 1995,
the Company purchased a home from Mr. Benton for $1.73 million, based on two
independent appraisals, and from the proceeds Mr. Benton repaid the balance owed
to the Company of $592,986 plus accrued interest and the $300,000 loan
guaranteed by the Company. The home, which the Company anticipates selling the home in 1996, has been included in other assets1996. The
Company loaned Mr. Pratt $95,000 on November 11, 1993 on the same terms as of December 31, 1995.
Note 12 - Earnings Per Share
Primary earnings per common share are computed by dividing net income (loss)the
$800,000 loan to Mr. Benton, which is payable on demand by the weighted average number of common and common equivalent shares outstanding.
Common equivalent shares are shares which may be issuable upon exercise of
outstanding stock options and warrants; however, they are not included in the
computation for the year ended December 31, 1993, since their effect would be
to reduce the net loss per share and for the year ended December 31, 1994,
because their effect would result in dilution of less than 3%. Fully diluted
earnings per share are not presented because they are not materially different
from primary earnings per share. Total weighted average shares outstanding
during the years ended December 31, 1995, 1994 and 1993 were 26,673,483,
24,850,922 and 18,608,770, respectively.
S-17
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Note 13 - Major Customers
The Company is principally involved in the business of oil and gas exploration
and production. Oil and gas purchasers which represented more than 10% of oil
and gas revenues were Lagoven, S.A. (79%) for the year ended December 31, 1995;
Lagoven, S.A. (67%) and Texon Corporation (10%) for the year ended December 31,
1994; and Texon Corporation (63%) and Lagoven, S.A. (18%) for the year ended
December 31, 1993.
Note 14 - Subsequent Events
SALE OF GULF COAST PROPERTIES
In March 1996, the Company entered into an agreement with Shell to sell its
Gulf Coast properties for approximately $35.4 million. The sale, which
includes virtually all of the Company's United States oil and gas reserves, is
expected to close in April 1996 and result in a gain of approximately $7.5
million after adjustments for revenues and expenses subsequent to the effective
date of December 31, 1995. In conjunction with this sale, the Company agreed
to repay $35 million in senior unsecured notes (see Note 3). Repayment of the
notes, which is contingent on the closing of the sale, will include estimated
prepayment premiums of approximately $11.1 million. The repayment will be made
$18.4 million at the closing of the sale and the balance of $27.7 million on
the completion of certain refinancing arrangements, required to be no later
than June 30, 1996. Additionally, with respect to a revolving credit facility
secured by these properties, the Company will repay $5.0 million to the lending
institution and up to $1.8 million to the arranging financial institution
pursuant to a credit enhancement agreement. Assuming the sale closes in April,
the gain on sale of properties will be recorded in the second quarter of 1996.
The debt prepayment premiums and related costs will be recognized as an
extraordinary loss, also in the second quarter of 1996.
Had the sale occurred on December 31, 1995, the pro forma effects of the
transaction on the consolidated balance sheet as of December 31, 1995 would be
an increase in cash of $9.6 million and reductions in oil and gas properties of
$22.9 million, other assets of $0.3 million and long term debt of $12.3
million. Retained earnings after giving effect to the sale would decrease by
$1.3 million.
Assuming the sale had occurred on January 1, 1995, pro forma effects on the
consolidated statement of operations for the year ended December 31, 1995 would
include reductions in oil and gas revenues, lease operating costs and
production taxes and depletion of $7.4 million, $1.0 million and $4.0 million,
respectively. Interest expense would also be reduced by $2.7 million. Income
from continuing operations and earnings per share, before charges and credits
related to this transaction, would increase $0.2 million and $.01,
respectively.
PARTNERSHIP EXCHANGE OFFER AND SALE OF PROPERTIES
In January 1996, the Company completed an exchange offer under which it issued
168,362 shares of common stock and warrants to purchase 587,783 shares of
common stock in exchange for the outstanding limited partnership interests in
the three remaining limited partnerships. The shares of common stock were
valued at $1.9 million, which was allocated to oil and gas properties. The oil
and gas properties were immediately sold at their approximate book value. The
warrants, which were issued as an inducement to the participants to accept the
Exchange Offer, were valued at $3.64 each, or a total of $2.1 million, and will
be charged to expense in the first quarter of 1996.
S-18
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Note 15 - Oil and Gas Activities
Total costs incurred in oil and gas acquisition, exploration and development
activities were:
Venezuela Russia United States Total
--------- ------ ------ ------ -----
Year Ended December 31, 1995
Property acquisition costs $ 435,575 $ 435,575
Development costs $ 54,533,329 $12,373,856 5,463,239 72,370,424
Exploration costs 112,054 593,367 705,421
------- ------------ ------- -------
$ 54,645,383 $12,373,856 $ 6,492,181 $73,511,420
============ =========== ============ ===========
Year Ended December 31, 1994
Property acquisition costs $ 13,446,757 $ 875,129 $ 14,321,886
Development costs 24,676,748 $ 8,654,730 2,993,728 36,325,206
Exploration costs 265,856 2,542,935 2,808,791
------- ------------ --------- ---------
$ 38,389,361 $ 8,654,730 $ 6,411,792 $ 53,455,883
============ =========== =========== ============
Year Ended December 31, 1993
Property acquisition costs 380,178 380,178
Development costs $ 6,307,756 $ 10,483,807 2,149,632 18,941,195
Exploration costs 373,348 6,258,127 6,631,475
------- ------------- --------- ---------
$ 6,681,104 $ 10,483,807 $ 8,787,937 $25,952,848
============ ============ =========== ===========
The Company's aggregate amount of capitalized costs related to oil and gas
producing activities consists of the following at December 31:
Venezuela Russia United States Total
--------- ------ ------ ------ -----
December 31, 1995
Proved property costs $ 93,910,671 $ 37,070,018 $130,980,689
Costs excluded from amortization 14,001,386 3,214,849 $ 709,136 17,925,371
Properties held for sale (net of
accumulated 22,885,176 22,885,176
depletion of $8,344,830)
Oilfield inventories 5,306,735 12,579 5,319,314
Less accumulated depletion (16,620,070) (2,449,846) (19,069,916)
----------- ------------ ------------ ------------
$ 96,598,722 $ 37,835,021 $ 23,606,891 $158,040,634
============= ============ ============ ============
December 31, 1994
Proved property costs $ 46,523,663 $ 25,482,193 $ 27,508,414 $ 99,514,270
Costs excluded from amortization 6,743,012 2,428,818 7,523,454 16,695,284
Oilfield inventories 1,228,225 16,385 1,244,610
Less accumulated depletion (5,227,293) (937,025) (13,278,505) (19,442,823)
---------- ------------ ----------- -----------
$ 49,267,607 $ 26,973,986 $ 21,769,748 $ 98,011,341
============= ============ ============ ============
December 31, 1993
Proved property costs $ 8,074,023 $ 16,832,410 $ 40,197,929 $ 65,104,362
Costs excluded from amortization 2,423,871 9,551,744 11,975,615
Less accumulated depletion (229,080) (99,207) (9,031,202) (9,359,489)
------------- ------------ ------------ ------------
$ 7,844,943 $ 19,157,074 $ 40,718,471 $ 67,720,488
============= ============ ============ ============
The Company regularly evaluates its unproved properties to determine whether
impairment has occurred. The Company has excluded from amortization its
interest in unproved properties, the cost of uncompleted exploratory
activities, and portions of major development costs. The principal portion of
such costs are expected to be included in amortizable costs during the next two
years.
S-19
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Excluded costs at December 31, 1995 consisted of the following by year
incurred:
Total 1995 1994 1993 Prior to 1993
----- ---- ---- ---- -------------
Property acquisition costs $ 1,412,850 $ 786,032 $ 4,947 $ 7,164 $ 614,707
Development costs 15,656,320 7,345,220 6,509,100 1,802,000
Exploration costs 856,201 513,417 342,784
----------- ---------- ---------- ---------- -----------
$17,925,371 $8,644,669 $6,856,831 $1,809,164 $ 614,707
=========== ========== ========== ========== ==========
Results of operations for oil and gas producing activities were:
Venezuela Russia United States Total
------------ ----------- ----------- -------------
Year ended December 31, 1995
Oil and gas revenues $ 49,173,832 $ 6,016,297 $ 7,682,768 $ 62,872,897
Expenses:
Lease operating costs and production taxes 6,482,775 2,763,860 1,456,162 10,702,797
Depletion 11,392,777 1,512,821 4,187,440 17,093,038
------------ ----------- ----------- -------------
Total expenses 17,875,552 4,276,681 5,643,602 27,795,835
------------ ----------- ----------- -------------
Results of operations from oil and gas
producing activities $ 31,298,280 $ 1,739,616 $ 2,039,166 $ 35,077,062
============ =========== ============ ==============
Year ended December 31, 1994
Oil and gas revenues $ 21,472,015 $ 3,512,940 $ 7,286,723 $ 32,271,678
Expenses:
Lease operating costs and production taxes 3,807,434 2,832,621 2,891,209 9,531,264
Depletion 4,998,213 837,818 4,247,303 10,083,334
------------ ----------- ----------- -------------
Total expenses 8,805,647 3,670,439 7,138,512 19,614,598
------------ ----------- ----------- -------------
Results of operations from oil and gas
producing activities $ 12,666,368 $ (157,499) $ 148,211 $ 12,657,080
============ =========== ============ ==============
Year ended December 31, 1993
Oil and gas revenues $ 1,332,927 $ 323,928 $ 5,565,455 $ 7,222,310
Expenses:
Lease operating costs and production taxes 1,164,453 458,301 3,487,510 5,110,264
Depletion 229,080 99,207 2,142,133 2,470,420
------------ ----------- ----------- -------------
Total expenses 1,393,533 557,508 5,629,643 7,580,684
------------ ----------- ----------- -------------
Results of operations from oil and gas
producing activities $ (60,606) $ (233,580) $ (64,188) $ (358,374)
============ =========== ============ ==============
Results of operations in Russia reflect the twelve months ended December 31,
1993 and 1994 and the nine months ended September 30, 1995 (see Note 1). The
Company estimates that oil and gas revenues and expenses in Russia for the
quarter ended December 31, 1995 would both amount to approximately $2.5
million, and will be included in the Company's consolidated results of
operations for the first quarter of 1996.
In May 1994, the Company entered into a commodity hedge agreement designed to
reduce a portion of the Company's risk from oil price movements. Pursuant to
the hedge agreement, the Company will receive $16.82 per Bbl and will pay the
average price per Bbl of West Texas Intermediate Light Sweet Crude Oil. Such
terms apply to production of 1,000 Bbl of oil per day for 1994, 1,250 Bbl of
oil per day in 1995 and 1,500 Bbl of oil per day for 1996. During the years
ended December 31, 1995 and 1994, respectively, the Company incurred losses of
$716,203 and $328,868, respectively, under the hedge agreement which reduced
oil and gas sales. The Company is exposed to credit loss in the event of
non-performance by the counterparty. The Company anticipates, however, that
the counterparty will be able to fully satisfy its obligation under the
contract.
S-20
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
QUANTITIES OF OIL AND GAS RESERVES (UNAUDITED)
Proved reserves are estimated quantities of crude oil, natural gas, and natural
gas liquids which geological and engineering data demonstrate with reasonable
certainty to be recoverable from known reservoirs under existing economic and
operating conditions. Proved developed reserves are those which are expected
to be recovered through existing wells with existing equipment and operating
methods. All Venezuelan reserves are attributable to an operating service
agreement between the Company and Lagoven, S.A., under which all mineral rights
are owned by the government of Venezuela. Sales of reserves in place in 1994
and 1995 include reserves related to the United States properties sold in March
1995 (see Note 2) and in March 1996 (see Note 14), respectively.
The evaluations of the oil and gas reserves as of December 31, 1995, 1994, 1993
and 1992 were audited by Huddleston & Co., Inc., independent petroleum
engineers.
S-21
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Minority
United Interest in
Venezuela Russia States Total Venezuela Net Total
- ------------------------------------------------------------------------------------------------------------------------------------
Proved Reserves - Crude oil, condensate, and
gas liquids (Mbbls)
Year ended December 31, 1995
Proved reserves beginning of the year 60,707 17,540 233 78,480 (12,141) 66,339
Revisions of previous estimates (12,877) (107) (12,984) 2,575 (10,409)
Extensions, discoveries and improved recovery 31,219 5,569 91 36,879 (6,243) 30,636
Production (5,456) (491) (69) (6,016) 1,091 (4,925)
Sales of reserves in place (148) (148) (148)
------ ------ ------ ------ ------ ------
Proved reserves end of year 73,593 22,618 0 96,211 (14,718) 81,493
====== ====== ====== ====== ====== ======
Year ended December 31, 1994
Proved reserves beginning of the year 19,389 10,121 10,258 39,768 39,768
Revisions of previous estimates (2,583) (201) 1,819 (965) 517 (448)
Purchases of reserves in place 19,389 19,389 (7,756) 11,633
Extensions, discoveries and improved recovery 27,032 7,914 152 35,098 (5,406) 29,692
Production (2,520) (294) (226) (3,040) 504 (2,536)
Sales of reserves in place (11,770) (11,770) (11,770)
------ ------ ------ ------ ------ ------
Proved reserves end of year 60,707 17,540 233 78,480 (12,141) 66,339
====== ====== ====== ====== ====== ======
Year ended December 31, 1993
Proved reserves beginning of the year 8,966 8,133 13,194 30,293 30,293
Revisions of previous estimates 32 259 (2,490) (2,199) (2,199)
Extensions, discoveries and improved recovery 10,551 1,757 132 12,440 12,440
Production (160) (28) (292) (480) (480)
Sales of reserves in place (286) (286) (286)
------ ------ ------ ------ ------
Proved reserves end of year 19,389 10,121 10,258 39,768 39,768
====== ====== ====== ====== ======
Proved Developed Reserves at:
December 31, 1995 30,032 3,475 0 33,507 (6,006) 27,501
December 31, 1994 12,580 2,772 155 15,507 (2,516) 12,991
December 31, 1993 3,999 400 8,153 12,552 12,552
January 1, 1993 2,269 10,905 13,174 13,174
Proved Reserves - Natural gas (Mmcf)
Year ended December 31, 1995
Proved reserves beginning of the year 16,077 16,077 16,077
Revisions of previous estimates (5,395) (5,395) (5,395)
Extensions, discoveries and improved recovery 12,927 12,927 12,927
Production (3,785) (3,785) (3,785)
Sales of reserves in place (19,818) (19,818) (19,818)
------ ------ ------
Proved reserves end of year 6 6 6
====== ====== ======
Year ended December 31, 1994
Proved reserves beginning of the year 18,099 18,099 18,099
Revisions of previous estimates (1,120) (1,120) (1,120)
Extensions, discoveries and improved recovery 9,153 9,153 9,153
Production (2,062) (2,062) (2,062)
Sales of reserves in place (7,993) (7,993) (7,993)
------ ------ ------
Proved reserves end of year 16,077 16,077 16,077
====== ====== ======
Year ended December 31, 1993
Proved reserves beginning of the year 19,455 19,455 19,455
Revisions of previous estimates (3,400) (3,400) (3,400)
Extensions, discoveries and improved recovery 2,820 2,820 2,820
Production (233) (233) (233)
Sales of reserves in place (543) (543) (543)
------ ------ ------
Proved reserves end of year 18,099 18,099 18,099
====== ====== ======
Proved Developed Reserves at:
December 31, 1995 6 6 6
December 31, 1994 8,385 8,385 8,385
December 31, 1993 6,584 6,584 6,584
January 1 , 1993 9,930 9,930 9,930
(1) The Securities and Exchange Commission requires the reserve presentation
to be calculated using year-end prices and costs and assuming a continuation of
existing economic conditions. Proved reserves cannot be measured exactly, and
the estimation of reserves involves judgmental determinations. Reserve
estimates must be reviewed and adjusted periodically to reflect additional
information gained from reservoir performance, new geological and geophysical
data and economic changes. The above estimates are based on current technology
and economic conditions, and the Company considers such estimates to be
reasonable and consistent with current knowledge of the characteristics and
extent of production. The estimates include only those amounts
S-22
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
considered to be Proved Reserves and do not include additional amounts which
may result from new discoveries in the future, or from application of secondary
and tertiary recovery processes where facilities are not in place.
(2) Proved Developed Reserves are reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.
This classification includes:
(a) Proved developed producing reserves which are reserves expected to be
recovered through existing completion intervals now open for production in
existing wells; and
(b) Proved developed nonproducing reserves which are reserves that exist
behind the casing of existing wells which are expected to be produced in the
predictable future, where the cost of making such oil and gas available for
production should be relatively small compared to the cost of a new well.
Any reserves expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing primary
recovery methods are included as Proved Developed Reserves only after testing
by a pilot project or after the operation of an installed program has confirmed
through production response that increased recovery will be achieved.
(3) Proved Undeveloped Reserves are Proved Reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on
undrilled acreage are limited to those drilling units offsetting productive
units, which are reasonably certain of production when drilled.
Proved Reserves for other undrilled units are claimed only where it can be
demonstrated with certainty that there is continuity of production from the
existing productive formation. No estimates for Proved Undeveloped Reserves
are attributable to or included in this table for any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated unless proved effective by actual tests in the area and in the
same reservoir.
(4) The Company's engineering estimates indicate that a significant quantity
of natural gas reserves (net to the Company's interest) will be developed and
produced in association with the development and production of the Company's
proved oil reserves in Russia. The Company expects that, due to current market
conditions, it will initially reinject or flare such associated natural gas
production, and accordingly, no future net revenue has been assigned to these
reserves. Under the joint venture agreement, such reserves are owned by the
Company in the same proportion as all other hydrocarbons in the field, and
subsequent changes in conditions could result in the assignment of value to
these reserves.
(5) Changes in previous estimates of proved reserves result from new
information obtained from production history and changes in economic factors.
S-23
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES (UNAUDITED)
The standardized measure of discounted future net cash flows is presented in
accordance with the provisions of SFAS No. 69. In preparing this data,
assumptions and estimates have been used, and the Company cautions against
viewing this information as a forecast of future economic conditions.
Future cash inflows were estimated by applying year-end prices, adjusted for
fixed and determinable escalations provided by contract, to the estimated
future production of year-end proved reserves. Future cash inflows were
reduced by estimated future production and development costs to determine
pre-tax cash inflows. Future income taxes were estimated by applying the
year-end statutory tax rates to the future pre-tax cash inflows, less the tax
basis of the properties involved, and adjusted for permanent differences and
tax credits and allowances. The resultant future net cash inflows are
discounted using a ten percent discount rate.
Russia has established an export tariff on all oil produced in and exported
from Russia. GEOILBENT received a waiver from the export tariff for 1995. For
purposes of estimating future net cash flows, the export tariff was applied to
the Company's Russian production for the remainder of the life of the
operations after 1995, although the Company believes that additional waivers
may be obtained in the future. The discounted value of the waiver net to the
Company's interest as of December 31, 1994 was approximately $3 million.
Russia has recently announced that in July 1996, such oil export tariffs will
be terminated in conjunction with a loan agreement with the International
Monetary Fund. It is anticipated that the tariff on oil exporters may be
replaced by an excise or other duty levied on all oil producers, but it is
currently unclear how such other tax rates and regimes will be set and
administered. For purposes of estimating future net cash flows, a tariff of
approximately $1.84 per Bbl has been applied to all future production.
S-24
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
Standardized Measure Minority
United Interest in
Venezuela Russia States Total Venezuela Net Total
------------------------------------------------------------------------
December 31, 1995 (amounts in thousands)
Future cash inflow $652,110 $283,630 $ 19 $935,759 ($130,422) $805,337
Future production costs (170,328) (102,783) (2) (273,113) 34,066 (239,047)
Other related future costs (76,368) (36,686) 0 (113,054) 15,274 (97,780)
-------- -------- -------- -------- -------- --------
Future net revenue before income taxes 405,414 144,161 17 549,592 (81,082) 468,510
10% annual discount for estimated timing of cash flows (118,498) (58,800) (1) (177,299) 23,700 (153,599)
-------- -------- -------- -------- -------- --------
Discounted future net cash flows before income taxes 286,916 85,361 16 372,293 (57,382) 314,911
Future income taxes, discounted at 10% per annum (80,371) (29,927) 0 (110,298) 16,074 (94,224)
-------- -------- -------- -------- -------- --------
Standardized measure of discounted future net cash flows $206,545 $ 55,434 $ 16 $261,995 ($ 41,308) $220,687
======== ======== ======== ======== ======== ========
December 31, 1994
Future cash inflow $528,214 $204,520 $32,091 $764,825 $(105,643) $659,182
Future production costs (64,950) (98,767) (3,760) (167,477) 12,990 (154,487)
Other related future costs (79,486) (25,378) (2,002) (106,866) 15,897 (90,969)
-------- -------- -------- -------- -------- --------
Future net revenue before income taxes 383,778 80,375 26,329 490,482 (76,756) 413,726
10% annual discount for estimated timing of cash flows (114,948) (31,542) (7,672) (154,162) 22,990 (131,172)
-------- -------- -------- -------- -------- --------
Discounted future net cash flows before income taxes 268,830 48,833 18,657 336,320 (53,766) 282,554
Future income taxes, discounted at 10% per annum (96,127) (16,435) (371) (112,933) 19,225 (93,708)
-------- -------- -------- -------- -------- --------
Standardized measure of discounted future net cash flows $172,703 $ 32,398 $ 18,286 $223,387 $(34,541) $188,846
======== ======== ======== ======== ======== ========
S-25
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
December 31, 1993
Future cash inflow $148,130 $111,333 $183,911 $443,374
Future production costs (16,952) (55,461) (65,224) (137,637)
Other related future costs (19,841) (16,370) (54,733) (90,944)
-------- -------- -------- --------
Future net revenue before income taxes 111,337 39,502 63,954 214,793
10% annual discount for estimated timing of cash flows (39,131) (15,265) (28,984) (83,380)
-------- -------- -------- --------
Discounted future net cash flows before income taxes 72,206 24,237 34,970 131,413
Future income taxes, discounted at 10% per annum (21,248) (4,725) (2,924) (28,897)
-------- -------- -------- --------
Standardized measure of discounted future net cash flows $ 50,958 $ 19,512 $ 32,046 $102,516
======== ======== ======== ========
Years Ended December 31,
----------------------------------------------------------
Changes in Standardized Measure 1995 1994 1993
---- ---- ----
(amounts in thousands)
Balance, January 1 $223,387 $102,516 $ 104,010
Changes resulting from:
Sales of oil and gas, net of related costs (52,170) (22,741) (2,112)
Revisions to estimates of proved reserves:
Pricing (6,990) (6,243) (52,239)
Quantities (63,802) (4,150) (6,292)
Sales of reserves in place (28,102) (28,664) (1,735)
Extensions, discoveries and improved recovery,
net of future costs 170,037 169,860 47,700
Purchases of reserves in place 72,206
Accretion of discount 33,632 13,142 14,181
Change in income taxes 2,635 (84,036) 8,903
Development costs incurred 47,657 13,365 10,480
Changes in timing and other (64,289) (1,868) (20,380)
-------- -------- ---------
Balance, December 31 $261,995 $223,387 $ 102,516
======== ======== =========
S-26
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS-CONTINUED
NOTE 16 - QUARTERLY FINANCIAL DATA (UNAUDITED)
Summarized quarterly financial data is as follows:
Quarter Ended
----------------------------------------------------------------
March 31 June 30 September 30 December 31 (a)
-------- ------- ------------ ---------------
(amounts in thousands, except per share data)
Year ended December 31, 1995
Revenues $ 12,661 $ 13,209 $18,290 $ 20,908
Expenses 8,678 10,327 12,735 14,955
-------- -------- -------- --------
Income before incomes taxes and minority interest 3,983 2,882 5,555 5,953
Income taxes 1,079 892 1,308 (801)
-------- -------- -------- --------
2,904 1,990 4,247 6,754
Minority interest 863 880 1,343 2,218
-------- -------- -------- --------
Net income $ 2,041 $ 1,110 $ 2,904 $ 4,536
======== ======== ======== ========
Net income per common share $ 0.08 $ 0.04 $ 0.11 $ 0.17
======== ======== ======== ========
Year ended December 31, 1994
Revenues $ 3,755 $ 8,478 $ 9,573 $ 12,899
Expenses 4,834 6,649 6,726 10,750
-------- -------- -------- --------
Income (loss) before incomes taxes and minority interest (1,079) 1,829 2,847 2,149
Income taxes -- -- 270 428
-------- -------- -------- --------
(1,079) 1,829 2,577 1,721
Minority interest 63 685 751 595
-------- -------- -------- --------
Net income (loss) $ (1,142) $ 1,144 $ 1,826 $ 1,126
======== ======== ======== ========
Net income (loss) per common share $ (0.05) $ 0.05 $ 0.07 $ 0.05
======== ======== ======== ========
(a) The quarter ended December 31, 1995 does not include revenues and expenses
related to GEOILBENT (see Note 15).
S-27
53Company.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) 1. Index to Financial Statements: Page
----
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-1
Consolidated Balance Sheets at December 31, 1995 and 1994 . . . . . . . . . . . . . . . . . . . . . . . . S-2
Consolidated Statements of Operations for the Years Ended
December 31, 1995, 1994 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-3
Consolidated Statements of Stockholders' Equity for the
Years Ended December 31, 1995, 1994 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-4
Consolidated Statements of Cash Flows for the Years Ended
December 31, 1995, 1994 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-5
Notes to Consolidated Financial Statements for the Years
Ended December 31, 1995, 1994 and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . S-7
2. Consolidated Financial Statement Schedules:
Schedules for which provision is made in Regulation S-X are not
required under the instructions contained therein, are inapplicable,
or the information is included in the footnotes to the financial
statements.
3. Exhibits:
3.1 Certificate of Incorporation of the Company filed September 9, 1988.*
3.2 Amendment to Certificate of Incorporation of the Company filed June 7, 1991.**
3.3 Restated Bylaws of the Company.
4.1 Form of Common Stock Certificate.*
4.2 Form of Indenture dated May 1992 between the Company and Meridian Trust Company of California.****
10.1 1988 Stock Option Plan (Exhibit 10.6).*
10.2 Amended 1988 Stock Option Plan (Exhibit 10.17).*
10.3 1989 Nonstatutory Stock Option Plan (Exhibit 10.18).*
10.4 Form of Employment Agreements (Exhibit 10.19).*
10.5 Form of Stock Option Agreement under 1988 Stock Option Plan (Exhibit 10.20).*
10.6 Form of Nonstatutory Stock Option Agreement under 198 Nonstatutory Stock Option Plan (Exhibit 10.21).*
10.7 Benton Oil and Gas Company 1991-1992 Stock Option Plan (Exhibit 10.14).***
10.8 Benton Oil and Gas Company Directors' Stock Option Plan (Exhibit 10.15).***
54
10.9 Agreement dated October 16, 1991 among Benton Oil and Gas
Company, Puror State Geological Enterprises for Survey,
Exploration, Production and Refining of Oil and Gas; and
Puror Oil and Gas Production Association (Exhibit
10.14)****
10.10 Operating Service Agreement between the Company and
Lagoven, S.A., dated July 31, 1992, (portions have been
omitted pursuant to Rule 406 promulgated under the
Securities Act of 1933 and filed separately with the
Securities and Exchange Commission--Exhibit 10.15).*****
10.11 Letter Agreement between Benton Oil and Gas Company and
Vinccler, C.A., dated February 9, 1994 (Exhibit 10.16).
******
10.12 Loan Agreement between GEOILBENT and International Moscow
Bank dated August 16, 1994
10.13 Note Agreement dated September 30, 1994 between the
Company and the Purchasers thereof related to the 13%
Senior Notes due September 30, 2002 (Incorporated by
reference to Exhibit 10.1 to the Company's Quarterly
Report on Form 10-Q for the quarter ended September 30,
1994).
10.148-K.
(a)(3) 99.1 Credit Agreement dated December 27, 1994 among the
Company, Benton Oil and Gas Company of Louisiana, New
York Gas Fund I and Christiania Bank og Kreditkasse
{Incorporated by reference to Exhibit 99.5 to the
Company's S-3 Registration Statement (Registration No.
33-79494).
10.15 Stock Purchase and Sale Agreement by and between Benton
Oil and Gas Company and Shell Offshore, Inc. Re: Benton
Oil and Gas Company of Louisiana dated effective as of December 31, 1995 (Incorporated by reference to Exhibit
2.1 to the Company's Current Reports on Form 8-K filed
March 27, 1996.)
10.16 Consent and Waiver by and between Benton Oil and Gas
Company and John Hancock Mutual Life Insurance Company
related to $15 million aggregate principal amount of 13%
Senior Notes due SeptemberMay 30, 2002, dated March 18, 1996
(Incorporated by reference to Exhibit 2.2 to the
Company's Current Report on Form 8-K filed March 27,
1996).
10.17 Consent and Waiver by and between Benton Oil and Gas
Company and John Hancock Mutual Life Insurance company
related to $20 million aggregate principal amount of 13%
Senior Notes due June 30, 2007, dated March 18, 1996
(Incorporated by reference to Exhibit 2.3 to the
Company's Current Report on Form 8-K filed March 27,
1996).
10.18 Consent and Waiver by and among Benton
Oil and Gas Company and Christiania Bank og Kreditkasse dated asMorgan Guaranty Trust Company of March 28, 1996.
11.1 Computation of per share earnings.
21.1 Lists of subsidiaries.
23.1 Consent of Deloitte & Touche LLP.
23.2 Consent of Huddleston & Co., Inc.
27.1 Financial Data Schedule
____________________________
* Previously filed as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-26333).
** Previously filed as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-39214).
*** Previously filed as an exhibit to the Company's S-1 Registration Statement
(Registration No. 33-43662).
**** Previously filed as an exhibit to the Company's S-1 Registration
Statement (Registration No. 33-46077).
***** Previously filed as an exhibit to the Company's S-1 Registration
Statement (Registration No. 33-52436).
******Previously filed as an exhibit to the Company's Form 8-K report dated
February 9, 1994.
25New
York.
55
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the registrant's fiscal
year.
26
5610
SIGNATURES
Pursuant to the requirements of SectionPURSUANT TO THE REQUIREMENTS OF SECTION 13 orOR 15(d) of the Securities
Exchange Act ofOF 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
Carpinteria, State of California, on the 28th day of March, 1996.THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED ON
ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
BENTON OIL AND GAS COMPANY
--------------------------
(Registrant)
Date: March 28,June 12, 1996 By: /s/ A. E. Benton
-----------------------------
A.E. Benton
--------------- ---------------------------Principal Executive Officer
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
/s/ A. E. BENTON June 12, 1996
- -------------------------------------
A.E. Benton
ChiefPrincipal Executive Officer and Director
/s/ MICHAEL B. WRAY June 12, 1996
- -------------------------------------
Michael B. Wray
Principal ExecutiveFinancial Officer, Pursuant to the requirements of the Securities Exchange Act of 1934,
this Report has been signed by the following persons on the 28th day of March,Director
/s/ CHRIS C. HICKOK June 12, 1996
on behalf of the Registrant in the capacities indicated:
Signature Title
--------- -----
/s/A. E. Benton Chairman, Chief Executive Officer and Director
--------------------------------
A. E. Benton
(Principal Executive Officer)
/s/Michael B. Wray President, Principal Financial Officer and
-------------------------------- Director
Michael B. Wray
(Principal Financial Officer)
/s/William H. Gumma Senior Vice President - Operations and Director
--------------------------------
William H. Gumma
/s/Chris C. Hickok Vice President - Controller
--------------------------------
Chris C. Hickok
(Principal Accounting Officer)
/s/Bruce M. McIntyre Director
--------------------------------
Bruce M. McIntyre
/s/Richard W. Fetzner Director
--------------------------------
Richard W. Fetzner
/s/Garrett A. Garrettson Director
--------------------------------- -------------------------------------
Chris C. Hickok,
Principal Accounting Officer
/s/ WILLIAM H. GUMMA June 12, 1996
- -------------------------------------
William H. Gumma, Director
/s/ BRUCE M. MCINTYRE June 12, 1996
- -------------------------------------
Bruce M. McIntyre, Director
/s/ RICHARD W. FETZNER June 12, 1996
- -------------------------------------
Richard W. Fetzner, Director
/s/ GARRETT A. GARRETTSON June 12, 1996
- -------------------------------------
Garrett A. Garrettson,
Director