<PAGE> 1
================================================================================
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
-----------------------
FORM 10-K/A-1
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE YEAR ENDED DECEMBER 31, 1994
/ / TRANSACTION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from to
--------------- ---------------
Commission file number 1-8674
GLOBAL NATURAL RESOURCES INC.
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C>
NEW JERSEY 93-0835865
(State or other jurisdiction of (IRS Employer
incorporation or organization) Identification No.)
5300 MEMORIAL DRIVE, SUITE 800 77007-8295
HOUSTON, TEXAS (Zip Code)
(Address of principal executive
offices)
</TABLE>
REGISTRANT'S TELEPHONE NUMBER: (713) 880-5464
-------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
<TABLE>
<S> <C>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- -----------------------
Common Stock, $1.00 par value New York Stock Exchange
</TABLE>
-------------------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
-----------------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.
X YES NO
----- -----
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/A-1 or any
amendment to this Form 10-K/A-1. /X/
State the aggregate market value of the voting stock held by
non-affiliates of the registrant. (Computed by reference to the closing New
York Stock Exchange ("NYSE") price on May 1, 1995): $294,676,620.
As of May 1, 1995, 29,467,662 shares of common stock were outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant's definitive Proxy Statement dated April 3,
1995 for the Annual Stockholders' Meeting held May 9, 1995, are incorporated by
reference into Part III.
================================================================================
<PAGE> 2
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C> <C> <C>
Part I. Items 1
and 2. Business and Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
The Company . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Oil and Gas Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Oil and Gas Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
United States . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
Exploration and Development Activities and Producing Wells . . . . . . . . 5
Producing and Marketing Activities . . . . . . . . . . . . . . . . . . . . 6
Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Russia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Exploration and Development Activities and Producing Wells . . . . . . . . 10
Certain Risks Applicable to Operations in Russia . . . . . . . . . . . . . 11
Indonesia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12
Producing and Marketing Activities . . . . . . . . . . . . . . . . . . . . 13
Exploration Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Certain Risks Applicable to Operations in Indonesia . . . . . . . . . . . 14
Ivory Coast . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Exploration Activities . . . . . . . . . . . . . . . . . . . . . . . . . . 15
Production Sharing Contract . . . . . . . . . . . . . . . . . . . . . . . 16
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Certain Risks Applicable to Operations in Ivory Coast . . . . . . . . . . 17
Malaysia . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Certain Risks Applicable to Operations in Malaysia . . . . . . . . . . . . 17
Egypt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18
Qarun Concession Agreement . . . . . . . . . . . . . . . . . . . . . . . . 18
Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Certain Risks Applicable to Operations in Egypt . . . . . . . . . . . . . 19
Turkey . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19
Certain Risks Applicable to Operations in Turkey . . . . . . . . . . . . . 20
Argentina . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Certain Risks Applicable to Operations in Argentina . . . . . . . . . . . 20
Pipeline Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
General . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Natural Gas Marketing . . . . . . . . . . . . . . . . . . . . . . . . . . 20
Natural Gas Supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Natural Gas Pipeline Operations . . . . . . . . . . . . . . . . . . . . . 21
Natural Gas Processing . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Natural Gas Treating . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Other Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
Investment Properties International Limited . . . . . . . . . . . . . . . 21
Arctic Islands Interest . . . . . . . . . . . . . . . . . . . . . . . . . 22
North Cook Inlet . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Foreign Acreage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Regulatory Matters . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23
Additional Factors Affecting the Business . . . . . . . . . . . . . . . . 26
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26
</TABLE>
i
<PAGE> 3
<TABLE>
<S> <C> <C>
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
Item 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . 27
Part II. Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . 28
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Five Year Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
Interim Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
Results of Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Oil and Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
Pipeline Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Russian Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . 32
Liquidity and Capital Resources . . . . . . . . . . . . . . . . . . . . . . 33
Item 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . 35
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Part III. Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . 61
Item 11. Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . 61
Item 13. Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . 61
Part IV. Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . 62
Signatures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63
</TABLE>
ii
<PAGE> 4
PART I
ITEMS 1. AND 2. BUSINESS AND PROPERTIES
THE COMPANY
Global Natural Resources Inc., its predecessor, and their respective
subsidiaries are hereinafter referred to collectively as the "Company." The
Company was incorporated in New Jersey in 1983 and is the successor to Global
Natural Resources PLC, a company organized in 1970 under the laws of the United
Kingdom. The Company is an independent producer of oil and natural gas and has
operations in the United States, Tatarstan - Russia, Indonesia, Ivory Coast,
Egypt, and Malaysia. The principal executive offices of the Company are
located at 5300 Memorial Drive, Suite 800, Houston, Texas 77007-8295.
In 1992, the Company adopted a two-fold strategy to direct internally
generated cash at growing the Company's base domestic assets, while directing
the balance sheet cash primarily towards international opportunities. The
primary objective is to generate significant growth in assets by means of
exploratory drilling, both domestically and internationally.
The Company's principal domestic activities during 1994 were
concentrated in the Texas gulf coast and offshore Gulf of Mexico. During 1994,
the Company significantly expanded its seismic data base, from which it will
identify opportunities of suitable reserve potential and geologic risk. Three
of the nine exploratory wells completed in 1994 were developed and operated by
the Company. In addition, the Company will continue evaluating farm-out
opportunities from others.
The Company's Russian activities began in 1990 and are conducted
through its 90% owned subsidiary, Texneft Inc. ("Texneft"), which has a 50%
interest in a joint venture ("Tatex") in Tatarstan, a republic which is part of
the Russian Federation. Texneft's 50% partner in the joint venture is Tatneft,
the state enterprise which operates the oil fields of Tatarstan. Joint venture
activities currently include two projects: 1) vapor recovery and 2) the
development and operation of the Onbysk field.
In Indonesia, the Company has a 1.714% interest in a joint venture for
the exploration, development and production of oil and gas in East Kalimantan,
Indonesia, under a production sharing contract ("PSC") with Perusahaan
Pertambangan Minyak Dan Gas Bumi Negara, the state petroleum enterprise of
Indonesia ("Pertamina").
In February 1993, the Company acquired an interest in 335,320 gross
acres in Block CI-11 offshore Ivory Coast, West Africa. The Company acquired a
10% working interest in an area referred to as the "Special Area" and 16%
working interest in an area referred to as the "Remaining Area." The Company
has drilled two discoveries on this block and is proceeding with development
plans which include first oil production in the second quarter of 1995 and
initial gas production in the third quarter of 1995. In addition, the Company
and its working interest partners have signed an agreement with the government
of the Ivory Coast which provides the option to enter into a production sharing
contract on Block CI-12 which lies immediately adjacent to the east of CI-11.
In August 1994, the Company acquired a 25% working interest in the 1.9
million acre Qarun block located in the western desert of Egypt. During 1994,
the Company drilled two discoveries on this block. In September 1992, the
Company acquired a 10% net working interest in the SB-4 contract area offshore
Sabah, Malaysia covering 1,556,100 acres. In 1993, the Company exercised its
option and increased its net working interest to 15% in the contract area.
USAgas Pipeline, Inc. ("USAgas") is engaged in the operation and
development of natural gas gathering and transmission systems, natural gas
processing and treating plants, and the marketing and transportation of natural
gas for the Company and its joint interest partners.
For financial information relating to industry segments, see Note 10
of Notes to Consolidated Financial Statements included herein.
1
<PAGE> 5
OIL AND GAS RESERVES*
The Company's net quantities of proved oil and natural gas reserves,
the estimated future net revenues based upon year-end prices held constant for
life and the present value of estimated future net revenues of oil and gas
reserves calculated at a 10% discount rate for the three years ended December
31, 1994 are presented in the table below. See "Supplementary Tables on Reserve
Data and Oil and Gas Operations" included in Item 8 herein.
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
UNITED STATES
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . 59,498 63,981 42,094
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . . . 2,173 1,459 939
Future net revenues before tax (thousands) . . . . . . . . . . . . $ 85,396 $108,418 $ 68,484
Present value of future net revenues before tax (thousands) . . . $ 61,090 $ 73,027 $ 41,975
Present value of future net revenues after tax (thousands) . . . . $ 59,990 $ 68,227 $ 41,975
INDONESIA(1)
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . 79,990 79,706 76,081
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . . . 1,066 1,005 837
Future net revenues before tax (thousands) . . . . . . . . . . . . $131,838 $110,900 $152,292
Present value of future net revenues before tax (thousands) . . . $ 67,369 $ 55,783 $ 78,294
Present value of future net revenues after tax (thousands) . . . . $ 34,223 $ 28,150 $ 38,607
RUSSIA(2)
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . - - -
Oil and condensate ( MBbl)(4) . . . . . . . . . . . . . . . . . . 13,157 7,297 4,882
Future net revenues before tax (thousands) . . . . . . . . . . . . $ 77,990 $ 34,796 $ 41,191
Present value of future net revenues before tax (thousands) . . . $ 44,193 $ 17,833 $ 17,379
Present value of future net revenues after tax (thousands)(5) . . $ 30,809 $ 12,825 $ 12,220
IVORY COAST
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . 18,432 - -
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . . . 2,210 - -
Future net revenues before tax (thousands) . . . . . . . . . . . . $ 28,853 $ - $ -
Present value of future net revenues before tax (thousands) . . . $ 13,778 $ - $ -
Present value of future net revenues after tax (thousands) . . . . $ 9,441 $ - $ -
EGYPT
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . - - -
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . . . 3,520 - -
Future net revenues before tax (thousands) . . . . . . . . . . . . $ 26,250 $ - $ -
Present value of future net revenues before tax (thousands) . . . $ 14,357 $ - $ -
Present value of future net revenues after tax (thousands) . . . . $ 8,152 $ - $ -
OTHER INTERNATIONAL(3)
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . - - 239
Oil and condensate (MBbl) . . . . . . . . . . . . . . . . . . . . - - 148
Future net revenues before tax (thousands) . . . . . . . . . . . . $ - $ - $ 1,995
Present value of future net revenues before tax (thousands) . . . $ - $ - $ 1,153
Present value of future net revenues after tax (thousands) . . . . $ - $ - $ 1,153
TOTALS
Natural gas (Mmcf) . . . . . . . . . . . . . . . . . . . . . . . . 157,920 143,687 118,414
Oil and condensate ( MBbl )(4) . . . . . . . . . . . . . . . . . . 22,126 9,761 6,806
Future net revenues before tax (thousands) . . . . . . . . . . . . $350,327 $254,114 $263,962
Present value of future net revenues before tax (thousands) . . . $200,787 $146,643 $138,801
Present value of future net revenues after tax (thousands)(5) . . $142,615 $109,202 $ 93,955
</TABLE>
(Footnotes on following page)
2
<PAGE> 6
* Quantities of gas are expressed throughout as "Mcf" or "Mmcf" or "Bcf"
meaning thousand, million or billion cubic feet, respectively.
Quantities of oil are expressed as "Bbl" or "MBbl" or "Mmbl"
meaning barrel, thousand barrels, or million barrels, respectively.
(1) The Indonesian Joint Venture ("IJV") has no ownership in the
underlying oil and gas reserves. The Company's reserve estimates in
Indonesia have been obtained by the Company from a public source
which, although not independently verified, the Company believes to be
reliable. All Indonesian Mmcf amounts are for dry gas.
(2) The Russian reserves are associated with two projects operated by the
Company's Russian joint venture, Tatex. These projects are vapor
recovery and Onbysk field development. The vapor recovery reserves
are derived from recovered stock tank vapors which are exchanged for
export grade crude oil and sold on the international market. Tatex
has no ownership in the underlying oil reserves which are initially
placed in the stock tanks. The Company's share of the Onbysk field
anticipated recoverable reserves are computed net of the "Base Oil"
future production which is retained by an affiliate of Tatneft under
the terms of the field lease agreement. Base Oil attributable to the
Onbysk field amounts to 2.8 million barrels over the remaining
eighteen year term of the field lease. Production costs associated
with Base Oil volumes are paid to the joint venture by Tatneft
affiliates. On March 3, 1995, the Company was notified that Tatex had
received an exemption from paying export tax on crude oil sold outside
of Russia. The exemption received was for one year and was effective
January 1, 1995. The exemption which is subject to an annual review
by the government and contingent upon its approval, can be renewed for
two additional years. The Company believes its exemption will be
renewed for two more years.
(3) Includes Canadian and Argentinean reserves which were sold during
1993.
(4) Includes reserves of 1,316 MBbl, 1,459 MBbl and 976 MBbl in 1994,
1993 and 1992, respectively, attributable to a minority interest in a
consolidated subsidiary which was 10% in 1994 and 20% during 1993 and
1992.
(5) Includes $3.1 million, $2.6 million, and $2.4 million in 1994, 1993
and 1992, respectively, attributable to a minority interest in a
consolidated subsidiary which was 10% in 1994 and 20% during 1993 and
1992.
At December 31, 1994, 1993 and 1992, the Company's gross oil and gas
reserve estimates for properties located in the United States, Russia and
Argentina were prepared by Ryder Scott Company Petroleum Engineers. At
December 31, 1994, Ivory Coast and Egypt gross oil and gas reserve estimates
were prepared by Netherland, Sewell & Associates, Inc. At December 31, 1992,
Canadian gross oil and gas reserve estimates were reviewed by Coles Gilbert
Associates, Ltd. Indonesian reserves are based on information obtained by the
Company from public sources.
Domestic reserve volumes remained flat in 1994 in comparison with 1993
because 1994 discoveries, positive revisions to previous reserve estimates and
purchases of reserves offset 1994 production and sales of reserves. Future net
revenues before taxes decreased from 1993 to 1994 primarily due to the decrease
in year-end 1994 natural gas prices.
Russian reserve volumes increased in 1994 in comparison with 1993 due
primarily to the reclassification of additional undeveloped reserves in the
Onbysk field as proved undeveloped which were previously considered uneconomic
as a result of the lower crude oil price prevailing at year-end 1993.
Significant increases also resulted from upward revisions of previous
estimates. The increase in future net revenues from Russian properties in 1994
compared with 1993 corresponds to the combined effects of improved year-end oil
prices and reserve additions.
Indonesian reserve volumes increased slightly during 1994 in
comparison with 1993 due primarily to 1994 revisions to previous estimates
being somewhat greater than 1994 production. The increase in Indonesian future
net revenues before tax in 1994 compared to 1993 was $20.9 million. This
increase was primarily the result of an increase in year-end gas prices from
approximately $2.28 per MMBTU in 1993 to $2.50 per MMBTU in 1994.
Domestic reserve volumes and related present value of future net
revenues increased in 1993 in comparison with 1992 due primarily to 1993
discoveries and positive revisions to previous reserve estimates. During 1993,
domestic oil and gas reserves increased by 40% and 51%, respectively. The 1993
drilling program replaced 253% of 1993 oil production and 323% of 1993 gas
production. Included in the 1993 drilling program were significant discoveries
in five exploratory blocks offshore Texas and Louisiana and one new field
adjacent to the Company operated onshore Taylor Lake field. The Company
drilled 3.1 net wells in 1993 compared to 2.0 net wells in 1992.
3
<PAGE> 7
The remaining increase in 1993 domestic volumes over those of 1992 is
attributable to revisions to prior year reserve estimates. In addition to the
above mentioned drilling programs, reserve revisions represent 57% of oil
produced and 94% of gas produced during 1993. The most significant oil and gas
revisions are associated with the Company's Taylor Lake field. The increases
to the Taylor Lake field were primarily the result of well performance and
improved geologic control from additional 1993 drilling activity. Other
significant gas revisions are associated with the Company's San Juan and Oak
Hill fields.
Russian reserve volumes increased in 1993 in comparison with 1992 due
primarily to the addition of reserves associated with the Onbysk field. The
decrease in future net revenues from Russian properties in 1993 compared with
1992 is the result of declines in oil prices which were partially offset by
reserve additions.
The decrease in the present value of Indonesian future net revenues
from 1993 compared to 1992 is primarily attributable to declines in gas prices
which were partially offset by revisions in previous reserve estimates.
Selected major areas in the United States in which the Company held an
interest at December 31, 1994 are summarized in the table below:
<TABLE>
<CAPTION>
TOTAL
PROVED RESERVES
----------------------
OIL GAS
MAJOR AREA (MBbls) (Mmcf)
---------- ------- ------
<S> <C> <C>
Offshore Gulf Coast . . . . . . . . . . . . . 1,402 26,591
San Juan Basin . . . . . . . . . . . . . . . 4 15,274
Taylor Lake . . . . . . . . . . . . . . . . . 129 10,978
Royalties . . . . . . . . . . . . . . . . . . 159 3,672
</TABLE>
The above reserves account for 78% of the Company's United States oil
reserves and 95% of the Company's United States gas reserves at December 31,
1994.
Reserve estimates are based on many judgmental factors and may differ
from the quantities of oil and gas ultimately recovered. The accuracy of
reserve estimates depends on the quantity and quality of geological data,
production performance data and reservoir engineering data as well as the skill
and judgment of petroleum engineers in interpreting such data. Generally,
reserve estimates based on volumetric analysis (as is the case with certain
fields included in the above estimates) are less reliable than those based on
lengthy production history. The process of estimating reserves involves
continual revision of estimates (usually on an annual basis) based on
additional information becoming available through drilling, testing, reservoir
studies and acquiring historical pressure and production data and to reflect
the impact of changes in oil and gas prices. In addition, the discounted
present value of estimated future net revenues should not be construed as the
fair market value of oil and gas producing properties. Revenue calculations
are based on estimates by petroleum engineers as to the timing of oil and gas
production, and there is no assurance the actual timing of production will
conform to, or approximate, such estimates. Also, the estimates assume that
prices will remain constant from the date of the engineer's estimates except
for changes reflected under natural gas purchase contracts. There can be no
assurance that actual future prices will not vary as industry conditions,
governmental regulations and other factors affect the market price for oil and
gas.
The Company has not filed estimates of its net oil and gas reserves
with any other federal agencies within the last year. Certain reserve
information is provided to the Department of Energy each year. However, such
reserve information is accumulated on a total operated and gross working
interest basis and not on a Company net basis, as provided above.
See Supplementary Tables on Reserve Data and Oil and Gas Operations
following Notes to Consolidated Financial Statements for additional data
relating to oil and gas producing activities in Item 8, herein.
OIL AND GAS OPERATIONS
UNITED STATES
GENERAL
The Company conducts oil and gas exploration and development for its
own interest or in conjunction with others. In this connection, the Company
may develop its own prospects and "farm out" a portion of such prospects by
assigning
4
<PAGE> 8
interests to third parties or "farm in" prospects by acquiring interests from
third parties. Three of the nine exploratory wells completed during 1994 were
developed and operated by the Company. In addition, the Company has added
significantly to its seismic database, from which it will identify suitable
opportunities of reserve potential and geologic risk.
In 1994, 1993 and 1992, revenues from domestic production accounted
for approximately 32%, 26% and 33% of the Company's revenues, respectively.
Domestic oil and gas operations reported income (loss) before income tax
expense of $(11.8) million, $3.6 million and $(5.6) million in 1994, 1993 and
1992, respectively.
EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS
The Company expended approximately $34.6 million, $14 million and $5.4
million in 1994, 1993 and 1992, respectively, for domestic oil and gas
exploration and development. In 1994, the Company's activities were
principally in the offshore Gulf of Mexico and gulf coast areas.
The Company's 1995 domestic budget is approximately $15.3 million, of
which approximately $8.8 million is intended for exploration activities. The
majority of these expenditures are planned for the Texas gulf coast and
offshore Gulf of Mexico areas.
The Company's domestic oil and gas exploration and development
drilling during the years indicated and the gross and net wells in which the
Company had a working interest were as follows:
WELLS DRILLED (1)
<TABLE>
<CAPTION>
EXPLORATORY DEVELOPMENT
WELLS WELLS TOTAL
------------------ ------------------ ------------------
GROSS NET GROSS NET GROSS NET
------- ------ ------- ------ ------- ------
<S> <C> <C> <C> <C> <C> <C>
1994
Oil . . . . . . . . . . . . . . . . . . . - - 6 0.4 6 0.4
Gas . . . . . . . . . . . . . . . . . . . 9 2.7 12 1.8 21 4.5
Dry . . . . . . . . . . . . . . . . . . . 9 3.8 - - 9 3.8
---- ---- ---- ---- ---- ----
Total . . . . . . . . . . . . . . . 18 6.5 18 2.2 36 8.7
==== ==== ==== ==== ==== ====
1993
Oil . . . . . . . . . . . . . . . . . . . 1 0.2 3 0.2 4 0.4
Gas . . . . . . . . . . . . . . . . . . . 4 1.1 10 0.2 14 1.3
Dry . . . . . . . . . . . . . . . . . . . 5 1.1 1 0.3 6 1.4
---- ---- ---- ---- ---- ----
Total . . . . . . . . . . . . . . . 10 2.4 14 0.7 24 3.1
==== ==== ==== ==== ==== ====
1992
Oil . . . . . . . . . . . . . . . . . . . 4 0.5 7 0.4 11 0.9
Gas . . . . . . . . . . . . . . . . . . . - - 2 0.1 2 0.1
Dry . . . . . . . . . . . . . . . . . . . 8 0.9 3 0.1 11 1.0
---- ---- ---- ---- ---- ----
Total . . . . . . . . . . . . . . . 12 1.4 12 0.6 24 2.0
==== ==== ==== ==== ==== ====
</TABLE>
(1) The term "gross" as used herein with respect to wells refers
to the total number of wells in which the Company has any
interest and "net" refers to the Company's interest in such
wells.
At December 31, 1994, the Company had 3 gross (.8 net) exploratory
wells and 1 gross (0.2 net) development wells awaiting completion; 1 gross (0.6
net) exploratory wells and 1 gross (0.3 net) development wells were in the
process of drilling.
5
<PAGE> 9
PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION
<TABLE>
<CAPTION>
GROSS PRODUCING NET PRODUCING
--------------- -------------
<S> <C> <C>
1994(1)
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . 1,754 10
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 430 20
--------------- -------------
Total . . . . . . . . . . . . . . . . . . . . . . 2,184 30
=============== =============
1993
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . 1,763 15
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 482 33
--------------- -------------
Total . . . . . . . . . . . . . . . . . . . . . . 2,245 48
=============== =============
1992
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . 1,851 28
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . 543 45
--------------- -------------
Total . . . . . . . . . . . . . . . . . . . . . . 2,394 73
=============== =============
</TABLE>
(1) The number of oil and gas wells completed in more than one
producing formation were 4 gross (0.7 net) wells at December 31,
1994.
The decreases in gross and net producing wells from 1993 to 1994 and
from 1992 to 1993 are the result of the dispositions during 1994 and 1993 of
certain domestic properties.
PRODUCING AND MARKETING ACTIVITIES
The Company's United States oil and gas sales in 1994 aggregated $20.1
million, of which gas sales accounted for 82%. The following table is a
summary of the Company's domestic production volumes expressed in Bbls and
Mcfs, average sales prices and average production (lifting) costs for each of
the three years ended December 31, 1994:
<TABLE>
<CAPTION>
VOLUME PRODUCED 1994 1993 1992
--------------- --------- --------- ---------
<S> <C> <C> <C>
Oil and Condensate (Bbl) . . . . . . . . 229,000 263,000 334,000
Natural Gas (Mcf) . . . . . . . . . . . . 8,904,000 7,088,000 6,425,000
AVERAGE SALES PRICE
-------------------
Oil and Condensate per Bbl . . . . . . . $ 15.65 $ 17.11 $ 18.97
Natural Gas per Mcf (1) . . . . . . . . . $ 1.86 $ 2.11 $ 2.00
AVERAGE LIFTING COSTS(2)
--------------------- ---
Bbl equivalent . . . . . . . . . . . . . $ 1.97 $ 2.61 $ 3.68
Mcf equivalent . . . . . . . . . . . . . $ 0.33 $ 0.44 $ 0.62
</TABLE>
(1) Included in the 1992 gas revenues are pricing dispute
settlement proceeds of approximately $422,000. The 1992 gas
price excluding this settlement would have been $1.93 per Mcf.
Included in the 1993 gas revenues are pricing dispute
settlement proceeds of approximately $660,000. The 1993 gas
price excluding this settlement would have been $2.01 per Mcf.
(2) For purposes of this computation, one barrel is considered
equivalent to six Mcf, although actual oil to gas equivalent
will vary based upon British Thermal Unit (BTU) content. Since
the same field or well often produces both oil and gas,
lifting costs per Bbl or Mcf represent the aggregate lifting
costs per unit based on the foregoing equivalent.
The Company's domestic natural gas production is marketed through a
combination of long-term and spot-market contracts. The ability of the Company
to sell natural gas and the price obtained depends on numerous considerations,
including contractual terms (such as "market-out" price reduction provisions
and other provisions of long-term contracts), market conditions in general,
curtailments by gas purchasers and transportation companies, the effects of
government
6
<PAGE> 10
legislation and regulations on production, transportation tariffs and the
proximity of wells to adequate transmission facilities. While gas curtailments
and price reductions can affect earnings and cash flow, the ability to seek
alternate markets is now generally available in the majority of fields operated
by the Company.
During 1994, the Company sold gas production from most of its
properties to unaffiliated third parties for spot-market prices. The Company
marketed the majority of its operated production of crude oil and condensate to
Hydrocarbon Processing, Inc. and Sun Refining and Marketing Company,
unaffiliated third parties. The price obtained for crude oil and condensate
depends on various considerations, including the location, grade and quality of
production and general market conditions in world oil markets. Crude oil and
condensate are generally sold pursuant to short-term contracts. The Company
generally sells such production at a premium over the posted price.
Reference is made to the Supplementary Tables on Reserve Data and Oil
and Gas Operations following the Notes to Consolidated Financial Statements for
additional data relating to oil and gas producing activities in Item 8, herein.
ACREAGE
The Company's current policy is to only acquire acreage associated
with specific prospects, thereby minimizing carrying costs and administrative
expenses. Acreage in the United States in which the Company had an interest at
December 31, 1994 is summarized in the table below:
<TABLE>
<CAPTION>
MINERAL AND ROYALTY
WORKING INTEREST ACREAGE INTEREST ACREAGE
------------------------ -----------------------
GROSS NET GROSS NET
----------- --------- --------- ---------
PRODUCING OR DEVELOPED ACREAGE
<S> <C> <C> <C> <C>
Alabama . . . . . . . . . . . . . . . . 4,216 1,359 2,821 327
Alaska . . . . . . . . . . . . . . . . - - 9,920 103
California . . . . . . . . . . . . . . 160 40 779 7
Colorado . . . . . . . . . . . . . . . 200 66 838 13
Kansas . . . . . . . . . . . . . . . . 160 72 5,560 86
Louisiana . . . . . . . . . . . . . . . 1,520 395 17,715 920
Michigan . . . . . . . . . . . . . . . 837 309 - -
Mississippi . . . . . . . . . . . . . . 217 54 5,690 193
Montana . . . . . . . . . . . . . . . . 480 41 160 6
New Mexico . . . . . . . . . . . . . . 2,500 880 45,044 546
North Dakota . . . . . . . . . . . . . 2,244 279 520 1
Offshore (Gulf of Mexico) . . . . . . . 11,520 3,487 - -
Oklahoma . . . . . . . . . . . . . . . 2,169 356 84,295 3,564
Texas . . . . . . . . . . . . . . . . . 25,163 5,048 95,726 2,891
Utah . . . . . . . . . . . . . . . . . 640 320 8,539 159
Wyoming . . . . . . . . . . . . . . . . 2,630 1,360 1,529 41
Other . . . . . . . . . . . . . . . . . 905 83 320 5
------ ------ ------- -----
Total . . . . . . . . . . . . . . 55,561 14,149 279,456 8,862
====== ====== ======= =====
</TABLE>
(Table continued on following page)
7
<PAGE> 11
<TABLE>
<CAPTION>
MINERAL AND ROYALTY
WORKING INTEREST ACREAGE INTEREST ACREAGE
------------------------ -----------------------
UNDEVELOPED ACREAGE GROSS NET GROSS NET
----------- --------- --------- ---------
<S> <C> <C> <C> <C>
Alabama . . . . . . . . . . . . . . . . 2,740 942 12,949 1,150
Alaska . . . . . . . . . . . . . . . . - - 3,834 29
Arkansas . . . . . . . . . . . . . . . 2,345 1,336 - -
California . . . . . . . . . . . . . . - - 528 30
Colorado . . . . . . . . . . . . . . . 15,566 13,025 25,788 6,180
Kansas . . . . . . . . . . . . . . . . - - 10,622 305
Louisiana . . . . . . . . . . . . . . . 1,705 772 40,900 342
Michigan . . . . . . . . . . . . . . . 822 461 1,430 363
Mississippi . . . . . . . . . . . . . . 514 145 30,062 795
Montana . . . . . . . . . . . . . . . . 880 52 4,220 197
New Mexico . . . . . . . . . . . . . . 19,907 2,624 17,051 682
North Dakota . . . . . . . . . . . . . 1,274 19 38,316 2,582
Offshore (Gulf of Mexico) . . . . . . . 42,239 22,199 1,946 18
Oklahoma . . . . . . . . . . . . . . . 2,197 307 59,833 3,340
Texas . . . . . . . . . . . . . . . . . 81,154 27,174 63,068 3,490
Utah . . . . . . . . . . . . . . . . . - - 19,208 893
Wyoming . . . . . . . . . . . . . . . . 7,853 2,855 7,216 74
Other . . . . . . . . . . . . . . . . . 792 80 1,348 28
------- ------ ------- ------
Total . . . . . . . . . . . . . . 179,988 71,991 338,319 20,498
======= ====== ======= ======
</TABLE>
RUSSIA
GENERAL
Through its 90% owned subsidiary, Texneft, the Company has a net 45%
interest in a joint venture in Russia with Tatneft, a Russian production
amalgamation which operates the oil fields of Tatarstan, a republic which is
part of the Russian Federation and is located west of the Ural Mountains and
east of the Volga River. The joint venture, Tatex, which is owned 50% by
Tatneft and 50% by Texneft, was registered with the Ministry of Finance of the
former USSR on November 15, 1990 and is also registered with the governments of
Russia, Tatarstan and the city of Almetyevsk. Under the terms of the joint
venture and various supplemental agreements, the funding for the joint venture
is supplied by Texneft and Tatneft through various credit agreements. In
November 1994, the Company purchased an additional 10% of Texneft's common
stock for approximately $.5 million increasing its ownership from 80% to 90%.
An agreement between the minority shareholder of Texneft and the Company
requires the Company to advance to Texneft sufficient cash to fund its
administrative expenses and its contributions to Tatex. In turn, Texneft will
make no distributions to its shareholders until the Company has been repaid a
sum equal to the total of its advances to Texneft.
The joint venture's activities currently include two projects: 1)
vapor recovery and 2) the development and operation of the Onbysk field. The
vapor recovery project began operations in 1991. Tatex has installed and
operates vapor recovery facilities which recover stock tank vapors from
Tatneft's production facilities located near the city of Almetyevsk. The
recovered vapors are exchanged for export grade Volga-Ural crude oil, which is
sold for hard currency on the international market. The vapor recovery
activity at certain locations eliminates gas and associated liquids which would
otherwise be flared and thus reduces the level of harmful pollutants; however,
production has declined at certain tank farms such that of the twenty-two vapor
units delivered, only nineteen were in service at the end of 1994 at seventeen
tank farms. The joint venture intends to sell the surplus vapor recovery units
to other users in the area. Tatex received 790,000 barrels, 573,000 barrels
and 278,000 barrels of crude oil in 1994, 1993 and 1992, respectively. Tatex
expects to meet its quota to export an average of 2,167 barrels of oil per day
in 1995 in exchange for recovered vapors.
Two sour gas compression units have been delivered and located in
Tatarstan but neither has been placed in continuous service to date, although
at least one unit may go on stream in 1995. The construction and installation
of additional compressor units for sour gas recovery at various points in
Tatarstan has been deferred because of delays in the acceptance of a
standardized design and until the integrity of the downstream pipelines and
facilities handling the recompressed sour gas can be reliably established. The
integrity of the downstream systems is the responsibility of Tatneft and its
affiliates.
8
<PAGE> 12
In August 1993, Tatex signed a 20 year lease agreement with
Zainskneft, an affiliate of Tatneft, pursuant to which Tatex assumed operations
and development of the Onbysk field effective January 1, 1993. The lease
agreement, which requires lease payments totaling 349 million rubles over the
life of the lease, includes a provision that the equipment will become the sole
property of Tatex at the end of the lease. Tatex prepaid the lease obligation
in 1993 by making a one time payment of $295,000. In addition to the lease
payments, the agreement provides for the delivery of "Base Oil" volumes to
Zainskneft during the life of the lease. The Base Oil production has been
defined as the expected production of the field were the previous operator to
continue operations and equals a total of 797 barrels of oil per day during
1995 which is estimated to decline at a rate of 10% per year. Any oil
incremental to this volume, defined as "Own Oil," is the property of Tatex and
may be exported for hard currency.
Tatex continued development drilling in the Onbysk field in 1994.
Thirteen directional wells and six horizontal wells were drilled by Texneft
directed personnel. Production for the year totaled approximately 1,075,000
barrels, of which approximately 240,000 barrels were classified as Base Oil and
835,000 barrels as Own Oil, from a total of 139 wells producing on December 31,
1994. Production for 1993 totaled approximately 541,000 barrels, of which
approximately 328,000 barrels were classified as Base Oil and 213,000 barrels
as Own Oil, from a total of 114 wells producing on December 31, 1993.
Interruptions of production from the Onbysk field occurred during 1994 as a
result of the temporary inability of a primary purchaser to pay Tatneft for its
oil. The aerial extent and multiple reservoirs present in the Onbysk field
will require considerable future drilling. The pace of development of this
field will depend upon results achieved, oil prices, available markets for the
oil, pipeline capacity and applicable taxes and expenses.
The Company's share of current proved reserves assigned to vapor
recovery facilities and to the Onbysk field based upon the year-end price of
$14.41 per barrel are 11,841 MBbl. The average price received during 1994 was
$14.21 per barrel as compared to $14.24 per barrel received in 1993.
A third project, now inactive, was a well stimulation program in and
adjacent to the sizeable Romashkino field. This project was conducted in 1994,
but the contract with Western Petroleum International Services ("Western") to
provide matrix acidizing and hydraulic fracturing stimulation services was
terminated in November 1994 and the project suspended pending resolution of
issues explained below. In connection with the third project, Tatex contracted
with Western to stimulate by matrix acidizing and hydraulic fracturing methods
selected wells from approximately 12,000 producing wells in the western and
northern part of the Romashkino field and certain fields adjacent to the north
and west of the Romashkino field owned by various production amalgamations of
Tatneft.
Western began operations in November 1993 and acidized six wells in
the Onbysk field and five wells in the Romashkino field before year's end. In
1994, Western performed a total of forty-two stimulations of which thirty-four
jobs were performed within the Onbysk field and eight in other fields.
Activities were directed primarily at the Onbysk field because the Government
had not indicated whether or not, in the long-term, incremental oil resulting
from the stimulation activities in the Romashkino area would be designated Own
Oil and be exportable for hard currency. Because of the lack of clarification
of a long-range government policy towards stimulation, the contract was
terminated on November 1, 1994. Should progress be made in establishing a firm
Own Oil classification over a clearly defined period, the stimulation program
may be reactivated at some later date.
A fourth project, an environmentally-driven program of development of
undrained reserves beneath the city of Almetyevsk, was proposed using the
latest long reach and horizontal drilling technology; however, it is no longer
considered an appropriate project for Tatex under the prevailing tax and
administrative uncertainties. As a result, no further action will be taken to
finalize the contract for the urban project which existed in draft form;
however, Tatneft and Texneft have agreed to examine alternative opportunities
to expand Tatex operations into other fields in which exploration but not
development activities have been carried out.
Texneft entered into a Service Agreement in October 1993 with Tatex
whereby Texneft agreed to furnish certain MWD (measurement while drilling)
tools, ancillary equipment and supervisory assistance to Tatex for deployment
in Tatarstan to insure that horizontal and long reach wells in the Onbysk field
and urban areas are drilled efficiently and in a cost effective manner.
Texneft's investment in the tools and equipment amounted to approximately $1.3
million. After being used to drill four horizontal wells effective January 1,
1995, the tools were sold to Tatex for approximately $1 million which
represents the purchase price less the cumulative rental charges paid by Tatex.
In January 1992, the Russian Federation imposed a tax of 30 European
Currency Units ("ECUs") per ton, currently approximately $5.22 per barrel, on
crude oil exported from Russia. Effective January 1, 1995, the export tax for
the first quarter of 1995 was set by Resolution 1446 at 23 ECUs per ton or
approximately $4.00 per barrel. The Company first
9
<PAGE> 13
applied for exemption from the tax in 1992 in accordance with the procedures
stipulated by Regulation 1375-r for enterprises which were registered before
January 1, 1992. The Company's efforts for exemption from the export tax in
1993 and 1994 culminated in an application prepared in accordance with
Resolution 497 of the Government of the Russian Federation dated May 19, 1994,
"About Preferential Tariffs Concerning the Export from the Russian Federation
of Oil and Petroleum Products Production of Enterprises with Foreign
Investment." As a result of limited government action on the application,
Tatex continued to pay the tax on crude oil shipments throughout 1992, 1993 and
1994. On February 28, 1995, Mr. V. Chernomyrdin, the Prime Minister of the
Russian Federation, signed Government Order #282r whereby Tatex received an
exemption from paying export tax on exported oil effective January 1, 1995.
This exemption is subject to an annual review by the government and can be
effective for no more than three years.
Under an order by the State Tax Service of the Russian Federation
effective January 1, 1995, oil producers will be required to pay the 10%
Mineral Replacement Tax based upon the export price of crude oil net of certain
deductions. In 1994, the tax was based upon the Russian domestic price of
crude oil which was typically one-third of the export price. Tatex is
currently seeking a clarification of this ruling. Tatex used the domestic
price as the basis for payments of the Mineral Replacement Tax in 1994 and will
continue to do so until a clarification is received.
Tatex's production is subject to an annual determination of Own Oil
established by the Ministry of Fuel & Energy of the Russian Federation and
certified by the Ministry of Economics as registered for export as follows for
1995: vapor recovery 791,000 barrels and Onbysk field development 1,535,000
barrels. The Company believes that the export quota levels set for 1995 are
commensurate with the planned activities for the projects.
Tatex oil production to date has been sold outside of the former USSR
for hard currency via the Transneft operated Druzhba pipeline. Access to the
Transneft pipeline system has been subject to intermittent interruption since
startup. Recent statements and actions by government ministries in connection
with the liberalization of Russian crude export controls indicate that in the
future, joint ventures may have to compete with Russian production associations
for limited pipeline capacity to export markets.
In 1992, the Company contributed to Tatex a 10% interest in
exploration licenses held 50% by the Company (the remaining 50% is owned
indirectly by Garnet Resources Corporation) covering the Akseki, Isparta and
Egridir blocks in southwestern Turkey, concurrently with the contribution to
Tatex by Tatneft of a study which Tatneft conducted of that area. See "Oil and
Gas Operations-Turkey" included herein.
EXPLORATION AND DEVELOPMENT ACTIVITIES AND PRODUCING WELLS
The Russian joint venture expended approximately $9.1 million and $5.2
million in 1994 and 1993, respectively, for oil exploration and development in
Russia. In 1994, the joint venture's activities were principally development
drilling and oil production.
The Russian joint venture incorporated expenditures in its 1995 budget
of approximately $13.1 million, of which approximately $9.9 million is intended
for Onbysk field development. The majority of these budgeted expenditures are
projected to be funded through cash flow generated from the joint venture.
10
<PAGE> 14
The Company's Russian joint venture's oil and gas exploration and
development drilling during the years indicated were as follows:
WELLS DRILLED
<TABLE>
<CAPTION>
EXPLORATORY DEVELOPMENT TOTAL
----------- ----------- -------------
<S> <C> <C> <C>
1994
Oil . . . . . . . . . . . . . . . . . . . . . . - 19 19
Gas . . . . . . . . . . . . . . . . . . . . . . - - -
Dry . . . . . . . . . . . . . . . . . . . . . . - - -
----------- ----------- -------------
Total . . . . . . . . . . . . . . . . . . - 19 19
=========== =========== =============
1993
Oil . . . . . . . . . . . . . . . . . . . . . . - 22 22
Gas . . . . . . . . . . . . . . . . . . . . . . - - -
Dry . . . . . . . . . . . . . . . . . . . . . . - - -
----------- ----------- -------------
Total . . . . . . . . . . . . . . . . . . - 22 22
=========== =========== =============
</TABLE>
At December 31, 1994, the Russian joint venture had 3 development
wells awaiting completion; and 2 development wells were in the process of
drilling.
PRODUCING WELLS AND WELLS CAPABLE OF PRODUCTION
<TABLE>
<CAPTION>
GROSS PRODUCING
---------------
<S> <C>
1994(1)
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -
---------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139
===============
1993
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -
---------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 114
===============
1992
Oil . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
Gas . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -
---------------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 87
===============
</TABLE>
(1) The number of oil and gas wells completed in more than one
producing formation was 24 wells at December 31, 1994.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN RUSSIA
The Company's activities in Russia are subject to the usual risks
associated with foreign operations, including political and economic
uncertainties, risks of cancellation or unilateral modification of agreements,
operating restrictions, currency repatriation restrictions, expropriation,
export restrictions, the imposition of new taxes and the increase of existing
taxes, inflation and other risks arising out of foreign government sovereignty
over areas in which the operations are conducted. The Company has endeavored to
protect itself against certain political and commercial risks inherent in the
venture. There is no certainty that the steps taken by the Company will provide
adequate protection.
11
<PAGE> 15
INDONESIA
GENERAL
The Company has a 1.714% interest in the IJV, a joint venture for the
exploration, development and production of oil and natural gas in East
Kalimantan, Indonesia, under a PSC with Pertamina. The majority of the revenue
derived from the IJV results from the sale of liquefied natural gas ("LNG").
In 1994, the $11.7 million of revenues from the Company's interest in
the IJV accounted for approximately 19% of the Company's revenues.
Approximately 15% and 20% of the Company's 1993 and 1992 revenues,
respectively, were contributed by the IJV.
Under the PSC with Pertamina that was amended and extended in 1990
until August 7, 2018, the IJV is authorized to explore for, develop and produce
petroleum reserves in an approximately 1.1 million acre area in East
Kalimantan. In accordance with the requirements of the PSC, during 1994 the
IJV selectively relinquished approximately 10% of the PSC area. In addition,
the IJV must relinquish 10% of the PSC area by August 7, 1998; 10% by December
31, 2000; 15% by December 31, 2002 and 15% by December 31, 2004. However, the
IJV is not required to relinquish any of the PSC area in which oil or gas is
held for production.
Under the PSC, the IJV participants are entitled to recover cumulative
operating and certain capital costs out of the crude oil, condensate and
natural gas ("gas") produced each year, and to receive a share of the remaining
crude oil and condensate production and a share of the remaining revenues from
the sale of gas on an after Indonesian tax basis. The share of revenues from
the sale of gas after cost recovery through August 7, 1998 will remain at 35%
to the IJV after Indonesian income taxes and 65% to Pertamina. The split after
August 7, 1998 will be 25% to the IJV after Indonesian income taxes and 75% to
Pertamina for gas sales under the 1973 and 1981 LNG Sales Contracts, Korean
Carryover Sales Contract and liquefied petroleum gas sales contracts to the
extent that the gas to fulfill these contracts is committed from the Badak or
Nilam fields. After August 7, 1998, all other LNG sales contract revenues will
be split 30% to the IJV after Indonesian income taxes and 70% to Pertamina.
Based on current and projected oil production, the revenue split from oil sales
after cost recovery through August 7, 2018 will remain at 15% to the IJV after
Indonesian income taxes and 85% to Pertamina. These revenue splits are based on
Indonesian income tax rates of 56% through August 7, 1998 and 48% thereafter.
In addition, the IJV is required to sell out of its share of production 8.5% of
the total oil and gas condensate production from the contract area for
Indonesian domestic consumption. The sales price for the domestic market
consumption is $0.20 per barrel with respect to fields commencing production
prior to February 23, 1989 and 10% of the weighted average price of crude oil
sold from such fields commencing production after February 23, 1989. However,
for the first sixty consecutive months of production from new fields, domestic
market compensation is priced at the official Indonesian crude price. The
participants' remaining oil and condensate production is generally sold in
world markets. The IJV is also obligated to supply approximately 74 Mmcf per
day of gas to three local fertilizer plants at a price of $1.00 per million BTU
subject to a pipeline tariff. In addition, the IJV is required to supply
approximately 5 Mmcf per day of gas to the Balikpapan refinery at a price of
$1.49 per million BTU. In 1994, Pertamina executed a twenty-year contract,
commencing in November of 1997, for the sale of approximately 70 Mmcf per day
of gas to a local methanol plant at a price not less than $1.25 per million
BTU.
The IJV has no ownership interest in the oil and gas reserves. The
IJV has long-term supply agreements with Pertamina for the supply of natural
gas and petroleum gas to be liquefied at a liquefaction plant owned by
Pertamina at Bontang Bay (the "LNG Plant") and sold to certain buyers pursuant
to sales contracts. The IJV, other participating production sharing
contractors and Pertamina together market the LNG and the liquefied petroleum
gas ("LPG") produced at the LNG Plant and LPG facilities, and as to the amounts
allocated to the PSC, the IJV and Pertamina divide the net proceeds in
accordance with the percentages set out above.
Since the Company does not have direct access to information with
respect to oil and gas operations under the PSC, the information contained
herein is from a public source which, although not independently verified, the
Company believes to be reliable.
12
<PAGE> 16
PRODUCING AND MARKETING ACTIVITIES
The following table sets forth total natural gas liquefied and sold as
LNG, the Company's net share of such production, average sales prices
(excluding transportation costs) and average production (lifting) costs for
each of the three years ended December 31, 1994:
<TABLE>
<CAPTION>
1994 1993 1992
------- ------- -------
<S> <C> <C> <C>
Natural Gas Production for LNG (Mmcf)(1) . . . . . 735,116 637,847 621,600
Company's net share of gas (Mmcf equivalency)(2) . 4,473 3,769 3,667
Average Sales Price per Mcf(3) . . . . . . . . . . $ 2.45 $ 2.75 $ 2.92
Average Production (Lifting) cost per Mcf(4) . . . $ 0.12 $ 0.13 $ 0.14
</TABLE>
(1) Represents the volumes of LNG delivered and sold to
purchasers, which is measured by its BTU content and, for
purposes of this table, has been converted to Mmcf equivalents
based on a ratio of approximately 3.0 Bcf of natural gas
required at the plant to produce 2.9 trillion BTUs of LNG.
The total natural gas production includes production
attributable to others.
(2) The Company's net share figures shown above represent the Mcf
equivalent of the Company's share of IJV revenues.
(3) The sales price is based on the average sales price (excluding
transportation) per MMBTU of LNG received by Pertamina. The
term "MMBTU" refers to 1 million BTU. The sales price per
MMBTU has been converted to a price per Mcf based on the
conversion ratio referred to in note (1) above.
(4) The production (lifting) costs do not include costs of
liquefaction and transportation.
The majority of the revenue derived from the IJV results from gas
produced, liquefied and sold as LNG. Gas subject to the PSC is liquefied at the
LNG Plant and transported via special tankers pursuant to several sales
contracts between Pertamina and its customers which principally consist of
Japanese, Taiwanese and Korean utility and industrial companies. The table
below sets forth information regarding the LNG Plant share of the LNG sales
contracts grouped together by the IJV's participating percentages in the sales
contracts (each such group being referred to as a "package").
<TABLE>
<CAPTION>
BASE LNG PRICE PER
REMAINING LNG MILLION BTU
SALES -----------------------
PACKAGE AND EQUITY INTEREST TERM VOLUMES 12/31/94 02/24/95
- --------------------------- ------------ ------------- -------- --------
(TRILLION BTUS)
---------------
<S> <C> <C> <C> <C>
Package I - 97.9%
1973 LNG Sales . . . . . . . . . . . . . 1977-1999 462 $2.58 $2.84
Package II - 66.4%
1981 LNG Sales Contract . . . . . . . . 1983-2003 1,409 $2.54 $2.82
Package III A - 50%
Korean Carryover Sales Contract . . . . 1986-2006 180 $2.58 $2.84
Package III B - 29.6%
Taiwan . . . . . . . . . . . . . . . . . 1990-2009 1,369 $2.52 $2.79
Toho . . . . . . . . . . . . . . . . . . Various, 17 $2.58 $2.84
ranging from
1988 to 1997
Additional 1981 Sales Contract cargoes 1990-2003 146 $2.54 $2.82
Package IV - 27.2%
Train F LNG Sales Contract . . . . . . . 1994-2013 2,271 $2.40 $2.66
Korea II LNG Sales Contract . . . . . . 1994-2014 1,115 $2.42 $2.68
Other LNG Sales Contracts . . . . . . . 1990-2015 676 $2.40 $2.66
</TABLE>
During 1994, Pertamina executed agreements to extend the 1973 and 1981
LNG Sales Contracts. The 1973 Sales Contract Extension (Package V) involves
the sale of 4,368 trillion BTUs over a ten-year period commencing in 2000.
Also executed was the Taiwan Medium-Term Sales Contract (Package VI) for the
sale of 46 trillion BTUs between 1998 and 1999. The IJV has been allocated a
provisional 22% equity interest in deliveries under the 1973 LNG Sales
13
<PAGE> 17
Contract Extension and the Taiwan Medium-Term Sales Contract. The 1981 Sales
Contract Extension (Package VI) involves the sale of 941 trillion BTUs over a
five-year period commencing in 2003. The equity sharing percentage for Package
VI has not yet been determined.
EXPLORATION ACTIVITIES
The IJV has conducted extensive drilling activities on the island of
East Kalimantan. From 1972 through December 31, 1994, the IJV drilled 539
wells in the area, 471 of which resulted in oil and/or gas condensate
production. Two significant fields, Badak and Nilam, have been discovered. The
following tables summarize drilling activity for each of the three years ended
December 31, 1994:
EXPLORATORY DRILLING
<TABLE>
<CAPTION>
WELLS NEW DRY
YEAR DRILLED DISCOVERIES HOLES
- ------ ------- ----------- -----
<S> <C> <C> <C>
1994 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 1 1
1993 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 - 3
1992 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2 - 2
</TABLE>
DEVELOPMENT OR FIELD EXTENSION DRILLING
<TABLE>
<CAPTION>
WELLS DUAL DRY
YEAR DRILLED GAS OIL OIL & GAS HOLES
- ------ ------- --- --- --------- -----
<S> <C> <C> <C> <C> <C>
1994 . . . . . . . . . . . . . . . . . . . . 20 10 1 8 1
1993 . . . . . . . . . . . . . . . . . . . . 31 25 1 3 2
1992 . . . . . . . . . . . . . . . . . . . . 31 24 5 2 -
</TABLE>
Of the 471 completed productive wells in the East Kalimantan contract
area, 268 contain more than one completion in the same bore hole.
Three wells were in progress at December 31, 1994. These include
wells which were drilled but not completed at the end of 1994. None of the
suspended or "in-progress" wells are included in the table above.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN INDONESIA
The Company's interest in the IJV is an assignment of an interest in a
constructive trust. This interest is essentially a revenue interest without
any operating or informational rights. Although the Company now obtains
information about the IJV from a public source, there is no assurance that this
source of information will continue to be available in the future or that the
Company will be able to find alternative sources of information if its current
source of information becomes unavailable.
Indonesian oil competes in the world market with oil produced from
other nations. Indonesia is a member of the Organization of Petroleum Exporting
Countries ("OPEC"), and any OPEC-imposed restrictions on oil or LNG exports in
which Indonesia participates could have a material adverse effect on the
Company. The price of Indonesian oil is regulated by Pertamina.
The LNG plant competes for sales with other LNG plants in Indonesia,
the Middle East, Australia, Malaysia and elsewhere.
The IJV's activities in Indonesia are subject to risks common to
foreign operations in the oil and gas industry, including political and
economic uncertainties, the risks of cancellation or unilateral modification of
contract rights, operating restrictions, currency repatriation restrictions,
expropriation, export restrictions, the imposition of new taxes and the
increase of existing taxes and other risks arising out of foreign governmental
sovereignty over areas in which the IJV's operations are conducted.
14
<PAGE> 18
No methods to deliver or utilize the East Kalimantan natural gas
reserves are presently in place or in operation except liquefaction at the LNG
Plant and shipment by LNG tanker to purchasers. Consequently, any significant
reduction in the output of the LNG Plant or disruption in tanker operations
would have a material adverse effect on the Company's revenues from the IJV.
IVORY COAST
GENERAL
In May 1993, the Company acquired an interest in 335,320 gross acres
in the CI-11 Production Sharing Contract ("PSC") approximately eight miles
offshore Ivory Coast, West Africa. The Company acquired a 10% working interest
in an area referred to as the "Special Area" and an 16% working interest in an
area referred to as the "Remaining Area."
During November 1993, the Panthere #1 well was drilled in the
"Remaining Area" to a total depth of 10,575 feet and tested gas and condensate
at the rate of 34.8 Mmcf per day plus 675 Bbls per day on a 56/64 inch choke
with a flowing tubing pressure of 1,909 pounds per square inch from 66 feet of
perforations between 9,316 and 9,382 feet. The well was drilled in 264 feet of
water and a production caisson was set over the well.
The Lion #1 well was spudded in January 1994 to test a separate
structure in the "Special Area." This well was directionally drilled to a
total depth of 11,270 feet and encountered approximately 205 feet of
log-indicated net hydrocarbon pay. Three intervals flowed a combined 23,700
barrels of 38 degree crude oil per day and 65 Mmcf of gas per day through choke
sizes ranging from one inch to 7/8 inch. In November 1994, the B1-8X well,
which was drilled by the previous operator, was re-entered, completed and tied
back to the Lion caisson. The well tested a combined rate of 9,575 barrels of
oil per day and 10 Mmcf of gas per day on a 3/4 inch choke from a total of 75
feet of perforations between 8,294 and 9,495 feet. The Lion #2A well was
spudded in December 1994, and during initial tests flowed 5,460 barrels of 37.1
degree crude oil per day and 4 Mmcf of gas per day on a one inch choke. The
well is currently being tied back to the Lion caisson.
On September 12, 1994, the government of the Ivory Coast granted the
Company and its PSC partners an exclusive exploitation authorization covering a
portion of the Special Area and the Remaining Area. This authorization allows
the joint venture to proceed with development activities in the authorized
area. In addition, the government has approved a gas development project and
has signed with the Company and its PSC partners a gas sales contract for gas
produced from the exploitation area. The contract calls for initial deliveries
of 20 Mmcf per day which increases to 50 Mmcf per day in year two, with a
maximum of 90 Mmcf per day. The gas will be sold at approximately $1.75 per
Mcf with a cost escalator in the fifth year of the contract.
The development plan approved by the government of the Ivory Coast
calls for first oil production in the second quarter of 1995 and initial gas
production in the third quarter of 1995. Total development expenditures for
the first phase of the project are estimated to be approximately $165 million.
The PSC partners are currently in the final stages of negotiating with the
International Finance Corporation, a subsidiary of the World Bank, for project
financing.
Future activity in the Ivory Coast, in addition to the development of
the two discoveries, includes exploratory drilling on additional prospects
which have been identified on Block CI-11. In addition, the Company and its
working interest partners have signed an agreement with the government of the
Ivory Coast which provides the option to enter into a production sharing
contract on Block CI-12 which lies immediately adjacent to the east of CI-11.
EXPLORATION ACTIVITIES
In 1994 and 1993, the Company's activities were principally in Block
CI-11 offshore. The Company expended approximately $3.0 million, and $4.0
million in 1994 and 1993, respectively, for oil and gas exploration activities
in the Ivory Coast. In addition, the Company expended in 1994 approximately
$2.6 million for development activities. The Company's 1995 Ivory Coast budget
is approximately $10.9 million, of which approximately $8.7 million is intended
for developmental activities in Block CI-11.
15
<PAGE> 19
The Company's Ivory Coast oil and gas exploration and development
drilling during the years indicated and the gross and net wells in which the
Company had a working interest were as follows:
WELLS DRILLED (1)
<TABLE>
<CAPTION>
EXPLORATORY DEVELOPMENT TOTAL
---------------- ---------------- ----------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
1994
Oil . . . . . . . . . . . . . . . . . . . 1 0.1 1 0.1 2 0.2
Gas . . . . . . . . . . . . . . . . . . . - - - - - -
Dry . . . . . . . . . . . . . . . . . . . - - - - - -
----- ----- ----- ----- ----- -----
Total . . . . . . . . . . . . . . . 1 0.1 1 0.1 2 0.2
===== ===== ===== ===== ===== =====
1993
Oil . . . . . . . . . . . . . . . . . . . - - - - - -
Gas . . . . . . . . . . . . . . . . . . . 1 0.2 - - 1 0.2
Dry . . . . . . . . . . . . . . . . . . . - - - - - -
----- ----- ----- ----- ----- -----
Total . . . . . . . . . . . . . . . 1 0.2 - - 1 0.2
===== ===== ===== ===== ===== =====
</TABLE>
(1) The term "gross" as used herein with respect to wells refers
to the total number of wells in which the Company has any
interest and "net" refers to the Company's interest in such
wells.
At December 31, 1994, the Company had no exploratory wells and no
development wells awaiting completion; no exploratory wells and 1 gross (.1
net) development well was in the process of drilling.
PRODUCTION SHARING CONTRACT
Under the CI-11 PSC, the working interest partners pay 100% of capital
and operating costs, and production is split between the Ivorian government and
the working interest partners. Up to 40% of the oil and gas produced and sold
from the contract area is available to the working interest partners to recover
costs ("cost recovery petroleum"). Cost recovery petroleum forms a single,
unified pool for the entire area from which costs of all fields, zones,
products and types may be recovered without differentiation, except that
operating costs and financial costs are recovered prior to the recovery of any
capital costs. Capital costs include exploration, development and other
equipment and facilities costs. If during a calendar year any costs are not
recovered by the working interest partners from that year's cost recovery
petroleum, the unrecovered costs are carried forward to the next succeeding
calendar year until full recovery of all costs or until the end of the
contract. Any portion of cost recovery petroleum not used to recover costs
will be split between the Ivorian government and the working interest partners
in the same manner as remaining petroleum.
The remaining 60% of oil and gas produced and sold ("remaining
petroleum") is divided between the Ivorian government and the working interest
partners. All Ivorian government royalties and the working interest partners'
Ivorian income taxes attributable to their share of Ivorian taxable income,
determined in barrels ("tax petroleum"), are included in the Ivorian
government's share of remaining petroleum.
The working interest partners' percentage of remaining petroleum
("remaining oil and remaining gas") is applied to increments of production
based on the gross daily average of oil or gas production determined on a
quarterly basis and varies with the respect to the water depth location of the
specific wellhead as follows:
<TABLE>
<CAPTION>
WORKING INTEREST PARTNERS' % OF REMAINING OIL
-------------------------------------------------
GROSS PRODUCTION WATER DEPTHS WATER DEPTHS
(BBLS OF OIL PER DAY) LESS THAN 200 METERS GREATER THAN 200 METERS
- ----------------------------- -------------------- -----------------------
<S> <C> <C>
Up to 10,000 . . . . . . . . . . . . . . . . . . . . . . . . 40% 50%
10,001 to 20,000 . . . . . . . . . . . . . . . . . . . . . . 30% 50%
20,001 to 25,000 . . . . . . . . . . . . . . . . . . . . . . 20% 50%
25,001 to 30,000 . . . . . . . . . . . . . . . . . . . . . . 20% 40%
30,001 to 50,000 . . . . . . . . . . . . . . . . . . . . . . 10% 40%
Over 50,000 . . . . . . . . . . . . . . . . . . . . . . . . 10% 30%
</TABLE>
16
<PAGE> 20
<TABLE>
<CAPTION>
WORKING INTEREST PARTNERS' % OF REMAINING GAS
---------------------------------------------------
GROSS PRODUCTION WATER DEPTHS WATER DEPTHS
(MCF OF GAS PER DAY) LESS THAN 200 METERS GREATER THAN 200 METERS
- ------------------------------ -------------------- -----------------------
<S> <C> <C>
Up to 75,000 . . . . . . . . . . . . . . . . . . . . . . . . . 40% 50%
75,001 to 150,000 . . . . . . . . . . . . . . . . . . . . . . 30% 50%
Over 150,000 . . . . . . . . . . . . . . . . . . . . . . . . . 20% 40%
</TABLE>
RESERVES
At December 31, 1994, gross proved oil and gas reserves for the CI-11
area were estimated to be 27.9 million barrels and 173.1 million cubic feet of
gas. The Company's net proved oil and gas reserves at December 31, 1994 were
5.3 million barrels of oil equivalent. The Company's share of proved reserve
quantities includes an assumed dollar amount of estimated future production
necessary to recover costs. Therefore, the amount of Company net reserves for
a given amount of total CI-11 reserves varies with the assumed oil and gas
prices. The Company's net reserves include its share of cost recovery
petroleum, remaining petroleum and tax petroleum which are 2.9 million
equivalent barrels, 1.7 million equivalent barrels, and 0.7 million equivalent
barrels, respectively.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN IVORY COAST
The Company's activities in the Ivory Coast are subject to certain
risks, including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.
MALAYSIA
GENERAL
In September 1992, the Company acquired a 10% net working interest in
the SB-4 contract area offshore Sabah, Malaysia, covering 1,556,100 acres. In
1993, the Company exercised an option to increase its net working interest to
15% in the contract area.
The initial well, Titik Terang #1, reached a total depth of 9,021 feet
in October 1992 and was abandoned as a gas discovery after three tests flowed
gas at a combined flow rate of approximately 46 Mmcf per day. The well
encountered in excess of 250 feet of net gas pay. Since that time, the Company
has acquired both 2-D and 3-D seismic data over the discovery, as well as other
parts of the block. Based upon this data, the Company, together with its joint
venture partners, has identified at least two additional prospects. However,
the joint venture partners have been waiting for the award by the government of
Sabah of a contract for electric power generation using natural gas as fuel.
After extensive delay in the award process, provisional selection of a bid was
made in December 1994. If a gas sales contract is signed, it would trigger a
cost recovery process whereby additional exploratory, as well as development,
costs would be recovered out of the first revenues from such gas sales. The
joint venture partners have determined that additional work will take place
only when such a gas sales agreement is in place.
During 1993, the Nangka-1 well was drilled on a second structure to a
total depth of 5,366 feet without successfully finding hydrocarbons. Neither
the Company nor its joint venture partners have any additional activities
planned for this structure at this time.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN MALAYSIA
The Company's activities in Malaysia are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.
17
<PAGE> 21
EGYPT
GENERAL
In August 1994, the Company acquired a 25% working interest in the
Qarun Concession Agreement ("QCA") located 45 miles southwest of Cairo, Egypt.
The concession covers approximately 1.9 million acres. The Company, together
with its QCA partners, were committed to drill at least one exploratory well in
the initial three year exploratory period. The exploration rights may be
extended up to an additional four years by assuring additional drilling
obligations.
The first exploratory well, the El Sagha #1A, was spudded on August
28, 1994 with dual objectives at approximately 9,000 and 14,000 feet. The
shallower objectives were successfully drilled and logged with open hole logs
indicating hydrocarbon zones in both the Bahariya and Kharita formations. The
logs indicated the presence of an aggregate of over 100 feet of net oil pay in
three sandstone intervals in the Bahariya plus over 100 feet of net oil pay in
a single sandstone interval in the Kharita. Analysis of a 90-foot core of some
of the Bahariya pay zones indicated good reservoir quality. While drilling to
the deeper objectives, mechanical problems developed which eventually led to
the plugging and abandonment of the well without production testing.
On November 30, 1994, the El Sagha #2 was spudded at a location
approximately 1.6 miles northwest of the El Sagha #1. This exploratory well
had the same objectives (shallow and deep) as the first well and resulted in
the second new field discovery. This well encountered at the shallow objective
approximately 45 feet of net pay which tested at a rate of 1,370 barrels of 38
degree crude oil per day from 22 feet of perforations.
Activity in 1995 will include the drilling of a well updip to the El
Sagha #1A, the drilling of an exploratory well updip to a well drilled several
years ago with oil pay on water and the drilling of other prospects which have
been identified on the block. In addition, the Company plans to participate in
a bid for a concession which will be offered by the Egyptian government in
March 1995.
Pursuant to the QCA, after commercial quantities of petroleum are
established, an Egyptian operating company will be formed to operate the block.
The operating company will be jointly owned by the QCA partners and EGPC (the
Egyptian national oil company). Production facilities and transportation
pipelines would need to be constructed before commercial production could
begin.
QARUN CONCESSION AGREEMENT
Under the QCA, the working interest partners pay 100% of capital and
operating costs and the production is split between EGPC and the working
interest partners. Up to 40% of the oil and gas produced and sold from the
Qarun concession is available to the working interest partners to recover costs
("cost recovery petroleum"). Cost recovery petroleum forms a single, unified
pool for the entire concession from which costs of all fields, zones, products
and types may be recovered without differentiation, except that operating costs
are recovered prior to the recovery of any capital costs. Capital costs (which
include exploration, development and other equipment and facilities costs) are
amortized for recovery over five years while operating expenses are recoverable
on a current basis. To the extent that costs eligible for recovery in any
quarter exceed the amount of cost recovery petroleum produced and sold in that
quarter, such costs are recoverable from cost recovery petroleum in future
quarters with no limit on the ability to carry forward such costs. Any portion
of cost recovery petroleum not used to recover costs goes to EGPC.
The remaining 60% of oil and gas produced and sold ("remaining
petroleum") is divided between EGPC and the working interest partners. All
Egyptian government royalties and the working interest partners Egyptian income
taxes attributable to their share of Egyptian taxable income, determined in
barrels ("tax petroleum"), are included in EGPC's share of remaining petroleum.
18
<PAGE> 22
The working interest partners' percentage of remaining petroleum
("remaining oil") is applied to increments of production based on the gross
daily average of oil production determined on a quarterly basis as follows:
<TABLE>
<CAPTION>
GROSS PRODUCTION WORKING INTEREST
(BBLS OF OIL PER DAY) % OF REMAINING OIL
-------------------------- ------------------
<S> <C>
Up to 5,000 . . . . . . . . . . . . . . . . . . . . . . . . . . . 30%
5,001 to 25,000 . . . . . . . . . . . . . . . . . . . . . . . . . 25%
25,001 to 50,000 . . . . . . . . . . . . . . . . . . . . . . . . 22%
Over 50,000 . . . . . . . . . . . . . . . . . . . . . . . . . . . 20%
</TABLE>
The working interest partners' percentage of the gas segment of
remaining petroleum is 22%.
RESERVES
At December 31, 1994, gross proved oil reserves for the Qarun
concession were estimated to be 23.6 million barrels. No proved gas reserves
had been assigned at December 31, 1994. The Company's net proved oil reserves
at December 31, 1994 were 3.5 million barrels. The Company's share of proved
reserve quantities includes an assumed dollar amount of estimated future
production necessary to recover costs. Therefore, the amount of Company net
reserves for a given amount of total concession reserves varies with the
assumed oil price. The Company's net reserves include its share of cost
recovery petroleum, remaining petroleum and tax petroleum which are 1.9 million
barrels, 1.0 million barrels and 0.6 million barrels, respectively.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN EGYPT
The Company's activities in Egypt are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.
TURKEY
GENERAL
The Company owns interests in the "Isparta Permit," "Egridir Permit"
and "Akseki Permit" in southwestern Turkey covering 1,714,350 gross acres. In
1992, the Company contributed to Tatex a 10% working interest in all three
exploration licenses, concurrently with the contribution to Tatex by Tatneft of
a study which Tatneft conducted of the area.
In April 1993, the Company signed a farm-out agreement with Tatneft
whereby Tatneft would conduct certain activities in the permit areas during
1993 to earn the right to drill two exploratory wells in 1994. The first phase
of the farm-out agreement was fulfilled during the last quarter of 1993 when
Tatneft successfully completed a 195 kilometer seismic survey. In the second
phase, Tatneft agreed to drill at least one exploratory well during 1994 and to
consider drilling a second well. The first well, Sobutepe #1, was spudded on
August 21, 1994. The well has been temporarily suspended at approximately
9,350 feet. Tatneft will determine in early 1995 whether or not to re-enter
the well.
The Company's share of the costs for the seismic survey and for the
two exploratory wells is borne by Tatneft in exchange for a portion of the
Company's working interest in the permit areas. Including its interest through
Tatex, the Company will retain in the three areas a 26.2% working interest
after the drilling of the first exploratory well.
Tatneft has informed the Company that at this time it does not intend
to drill the second exploratory well. Therefore, the Company relinquished
737,013 gross acres in February, 1995.
19
<PAGE> 23
CERTAIN RISKS APPLICABLE TO OPERATIONS IN TURKEY
The Company's activities in Turkey are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.
ARGENTINA
GENERAL
The Company owns overriding royalty interests in approximately
1,268,200 gross acres in the northwest basin of Argentina. The properties are
comprised of the Santa Victoria exploration permit and Ipaguazu concession,
covering 1,114,900 acres, and the El Chivil and Surubi concessions, covering
153,300 acres.
In late 1992, the Company decided to farmout or sell its working
interest in these properties and in 1993, sold all of its producing and
non-producing properties. The Company retained an overriding royalty interest
in the properties.
CERTAIN RISKS APPLICABLE TO OPERATIONS IN ARGENTINA
The Company's activities in Argentina are subject to certain risks,
including political and economic uncertainties, risks of cancellation or
unilateral modification of agreements, operating restrictions, currency
repatriation restrictions, expropriation, export restrictions, the imposition
of new taxes and the increase of existing taxes, inflation and other risks
arising out of foreign government sovereignty over areas in which the
operations are conducted.
PIPELINE OPERATIONS
GENERAL
The Company's pipeline operations, acquired during 1990, are conducted
through USAgas Pipeline, Inc. ("USAgas"). In 1992, the Company increased its
ownership in these operations from 80% to 100% in a non-cash transaction.
USAgas is engaged in the operation and development of natural gas gathering
systems, natural gas processing and treating plants and the marketing and
transportation of natural gas for the Company and its joint interest partners.
USAgas purchases and takes title to gas at the wellhead, processing plants or
other points of receipt and sells such gas to major pipelines, industrial and
institutional users, local gas distribution companies and electric utilities.
USAgas' pipeline operating assets are as follows:
<TABLE>
<CAPTION>
CAPACITY
---------------
<S> <C>
Natural Gas Processing Plant . . . . . . . . . . . . . . . . . . . . . . . . 20,000
Natural Gas Treating Plant . . . . . . . . . . . . . . . . . . . . . . . . . 10,000 Mcf/day
Gathering Systems (14 systems) . . . . . . . . . . . . . . . . . . . . . . . 250,000 Mcf/day
</TABLE>
NATURAL GAS MARKETING
USAgas' gas marketing activities are conducted through its office in
Houston, Texas. It is USAgas' general practice to contract for a diverse
supply of gas from various geographic locations and producers to minimize its
reliance on any single source or region and to maximize its ability to deliver
gas to its customers.
USAgas' practice is to match its gas sales contracts with
corresponding gas purchase contracts. A single matched group may include one
or more sales contracts and one or more purchase contracts. The objective is
for the corresponding purchase and sales contracts to provide for the same
aggregate maximum (and minimum, if any) volumes of gas to be delivered, to
extend for the same term between price re-determinations or other possible
events of termination and to provide for a built-in "spread" between the
purchase and sales prices.
20
<PAGE> 24
NATURAL GAS SUPPLY
There is a trend in the natural gas pipeline business toward more
flexibility in commitment of gas reserves both as to term and pricing. It is
not practical for a pipeline company to tabulate gas reserves as being firmly
committed to its facilities. The Company believes that most of the gas wells
connected to USAgas' fourteen existing gathering systems are likely to remain
connected until their depletion. The gas from these reserves is primarily sold
to customers under contracts which require the customers to purchase defined
daily volumes. The shutting in or curtailment of these volumes is minimized
because the systems are tied into numerous major East Texas/Northwest Louisiana
pipeline systems. When one market lowers its daily throughput requirements,
the natural gas can be routed to another market.
In order for USAgas to maintain current levels of throughput in its
pipeline systems, new natural gas supplies must be obtained, primarily from
newly drilled wells, to offset the natural decline of production from existing
wells. Newly drilled wells also provide opportunities to increase business by
building additional natural gas pipeline systems to purchase or transport these
new supplies. However, the Company cannot predict whether new natural gas
supplies will become available in adequate quantities to maintain current
levels of throughput in USAgas' pipeline system.
NATURAL GAS PIPELINE OPERATIONS
The natural gas pipeline operations involve transportation of natural
gas located primarily in East Texas for others on a fee basis as well as the
purchase of natural gas from various suppliers and the transportation and
resale of such natural gas. USAgas' pipeline systems have considerable
flexibility in providing connections between producing and consuming areas.
The systems have multiple interconnections with interstate and intrastate
pipelines.
NATURAL GAS PROCESSING
USAgas' natural gas processing plant located in McLeod, Texas
extracts natural gas liquids (ethane, propane, butane and natural gasoline,
collectively, "NGLs") from natural gas supplied by producers located on two
gathering systems. After processing, the residue natural gas is sold. The
processing contracts provide that USAgas receives, as its fee for the
gathering, processing, treating and compressing of the natural gas, a portion
of the proceeds from the sale of the extracted NGLs and a portion of the
proceeds from the sale of the residue gas. USAgas sells the extracted NGLs and
residue gas on the open market. The profitability of such plants depends
directly upon the volumes and sales prices of the extracted NGLs and residue
gas.
NATURAL GAS TREATING
USAgas owns a natural gas treating plant also located in McLeod,
Texas. Natural gas treating operations involve removing impurities from
natural gas to make it marketable. This service is generally performed for
purchasers or producers located on the gathering systems. USAgas' facility
removes acid gas components, such as carbon dioxide, and inert gases, such as
nitrogen, from the natural gas delivered to the facility. These services are
performed under long-term contracts for a fee per unit of natural gas treated.
The Company has temporarily shut down operations of the nitrogen rejection unit
at its McLeod plant because of insufficient quantities of nitrogen laden
natural gas. The Company is not certain when sufficient quantities of nitrogen
laden natural gas will be available to resume operating this unit.
COMPETITION
The natural gas pipeline industry is highly competitive, both in terms
of buying, transporting and marketing natural gas on existing pipelines and in
terms of obtaining opportunities to construct new pipelines to connect new
supplies and serve new markets. Because of intense competition and market
uncertainties, USAgas' ability to maintain or increase its natural gas pipeline
throughput cannot be predicted. In addition, gas pipeline operations are
subject to significant state and federal regulations.
OTHER OPERATIONS
INVESTMENT PROPERTIES INTERNATIONAL LIMITED
The Company owns a 47% equity interest in Investment Properties
International Limited ("IPI"), a real estate investment company now in
liquidation under the supervision of a liquidator appointed by the Supreme
Court of Ontario. The principal asset of IPI is 89% of the equity interest in
Property Resources Limited ("PRL"), a Bahamian real estate
21
<PAGE> 25
investment company. The Board of PRL has undertaken to liquidate PRL and has
made seven distributions to its shareholders of proceeds received from the
disposition of its assets. The Company has received approximately $77.8
million in liquidating distributions since 1979. The estimated net realizable
assets of IPI and PRL are subject to liquidators' fees and to certain other
claims which could reduce the amount of any potential future distributions.
Definitive information as to the remaining net realizable assets of IPI is not
readily available. However, based upon the limited information available, the
Company believes that the majority of the assets have been liquidated. The
Company received no distribution from IPI during 1994 or 1992 and $1.3 million
in 1993. At December 31, 1994 and 1993, the Company had no costs recorded
related to this investment.
ARCTIC ISLANDS INTEREST
The Company has interests in thirteen "Significant Discovery Areas"
("SDAs") representing 752,293 gross (33,364 net) acres in the Queen Elizabeth
Islands. These SDAs are Hecla, Whitefish, Cisco, Drake, Char, Balaena, Cape
MacMillan, MacLean, Skate, Jackson Bay, Kristoffer Bay, Cape Allison and
Sculpin. In the current economic environment, oil and gas prices are not
sufficient to generate positive cash flows from the production of oil and gas
from any of the aforementioned SDAs. Additionally, certain environmental and
engineering questions must also be resolved and transportation facilities for
Arctic oil and gas must be developed. Development of the region may also be
slowed by reduced demand, uncertain price structures and the Canadian
government's policies regarding the export of natural resources. The Company
cannot predict when or if its Arctic interest may be developed. At December
31, 1994 and 1993, the Company had no costs recorded related to this
investment.
NORTH COOK INLET
The Company has a 1% override in 9,620 acres in the North Cook Inlet
area of Alaska. Test rates announced for certain wells drilled during 1993
indicate the presence of a potentially significant oil field. The Company
continues to monitor the activity in this area.
FOREIGN ACREAGE
The Company's acreage in areas outside the United States as of
December 31, 1994 is summarized in the tables below.
<TABLE>
<CAPTION>
UNDEVELOPED ACREAGE
-----------------------------------------------------------
WORKING INTEREST ACREAGE ROYALTY INTEREST ACREAGE
------------------------- -------------------------
AREA: GROSS NET GROSS NET
--------- --------- --------- ------
<S> <C> <C> <C> <C>
Arctic Islands . . . . . . . . . 752,293 33,364 - -
Argentina . . . . . . . . . . . . - - 1,268,100 19,022
Australia . . . . . . . . . . . . - - 3,502,007 4,382
Egypt . . . . . . . . . . . . . . 1,900,000 475,000 - -
Indonesia . . . . . . . . . . . . 1,156,780 19,827 - -
Ivory Coast . . . . . . . . . . . 335,320 59,755 - -
Malaysia . . . . . . . . . . . 1,556,100 233,415 - -
Russia . . . . . . . . . . . . . 12,107 6,053 - -
Turkey . . . . . . . . . . . . . 1,714,350 379,043 - -
--------- --------- --------- ------
Total . . . . . . . . . . . 7,426,950 1,206,457 4,770,107 23,404
========= ========= ========= ======
</TABLE>
<TABLE>
<CAPTION>
PRODUCING OR DEVELOPED ACREAGE
-----------------------------------------------------------
WORKING INTEREST ACREAGE ROYALTY INTEREST ACREAGE
------------------------- -------------------------
AREA: GROSS NET GROSS NET
--------- --------- --------- ------
<S> <C> <C> <C> <C>
Argentina . . . . . . . . . . . . - - 479 8
Australia . . . . . . . . . . . . - - 91,793 80
Indonesia . . . . . . . . . . . . 97,000 1,663 - -
Russia . . . . . . . . . . . . . 12,630 6,315 - -
------- ----- ------ -----
Total . . . . . . . . . . . 109,630 7,978 92,272 88
======= ===== ====== =====
</TABLE>
22
<PAGE> 26
OTHER
REGULATORY MATTERS
Regulation at the federal level of natural gas transportation and sale
for resale is administered primarily by the Federal Energy Regulatory
Commission ("FERC") pursuant to the Natural Gas Act ("NGA") and the Natural Gas
Policy Act ("NGPA"). The sale for resale of natural gas in interstate commerce
is regulated, in part, pursuant to the NGA, and maximum sales prices of certain
categories of gas, whether sold in interstate or intrastate commerce, have been
regulated pursuant to the NGPA since 1978. Effective January 1, 1993, the
Natural Gas Wellhead Decontrol Act of 1989 deregulated natural gas prices for
all "first sales" of natural gas, which include all sales by the Company of its
own production. Consequently, sales of the Company's natural gas currently may
be made at market prices, subject to applicable contract provisions.
Transportation and sales for resale of gas in interstate commerce by
intrastate pipelines are regulated by FERC pursuant to NGPA Section 311.
Section 311 permits intrastate companies under certain circumstances to sell
gas to, transport gas for, or have gas transported by interstate pipeline
companies, and assign contract rights to purchase surplus gas from producers to
interstate pipeline companies without being regulated as interstate pipelines
under the NGA. In 1991, FERC issued regulations (Order 555) regarding new
pipeline construction, including construction performed by intrastate pipelines
of facilities for use for transportation pursuant to Section 311. The
regulations impose certain reporting and environmental requirements that could
affect new pipeline construction the Company may undertake. While FERC has
withdrawn these rules with respect to interstate pipelines, the reporting and
environmental requirements still apply to intrastate pipelines.
In 1990, one aspect of FERC's interpretation of the scope of NGPA
Section 311 transportation authority was reversed by an appellate court. In
September 1991, and as clarified in September 1992, FERC issued a new rule
(Order 537) which generally requires the entity on whose behalf service is
provided to take physical custody of and to transport the natural gas at some
point during the transaction or to hold title to the natural gas for a purpose
related to its status as an intrastate pipeline, local distribution company or
interstate pipeline, as applicable. The Company currently offers these
services on its intrastate pipelines. The new rule may also affect the
availability of transportation for gas sold by the Company.
Since 1985, FERC has endeavored to make natural gas transportation
more accessible to gas buyers and sellers on an open and non-discriminatory
basis. These efforts have significantly altered the marketing and pricing of
natural gas. Commencing in April 1992, FERC issued Order Nos. 636, 636-A and
636-B ("Order 636"), which contemplate, in part, the unbundling of pipeline
merchant and transportation functions. The goal of Order 636 is to ensure
comparability of service so that pipeline system supply is treated no
differently than gas of third-party shippers. Specifically, Order 636 proposes
several procedures to increase competition in the industry, including: (i) the
issuance of blanket sales certificates to interstate pipelines for unbundled
services; (ii) the continuation of pregranted abandonment of previously
committed pipeline sales and transportation services, essentially freeing up
unused pipeline capacity and clearing the way for excess transportation
capacity to be reallocated to the marketplace; (iii) requiring that firm and
interruptible transportation services be provided by the pipelines to all
parties on a comparable basis; and (iv) generally requiring that pipelines
derive transportation rates using a straight fixed variable ("SFV") rate
method, which places all fixed costs in a fixed demand charge. The specific
details of each interstate pipeline's restructuring plan were to be resolved in
restructuring compliance filings and through settlement conferences held
between each interstate pipeline and all interested parties. In many
instances, Order 636 has substantially reduced or brought to an end interstate
pipelines' traditional role as wholesalers of natural gas in favor of providing
only storage and transportation services.
As of early 1995, FERC has issued final orders accepting most
pipelines' Order 636 compliance filings, and had commenced a series of one year
reviews of individual pipeline implementations of Order 636. Numerous parties
have filed petitions for review of Order 636, as well as orders in individual
pipeline restructuring proceedings. Upon such judicial review, these orders
may be remanded or reversed in whole or in part. With Order 636 subject to
court review, and pending ongoing FERC reviews of individual pipeline
restructurings, it is difficult to predict with precision its ultimate effects.
While Order 636 does not directly regulate the Company's activities,
it has had and will have an indirect effect because of its broad scope. Among
other effects, Order 636 has substantially increased competition in natural gas
23
<PAGE> 27
markets, even though there remains significant uncertainty with respect to the
marketing and transportation of natural gas. Ultimately, however, Order 636
may enhance the Company's ability to market and transport its gas production,
although it may also subject the Company to more restrictive pipeline imbalance
tolerances and greater penalties for violations of such tolerances.
In December 1992, the FERC issued Order No. 547, governing the
issuance of blanket marketer sales certificates to all natural gas sellers
other than interstate pipelines. The order eliminates the need for natural gas
producers and marketers to seek specific authorization under Section 7 of the
NGA from the FERC to make sales of natural gas for resale. Instead, effective
January 7, 1993, these natural gas sellers, by operation of the order, were
issued blanket certificates of public convenience and necessity allowing them
to make jurisdictional natural gas sales for resale at negotiated rates without
seeking specific FERC authorization. The FERC intends Order No. 547, in tandem
with Order 636, to foster a competitive market for natural gas by giving
natural gas purchasers access to multiple supply sources at market-driven
prices. Order No. 547 does not apply to sales by the Company of gas produced
from its own properties, but Order No. 547 may increase competition in markets
in which the Company's natural gas is sold.
In July 1994, the FERC eliminated a regulation that had rendered
virtually all sales of natural gas by pipeline affiliates, such as the Company,
to be deregulated first sales. As a result, only sales by the Company of its
own production now qualify for this status. All other sales of gas by the
Company, such as those of gas purchased from third parties, are now
jurisdictional sales subject to the Order No. 547 certificate. The Company
does not anticipate this change will have any significant current adverse
effects in light of the flexible terms and conditions of the existing blanket
certificate. Such sales are subject to the future possibility of greater
federal oversight, however, including the possibility the FERC might
prospectively impose more restrictive conditions on such sales.
In October 1992, the Energy Policy Act of 1992 was enacted. This Act
streamlined the permitting process necessary to import Canadian gas and altered
the treatment of such gas under the NGPA, eliminating the FERC's jurisdiction
over the price of non-pipeline sales of gas imported from Canada. Canadian gas
imports still require import authorizations from the Department of Energy's
Office of Fossil Energy under Section 3 of the NGA, and construction and citing
authorizations, where applicable, from the FERC. These changes have enhanced
the ability of Canadian producers to export gas to the United States, and
increased competition in the domestic natural gas market.
The FERC has recently announced its intention to re-examine certain of
its transportation-related policies, including the appropriate manner in which
interstate pipelines release transportation capacity under Order 636, and the
use of market-based rates for interstate gas transmission. While any resulting
FERC action would affect the Company only indirectly, these inquires are
intended to further enhance competition in natural gas markets.
The Company's natural gas gathering operations may be or become
subject to safety and operational regulations relating to the design,
installation, testing, construction, operation, replacement, and management of
facilities. Pipeline safety issues have recently become the subject of
increasing focus in various political and administrative arenas at both the
state and federal levels. For example, federal legislation addressing pipeline
safety issues has been introduced, which, if enacted, would establish a federal
"one call" notification system. Additional pending legislation would, among
other things, increase the frequency with which certain pipelines must be
inspected, as well as increase potential civil and criminal penalties for
violations of pipeline safety requirements. The Company cannot predict what
effect, if any, the adoption of this or other additional pipeline safety
legislation might have on its operations.
Regulatory agencies in certain states have authority to issue permits
for the drilling of wells, regulate the spacing of wells, prevent the waste of
oil and gas resources through proration, require drilling bonds and reports
concerning operations, and regulate environmental and safety matters. In 1993,
the states of Texas and Oklahoma adopted changes to oil and gas production and
proration regulations which alter the methods used to prorate gas production
from wells located in the state. These measures may limit the rate at which
gas can be produced from wells the Company operates or in which it has an
interest in such states.
Operations conducted by the Company on federal oil and gas leases must
comply with numerous regulatory restrictions, including various
non-discrimination statutes. Additionally, certain operations must be
conducted pursuant to appropriate permits issued by the Bureau of Land
Management and the Minerals Management Service of the Department of Interior,
and, in regard to certain federal leases, with prior approval of drill site
locations by the Environmental Protection Agency.
24
<PAGE> 28
Regulation of natural gas gathering activities is primarily a matter
of state oversight. While some states provide for the rate regulation of
pipelines engaged in the intrastate transportation of natural gas, such
regulation has not generally been applied against gatherers of natural gas.
State regulation of gathering facilities generally includes various safety,
environmental, and in some circumstances, non-discriminatory take requirements.
Natural gas gathering may receive greater regulatory scrutiny at the federal
and state levels as the pipeline restructuring under Order 636 is completed.
For example, in 1993, the State of Oklahoma enacted a prohibition against
discriminatory gathering rates, and recently announced plans to conduct an
inquiry on alleged discriminatory practices by gatherers and transporters.
Commencing in May 1994, FERC issued a series of orders in individual cases that
delineate its gathering policy. Among other matters, FERC slightly narrowed
its statutory tests for establishing gathering status and reaffirmed that,
except in situations in which the gatherer acts in concert with an interstate
pipeline affiliate to frustrate FERC's transportation policies, it does not
have jurisdiction over gathering facilities and services and that such
facilities and services are properly regulated by state authorities. This FERC
action may further encourage regulatory scrutiny of natural gas gathering by
state agencies. In addition, FERC has approved several transfers by interstate
pipelines of gathering facilities to unregulated, independent or affiliated
gathering companies. This could increase competition among gatherers in the
affected areas. Certain FERC orders delineating its new gathering policy are
subject to pending court appeals. The Company's operations could be adversely
affected should they be subject in the future to the application of state or
federal regulation of rates and services.
Regulation of gathering and transportation activities in Louisiana and
Texas includes various transportation, safety, environmental and
non-discriminatory purchase and transport requirements. Most of the Company's
intrastate transportation operations occur within the State of Texas.
Intrastate pipeline rates excluding rates for city-gate sales for resale are
presumed by the Railroad Commission of Texas ("RRC") to be just and reasonable
where (i) neither the company nor the customer had an unfair advantage during
negotiations, (ii) the rates are substantially the same as rates for similar
service, or (iii) competition does or did exist for the market with another
supplier of natural gas or an alternative form of energy.
As required by the Energy Policy Act of 1992, in October 1993 the FERC
adopted a proposal to simplify the manner in which oil pipeline rates are set,
which, effective as of January 1, 1995, would generally index such rates to
inflation, subject to certain conditions and limitations. The FERC's decision
in this matter is currently the subject of various petitions for judicial
review. It is difficult to predict at this time what effect the new rules
might have on the cost of moving the Company's oil, condensate, and other
liquid products to market, but the new rules may have the effect of increasing
the cost of such transportation.
The Company cannot predict the effect that any of the aforementioned
orders or the challenges to the orders will have on the Company's operations.
Additional proposals and proceedings that might affect the natural gas industry
are pending before Congress, FERC and the courts. These include congressional
energy bills and executive branch energy initiatives which have as their goal
the decreased reliance by the United States on foreign energy supplies. The
Company cannot predict when or whether any such proposals or proceedings may
become effective.
Various federal, state and local laws and regulations covering the
discharge of materials into the environment, or otherwise relating to the
protection of the public health and the environment, may affect the Company's
operations, expenses and costs. The clear trend in environmental regulation is
to place more restrictions and limitations on activities that may impact the
environment, such as emissions of pollutants, generation and disposal of
wastes, and use and handling of chemical substances. Increasingly strict
environmental restrictions and limitations have resulted in increased operating
costs for the Company and other similar businesses throughout the United
States, and it is possible that the costs of compliance with environmental laws
and regulations will continue to increase. In particular, Congress is
currently considering reauthorization of the Federal Resource Conservation and
Recovery Act ("RCRA"), the principal statute governing the disposal of solid
and hazardous wastes, and congressional committees are considering amendments
to RCRA in connection with such reauthorization that would repeal the statutory
exemption that classifies oil and gas exploration and production wastes as
non-hazardous. Such amendments, if adopted, could result in substantial
remedial obligations with respect to such wastes being imposed on domestic oil
and gas producers, including the Company. State initiatives to regulate
further the disposal of oil and gas wastes are also pending in certain states,
including states in which the Company has operations, and these initiatives
could have a similar impact on the Company. For instance, Texas State Senate
Bill 1103, adopted in 1991, directs the RRC to promulgate additional rules for
the disposal of oil and gas waste; however, no proposed rules have been issued
as of the date of this filing. In addition, the Company is subject to laws
and regulations concerning occupational health and safety. It is not
anticipated that the Company will be required in the near future to expend
amounts that are material in relation to its total capital expenditures program
by reason of
25
<PAGE> 29
environmental or occupational health and safety laws and regulations, but
inasmuch as such laws and regulations are frequently changed, the Company is
unable to predict the ultimate cost of compliance.
The Oil Pollution Act of 1990 (the "OPA") and regulations thereunder
impose a variety of regulations on "responsible parties" related to the
prevention of oil spills and liability for damages resulting from such spills
in United States waters. A "responsible party" includes the owner or operator
of a facility or vessel, or the lessee or permittee of the area in which an
offshore facility is located. The OPA assigns liability to each responsible
party for oil removal costs and a variety of public and private damages. While
liability limits apply in some circumstances, a party cannot take advantage of
liability limits if the spill was caused by gross negligence or willful
misconduct or resulted from violation of a federal safety, construction or
operating regulation. If the party fails to report a spill or to cooperate
fully in the cleanup, liability limits likewise do not apply. Few defenses
exist to the liability imposed by the OPA.
The OPA also imposes ongoing requirements on a responsible party,
including proof of financial responsibility to cover a least some costs in a
potential spill. On August 25, 1993, the United States Minerals Management
Service (the "MMS"), which administers federal oil and gas leases, published an
advance notice of its intention to adopt a rule under the OPA that would
require owners and operators of offshore oil and gas facilities to establish
$150 million in financial responsibility. Under the proposed rule, financial
responsibility could be established through insurance, guaranty, indemnity,
surety bond, letter of credit, qualification as a self-insurer or a combination
thereof. There is some question as to whether insurance companies or
underwriters would be willing to provide coverage under the OPA because the
statute provides for direct lawsuits against insurers who provide financial
responsibility coverage, and most insurers have strongly protested this
requirement. Because of the negative comments submitted to the advanced
rulemaking notice, the MMS has not yet proposed a financial responsibility rule
under the OPA.
The OPA also imposes other requirements, such as the preparation of an
oil spill contingency plan. The Company has such a plan in place. Failure to
comply with ongoing requirements or inadequate cooperation during a spill event
may subject a responsible party to civil or criminal enforcement actions.
ADDITIONAL FACTORS AFFECTING THE BUSINESS
The oil and gas business is highly competitive in both the exploration
and the acquisition of reserves and in the marketing of oil and gas production.
Exploration for oil and gas is subject to a high degree of risk, and the
Company faces intense competition from present and potential competitors, many
of whom have greater resources than the Company.
Large expenditures are required to locate and acquire properties and
to drill exploratory and development wells, and the Company can never be
certain that such expenditures will result in the discovery of oil and gas
reserves in commercial quantities sufficient to replace reserves currently
being produced and sold. In certain areas where the Company operates, even
where natural gas or crude oil is present in substantial quantities, there may
be no means to transport the gas or oil to market.
The operations of the Company have been, and in the future from time
to time may be, affected by political developments in countries in which it
operates and by federal, state and local laws and regulations, such as
restrictions on production, changes in taxes, royalties and other amounts
payable to governments or governmental agencies, price controls and
environmental protection regulations, and the risks of nationalization and of
unilateral cancellation or adverse modification of contract or other rights.
The exploration, development, and production of crude oil and natural
gas are also subject to such operating risks as fires, blowouts, pollution and
other hazards. In many cases insurance for such risks is unavailable or
prohibitively expensive, and the occurrence of certain uninsured hazards could
have a material adverse effect on the Company's financial position and
operating results.
EMPLOYEES
As of March 1, 1995, the Company had a total of 92 full-time U.S.
employees which included 24 employees of the Company's wholly-owned subsidiary,
USAgas. In addition, outside consultants and specialists are sometimes
utilized in gathering and analyzing technical data, lease acquisitions,
operating activities, and field supervision.
26
<PAGE> 30
ITEM 3. LEGAL PROCEEDINGS
The Company has pending litigation incidental to its operations.
Management believes that none of the litigation is expected to have a material
adverse effect on the Company's financial position or results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of the Company's security
holders during the fourth quarter of the fiscal year ended December 31, 1994.
27
<PAGE> 31
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The high and low sales prices for the common stock of the Company for
each quarter of the two years ended December 31, 1994, in the United States on
the New York Stock Exchange (under the symbol "GNR"), were as follows:
<TABLE>
<CAPTION>
1994 MARKET PRICE 1993 MARKET PRICE
-------------------- --------------------
QUARTER ENDED HIGH LOW HIGH LOW
------------- ------ ------ ------ ------
<S> <C> <C> <C> <C>
March 31 . . . . . . . . . . . . . . . . . $8.375 $6.750 $8.125 $5.125
June 30 . . . . . . . . . . . . . . . . . . $7.875 $6.375 $8.875 $6.875
September 30 . . . . . . . . . . . . . . . $8.125 $7.125 $9.250 $7.875
December 31 . . . . . . . . . . . . . . . . $9.625 $6.625 $9.000 $6.250
</TABLE>
As of May 1, 1995, the Company had 2,681 stockholders of record. The
Company has never paid cash dividends and does not expect to pay cash dividends
in the near future.
As of December 31, 1994 and May 1, 1995, the Company held 3,900,697
and 3,894,275, respectively, of its own shares in treasury.
ITEM 6. SELECTED FINANCIAL DATA (AS RESTATED)
FIVE YEAR DATA
Selected financial data for the Company on a consolidated basis is
presented below. This data has been restated to reflect a change in entities
comprising the consolidated group, as discussed in Note 1 to the Consolidated
Financial Statements. Also see Note 1 for discussion of changes in the methods
of accounting for certain investments and natural gas revenues in 1994, and
income taxes in 1993.
<TABLE>
<CAPTION>
1994 1993 1992 1991 1990
------- ------- -------- ------- -------
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . . $62,943 $75,084 $57,506 $60,194 $58,078
Exploration expense . . . . . . . . . . 19,325 6,946 6,522 11,925 5,947
Net income (loss) from continuing
operations . . . . . . . . . . . . . (8,253) 4,487 (2,846) (39,105) 7,496
Net income (loss) per share from
continuing operations(1) . . . . . . (.28) .16 (.12) (1.66) .33
Cash provided from operations(2) . . . . 38,189 19,531 6,713 15,071 32,070
IPI distributions . . . . . . . . . . . - 1,267 - 3,040 4,560
Additions to properties and equipment. . 52,301 25,852 7,873 24,649 52,492
Standardized measure of discounted
future net cash flows relating to
proved oil and gas reserves . . . . 142,615 109,202 93,955 97,075 168,840
Total assets . . . . . . . . . . . . . . 154,500 161,931 131,511 140,177 179,216
Non-current redeemable bearer shares(3). 17,467 18,375 - - -
Common stock subject to put . . . . . . - - 200 650 1,040
Shareholders' equity(4) . . . . . . . . 107,756 120,376 114,653 118,156 101,240
Long-term portion of debt . . . . . . . 1,275 - 55 234 50,167
Working capital . . . . . . . . . . . . 26,298 61,689 42,467 35,276 31,637
Weighted average common shares
outstanding(5) . . . . . . . . . . . 29,661 28,361 23,593 23,515 22,543
</TABLE>
(Footnotes on following page)
28
<PAGE> 32
(1) Net income on a fully diluted basis for 1993 was $.15 per share.
(2) To be read in the context of the Consolidated Statements of Cash Flows
included in Item 8 herein.
(3) See Note 4 to Consolidated Financial Statements for discussion of
redeemable bearer shares.
(4) See Note 5 to Consolidated Financial Statements for discussion of
convertible preferred shares.
(5) Net of treasury shares.
INTERIM FINANCIAL DATA (UNAUDITED)
The following is a restated condensed summary of the results of
operations for the calendar quarters of 1994 and 1993.
<TABLE>
<CAPTION>
1994 QUARTER ENDED
-------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . . . . . . . . . $16,054 $13,450 $16,565 $16,874
Income (loss) from operations . . . . . . . . . . . . 3,110 (3,568) (706) (2,015)
Net income (loss) . . . . . . . . . . . . . . . . . . 2,065 (4,376) (2,415) (3,527)
Net income (loss) per share, primary . . . . . . . . . .07 (.15) (.08) (.12)
Net income (loss) per share, fully diluted . . . . . . .07 (.15) (.08) (.12)
</TABLE>
<TABLE>
<CAPTION>
1993 QUARTER ENDED
-------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
-------- ------- -------- -------
(AMOUNTS IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Revenues . . . . . . . . . . . . . . . . . . . . . . . $15,334 $17,539 $21,428 $20,783
Income (loss) from operations . . . . . . . . . . . . 1,688 (70) 2,923 570
Net income . . . . . . . . . . . . . . . . . . . . . . 2,230 267 1,612 378
Net income per share, primary . . . . . . . . . . . . .09 .01 .05 .01
Net income per share, fully diluted . . . . . . . . . .08 .01 .05 .01
</TABLE>
During the second, third and fourth quarters of 1994, the Company
incurred exploration expenditures of $6.4 million, $4.8 million and $6.4
million, respectively. Included in these expenditures were dry hole costs for
unsuccessful exploratory wells of $4.6 million, $2.5 million and $3.9 million,
respectively.
During the first and fourth quarters of 1993, the Company recorded
gains of $2.1 million ($.09 per share) and $.6 million ($.02 per share),
respectively, on the sale of assets. (Unless otherwise indicated, all per
share information presented herein is on a per primary share basis.)
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
As discussed in Notes 1 and 2 to the Consolidated Financial
Statements, the consolidated financial information for all periods presented
have been restated to consolidate the Russian joint venture operations. Prior
to the receipt on March 3, 1995, of an exemption from paying export tax on
crude oil sold outside of Russia, the activities of the Russian joint venture
were not significant to the Company and the Company accounted for these
activities using the equity method. This change had no effect on net income
(loss) or shareholders' equity for the periods presented.
INTRODUCTION
In 1994, 1993 and 1992, the Company generated $38.2 million, $19.5
million and $6.7 million, respectively, in cash from operating activities. The
Company's expenditures for exploration and development activities in 1994, 1993
and 1992 were $49.0 million, $22.1 million and $8.1 million, respectively. In
1994 and 1992, the Company's expenditures for the acquisition of producing
properties were $3.8 million and $15 thousand, respectively. In 1993, the
Company acquired no producing properties. The Company currently anticipates
expending approximately $37.3 million in 1995 for exploration and development
activities. Domestic exploration and development expenditures are projected to
be approximately $15.3 million with expenditures related to international
exploration and development activities including Russia projected to be
approximately $22 million in 1995.
29
<PAGE> 33
During 1994, 1993 and 1992 the Company's worldwide oil and gas
reserve base increased approximately 14.7 Mmbls (44%), 7.2 Mmbls (27%), and 2.5
Mmbls (11%) of oil equivalent, respectively. These increases are the direct
result of the Company's exploration and development efforts under taken during
these years.
The Company's reserve replacement ratio, inclusive of revisions of
previous estimates and based on net equivalent barrels, from exploration and
development activities for 1994, 1993 and 1992 was 576%, 403% and 220%,
respectively. The reserve replacement ratio for 1994 was the result of the
Company's 1994 drilling program, primarily international, and positive
revisions to previous estimates. The reserve replacement ratio for 1993 was the
result of the Company's 1993 drilling program, primarily domestic, and positive
revisions to previous reserve estimates primarily associated with the Company's
Taylor Lake and San Juan properties. The reserve replacement ratio for 1992 was
the result of the Company's activities in Russia partially offset by downward
revisions of previous estimates for the Oak Hill field in East Texas and a
diminished drilling program during the year.
RESULTS OF OPERATIONS
In 1994, the Company had a net loss of $8.3 million ($.28 per share)
compared to net income of $4.5 million ($.16 per share) and a net loss of $2.8
million ($.12 per share) in 1993 and 1992, respectively. The net loss for 1994
includes $19.3 million in exploration expenses. During 1993 and 1992,
exploration expenses were $6.9 million and $6.5 million, respectively. The
increase in exploration expenses during 1994 is reflective of the Company's
increased international and domestic exploration activities in comparison to
previous years. Included in 1994 exploration expenditures were dry hole costs
of $11.2 million as compared to $1.9 million and $0.9 million in 1993 and 1992,
respectively. The net income for 1993 includes a $1.3 million distribution
from IPI, a $1.6 million net gain on the sale of producing properties,
including certain interests in San Juan properties, and $.7 million in gains on
other asset sales. The net loss for 1992 includes a $.4 million loss on the
disposition of domestic producing properties.
Oil and Gas
In 1994, 1993 and 1992, worldwide oil and gas production accounted for
$43.8 million (70%), $35.7 million (48%) and $33.4 million (58%) of the
Company's operating revenues, respectively. Domestic oil and gas operations
accounted for $20.1 million (32%), $19.3 million (26%) and $19.0 million (33%)
of the Company's operating revenues during the same periods, respectively.
Indonesian oil and gas operations accounted for $11.7 million (19%), $11.4
million (15%) and $11.7 million (20%) of the Company's operating revenues in
1994, 1993 and 1992, respectively. Russian oil and gas operations accounted
for $12.0 million (19%), $ 4.6 million (6%) and $2.2 million (4%) of the
Company's operating revenues in 1994, 1993 and 1992, respectively.
Worldwide oil and gas revenues increased approximately $8.1 million
(23%) from 1993 to 1994. Russian revenues increased $7.4 million (160%)
during 1994, primarily as the result of increased oil production from the
Onbysk field. Slight increases were recorded for both Indonesian and domestic
revenues. During 1994, domestic oil and gas revenues increased approximately
4% as compared to 1993. This increase is the direct result of increased
natural gas production from the Company's Taylor Lake field and from new
offshore fields from which initial production began late in 1994. When
compared to 1993, domestic natural gas production increased 27% during 1994.
However, this increased production was principally offset by decreases during
1994 as compared to 1993 in gas prices, oil prices and oil production of 12%,
9% and 13%, respectively.
The 7% increase in worldwide oil and gas revenues from 1992 to 1993
was due primarily to a $2.4 million increase in Russian revenues. Domestic
gas production increased approximately 10% in 1993. This increased production
was primarily in the Taylor Lake field located in the onshore Gulf Coast area.
The price received per Mcf increased 6% and is attributed to the demand for
domestic natural gas which resulted in gradually increasing gas prices
throughout 1993. These increases were partially offset by decreases in both
domestic oil production and the overall price per barrel received in 1993. In
1993, domestic oil production decreased 21% primarily as the result of sales
during the fourth quarter of 1992 of certain properties in the Rockies area.
30
<PAGE> 34
The Company's oil and gas volumes and unit prices for the United
States, Indonesia, Russia and Argentina for 1994, 1993 and 1992 are summarized
in the following table:
<TABLE>
<CAPTION>
UNITED STATES INDONESIA RUSSIA ARGENTINA
------------------------ ------------------------ ---------------------- -----------------------
VOLUME UNIT PRICE VOLUME UNIT PRICE VOLUME UNIT PRICE VOLUME UNIT PRICE
------- ---------- ------- ---------- ------ ---------- ------ ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
1994
Oil (MBbl) . . . 229 $15.65 47 $16.58 842 $14.21 - -
Gas (Mmcf) . . . 8,904 $ 1.86 4,473 $ 2.45 - - - -
1993
Oil (MBbl) . . . 263 $17.11 54 $18.31 323 $14.24 19 $15.47
Gas (Mmcf) . . . 7,088 $ 2.11 3,769 $ 2.75 - - - -
1992
Oil (MBbl) . . . 334 $18.97 47 $20.65 128 $17.06 21 $18.37
Gas (Mmcf) . . . 6,425 $ 2.00 3,667 $ 2.92 - - - -
</TABLE>
The oil and gas revenue variances resulting from volume and price
changes for the United States, Indonesia and Russia during 1994 and 1993 are
summarized in the table below (amounts in thousands).
<TABLE>
<CAPTION>
UNITED STATES INDONESIA RUSSIA
------------------ ------------------ ------------------
VARIANCE DUE TO: VARIANCE DUE TO: VARIANCE DUE TO:
PRICE VOLUME PRICE VOLUME PRICE VOLUME
----- ------ ----- ------ ----- ------
<S> <C> <C> <C> <C> <C> <C>
1994 VS 1993
------------
Oil . . . . . . . . . . . . . $ (334) $ (582) $ (81) $ (128) $ (25) $7,390
Gas . . . . . . . . . . . . . $(2,226) $ 3,832 $(1,342) $1,936 $ - $ -
1993 VS 1992
------------
Oil . . . . . . . . . . . . . $ (489) $(1,347) $ (126) $ 145 $(946) $3,361
Gas . . . . . . . . . . . . . $ 780 $ 1,326 $ (641) $ 298 $ - $ -
</TABLE>
Future oil and gas revenues, both domestic and foreign, will depend on
volumes sold and prices received. These in turn will depend on a number of
factors beyond the control of the Company including demand and price
adjustments under buyers' contracts with Pertamina.
Worldwide production expenses increased 38% and 13% during 1994 and
1993, respectively, when compared to production expenses of the previous year.
Domestic production expenses per equivalent barrel of oil produced during 1992,
1993 and 1994 were $3.68, $2.61 and $1.97, respectively. The decrease in
domestic production expenses per equivalent barrel of oil during these three
years is reflective of the Company's decision to dispose of certain high cost
properties during 1992 and 1993 and of increased production during 1993 and
1994 from the Company's lower cost Taylor Lake field. Russian production
expenses accounted for $7.8 million (70%), $4.0 million (49%) and 1.5 million
(21%) of the Company's production expenses in 1994, 1993 and 1992,
respectively. Included in Russian production expenses were export tax expenses
of $4.1 million, $1.7 million and $0.4 million during 1994, 1993 and 1992,
respectively.
Exploration expenses in 1994 increased approximately $12.4 million
when compared to exploration expenses incurred during 1993 and 1992. This
increase is reflective of the increased worldwide exploration activities
undertaken by the Company. As a result of these exploration efforts, the
Company added during 1994 to its reserve base approximately 15.8 Mmbls (47%) on
a barrel of equivalent oil basis and increased future discounted net revenues
after tax effects approximately $49.8 million (46%). Included in 1994
exploration expenses were dry hole expenditures, leasehold impairments and
geological costs of approximately $11.2 million, $2.4 million and $3.1 million.
The same expenditures during 1993 were approximately $1.9 million, $2.4 million
and $1.1 million, respectively.
Depletion, depreciation and amortization increased approximately 17%
during 1994 when compared to 1993. This increase is the result of an increase
in oil and gas production. Domestic depletion, depreciation and amortization
per
31
<PAGE> 35
equivalent barrel of oil produced during 1992, 1993 and 1994 were $4.96, $4.12
and $3.83. This downward trend is reflective of disposition of certain high
cost properties and of the Company's successful exploration and development
activities. Russian depletion, depreciation and amortization expenses
accounted for $ 1.6 million (16%), $0.6 million (7%) and $0.3 million (3%) of
the Company's depletion, depreciation and amortization expenses in 1994, 1993
and 1992, respectively.
Administrative expenses decreased approximately 1% during 1994 and
approximately 6% in 1993 when compared to previous years. The overall decrease
from 1992 to 1994 of 7% is reflective of the Company's continuing efforts to
focus on and reduce controllable costs whenever possible. These cost
reductions have occurred during periods of increased exploration and
development activities and increased oil and gas production. Russian
administrative expenses account for $2.3 million (26%), $1.4 million (16%) and
$1.3 million (13%) of the Company's administrative expenses during 1994, 1993
and 1992, respectively.
Pipeline Operations
Pipeline operations accounted for $18 million (29%), $38.6 million
(51%) and $23.9 million (42%) of the Company's consolidated revenues in 1994,
1993 and 1992, respectively. Pipeline operating expenses exclusive of
depreciation were $16.9 million, $37.5 million and $22.0 million for 1994, 1993
and 1992, respectively. The pipeline segment generated losses from operations
before taxes of $0.3 million in 1994, $0.6 million in 1993 and $0.3 million in
1992. While the losses from operations before taxes improved during 1994, the
pipeline segment continued to experience constricted operating margins. The
increase in the loss from operations before taxes from 1992 to 1993 of $0.3
million was primarily the result of decreased operating margins in 1993. The
loss in 1992 was due primarily to the impairment of certain pipeline assets and
to repairs, environmental and safety expenditures.
The primary reason for the decrease in pipeline segment revenues and
expenditures in 1994 as compared to 1993 was a decrease in marketing activities
for working interest partners at the Taylor Lake field. During 1994, revenue
and expenses, excluding depreciation, attributable to the marketing of gas
production from certain of the Company's operated properties were $3.3 million
and $3.2 million, respectively. During 1993, these revenues and expenses were
$22.4 million and $22.2 million, respectively. In addition, the Company has
temporarily shut down operations of the nitrogen rejection unit at its McLeod
plant because of insufficient quantities of nitrogen laden natural gas. The
Company is not certain when or if sufficient quantities of nitrogen laden
natural gas will be available to resume operating this unit.
The increase in pipeline segment revenues and expenses from 1992 to
1993 was primarily due to increased gas marketing activities of gas production
from certain of the Company's operated properties, and from increased gathering
systems volumes. During 1992, revenues and expenses, excluding depreciation,
attributable to the marketing of gas production from certain of the Company's
operated properties were $5.3 million and $5.2 million, respectively.
Russian Operations
The Company, through its 90% owned subsidiary, Texneft, has a net 45%
interest in Tatex, a Russian joint venture. Tatex's activities currently
include two projects: 1) vapor recovery and 2) the development and operation of
the Onbysk field. The vapor recovery activity was expanded in 1994 with a
total of 19 units on production at year's end. In addition, a total of 19
wells were drilled in the Onbysk field by the joint venture during the year.
A third project, which is currently inactive, was a well stimulation
program in and adjacent to the Romashkino field. In connection with this
project during 1994, a total of 42 stimulations were performed of which 34 were
performed within the Onbysk field and 8 in other fields. Activities were
directed primarily at the Onbysk field because the Government had not indicated
whether or not, in the long-term, incremental oil resulting from the
stimulation activities in the Romashkino area would be designated as Own Oil
and which may be exported freely for hard currency. Because of the lack of
clarification of long-range government policy towards stimulation, the contract
was terminated on November 1, 1994. Should progress be made in establishing a
firm Own Oil classification over a clearly defined period, the stimulation
program may be reactivated at some later date.
The assumption of operations by the joint venture of a fourth project,
the development of undeveloped reserves underlying urban areas within the
Romashkino field, is no longer considered an appropriate project for Tatex
under the prevailing tax and administrative uncertainties. As a result, no
further action will be taken to finalize the contract for the urban project
which existed in draft form. However, Tatneft and Texneft have agreed to
examine alternative
32
<PAGE> 36
opportunities to expand Tatex operations into other fields in which exploration
but not development activities have been carried out.
As of December 31, 1994 and 1993, the Company's advances to Texneft
were $18.2 million and $11.7 million, respectively. The Company has recognized
net losses from its Russian operations for the periods ended December 31, 1994,
1993 and 1992 of $.1 million, $1.2 million and $.8 million, respectively.
Included in the 1994, 1993 and 1992 losses were $3.4 million, $1.4 million and
$.3 million, respectively, of expense for the Russian government export tax on
crude oil. On March 3, 1995, the Company was notified that Tatex had received
an exemption from paying export tax on crude oil sold outside of Russia. The
exemption received was for one year and was effective January 1, 1995. The
exemption is subject to an annual review by the Government and subject to its
approval, can be renewed for two additional years.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios stated in millions (except ratios
and per share amounts) at December 31, 1994, 1993 and 1992 were as follows:
<TABLE>
<CAPTION>
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Cash and cash equivalents . . . . . . . . . . . . . . . $ 3.9 $ 16.4 $ 20.6
Short-term liquid investments . . . . . . . . . . . . . $ 33.3 $ 49.9 $ 21.8
Current assets . . . . . . . . . . . . . . . . . . . . $ 53.1 $ 84.3 $ 58.4
Current liabilities . . . . . . . . . . . . . . . . . . $ 26.8 $ 22.6 $ 15.9
Current ratio . . . . . . . . . . . . . . . . . . . . . 198% 373% 367%
Non-current redeemable bearer shares . . . . . . . . . $ 17.5 $ 18.4 $ -
Long-term debt . . . . . . . . . . . . . . . . . . . . $ 1.3 $ - $ 0.1
Shareholders' equity . . . . . . . . . . . . . . . . . $107.8 $120.4 $114.7
Debt to equity ratio . . . . . . . . . . . . . . . . . 17.4% 15.3% -
Equity per common share outstanding(1) . . . . . . . . $ 3.67 $ 4.01 $ 4.89
Common shares outstanding at year end . . . . . . . . 29.4 30.0 23.5
</TABLE>
(1) If Prudential had converted its Preferred Stock to common stock on
December 31, 1992, equity per common share outstanding would have been
$3.85. See Note 5 to Consolidated Financial Statements.
Cash and cash equivalents combined with short-term liquid investments
decreased by $29.1 million during the year ended December 31, 1994. This
decrease was primarily due to capital expenditures of $52.3 million and a $5.3
million treasury stock acquisition. These cash outlays were partially offset
by the $38.2 million of cash provided by operating activities net of the $16.2
million change in short-term liquid investments.
Cash and cash equivalents combined with short-term liquid investments
increased by $23.9 million during the year ended December 31, 1993. This
increase was primarily due to the $19.2 million received in August 1993,
representing an interest-free loan, of the remaining cash held by Hambros
Trust. The loan is repayable on demand only to the extent necessary to redeem
bearer shares presented for exchange until July 2008. The loan is secured by a
letter of credit from a bank. The letter of credit is secured by certain of
the Company's short-term liquid investments. Each bearer share presented
during this period will be redeemed for $6.66. As of December 31, 1994, there
were 2,685,487 outstanding bearer shares. In July 2008, the obligation of the
Company to holders of bearer shares will cease, the interest-free loan will
terminate, and any remaining cash will revert to the Company and will be
accounted for as an increase in capital in excess of par value.
Cash provided by operating activities for the year ended December 31,
1994 was $38.2 million compared to $19.5 million for the same period in 1993.
This $18.7 million increase in cash provided by operations is primarily the
result of a decrease in short-term liquid investments of $16.2 million.
Cash provided by operating activities for the year ended December 31,
1993 was $19.5 million compared to $6.7 million for the same period in 1992.
This $12.8 million increase in cash provided by operations is primarily the
result of a $2.3 million net increase in income from operations adjusted for
depletion, impairments, dry hole expense and gain on disposition of properties
and a $10.2 million net increase resulting from changes in accounts receivable,
other current assets, accounts payable and accrued liabilities for 1993 as
compared to 1992.
33
<PAGE> 37
The Company expended approximately $52.3 million for additions to
properties and equipment in 1994 compared to $25.9 million and $7.9 million in
1993 and 1992, respectively. Capital expenditures combined with a $5.3 million
treasury stock acquisition were the primary reasons for the $35.4 million
decrease in working capital in 1994. Working capital increased $19.2 million
in 1993. The 1993 increase was primarily due to the $19.2 million proceeds
from redeemable bearer shares previously discussed.
In 1995, the Company intends to direct cash flow from its current base
of domestic properties and Indonesian interests to expand its exploration and
development efforts in the United States, mainly offshore Gulf of Mexico, while
directing its balance sheet cash (cash and short-term investments) primarily
toward international opportunities. The Company plans to spend in 1995
approximately $15.3 million on exploration and development activities in the
United States. Capital expenditures for international activities, primarily in
Russia, Egypt and the Ivory Coast, are projected to be approximately $22
million for 1995. Factors such as political stability in the various host
countries and world oil prices will heavily influence the amount and timing of
these expenditures. The Company believes that it has adequate resources to
fund these planned expenditures.
In order to insure that the Company continues to have the necessary
financial flexibility in the future, the Company is currently negotiating a $35
million unsecured line of credit. In addition, the Company and its working
interest partners are currently negotiating project financing for the Ivory
Coast development activities. The Company seeks to finalize these credit
resources by mid-1995. In addition, the Company plans to obtain project
financing for Egyptian development activities when the extent of those
activities is more clearly defined.
Effective January 1, 1994, the Company adopted Financial Accounting
Standards Board ("FASB") Statement No. 115, "Accounting for Certain Investments
in Debt and Equity Securities." This statement requires the use of fair value
accounting for investments in marketable equity and all debt securities. The
adoption of this statement had no impact on the Company's current year income.
Effective the second quarter of 1994, the Company changed its method
of accounting for natural gas revenues from the sales method, whereby the
Company recorded natural gas revenues based on the amount of gas sold, to the
entitlements method. Under the entitlements method, the Company records
natural gas revenues based upon the Company's entitled share of gas production.
The Company believes that the entitlement method will provide a more meaningful
presentation of the Company's financial position and will produce a better
matching of current revenues and costs. Prior to 1994, the Company had no
material gas imbalances, therefore the effect of the change in accounting
method would have had no material impact on net income reported in previous
periods. As of December 31, 1994, the Company had recorded a deferred credit
from the sale of approximately .4 billion cubic feet of natural gas in excess
of its entitled share. As a result, 1994 income was reduced by approximately
$.7 million.
The Company believes inflation has not had a material effect on its
domestic operations or on its financial condition, but there can be no
assurance that future increases in the inflation rate, particularly in Russia,
would not have an adverse effect on the Company's financial statements. In
addition, the Company is not aware of any impending material change in its cost
of supplies, materials, equipment or labor. The Company's employees are
currently not members of any labor union or trade association.
A continued trend to greater environmental and safety awareness and
increasing environmental regulation has resulted in higher operating costs for
the oil and gas industry and the Company. The Company believes environmental
and safety costs will continue to increase in the future. To date, compliance
with environmental laws and regulations has not had a material impact on the
Company's capital expenditures, earnings or competitive position. The Company
has not received any notices from any regulatory agency regarding violations of
environmental laws. The Company monitors environmental laws and believes it is
in compliance with applicable environmental regulations and certain air quality
standards set by the Texas Air Quality Control Board and other appropriate
regulatory agencies. The Company is unable to predict the impact of future
laws and regulations on the Company's operations.
34
<PAGE> 38
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
The Board of Directors and Shareholders of
Global Natural Resources Inc.:
We have audited the accompanying consolidated balance sheets of Global
Natural Resources Inc. and subsidiaries as of December 31, 1994 and 1993 and
the related consolidated statements of operations, shareholders' equity and
cash flows for each of the years in the three-year period ended December 31,
1994. These consolidated financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
consolidated 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, the consolidated financial statements referred to
above present fairly, in all material respects, the financial position of
Global Natural Resources Inc. and subsidiaries as of December 31, 1994 and
1993, and the results of their operations and their cash flows for each of the
years in the three-year period ended December 31, 1994, in conformity with
generally accepted accounting principles.
As discussed in notes 1 and 3 to the consolidated financial
statements, in 1994 the Company changed its method of accounting for certain
investments to adopt the provisions of Statement of Financial Accounting
Standards No. 115, "Accounting for Certain Debt and Equity Securities." As
discussed in note 1 to the consolidated financial statements, the Company
changed its method of accounting for natural gas revenues in 1994. As
discussed in notes 1 and 7 to the consolidated financial statements, in 1993
the Company changed its method of accounting for income taxes to adopt the
provisions of Statement of Financial Accounting Standards No. 109, "Accounting
for Income Taxes."
As discussed in notes 1 and 2 to the consolidated financial
statements, effective January 1, 1995, the consolidated financial statements
for all periods presented have been restated to present the Russian joint
venture operations as part of the consolidated group. These activities were
previously accounted for using the equity method.
KPMG PEAT MARWICK LLP
Houston, Texas
February 28, 1995, except as to
notes 1, 2, 6, 7 and 10, which
are as of May 10, 1995
35
<PAGE> 39
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (AS RESTATED)
DECEMBER 31, 1994 AND 1993
(AMOUNTS IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
1994 1993
-------- ---------
<S> <C> <C>
Current assets:
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,881 $ 16,356
Short-term liquid investments . . . . . . . . . . . . . . . . . . . . . . . . 33,279 49,947
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10,665 14,869
Current investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 832 1,663
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,436 1,434
-------- --------
Total current assets . . . . . . . . . . . . . . . . . . . . . . . . . . 53,093 84,269
-------- --------
Properties and equipment, at cost:
Oil and gas properties (successful efforts method) 119,602 95,368
Pipeline facilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19,320 18,976
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,961 11,561
-------- --------
151,883 125,905
Less: accumulated depletion, depreciation and amortization (58,534) (54,795)
-------- --------
Net properties and equipment . . . . . . . . . . . . . . . . . . . . . . 93,349 71,110
-------- --------
Notes receivable- Russian joint venture . . . . . . . . . . . . . . . . . . . . 3,606 1,404
Indonesian venture advances, net . . . . . . . . . . . . . . . . . . . . . . . . 2,453 3,099
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,999 2,049
-------- --------
$154,500 $161,931
======== ========
</TABLE>
LIABILITIES AND SHAREHOLDERS' EQUITY
<TABLE>
<S> <C> <C>
Current liabilities:
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $13,256 $ 15,523
Accrued liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,229 6,272
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,309 785
-------- ---------
Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . 26,794 22,580
-------- ---------
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,275 -
Deferred credits and other . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,208 600
Commitments and contingencies . . . . . . . . . . . . . . . . . . . . . . . . . - -
Redeemable bearer shares . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,467 18,375
Shareholders' equity:
Common stock; authorized 100,000,000 shares at $1.00 par value;
issued and outstanding 33,335,487 in 1994 and 33,190,287 in 1993 33,335 33,190
Capital in excess of par value. . . . . . . . . . . . . . . . . . . . . . . . 138,355 137,648
Accumulated deficit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (44,167) (35,914)
-------- ---------
127,523 134,924
Less: treasury stock; 3,900,697 shares in 1994 and 3,186,329 in 1993 . . . . (19,767) (14,548)
-------- ---------
Total shareholders' equity . . . . . . . . . . . . . . . . . . . . . . . 107,756 120,376
-------- ---------
$154,500 $161,931
======== =========
</TABLE>
See accompanying notes to consolidated financial statements.
36
<PAGE> 40
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS (as restated)
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(AMOUNTS IN THOUSANDS, EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
1994 1993 1992
------------- ------------- -------------
<S> <C> <C> <C>
Revenues:
Oil and gas . . . . . . . . . . . . . . . . . . . . . . . . $ 43,814 $ 35,693 $ 33,402
Pipeline . . . . . . . . . . . . . . . . . . . . . . . . . . 18,009 38,610 23,875
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,120 781 229
------------ ------------- -----------
62,943 75,084 57,506
------------ ------------- -----------
Expenses:
Production . . . . . . . . . . . . . . . . . . . . . . . . . 11,203 8,135 7,170
Exploration . . . . . . . . . . . . . . . . . . . . . . . . 19,325 6,946 6,522
Pipeline cost of sales . . . . . . . . . . . . . . . . . . . 16,852 37,495 21,990
Depletion, depreciation and amortization . . . . . . . . . . 9,837 8,376 10,247
Administrative . . . . . . . . . . . . . . . . . . . . . . . 8,905 9,021 9,634
------------ ------------- -----------
66,122 69,973 55,563
------------ ------------- -----------
Income (loss) from operations . . . . . . . . . . . . . (3,179) 5,111 1,943
Other income (expense):
Interest income . . . . . . . . . . . . . . . . . . . . . . 2,308 2,046 1,955
Interest expense . . . . . . . . . . . . . . . . . . . . . . (124) (101) (246)
Distribution from IPI . . . . . . . . . . . . . . . . . . . - 1,267 -
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . (602) 2,696 (26)
------------ ------------- -----------
1,582 5,908 1,683
------------ ------------- -----------
Income (loss) before income tax expense . . . . . . . . (1,597) 11,019 3,626
Income tax expense . . . . . . . . . . . . . . . . . . . . . . 6,656 6,532 6,472
------------ ------------- -----------
Net income (loss) . . . . . . . . . . . . . . . . . . . . . $ (8,253) $ 4,487 $ (2,846)
============ ============= ===========
Income (loss) per share based on weighted average shares:
Net income (loss) primary . . . . . . . . . . . . . . . . . $ (0.28) $ 0.16 $ (0.12)
============ ============= ===========
Net income (loss) assuming full dilution . . . . . . . . . . $ (0.28) $ 0.15 $ (0.12)
============ ============= ===========
Weighted average common shares outstanding:
Primary . . . . . . . . . . . . . . . . . . . . . . . . . . 29,660,578 28,360,697 23,593,288
============ ============= ===========
Assuming full dilution . . . . . . . . . . . . . . . . . . . 29,660,578 29,903,391 23,593,288
============ ============= ===========
</TABLE>
See accompanying notes to consolidated financial statements.
37
<PAGE> 41
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1994 1993 1992
--------- --------- ---------
<S> <C> <C> <C>
COMMON STOCK
Balance at beginning of year . . . . . . . . . . $ 33,190 $ 26,701 $ 26,569
Adjustment of common stock subject to put . . . - 28 67
Conversion of preferred stock into common stock - 6,311 -
Issuance of common stock . . . . . . . . . . . . 145 150 65
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . 33,335 33,190 26,701
-------- -------- --------
CAPITAL IN EXCESS OF PAR VALUE
Balance at beginning of year . . . . . . . . . . 137,648 88,423 87,739
Adjustment of common stock subject to put . . . - 172 383
Issuance of treasury stock for bearer shares . . - (198) -
Issuance of treasury stock to 401(k) plan . . . 35 13 -
Conversion of preferred stock into common stock - 48,387 -
Issuance of common stock . . . . . . . . . . . . 672 851 301
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . 138,355 137,648 88,423
-------- -------- --------
CONVERTIBLE PREFERRED STOCK
Balance at beginning of year . . . . . . . . . . - 54,698 54,698
Conversion of preferred stock into common stock - (54,698) -
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . - - 54,698
-------- -------- --------
ACCUMULATED DEFICIT
Balance at beginning of year . . . . . . . . . . (35,914) (40,401) (37,555)
Net income (loss) . . . . . . . . . . . . . . . (8,253) 4,487 (2,846)
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . (44,167) (35,914) (40,401)
-------- -------- --------
TREASURY STOCK
Balance at beginning of year . . . . . . . . . . (14,548) (14,768) (13,295)
Acquisition of treasury stock . . . . . . . . . (5,289) - (1,473)
Issuance of treasury stock for bearer shares . . - 198 -
Issuance of treasury stock to 401(k) plan . . . 70 22 -
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . (19,767) (14,548) (14,768)
-------- -------- --------
TOTAL SHAREHOLDERS' EQUITY $107,756 $120,376 $114,653
======== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
38
<PAGE> 42
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (AS RESTATED)
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1994 1993 1992
---------------- --------- --------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . $ (8,253) $ 4,487 $ (2,846)
Adjustments to reconcile net income (loss) to net cash provided by
operating activities:
Depreciation, depletion and amortization . . . . . . . . . . 9,837 8,376 10,247
Leasehold impairments and dry hole expense . . . . . . . . . 13,635 4,272 4,031
Unrealized loss on short-term liquid and current investments 458 - -
(Gain) loss on asset sales . . . . . . . . . . . . . . . . . 8 (2,974) 450
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (37) (226) (322)
Changes in:
Accounts receivable . . . . . . . . . . . . . . . . . . . . 4,204 (2,095) (1,036)
Other current assets . . . . . . . . . . . . . . . . . . . . (2,171) 1,775 (17)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . (2,267) 3,670 436
Accrued liabilities . . . . . . . . . . . . . . . . . . . . 5,957 2,303 (3,952)
Short-term liquid investments . . . . . . . . . . . . . . . 16,210 - -
Deferred credits . . . . . . . . . . . . . . . . . . . . . . 608 (57) (278)
--------------- -------- --------
Net cash provided by operating activities . . . . . . . . . . . 38,189 19,531 6,713
--------------- -------- --------
Cash Flows from Investing Activities:
Additions to oil and gas properties . . . . . . . . . . . . . . (50,381) (23,121) (6,410)
Additions to pipeline facilities and other properties and equipment (1,920) (2,731) (1,463)
Purchases of short-term liquid investments . . . . . . . . . . . - (829,948) (966,672)
Maturities of short-term liquid investments . . . . . . . . . . - 11,849 19,879
Proceeds from sales of short-term liquid investments . . . . . . - 789,936 952,458
Proceeds from sales of assets . . . . . . . . . . . . . . . . . 6,843 10,251 4,087
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,775) 331 (1,064)
--------------- -------- --------
Net cash used in investing activities . . . . . . . . . . . . . (47,233) (43,433) 815
--------------- -------- --------
Cash Flows from Financing Activities:
Proceeds from common stock issuance . . . . . . . . . . . . . . 852 685 366
Proceeds from redeemable bearer shares . . . . . . . . . . . . . - 19,149 -
Proceeds from long-term debt . . . . . . . . . . . . . . . . . . 1,275 - -
Redemptions of bearer shares . . . . . . . . . . . . . . . . . . (908) (129) -
Acquisitions of treasury stock . . . . . . . . . . . . . . . . . (5,289) - -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 639 (13) (324)
--------------- -------- --------
Net cash provided by (used in) financing activities . . . . . . (3,431) 19,692 42
--------------- -------- --------
Net increase (decrease) in cash and cash equivalents . . . . . . (12,475) (4,210) 7,570
Cash and cash equivalents at beginning of period . . . . . . . . 16,356 20,566 12,996
--------------- -------- --------
Cash and cash equivalents at end of period . . . . . . . . . . . $ 3,881 $16,356 $ 20,566
=============== ======== ========
Supplemental disclosure of cash flow information:
Cash paid for:
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 224 $ 125 $ 72
=============== ======== ========
Income taxes:
U. S. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ - $ 150 $120
Foreign . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,577 6,320 6,474
--------------- -------- --------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,577 $ 6,470 $ 6,594
=============== ======== ========
</TABLE>
See accompanying notes to consolidated financial statements.
39
<PAGE> 43
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
Supplemental disclosure of non-cash investing and financing activities:
In connection with the Company's Employees 401(k) Savings Plan referred to
in Note 8, the Company contributed 14,194 treasury shares during 1994 with a
market value of $104,000 to the plan. During 1993, the Company contributed
4,638 treasury shares with a market value of $35,000 to the plan.
As referred to in Note 5, in March 1993, Prudential converted its
preferred stock into 6,311,537 shares of the Company's common stock.
On September 21, 1992, Noel Group, Inc. ("Noel") completed a distribution
of shares owned by Noel in the Company, Garnet Resources Corporation ("Garnet")
and VISX, Incorporated ("VISX") to Noel shareholders. The Company received
from Noel 46,468 shares of Garnet, 53,907 shares of VISX and 203,098 shares of
the Company's stock as a result of the Noel distribution. The Company recorded
the investment in Garnet and VISX and the receipt of treasury stock at their
respective September 21, 1992 market values and reduced the book value of its
investment in Noel by a corresponding amount. On November 29, 1993, Noel
distributed shares owned by Noel in Sylvan Foods Holdings, Inc. ("Sylvan") to
Noel shareholders. The Company received from Noel 54,860 shares of Sylvan as a
result of the Noel distribution. The Company recorded the investment in Sylvan
at its November 29, 1993 market value and reduced the book value of Noel by a
corresponding amount.
As a result of the Hambros agreements referred to in Note 4, $.4 million
was transferred into capital in excess of par value and $.1 million into common
stock as a result of the reduction in common stock subject to put during 1992.
In 1993, $.2 million was transferred into capital in excess of par value and
approximately $28 thousand into common stock as a result of the reduction in
common stock subject to put.
See accompanying notes to consolidated financial statements.
40
<PAGE> 44
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (AS RESTATED)
(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Certain reclassifications have been made in the 1993 and 1992
financial statements to conform to presentation used in 1994.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Global
Natural Resources Inc. and its majority-owned entities (the "Company"). The
Consolidated Financial Statements for all periods presented have been restated
to present its Russian joint venture operations as part of the consolidated
group. These activities were previously accounted for using the equity method
(see Note 2). The Company's accounts include its pro rata share of the
balances and operations of the Tatex joint venture, in which a subsidiary of
the Company owns an undivided 50% interest. All significant intercompany
accounts and transactions have been eliminated.
Cash Equivalents
The Company considers all investments with a maturity of ninety days
or less when purchased to be cash equivalents.
Short-Term Liquid Investments
Short-term liquid investments include investments having a maturity at
the date of purchase of more than ninety days. These investments, which have a
minimum rating of A1/P1, consist primarily of repurchase agreements, commercial
paper, certificates of deposit and U.S. government securities and are carried
at cost, which approximates market value. The Company believes that no single
short-term liquid investment exposes the Company to significant credit risk.
As of December 31, 1994, excluding U.S. government securities, the largest
individual short-term liquid investment did not exceed $6 million.
Current Investments
Effective January 1, 1994, the Company adopted Statement of Financial
Accounting Standards No. 115 ("Statement No. 115"), "Accounting for Certain
Investments in Debt and Equity Securities." The cumulative effect of this
accounting change as of January 1, 1994 had no material impact upon the
financial statements of the Company. Under Statement No. 115, the Company
classifies its debt and marketable equity securities in one of three
categories: trading, available-for-sale, or held-to-maturity. Trading
securities are bought and held principally for the purpose of selling them in
the near term. Held-to-maturity securities are those securities for which the
Company has the ability and intent to hold until maturity. Any securities not
classified as trading or held-to-maturity are classified as available-for-sale.
The Company has no held-to-maturity or available-for-sale securities.
Trading securities are recorded at fair value. Unrealized holding gains and
losses on trading securities are included in earnings. Dividend and interest
income are recognized when earned.
Current investments are trading securities carried at fair value.
Prior to the adoption of Statement No. 115, current investments were carried at
the lower of aggregate cost or market value.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for
its oil and gas operations whereby acquisition costs and exploratory drilling
costs related to properties with proved reserves and all development costs,
including development dry holes, are capitalized. Geological and geophysical
costs and the cost of retaining unproven properties are charged to expense as
incurred. Exploratory drilling costs applicable to unsuccessful exploration
efforts are charged to expense at the time the wells or other exploration
activities are determined to be nonproductive. Costs incurred to operate and
maintain wells and equipment and to lift oil and gas to the surface are
expended as incurred. Acquisition costs of unproved properties are evaluated
periodically and any impairment assessed is charged to expense. Capitalized
costs are depleted using the unit of production method based upon proved
reserves for acquisition costs and proved developed reserves for exploration
and development costs. Estimated costs (net of salvage value) of dismantling
41
<PAGE> 45
oil and gas production facilities, including abandonment and site restoration
costs, are computed by the Company's engineers and are included when
calculating depreciation and depletion using the unit-of-production method. On
a world-wide basis, should net capitalized costs exceed the estimated future
undiscounted after tax net cash flows from proved oil and gas reserves, such
excess costs will be charged to expense.
Other Property and Equipment
Pipelines, plant and equipment are depreciated on the straight-line
method over their estimated useful lives ranging from three to twenty-two
years. Miscellaneous property and equipment are depreciated on the
straight-line and declining-balance methods, based upon estimated useful lives
ranging from three to ten years.
Investment in Indonesian Production Sharing Contract
The Company has a 1.714% interest in a joint venture (the "IJV") for
the exploration, development and production of oil and natural gas in East
Kalimantan, Indonesia, under a production sharing contract ("PSC") with
Perusahaan Pertambangan Minyak Dan Gas Bumi Negara, the state petroleum
enterprise of Indonesia ("Pertamina"). The Company makes advances to the
operator for exploration, development and operating costs. In April 1990,
Pertamina and the IJV signed an amendment and a 20-year extension to the PSC
with generally similar terms and conditions as the PSC prior to such amendment
and extension. The extended PSC will expire August 7, 2018. The share of
revenues from the sale of gas after cost recovery through August 7, 1998 will
remain at 35% to the IJV after Indonesian income taxes and 65% to Pertamina.
The split after August 7, 1998 will be either 25% or 30% to the IJV after
Indonesian income taxes and 75% or 70% to Pertamina, depending upon the sales
contract involved. Based on current and projected oil production, the revenue
split from oil sales after cost recovery through August 7, 2018 will remain at
15% to the IJV after Indonesian income taxes and 85% to Pertamina. These
revenue splits are based on Indonesian income tax rates of 56% through August
7, 1998 and 48% thereafter. The cost of the Company's original investment is
depleted on a straight-line basis over the remaining life of the original
production sharing contract.
Investment Properties International, Limited (IPI)
The Company owns 47% of the equity interests in IPI, which was a real
estate investment company that is now in liquidation under the supervision of a
liquidator. Definitive information relative to the net realizable assets of
IPI is not available. However, based upon limited information available from
the liquidator, the Company believes that the majority of the assets have been
liquidated. In 1993, the Company received a distribution from IPI of
approximately $1.3 million. No distributions were received from IPI during
1994 or 1992. At December 31, 1994 and 1993, the Company had no costs recorded
related to this investment.
Foreign Currency Translation
The Company uses the U.S. dollar as the functional currency for its
operations in Russia. Transactions denominated in rubles are translated into
U.S. dollars using the market rate.
Concentrations of Credit Risk
The Company's trade receivables include amounts due from purchasers of
oil and gas production and amounts due from joint venture partners for their
respective portions of operating expenses and exploration and development
costs. The Company believes that no single customer or joint venture partner
exposes the Company to significant credit risk. The Company's customers and
joint venture partners may be similarly affected by changes in economic,
regulatory or other factors and thereby impact the Company's overall credit
risk. There can be no assurance that the Company's joint venture partners will
be in a position to pay their joint venture obligations, in which case the
Company may be required to assume all or a portion of their financing
obligations. Trade receivables are generally not collateralized; however, the
Company analyzes customers' and joint venture partners' historical credit
positions prior to extending credit.
Environmental Liabilities
A provision for environmentally related expenditures is recorded when
it is determined that the Company's liability for environmental assessments
and/or cleanup is probable and the cost can be reasonably estimated. If it is
anticipated that future economic benefit will arise from environmental
expenditures, the amounts are capitalized; otherwise, they are expended.
42
<PAGE> 46
Natural Gas Revenues
Effective the second quarter of 1994, the Company changed its method
of accounting for natural gas revenues from the sales method, whereby the
Company recorded natural gas revenues based on the amount of gas sold, to the
entitlements method. Under the entitlements method, the Company records
natural gas revenues based upon the Company's entitled share of gas production.
The Company believes that the entitlement method will provide a more meaningful
presentation of the Company's financial position and will produce a better
matching of current revenues and costs. Prior to 1994, the Company had no
material gas imbalances, therefore the effect of the change in accounting
method would have had no material impact on net income reported in previous
periods. As of December 31, 1994, the Company had recorded a deferred credit
from the sale of approximately .4 billion cubic feet of natural gas in excess
of its entitled share. As a result, 1994 income was reduced by approximately
$.7 million ($.02 per share).
Income Taxes
Effective January 1, 1993, the Company adopted the provisions of
Statement of Financial Accounting Standards No. 109 ("Statement No. 109").
This change in accounting method had no impact on income. Under the asset and
liability method of Statement No. 109, deferred tax assets and liabilities are
recognized for the future tax consequences attributable to differences between
the financial statement carrying amounts of existing assets and liabilities and
their respective tax bases and operating loss and tax credit carry forwards.
Deferred tax assets and liabilities are measured using enacted tax rates
expected to apply to taxable income in the years in which those temporary
differences are expected to be recovered or settled. Under Statement No. 109,
the effect on deferred tax assets and liabilities of a change in tax rates is
recognized in income in the period that includes the enactment date.
Pursuant to the deferred method under APB Opinion 11, which was
applied in 1992 and prior years, deferred income taxes were recognized for
income and expense items that were reported in different years for financial
reporting and income tax purposes using the tax rate applicable for the year of
the calculation.
Earnings per Share
Earnings per share is computed based upon the weighted average common
shares outstanding, computed on a monthly basis. Unexercised stock options do
not have a dilutive effect on the reported amount of earnings per common share.
Fully diluted earnings per share for 1993 was calculated assuming conversion of
Prudential's preferred stock into Company common stock effective January 1,
1993. See Note 5.
(2) INVESTMENT IN TEXNEFT
In 1990, the Company formed Texneft Inc. ("Texneft") to participate in
a joint venture in Russia with Tatneft, a Russian oil production amalgamation
which operates the oil fields of Tatarstan, Russia. Texneft, a 90% owned
subsidiary, has a 50% interest in the joint venture, Tatex. In November 1994,
the Company purchased an additional 10% of Texneft's common stock, increasing
its ownership from 80% to 90%. An agreement between the minority shareholder
of Texneft and the Company requires the Company to advance to Texneft
sufficient cash to fund its administrative expenses and its contributions to
Tatex. In turn, Texneft will make no distributions to its shareholders until
the Company has been repaid a sum equal to the total of its advances to
Texneft. As of December 31, 1994, the Company's outstanding advances totaled
$18.2 million.
Tatex was registered with the Ministry of Finance of the former USSR
on November 15, 1990, and subsequently registered with the governments of
Russia, Tatarstan and the City of Almetyevsk. The joint venture activities
currently include two projects: 1) vapor recovery and, 2) the development and
operation of the Onbysk field. A third project which is currently inactive,
was well stimulation in and adjacent to the Romashkino field. The assumption
of operations by the joint venture of a fourth project, development of
undeveloped reserves underlying urban areas within the Romashkino field, is no
longer considered an appropriate project for Tatex under the prevailing tax and
administrative uncertainties. However, Tatneft and Texneft have agreed to
examine alternative opportunities to expand Tatex operations in other fields in
which exploration but not development activities have been carried out.
The joint venture capital contributions totaled approximately $2.8
million as of December 31, 1994. In 1991, Tatneft contributed .5 million
rubles while Texneft contributed the equivalent of .5 million rubles at the
official exchange rate. Fifty percent of Texneft's initial contribution, or
approximately $.4 million, was made in equipment and materials. In
43
<PAGE> 47
1993, Texneft and Tatneft each contributed $1 million to the Charter Fund as
their share of contributions required to finance the development of the Onbysk
field and the well stimulation operations.
Additional funding for the joint venture will be supplied by Texneft
and Tatneft through various credit agreements. The aggregate amount of all
loans made under the various credit agreements will not exceed $19.5 million
from Texneft and a total of 5.2 million rubles and $16.5 million from Tatneft.
As of December 31, 1994, 1993 and 1992, outstanding dollar advances from
Texneft were approximately $7.2 million, $2.8 million and $1.8 million,
respectively. As of December 31, 1994, outstanding advances from Tatneft were
approximately $2.6 million.
On March 3, 1995, the Company was notified that its Russian joint
venture had received an exemption from paying export tax on crude oil sold
outside of Russia. The exemption, which is subject to annual review by the
Russian government, is for one year beginning January 1, 1995. With government
approval, the exemption can be renewed for two additional years. Prior to the
receipt of the export tax exemption, the activities of the Russian joint
venture were not significant to the Company and the Company accounted for these
activities using the equity method. Because these activities have become
significant, effective January 1, 1995 the Company began consolidating its
Russian joint venture operations. The Consolidated Financial Statements for
1994, 1993 and 1992 have been restated for this change. The change had no
effect on net income for the periods presented or on accumulated deficit as of
the beginning of 1992.
Risks Applicable to Russian Operations
The Company's activities in Russia are subject to the usual risks
associated with foreign operations, including political and economic
uncertainties, risks of cancellation or unilateral modification of agreements,
operating restrictions, currency repatriation restrictions, expropriation,
export restrictions, the imposition of new taxes and the increase of existing
taxes, inflations and other risks arising out of foreign government sovereignty
over areas in which the operations are conducted. The Company has endeavored
to protect itself against certain political and commercial risks inherent in
the venture. There is no certainty that the steps taken by the Company will
provide adequate protection.
(3) CURRENT INVESTMENTS
Current investments at December 31, 1994 and 1993 consist of
certificates of deposit and U.S. government and corporate debt securities
(included in short-term liquid investments), and equity securities (included in
current investments). During the twelve month period ended December 31, 1994,
the Company recorded $0.5 million of unrealized losses resulting from changes
in the differences between cost and market value of short-term liquid
investments and current investments.
Short-term liquid investments at December 31, 1993 were carried at cost
which approximates fair value. Current investments at December 31, 1993 were
carried at the lower of aggregate cost ($1.7 million) or market value ($1.9
million). In 1993 the Company recorded a net unrealized loss of approximately
$0.6 million as the result of changes in the differences between the cost and
market value of items held as current investments at year end. No unrealized
losses were recorded in 1992.
(4) REDEEMABLE BEARER SHARES
Global Natural Resources Inc. became the successor issuer to Global
Natural Resources PLC, a United Kingdom company ("U.K. Company"), on July 26,
1983 pursuant to the terms of a Scheme of Arrangement (the "Arrangement") under
Section 206 of the English Companies Act. The effect of the Arrangement was to
move the domicile of the parent company to the United States from the United
Kingdom.
Under the terms of the Arrangement, 24,270,876 registered common
shares of the Company were registered in the name of Hambros Trust ("Trust
Shares"). The Trust Shares were held for the owners of share warrants to bearer
issued by the U.K. Company. Holders of bearer shares were entitled to receive
at their election either cash or Company shares on a share-for-share basis
until July 1993. After July 1993, holders of bearer shares are entitled to
receive only cash.
The Arrangement provided that Trust Shares not claimed by July 26,
1988 could be sold by the Trust and the proceeds from such sale together with
earned interest be used to satisfy future claims by the holders of share
warrants to bearer. Prior to August 1993, the Company was obligated to
maintain a sufficient number of treasury shares or unissued shares to be issued
in case the Trust determined that it held an insufficient number of Company
shares to effect an exchange. The Company was also obligated to maintain a
letter of credit in favor of the Trust equal to the number of Company shares
held by the Trust multiplied by the escalated price. This obligation was
accounted for as common
44
<PAGE> 48
stock subject to put. Prior to August 1993, unclaimed Trust Shares were
included in the total common shares issued and outstanding.
In August 1993, the Company received $19.2 million, the remaining cash
held by the Trust, in the form of an interest-free loan. The loan is repayable
on demand only to the extent necessary to redeem bearer shares presented for
exchange until July 2008. Each bearer share presented during this period will
be redeemed for $6.66. As of December 31, 1994 and 1993, there were 2,685,487
and 2,803,022 outstanding bearer shares, respectively. The loan is secured by
a letter of credit from a bank. The letter of credit is secured by certain of
the Company's short-term liquid investments. Drawings under the letter of
credit will revert to a term loan due more than one year from the date drawn.
Therefore the loan, except that portion estimated to be needed for the
redemption of bearer shares during the next twelve months, is classified as
non-current in the accompanying balance sheet. During 1994 and 1993, there
were no drawings under the letter of credit.
During July 2008, the obligation of the Company to holders of bearer
shares will cease, the interest-free loan will terminate, and any remaining
cash will revert to the Company and will be accounted for as an increase to
capital in excess of par value.
(5) SHAREHOLDERS' EQUITY
Preferred Share Purchase Rights Plan
In October 1988, the Board of Directors of the Company adopted a
preferred share rights plan (the "Rights Plan") pursuant to which holders of
the Company's common stock were issued rights ("Rights") to purchase shares of
a series of the Company's preferred stock. Generally, the Rights are
exercisable only if a person or group acquires 20% or more of the Company's
outstanding voting stock. The Rights Certificates are exercisable on the tenth
business day after the shares acquisition date, as defined, or such later date
as determined by the Board of Directors. Each Right entitles the holder
thereof to buy one one-hundredth of a share of Series B Junior Preferred Stock
("Preferred Stock") at an exercise price of $20.00 per Right, subject to
anti-dilution provisions. The Rights, under certain circumstances, are
redeemable at the option of the Company's Board of Directors at a price of $.01
per Right and expire on October 20, 1998.
In addition to the right to purchase Preferred Stock, in the event
that the Company is acquired in a merger or other business combination
transaction or 50% or more of its consolidated assets or earning power are
sold, each holder of a Right will thereafter have the right to receive, upon
the exercise thereof at the then current exercise price of the Right, that
number of shares of common stock of the acquiring company which at the time of
such transaction will have a market value of two times the exercise price of
the Right. In the event that the Company is the surviving corporation in a
merger and the Company's common stock is not changed or exchanged, each holder
of a Right, other than Rights that are beneficially owned by the Acquiring
Person (which will thereafter be void), will thereafter have the right to
receive upon exercise that number of shares of the Company's common stock
having a market value of two times the exercise price of the Right.
In the event that a person or group acquires 20% or more of the
outstanding Voting Shares, then each Right (other than Rights owned by the
Acquiring Person and its affiliates and associates and all transferees thereof)
will entitle the holder to purchase, for the exercise price, a number of shares
of the Company's common stock having a then current market value of two times
the exercise price of the Right. If this provision becomes effective and the
Acquiring Person owns less than 50% of the Company's Voting Shares then
outstanding, the Board of Directors would have the option to redeem the Rights
in exchange for Common Shares at the rate of one share for each two shares for
which the Rights are then exercisable.
45
<PAGE> 49
Stock Activity
The following table reflects the activity in shares of the Company's
Common Stock, Convertible Preferred Stock and Treasury Stock during the three
years ended December 31, 1994.
<TABLE>
<CAPTION>
1994 1993 1992
----------- ----------- -----------
<S> <C> <C> <C>
COMMON STOCK OUTSTANDING
Shares at beginning of year . . . . . . . . . . . 33,190,287 26,700,646 26,568,681
Adjustment of common stock subject to put . . . . - 28,304 66,965
Conversion of preferred stock into common stock . - 6,311,537 -
Issuance of common stock . . . . . . . . . . . . . 145,200 149,800 65,000
----------- ----------- -----------
Shares at end of year . . . . . . . . . . . . . . 33,335,487 33,190,287 26,700,646
----------- ----------- -----------
CONVERTIBLE PREFERRED STOCK OUTSTANDING
Shares at beginning of year . . . . . . . . . . . - 6,153,847 6,153,847
Conversion of preferred stock into common stock . - (6,153,847) -
----------- ----------- -----------
Shares at end of year . . . . . . . . . . . . . . - - 6,153,847
----------- ----------- -----------
TREASURY STOCK OUTSTANDING
Shares at beginning of year . . . . . . . . . . . 3,186,329 3,234,473 3,031,375
Acquisition of treasury stock . . . . . . . . . . 728,562 - 203,098
Issuance of treasury stock for bearer shares . . . - (43,506) -
Issuance of treasury stock to 401(k) plan . . . . (14,194) (4,638) -
----------- ----------- -----------
Shares at end of year . . . . . . . . . . . . . . 3,900,697 3,186,329 3,234,473
----------- ----------- -----------
</TABLE>
On May 31, 1994, the Company purchased in a private transaction 705,196
shares of its common stock from Noel Group Inc. ("Noel"). The purchase price
was $7.50 per share or approximately $5.3 million. In connection with the
repurchase of the shares, two of the four representatives of Noel on the
Company's Board of Directors resigned.
Preferred Stock
In 1987, the Board of Directors authorized the issuance of 6,153,847
shares of $1.00 par value Series A Preferred Stock (the "Preferred
Stock"). All such Preferred Stock was issued to Prudential Insurance Company of
America ("Prudential") in 1991 in exchange for $50 million of convertible
subordinated notes ("Notes"). Accrued long-term interest of $5.5 million that
would have been paid at the end of the term of the Notes, net of unamortized
deferred debt costs, was credited to convertible preferred stock. In March
1993, Prudential converted the Preferred Stock into 6,311,537 shares of the
Company's common stock. These shares are not registered and Prudential will be
unable to sell these shares in the public market without registration with the
SEC or an exemption from such registration.
In 1988, the Board of Directors of the Company authorized the issuance
of 750,000 shares of $1.00 par value Series B Junior Preferred Stock for the
purpose of issuance upon the exercise of Rights under the Rights Plan as
described above. Each share of such preferred stock issuable upon exercise of
the Rights will bear quarterly dividends of $2.50, a liquidation preference of
$2,000 and will be redeemable by the Company.
Stock Option Plans
The Key Employees Stock Option Plan was approved by the Company's
shareholders in June 1989. This plan reserved 1,500,000 shares of the
Company's common stock for issuance to employees at a price not less than the
greater of par value or fifty percent of the fair market value of such shares.
Options granted vest as determined by the Board of Directors and expire ten
years after grant. All options granted as of December 31, 1994 were granted at
the fair market value of the Company's common stock on the date of grant. At
December 31, 1994, 70,950 shares of common stock were available for grant.
Information related to the options granted under the Key Employees
Stock Option Plan is summarized as follows:
46
<PAGE> 50
<TABLE>
<CAPTION>
1994 1993
------------------------------- -------------------------------
NUMBER OF OPTION PRICE NUMBER OF OPTION PRICE
SHARES RANGE PER SHARE SHARES RANGE PER SHARE
---------- ----------------- ---------- -----------------
<S> <C> <C> <C> <C>
Options outstanding:
Beginning of period . . . . 1,045,350 $5.1875 - $10.500 939,550 $5.1875 - $10.50
Granted . . . . . . . . . . 5,000 $7.75 - $7.9375 256,500 $6.25 - $7.875
Exercised . . . . . . . . . (145,200) $5.1875 - $6.2500 (149,800) $5.1875 - $7.250
Canceled . . . . . . . . . . (5,400) $6.25 - $6.6875 (900) $6.625 - $6.625
---------- ----------------- ---------- -----------------
End of period . . . . . . . 899,750 $5.1875 - $10.500 1,045,350 $5.1875 - $10.50
========== ================= ========== =================
Options exercisable . . . . 662,150 $5.1875 - $10.500 631,400 $5.1875 - $10.50
========== ================= ========== =================
</TABLE>
The 1992 Stock Option Plan ("1992 Plan") was approved by the Company's
shareholders in June 1992. This plan reserved 1,000,000 shares of the
Company's common stock for issuance to employees, directors and other persons
who perform services for or on behalf of the Company. Options granted under
the 1992 Plan may be either incentive stock options, ("ISO") within the meaning
of the Internal Revenue Code or options which do not constitute incentive stock
options ("NQSO"). The price at which the Company can issue the options shall
not be less than the fair market value of such shares at the date of the grant
for ISO options and shall not be less than 50% of the fair market value of such
shares at the date of the grant for NQSO options. As of December 31, 1994, all
options granted were NQSO options and all except 50,000 options were granted at
the fair market value of the Company's common stock on the date of the grant.
On May 3, 1993, 50,000 options were granted to a member of the Board of
Directors at an option price of $5.875. The fair market value of the Company's
common stock on that date was $8.50. At December 31, 1994, 340,000 shares of
common stock were available for grant.
Information related to the options granted under the 1992 Plan is
summarized as follows:
<TABLE>
<CAPTION>
1994 1993
-------------------------------- ---------------------------------
NUMBER OF OPTION PRICE NUMBER OF OPTION PRICE
SHARES RANGE PER SHARE SHARES RANGE PER SHARE
---------- ------------------ ---------- ------------------
<S> <C> <C> <C> <C>
Options outstanding:
Beginning of period . . . . 622,500 $5.875 - $7.750 500,000 $7.75 - $7.7500
Granted . . . . . . . . . . 37,500 $7.1875 - $8.000 122,500 $5.875 - $7.4375
Canceled . . . . . . . . . . - - - - - -
---------- ------------------ ---------- ------------------
End of period . . . . . . . 660,000 $5.875 - $8.000 622,500 $5.875 - $7.7500
========== ================== ========== ==================
Options exercisable . . . . 480,000 $5.875 - $8.000 352,500 $5.875 - $7.7500
========== ================== ========== ==================
</TABLE>
Dividends
No dividends have been paid or declared.
(6) LONG-TERM DEBT
The Company's Russian joint venture has a $5 million line of credit
with the International Moscow Bank. At December 31, 1994, this loan had
an outstanding balance of $2,550,000 ($1,275,000 net to the Company's
interest). This loan bears annual bank charges at the lower of interest
at 8.75% per annum plus bank fees, or interest at 10% per annum payable
semi-annually on June 15 and December 15. The line of credit is secured by the
guarantee of Tatneft, the Company's Russian joint venture partner. The Company
capitalizes a portion of its interest costs as part of property and equipment.
Amounts capitalized in 1994 and 1993 were $0.1 million and $0.1 million,
respectively.
47
<PAGE> 51
(7) INCOME TAXES
Effective January 1, 1993, the Company adopted Statement No. 109. The
cumulative effect of this accounting change as of January 1, 1993 had no impact
on 1993 net income.
Income before income taxes and the components of income tax expense
for each of the three years ended December 31, 1994 stated in thousands,
consisted of the following:
<TABLE>
<CAPTION>
1994 1993 1992
------------ ------------ ------------
<S> <C> <C> <C>
Income (loss) before income tax expense:
Domestic . . . . . . . . . . . . . . . . . . . $ (7,450) $ 4,857 $ (5,132)
Foreign(1) . . . . . . . . . . . . . . . . . . 5,853 6,162 8,758
------------ ------------ ------------
$ (1,597) $ 11,019 $ 3,626
============ ============ ============
Current income tax expense:
Federal . . . . . . . . . . . . . . . . . . . $ 24 $ 175 $ (2)
Foreign . . . . . . . . . . . . . . . . . . . 6,632 6,357 6,474
------------ ------------ ------------
$ 6,656 $ 6,532 $ 6,472
============ ============ ============
</TABLE>
- ----------------
(1) Includes 1994, 1993 and 1992 losses related to Argentina, Canada,
Russia, Malaysia, Ivory Coast, Egypt and Turkey of $5,747, $5,055 and
$2,798, respectively.
The tax effects of temporary differences that gave rise to the
significant portions of the deferred tax assets as of
December 31, 1993 and 1994 stated in thousands were as follows:
<TABLE>
<CAPTION>
1994 1993
----------- -----------
<S> <C> <C>
Deferred tax assets:
Properties and equipment . . . . . . . . $ 3,160 $ 2,327
Notes receivable . . . . . . . . . . . . 5,248 6,978
Other . . . . . . . . . . . . . . . . . . 84 273
Net operating loss carryforwards . . . . 10,267 8,955
Percentage depletion carryforwards . . . 3,736 3,485
Foreign tax credit carryforwards . . . . 1,545 2,067
Minimum tax credit carryforwards . . . . 934 811
Investment tax credit carryforwards . . . 1,192 1,290
----------- -----------
Deferred tax assets 26,166 26,186
Less - valuation allowance . . . . . . . (26,166) (26,186)
----------- -----------
Net deferred tax . . . . . . . . $ - $ -
=========== ===========
</TABLE>
The Company's operating loss carryforwards expire in various amounts
from 1997-2009, and the investment tax credit carryforwards expire in various
amounts from 1995-2000. The statutory depletion carryforward may be carried
forward indefinitely. Utilization of these carryforwards may be limited
because these tax attributes were generated in separate return limitation
years. In management's judgement, it is unlikely that the majority of the
deferred tax assets in the preceding table can be realized as reductions in
future taxable income or by utilizing available tax planning strategies.
Therefore, an appropriate valuation allowance has been established to recognize
this uncertainty. The Company will periodically review the likelihood of
realizing these assets and adjust the valuation allowance as needed.
48
<PAGE> 52
The effective tax rate in the accompanying consolidated statements of
operations was more than the computed expected tax expense at the federal
statutory rate of 35% for the years ended December 31, 1994 and 1993 and 34%
for the year ended December 31, 1992. Sources of these differences for each of
the three years ended December 31, 1994 stated in thousands are as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Computed statutory tax expense (benefit) . . . . . . . . . . . . . . . . . . $ (559) $ 3,857 $ 1,233
Increase (decrease) in taxes resulting from:
Foreign tax expense, net of federal income tax benefits . . . . . . . . 4,311 4,132 4,273
Benefit from sale of stock of Canadian subsidiary . . . . . . . . . . . - (4,129) -
Income tax benefit not utilized . . . . . . . . . . . . . . . . . . . . 2,880 2,497 527
Depletion and depreciation applicable to different financial
cost basis of assets due to purchase accounting . . . . . . . . . - - 162
Foreign income not taxed or taxed at different rates on
which U.S. federal income taxes are not provided . . . . . . . . . - - 279
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 175 (2)
---------- ---------- ----------
$ 6,656 $ 6,532 $ 6,472
========== ========== ==========
</TABLE>
Deferred federal income tax provisions result from timing differences
in the recognition of revenue and expense for tax and financial
reporting purposes. The sources of these differences and the tax effect of each
for the year ended December 31, 1992 stated in thousands were as follows:
<TABLE>
<CAPTION>
1992
---------
<S> <C>
Intangible exploration and development costs deducted for tax
purposes which are capitalized and amortized for
financial purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 645
Lease impairments deducted for tax purposes less than amounts
recorded for financial purposes . . . . . . . . . . . . . . . . . . . . . . . . (625)
Depletion, depreciation and amortization deducted for tax purposes
less than amounts recorded for financial purposes . . . . . . . . . . . . . . . (1,842)
Other losses recognized for financial purposes prior to recognition
for tax purposes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,380
Loss on disposal of assets for tax purposes in excess of
amounts recognized for financial purposes . . . . . . . . . . . . . . . . . . . (550)
Income tax benefit not utilized . . . . . . . . . . . . . . . . . . . . . . . . . . 1,342
Other, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (350)
---------
$ -
=========
</TABLE>
(8) EMPLOYEES' PENSION AND RETIREMENT BENEFITS
Pension Plan
The Company sponsors a defined benefit pension plan which covers
substantially all U.S. employees. The plan provides benefits based on the
employee's years of service and compensation during the years immediately
preceding retirement. The Company makes annual contributions to the plan to
comply with the minimum funding provisions of the Employee Retirement Income
Security Act. The plan investments consist primarily of common equities and
fixed income securities.
49
<PAGE> 53
The following tables detail (i) the components of pension income and
expenses, (ii) the funded status of the plan and amounts recognized in the
Company's consolidated balance sheets and (iii) major assumptions used to
determine these projected benefit obligations (amounts stated in thousands).
<TABLE>
<CAPTION>
1994 1993 1992
----------- ----------- -----------
<S> <C> <C> <C>
Components of pension income (expense):
Service cost . . . . . . . . . . . . . . . . . . . . . . . . . $ (492) $ (524) $ (338)
Interest cost . . . . . . . . . . . . . . . . . . . . . . . . . (348) (311) (309)
Actual return (loss) on plan assets . . . . . . . . . . . . . . (306) 430 413
Net amortization and deferral . . . . . . . . . . . . . . . . . 577 (168) (168)
----------- ----------- -----------
Net pension cost . . . . . . . . . . . . . . . . . $ (569) $ (573) $ (402)
=========== =========== ===========
Actuarial present value of benefit obligations:
Accumulated benefit obligations
Vested . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,952 $ 3,877 $ 3,329
Nonvested . . . . . . . . . . . . . . . . . . . . . . . . 361 430 188
----------- ----------- -----------
Total . . . . . . . . . . . . . . . . . . . . . . . $ 4,313 $ 4,307 $ 3,517
=========== =========== ===========
Projected benefit obligations for service rendered
to date . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,229 $ 5,129 $ 4,258
Plan assets at fair value . . . . . . . . . . . . . . . . . . . . . . 3,733 3,952 3,497
----------- ----------- -----------
Projected benefit obligations in excess of plan
assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,496 1,177 761
Unrecognized net transition obligation at January 1,
1986, recognized over 15 years . . . . . . . . . . . . . . . . . (66) (76) (88)
Unrecognized prior service cost at January 1, 1989,
recognized over 9 years . . . . . . . . . . . . . . . . . . . . . (180) (189) (198)
Unrecognized net loss . . . . . . . . . . . . . . . . . . . . . . . . (670) (377) (106)
----------- ----------- -----------
Accrued pension liability . . . . . . . . . . . . . . . . . . . . $ 580 $ 535 $ 369
=========== =========== ===========
Assumptions:
Discount rate . . . . . . . . . . . . . . . . . . . . . . . . . . 7.5% 7.0% 8.0%
Rate of increase in compensation levels . . . . . . . . . . . . . 5.0% 5.0% 5.0%
Expected long-term rate of return on plan assets . . . . . . . . 7.0% 8.0% 8.0%
</TABLE>
Employee Savings Plan
On October 1, 1993, the Company adopted the Employees 401(k) Savings
Plan ("ESP"), a defined contribution plan, which covers substantially all U.S.
employees. The Company matches a portion of the employees' contributions with
treasury shares of the Company's common stock. The Company recorded expense of
approximately $104,000 and $35,000 relating to its contributions to the ESP
during 1994 and 1993, respectively.
(9) COMMITMENTS AND CONTINGENCIES
Commitments
In the normal course of business, the Company undertakes commitments
for purchases of leases and delay rentals under oil, gas and mineral leases,
all of which are not expected to be material.
The Company leases office space and pipeline equipment under operating
leases that expire over the next several years. Minimum annual rental payments
stated in thousands for each of the next four years are:
<TABLE>
<S> <C>
1995 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 344
1996 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 344
1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 344
1998 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
------------
$ 1,061
============
</TABLE>
50
<PAGE> 54
During 1994, 1993 and 1992, the Company's rent expense was $321,000,
$362,000 and $433,000, respectively.
Contingencies
The Company has pending litigation incidental to its operations.
Management believes none of the litigation is expected to have a
material adverse effect on the Company's financial position or the results of
operations.
(10) MAJOR BUSINESS SEGMENTS AND MAJOR CUSTOMERS
The Company operates in two industry segments, oil and gas exploration,
development and production and the transportation of natural gas and crude oil.
Oil and gas production is marketed with numerous purchasers under long-term,
short-term and spot-market contracts. In 1994, 1993 and 1992, sales to El Paso
Natural Gas Company represented 9%, 13% and 14% of the Company's consolidated
oil and gas revenues, respectively. Beginning January 1, 1994, the Company
entered into a long-term contract with Midcon Texas Pipeline ("Midcon") for gas
sales from the Taylor Lake field. During 1994, 13% of the Company's
consolidated oil and gas revenues were attributable to sales to Midcon.
The pipeline segment's customers are primarily located in the
Southwest and Midwest states. During 1994, the pipeline segment's sales
were concentrated with six customers accounting for 69% of its total sales.
Financial information by segment is stated in thousands and summarized
as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Revenues:
Oil and gas operations (1) . . . . . . . . . $ 44,934 $ 36,474 $ 33,631
Pipeline operations . . . . . . . . . . . . 20,664 43,415 25,721
Intersegment eliminations . . . . . . . . . . (2,655) (4,805) (1,846)
---------- ---------- ----------
Total revenues . . . . . . . . . . . . . . $ 62,943 $ 75,084 $ 57,506
========== ========== ==========
Income (loss) before income tax expense:
Oil and gas operations (1) . . . . . . . . . $ (2,012) $ 10,486 $ 5,636
Pipeline operations . . . . . . . . . . . . (299) (642) (333)
Corporate . . . . . . . . . . . . . . . . . . 714 1,175 (1,677)
---------- ---------- ----------
Total income (loss) before income tax
expense . . . . . . . . . . . . . . . . . $ (1,597) $ 11,019 $ 3,626
========== ========== ==========
Depletion, depreciation and amortization:
Oil and gas operations . . . . . . . . . . . $ 7,744 $ 6,591 $ 7,717
Pipeline operations . . . . . . . . . . . . . 1,229 1,184 2,120
Corporate . . . . . . . . . . . . . . . . . . 864 601 410
---------- ---------- ----------
Total depletion, depreciation and
amoritzation . . . . . . . . . . . . . . $ 9,837 $ 8,376 $ 10,247
========== ========== ==========
Capital expenditures:
Oil and gas operations . . . . . . . . . . . $ 50,381 $ 23,121 $ 6,410
Pipeline operations . . . . . . . . . . . . . 477 1,191 1,201
Corporate . . . . . . . . . . . . . . . . . . 1,443 1,540 262
---------- ---------- ----------
Total capital expenditures . . . . . . . . $ 52,301 $ 25,852 $ 7,873
========== ========== ==========
Identifiable assets:
Oil and gas operations . . . . . . . . . . . $ 96,398 $ 68,752 $ 62,402
Pipeline operations . . . . . . . . . . . . 18,303 24,146 20,667
Corporate . . . . . . . . . . . . . . . . . 39,799 69,033 48,442
---------- ---------- ----------
Total identifiable assets . . . . . . . . $ 154,500 $ 161,931 $ 131,511
========== ========== ==========
</TABLE>
- ---------------
(1) See Note 1 for discussion of the 1994 change in method of accounting
for natural gas revenues.
51
<PAGE> 55
Financial information by geographic area is stated in thousands and
summarized as follows:
<TABLE>
<CAPTION>
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Revenues
United States . . . . . . . . . . . . . $ 39,028 $ 58,667 $ 43,066
Indonesia . . . . . . . . . . . . . . . 11,738 11,349 11,687
Russia . . . . . . . . . . . . . . . . 12,171 4,602 2,182
Other International (1) . . . . . . . . 6 466 571
---------- ---------- ----------
Total . . . . . . . . . . . . . . . $ 62,943 $ 75,084 $ 57,506
========== ========== ==========
Income (loss) before income tax expense
United States . . . . . . . . . . . . . $ (7,450) $ 4,857 $ (5,132)
Indonesia . . . . . . . . . . . . . . . 11,600 11,218 11,556
Russia . . . . . . . . . . . . . . . . (1,475) (2,457) (784)
Other International (1) . . . . . . . . (4,272) (2,599) (2,014)
---------- ---------- ----------
Total . . . . . . . . . . . . . . . $ (1,597) $ 11,019 $ 3,626
========== ========== ==========
Identifiable assets
United States . . . . . . . . . . . . . $ 115,678 $ 140,933 $ 115,227
Indonesia . . . . . . . . . . . . . . . 4,535 5,636 5,842
Russia . . . . . . . . . . . . . . . . 19,228 10,011 6,969
Other International (1) . . . . . . . . 15,059 5,351 3,473
---------- ---------- ----------
Total . . . . . . . . . . . . . . . $ 154,500 $ 161,931 $ 131,511
========== ========== ==========
</TABLE>
- ------------------
(1) Other International includes Turkey, Malaysia, Ivory Coast, Egypt,
Argentina and Canada. During 1993, the Company sold its Argentinean and
Canadian properties.
(11) RELATED PARTY TRANSACTIONS
In 1990, the Company issued 1,100,000 shares of common stock from its
treasury to Noel in exchange for Noel's 10% subordinated convertible debenture
in the principal amount of $6.6 million (the "Noel Debenture"). On December
31, 1990, the Noel Debenture was surrendered to Noel in exchange for 789,946
shares of Noel common stock, such number of shares having been determined by a
formula based upon the net value of Noel's assets. Noel conducts its principal
operations through small and medium sized operating companies in which Noel
holds controlling or other significant equity interests. Two members of Noel's
Board of Directors currently serve on the Company's Board of Directors.
On September 21, 1992, Noel distributed shares of certain companies
owned by Noel to Noel shareholders. The Company received 46,468 shares
of Garnet, 53,907 shares of VISX Incorporated ("VISX") and 203,098 shares of the
Company's stock as a result of the distribution. During February 1993, the
Company disposed of its entire investment in VISX for an average net sales
proceeds of $11.76 per share. The distribution by Noel of shares of common
stock of the Company reduced Noel's ownership of the Company from approximately
25% to approximately 3%.
On November 29, 1993, Noel distributed shares of Sylvan Foods
Holdings, Inc. ("Sylvan") owned by Noel to Noel shareholders. The
Company received 54,860 shares of Sylvan as the result of the distribution.
During December 1993, the Company disposed of 25,000 shares of Sylvan stock for
an average net sales proceeds of $8.37 per share. During January 1994, the
Company disposed of its remaining investment in Sylvan for an average net sales
proceeds of $7.89 per share.
On December 22, 1993, the Company sold 710,000 shares of Noel common
stock for an average net sales proceeds of $6.625 per share. On January
10, 1994, the Company sold its remaining 79,946 shares of Noel common stock for
an average net sales proceeds of $7.00 per share.
See Note 5 for discussion of additional related party transactions.
52
<PAGE> 56
GLOBAL NATURAL RESOURCES INC.
SUPPLEMENTARY TABLES ON RESERVE DATA AND OIL AND GAS OPERATIONS (AS RESTATED)
(UNAUDITED)
<TABLE>
<CAPTION>
Page
----
<S> <C>
Results of Operations for Producing Activities and Costs Incurred in Oil and
Gas Property Acquisition, Exploration and Development Activities for the
three years ended December 31, 1994 and Capitalized Costs Relating to Oil
and Gas Producing Activities at December 31, 1994, 1993 and 1992
Table 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 54
Reserve Quantity Information for the three years ended December 31, 1994
Table 2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57
Standardized Measure of Discounted Future Net Cash Flows Related to Proved
Oil and Gas Reserves for the three years ended December 31, 1994
Table 3 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 59
Notes to Supplementary Tables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 60
</TABLE>
53
<PAGE> 57
TABLE 1
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
RESULTS OF OPERATIONS FOR PRODUCING ACTIVITIES AND COSTS INCURRED IN OIL AND
GAS PROPERTY ACQUISITION EXPLORATION AND DEVELOPMENT ACTIVITIES FOR THE
THREE YEARS ENDED DECEMBER 31, 1994 AND CAPITALIZED COSTS RELATING TO OIL
AND GAS PRODUCING ACTIVITIES AT DECEMBER 31, 1994, 1993 AND 1992
(AMOUNTS IN THOUSANDS) (UNAUDITED)
The following table reflects activity relating to oil and gas
producing activities by geographic area.
<TABLE>
<CAPTION>
UNITED STATES RUSSIA INDONESIA OTHER(1) TOTAL
------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1994
Net Revenues from production:
Sales of oil and gas to non-affiliates. . $ 20,119 $ 11,955 $ 11,738 $ 2 $ 43,814
Production (lifting costs)(2). . . . . . . 3,368 7,835 - - 11,203
Depletion, depreciation and amortization . 6,559 1,054 131 - 7,744
Exploration expense. . . . . . . . . . . . 17,710 496 - 1,119 19,325
Income tax expense . . . . . . . . . . . . 24 55 6,577 - 6,656
----------- ----------- ----------- ----------- -----------
Results of activities . . . . . . . . . . $ (7,542) $ 2,515 $ 5,030 $ (1,117) $ (1,114)
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1993
Net Revenues from production:
Sales of oil and gas to non-affiliates. . $ 19,272 $ 4,602 $ 11,349 $ 470 $ 35,693
Production (lifting costs)(2). . . . . . . 3,730 3,962 - 443 8,135
Depletion, depreciation and amortization . 5,888 260 131 312 6,591
Exploration expense . . . . . . . . . . . 5,580 124 - 1,242 6,946
Income tax expense . . . . . . . . . . . . 177 37 6,320 (2) 6,532
----------- ----------- ----------- ----------- -----------
Results of activities . . . . . . . . . . $ 3,897 $ 219 $ 4,898 $ (1,525) $ 7,489
=========== =========== =========== =========== ===========
YEAR ENDED DECEMBER 31, 1992
Net Revenues from production:
Sales of oil and gas to non-affiliates. . $ 18,962 $ 2,182 $ 11,687 $ 571 $ 33,402
Production (lifting costs)(2) . . . . . . 5,115 1,484 - 571 7,170
Depletion, depreciation and amortization . 6,900 119 131 567 7,717
Exploration expense . . . . . . . . . . . 6,286 - - 236 6,522
Income tax expense . . . . . . . . . . . . - - 6,474 (2) 6,472
----------- ----------- ----------- ----------- -----------
Results of activities . . . . . . . . . . $ 661 $ 579 $ 5,082 $ (801) $ 5,521
=========== =========== =========== =========== ===========
</TABLE>
- ----------------
(1) Other includes Malaysia, Egypt, Ivory Coast, Turkey, Argentina and
Canada. During 1993, the Company sold its Argentinean and Canadian
properties.
(2) Included in Russian production expenses are export tax expenses of $4.1
million, $1.7 million and $0.4 million during 1994, 1993 and 1992,
respectively.
See accompanying notes to supplementary tables.
54
<PAGE> 58
TABLE 1 CONTINUED.
The following table reflects activity relating to costs incurred
in oil and gas property acquisition, exploration and development
activities by geographic area.
<TABLE>
<CAPTION>
UNITED STATES RUSSIA EGYPT IVORY COAST OTHER(1) TOTAL
------------- ---------- ---------- ------------ ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
YEAR ENDED DECEMBER 31, 1994
Property acquisition costs:
Proved . . . . . . . . . . . . . . $ 3,790 $ - $ - $ - $ - $ 3,790
Unproved . . . . . . . . . . . . . 2,440 - 885 - - 3,325
Exploration costs . . . . . . . . . . 25,876 496 2,022 3,032 602 32,028
Development costs . . . . . . . . . . 8,773 5,527 - 2,624 - 16,924
---------- ---------- ---------- ----------- ---------- ----------
Total . . . . . . . . . . . . . . . $ 40,879 $ 6,023 $ 2,907 $ 5,656 $ 602 $ 56,067
========== ========== ========== =========== ========== ==========
YEAR ENDED DECEMBER 31, 1993
Property acquisition costs:
Proved . . . . . . . . . . . . . $ - $ - $ - $ - $ - $ -
Unproved . . . . . . . . . . . . 3,334 - - 9 21 3,364
Exploration costs . . . . . . . . . 12,971 124 - 4,001 917 18,013
Development costs . . . . . . . . . 1,027 3,007 - 41 (10) 4,065
---------- ---------- ---------- ----------- ---------- ----------
Total . . . . . . . . . . . . . . $ 17,332 $ 3,131 $ - $ 4,051 $ 928 $ 25,442
========== ========== ========== =========== ========== ==========
YEAR ENDED DECEMBER 31, 1992
Property acquisition costs:
Proved . . . . . . . . . . . . . $ 15 $ - $ - $ - $ - $ 15
Unproved . . . . . . . . . . . . 273 - - - 507 780
Exploration costs . . . . . . . . . 4,546 - - - 1,500 6,046
Development costs . . . . . . . . . 902 773 - - 383 2,058
---------- ---------- ---------- ----------- ---------- ----------
Total . . . . . . . . . . . . . . $ 5,736 $ 773 $ - $ - $ 2,390 $ 8,899
========== ========== ========== =========== ========== ==========
</TABLE>
- --------------
(1) Other includes Malaysia, Turkey, Argentina and Canada. During 1993, the
Company sold its Argentinean and Canadian properties.
See accompanying notes to supplementary tables.
55
<PAGE> 59
TABLE 1 CONTINUED.
The following table reflects the capitalized costs relating to oil and
gas producing activities by geographic area.
<TABLE>
<CAPTION>
UNITED STATES RUSSIA INDONESIA EGYPT IVORY COAST OTHER(1) TOTAL
------------- --------- --------- --------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
AT DECEMBER 31, 1994
Capitalized cost:
Unproved . . . . . . . . . . . $ 3,350 $ - $ - $ 885 $ 9 $ 386 $ 4,630
Producing . . . . . . . . . . 89,666 9,753 3,962 1,877 8,798 916 114,972
Accumulated depletion and
depreciation . . . . . . . . . (45,727) (1,423) (2,648) - - - (49,798)
--------- --------- --------- --------- --------- --------- ---------
Net Capitalized Costs . . . . . . $ 47,289 $ 8,330 $ 1,314 $ 2,762 $ 8,807 $ 1,302 $ 69,804
========= ========= ========= ========= ========= ========= =========
AT DECEMBER 31, 1993
Capitalized cost:
Unproved . . . . . . . . . . . $ 6,064 $ - $ - $ - $ 9 $ 389 $ 6,462
Producing . . . . . . . . . . 76,828 4,332 3,962 - 3,784 - 88,906
Accumulated depletion and
depreciation . . . . . . . . . (44,832) (387) (2,516) - - - (47,735)
--------- --------- --------- --------- --------- --------- ---------
Net Capitalized Costs . . . . . . $ 38,060 $ 3,945 $ 1,446 $ - $ 3,793 $ 389 $ 47,633
========= ========= ========= ========= ========= ========= =========
AT DECEMBER 31, 1992
Capitalized cost:
Unproved . . . . . . . . . . . $ 5,659 $ - $ - $ - $ - $ 1,317 $ 6,976
Producing . . . . . . . . . . 79,559 1,325 3,962 - - 2,864 87,710
Accumulated depletion and
depreciation . . . . . . . . . (52,589) (127) (2,385) - - (1,047) (56,148)
--------- --------- --------- --------- --------- --------- ---------
Net Capitalized Costs . . . . . . $ 32,629 $ 1,198 $ 1,577 $ - $ - $ 3,134 $ 38,538
========= ========= ========= ========= ========= ========= =========
</TABLE>
- -----------------
(1) Other includes Malaysia, Turkey, Argentina and Canada. During 1993, the
Company sold its Argentinean and Canadian properties.
See accompanying notes to supplementary tables.
56
<PAGE> 60
TABLE 2
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
RESERVE QUANTITY INFORMATION
NATURAL GAS (MMCF)
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(UNAUDITED)
<TABLE>
<CAPTION>
UNITED STATES INDONESIA(1) IVORY COAST OTHER(2) TOTAL
------------- ------------ ----------- ---------- ----------
<S> <C> <C> <C> <C> <C>
PROVED RESERVES:
January 1, 1992 . . . . . . . . . . . . . 54,435 74,971 - 223 129,629
Revisions of previous estimates . . . (6,068) 4,777 - 56 (1,235)
Extensions, discoveries and
other additions . . . . . . . . . 287 - - - 287
Sales of reserves-in-place . . . . . (175) - - - (175)
Production . . . . . . . . . . . . . (6,385) (3,667) - (40) (10,092)
---------- ---------- ---------- ---------- ----------
December 31, 1992 . . . . . . . . . . . . 42,094 76,081 - 239 118,414
Revisions of previous estimates . . . 6,651 7,394 - - 14,045
Extensions, discoveries and
other additions . . . . . . . . . 22,920 - - - 22,920
Sales of reserves-in-place . . . . . (665) - - (170) (835)
Production . . . . . . . . . . . . . (7,019) (3,769) - (69) (10,857)
---------- ---------- ---------- ---------- ----------
December 31, 1993 . . . . . . . . . . . . 63,981 79,706 - - 143,687
Revisions of previous estimates . . . 1,270 4,757 - - 6,027
Extensions, discoveries and
other additions . . . . . . . . . 9,875 - 18,432 - 28,307
Purchases of reserves-in-place . . . 2,079 - - - 2,079
Sales of reserves-in-place . . . . . (8,803) - - - (8,803)
Production . . . . . . . . . . . . . (8,904) (4,473) - - (13,377)
---------- ---------- ---------- ---------- ----------
December 31, 1994 . . . . . . . . . . . . 59,498 79,990 18,432 - 157,920
========== ========== ========== ========== ==========
PROVED DEVELOPED RESERVES:
December 31, 1992 . . . . . . . . . . 31,077 54,362 - 239 85,678
December 31, 1993 . . . . . . . . . . 42,204 53,931 - - 96,135
December 31, 1994 . . . . . . . . . . 48,946 65,021 - - 113,967
</TABLE>
- --------------
(1) All Indonesia Mmcf amounts appearing in this table are for dry gas.
(2) Other includes Argentina and Canada which were sold during 1993.
See accompanying notes to supplementary tables.
57
<PAGE> 61
TABLE 2 CONTINUED.
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
RESERVE QUANTITY INFORMATION
OIL/CONDENSATE (MBBL)
FOR THE THREE YEARS ENDED DECEMBER 31, 1994
(UNAUDITED)
<TABLE>
<CAPTION>
UNITED STATES INDONESIA RUSSIA EGYPT IVORY COAST OTHER(1) TOTAL
------------- --------- --------- --------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
PROVED:
January 1, 1992 . . . . . . . . . . . . . 1,402 827 - - - 160 2,389
Revisions of previous estimates . . . (140) 57 - - - 17 (66)
Extensions, discoveries and
other additions . . . . . . . . . 90 - 5,010 - - - 5,100
Sales of reserves-in-place . . . . . (87) - - - - - (87)
Production . . . . . . . . . . . . . (326) (47) (128) - - (29) (530)
--------- --------- --------- --------- --------- --------- ---------
December 31, 1992(2) . . . . . . . . . . 939 837 4,882 - - 148 6,806
Revisions of previous estimates . . . 161 222 142 - - - 525
Extensions, discoveries and
other additions . . . . . . . . . 666 - 2,596 - - - 3,262
Sales of reserves-in-place . . . . . (48) - - - - (125) (173)
Production . . . . . . . . . . . . . (259) (54) (323) - - (23) (659)
--------- --------- --------- --------- --------- --------- ---------
December 31, 1993(2) . . . . . . . . . . 1,459 1,005 7,297 - - - 9,761
Revisions of previous estimates . . . 232 108 2,109 - - - 2,449
Extensions, discoveries and
other additions . . . . . . . . . 792 - 4,593 3,520 2,210 - 11,115
Purchase of reserves-in-place . . . . 15 - - - - - 15
Sales of reserves-in-place . . . . . (96) - - - - - (96)
Production . . . . . . . . . . . . . (229) (47) (842) - - - (1,118)
--------- --------- --------- --------- --------- --------- ---------
December 31, 1994(2) . . . . . . . . . . 2,173 1,066 13,157 3,520 2,210 - 22,126
========= ========= ========= ========= ========= ========= =========
PROVED DEVELOPED RESERVES:
December 31, 1992 . . . . . . . . . . 800 566 4,882 - - 92 6,340
December 31, 1993 . . . . . . . . . . 859 762 7,297 - - - 8,918
December 31, 1994 . . . . . . . . . . 1,085 870 8,866 - - - 10,821
</TABLE>
- -------------
(1) Other includes Argentina and Canada which were sold during 1993.
(2) Includes reserves of 1,316 MBbl, 1,459 MBbl and 976 MBbl in
1994, 1993 and 1992 respectively, attributable to a minority
interest in a consolidated subsidiary which was 10% in 1994 and
20% during 1993 and 1992.
See accompanying notes to supplementary tables.
58
<PAGE> 62
TABLE 3
GLOBAL NATURAL RESOURCES INC. AND SUBSIDIARIES
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS
RELATED TO PROVED OIL AND GAS RESERVES FOR THE THREE YEARS ENDED
DECEMBER 31, 1994
(AMOUNTS IN THOUSANDS) (UNAUDITED)
<TABLE>
<CAPTION>
UNITED
STATES INDONESIA RUSSIA EGYPT IVORY COAST OTHER(1) TOTAL
--------- --------- --------- -------- ----------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
DECEMBER 31, 1994
Future cash flows . . . . . . . . . . $124,471 $175,855 $189,592 $ 55,378 $ 66,448 $ - $611,744
Future production and
development costs . . . . . . . . 39,075 44,017 111,602 29,128 37,595 - 261,417
Future income taxes . . . . . . . . . 2,076 64,823 23,619 9,497 8,974 - 108,989
--------- --------- --------- --------- --------- --------- ---------
Future net cash flows . . . . . . . . 83,320 67,015 54,371 16,753 19,879 - 241,338
10% annual discount for estimated
timing of cash flows . . . . . . . 23,330 32,792 23,562 8,601 10,438 - 98,723
--------- --------- --------- --------- --------- --------- ---------
Standardized measure of
discounted future net cash
flows relating to oil
and gas reserves(2) . . . . . . . . $ 59,990 $ 34,223 $ 30,809 $ 8,152 $ 9,441 $ - $142,615
========= ========= ========= ========= ========= ========= =========
DECEMBER 31, 1993
Future cash flows . . . . . . . . . . $160,935 $154,573 $ 83,552 $ - $ - $ - $399,060
Future production and
development costs . . . . . . . . 52,516 43,673 48,756 - - - 144,945
Future income taxes . . . . . . . . . 7,705 54,915 9,771 - - - 72,391
--------- --------- --------- --------- --------- --------- ---------
Future net cash flows . . . . . . . . 100,714 55,985 25,025 - - - 181,724
10% annual discount for estimated
timing of cash flows . . . . . . . 32,487 27,835 12,200 - - - 72,522
--------- --------- --------- --------- --------- --------- ---------
Standardized measure of
discounted future net cash flows
relating to oil and gas
reserves(2) . . . . . . . . . . . . $ 68,227 $ 28,150 $ 12,825 $ - $ - $ - $ 109,202
========= ========= ========= ========= ========= ========= =========
DECEMBER 31, 1992
Future cash flows . . . . . . . . . . $ 97,162 $194,771 $ 79,774 $ - $ - $ 2,809 $374,516
Future production and
development costs . . . . . . . . 28,678 42,479 38,583 - - 814 110,554
Future income taxes . . . . . . . . . - 76,913 12,228 - - - 89,141
--------- --------- --------- --------- --------- --------- ---------
Future net cash flows . . . . . . . . 68,484 75,379 28,963 - - 1,995 174,821
10% annual discount for estimated
timing of cash flows . . . . . . . 26,509 36,772 16,743 - - 842 80,866
--------- --------- --------- --------- --------- --------- ---------
Standardized measure of
discounted future net cash flows
relating to oil and gas
reserves(2) . . . . . . . . . . . . $ 41,975 $ 38,607 $ 12,220 $ - $ - $ 1,153 $ 93,955
========= ========= ========= ========= ========= ========= =========
</TABLE>
- --------------
(1) Other includes Argentina and Canada which were sold during 1993.
(2) Includes $3.1 million, $2.6 million and $2.4 million in 1994, 1993
and 1992, respectively, attributed to a minority interest in a
consolidated subsidiary which was 10% in 1994 and 20% during 1993
and 1992.
See accompanying notes to supplementary tables.
59
<PAGE> 63
TABLE 3 CONTINUED.
The following table shows changes in the Standardized Measure of
Discounted Future Net Cash Flows for the three years ended December 31, 1994.
<TABLE>
<CAPTION>
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Beginning of year . . . . . . . . . . . . . . . . . $109,202 $93,955 $97,075
Changes resulting from:
Sales and transfers of oil and gas produced, net
of production costs . . . . . . . . . . . . . (32,612) (27,558) (26,232)
Net changes in prices and production costs . . . . (17,822) (45,242) (5,810)
Extensions, discoveries, additions and improved
recovery, less related costs . . . . . . . . . 49,847 33,610 18,663
Change in development cost during the period . . . (1,444) 3,308 3,949
Revisions of previous quantity estimates . . . . . 15,534 16,306 (854)
Purchase and sales of minerals-in-place, net . . . (9,115) (1,763) (685)
Accretion of discount . . . . . . . . . . . . . . . 14,407 12,944 13,192
Net changes in income taxes . . . . . . . . . . . . (20,731) 7,955 (653)
Changes in production, timing and other . . . . . . 35,349 15,687 (4,690)
-------- -------- -------
End of year . . . . . . . . . . . . . . . . . . . . $142,615 $109,202 $93,955
======== ======== =======
</TABLE>
Notes to Supplementary Tables
The estimates of proved reserves are inherently imprecise and are
continually subject to revision based on production history, results of
additional exploration and development and other factors.
At December 31, 1994, 1993 and 1992, the Company's gross oil and gas reserve
estimates for properties located in the United States, Russia and Argentina
were prepared by Ryder Scott Company Petroleum Engineers. At December 31,
1994, Ivory Coast and Egypt gross oil and gas reserve estimates were prepared
by Netherland, Sewell & Associates, Inc. At December 31, 1992, Canadian gross
oil and gas reserve estimates were reviewed by Coles Gilbert Associates, Ltd.
Indonesian reserves are based on information obtained by the Company from
public sources.
Income tax expense (benefit) in Table 1 for United States and Canada is
alternative minimum tax. There are no other income taxes for this geographic
area because of net operating loss carry forwards (see Note 6 to consolidated
financial statements). The income tax expense in Table 1 for Indonesia
reflects actual taxes paid in Indonesia.
60
<PAGE> 64
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1994. The information
required by this item with respect to officers and directors will appear in
such definitive Proxy Statement and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION.
The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1994. The information
required by this item with respect to executive compensation will appear in
such definitive Proxy Statement and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1994. The information
required by this item with respect to security ownership will appear in such
definitive Proxy Statement and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The Company will file with the Securities and Exchange Commission pursuant
to Regulation 14A a definitive Proxy Statement involving the election of
directors not later than 120 days after December 31, 1994. The information
required by this item with respect to certain relationships and related
transactions will appear in such definitive Proxy Statement and is incorporated
herein by reference.
61
<PAGE> 65
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
<TABLE>
<S> <C> <C>
(a)(1) Financial Statements listed below are included as Part II, Item 8 hereof:
Consolidated Financial Statements Page
----
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35
Consolidated Balance Sheets at December 31, 1994 and 1993 . . . . . . . . . . . . . . . . . . . . 36
Consolidated Statements of Operations for the three years ended December 31, 1994 . . . . . . . . . 37
Consolidated Statements of Shareholders' Equity for the three years ended December 31, 1994 . . . 38
Consolidated Statements of Cash Flows for the three years ended December 31, 1994 . . . . . . . . 39
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 41
Supplementary Tables on Reserve Data and Oil and Gas Operations . . . . . . . . . . . . . . . . . . . . 53
(a)(2) Financial Statement Schedules
None
(a)(3) Exhibits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64
(b) Reports on Form 8-K for the quarter ended December 31, 1994
None
</TABLE>
62
<PAGE> 66
SIGNATURES
PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
<TABLE>
<S> <C>
GLOBAL NATURAL RESOURCES INC.
Date: May 12, 1995
/s/ ROBERT F. VAGT
---------------------------------------------
Robert F. Vagt
Chairman of the Board
President and Chief Executive Officer
Date: May 12, 1995
/s/ ERIC LYNN HILL
---------------------------------------------
Eric Lynn Hill
Senior Vice President, Finance and Administration
(Principal Financial and Accounting Officer)
</TABLE>
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 INDICATED AS OF MAY 9, 1995.
<TABLE>
<S> <C>
Director
---------------------------------------------------
William L. Bennett
/s/ JOHN A. BROCK * Director
---------------------------------------------------
John A. Brock
/s/ PAUL E. CARLTON * Director
---------------------------------------------------
Paul E. Carlton
/s/ J. CHARLES HOLLIMON * Director
---------------------------------------------------
J. Charles Hollimon
/s/ PATRICK L. MACDOUGALL * Director
---------------------------------------------------
Patrick L. Macdougall
Director
---------------------------------------------------
James G. Niven
/s/ SIDNEY R. PETERSEN * Director
---------------------------------------------------
Sidney R. Petersen
Director
---------------------------------------------------
Linda F. Sjoman
/s/ ROBERT F. VAGT Chairman of the Board
---------------------------------------------------
Robert F. Vagt
</TABLE>
*Signed via Power of Attorney
63
<PAGE> 67
(a)3. Exhibits:
The following documents are included as Exhibits to this report. Those
Exhibits listed below as "incorporated herein by reference" are indicated as
such by the information supplied in the parenthetical thereafter. If no
parenthetical appears after an Exhibit in the list, copies of the document have
been filed with this Report.
3.1 Restated Certificate of Incorporation of the Company dated May
10, 1983. (Incorporated herein by reference to Exhibit 3.1 to
the Company's Form 10-k for the year ended December 31, 1992.)
3.2 Amendment to Restated Certificate of Incorporation of the Company
dated July 31, 1987. (Incorporated herein by reference to
Exhibit 3.2 to the Company's Form 10-k for the year ended
December 31, 1992.)
3.3 Amendment to Restated Certificate of Incorporation of the Company
dated August 20, 1987. (Incorporated herein by reference to
Exhibit 3.3 to the Company's Form 10-k for the year ended
December 31, 1992.)
3.4 Correction to Amendment to Restated Certificate of Incorporation
of the Company dated September 9, 1988. (Incorporated herein by
reference to Exhibit 3.4 to the Company's Form 10-k for the year
ended December 31, 1992.)
3.5 Amendment to Restated Certificate of Incorporation of the Company
dated October 5, 1988. (Incorporated herein by reference to
Exhibit 3.5 to the Company's Form 10-k for the year ended
December 31, 1992.)
3.6 Amendment to Restated Certificate of Incorporation of the Company
dated October 17, 1990. (Incorporated herein by reference to
Exhibit 3.6 to the Company's Form 10-k for the year ended
December 31, 1992.)
3.7 Bylaws of the Company, as amended June 7, 1990. (Incorporated
herein by reference to Exhibit 3.7 to the Company's Form 10-k for
the year ended December 31, 1992.)
3.8 Amendment to Restated Certificate of Incorporation of the Company
dated May 26, 1993. (Incorporated hererin by reference to
Exhibit 3.8 to the Company's Form 10-K for the year ended
December 31, 1993.)
3.9 Bylaws of the Company, as amended May 25, 1993. (Incorporated
herein by reference to Exhibit 3.9 to the Company's Form 10-K for
the year ended December 31, 1993.)
4.1 Rights Agreement dated as of October 5, 1988 between Global
Natural Resources Inc. and Registrar and Transfer Company, which
includes the form of Certificate of Amendment of Restated
Certificate of Incorporation setting forth the terms of the
Series B Junior Preferred Stock, par value $1.00 per share, as
Exhibit A, the form of Right Certificate as Exhibit B and the
Summary of Rights to Purchase Preferred Shares as Exhibit C
incorporated by reference to Exhibit A to the Company's
Registration Statement on Form 8-A, dated October 11, 1988.
(Incorporated herein by reference to Exhibit A to the Form 10-Q
for the quarter ended September 30, 1988.)
4.2 First Amendment to Rights Agreement dated as of July 19, 1989
between Global Natural Resources Inc. and Registrar and Transfer
Company (Incorporated herein by reference to Exhibit 1.1 to Form
8 dated August 9, 1989.)
4.3 Second Amendment to Rights Agreement dated as of February 5, 1993
between Global Natural Resources Inc. and Registrar and Transfer
Company. (Incorporated herein by reference to Exhibit 7.2 to Form
8 dated February 16, 1993.)
64
<PAGE> 68
4.4 Amended and Restated Rights Agreement dated as of September 28,
1993 between Global Natural Resources Inc. and Registrar and
Transfer Company. (Incorporated herein by reference to Exhibit
1.1 to Form 8-k dated October 20, 1993.)
10.1 Joint Venture Agreement dated August 8, 1968, between Huffington,
Virginia International Company, Austral Petroleum Gas
Corporation, Golden Eagle Indonesia, Limited and Union Texas Far
East Corporation, as amended. (Incorporated herein by reference
to Exhibit 6.6 to Registration Statement No. 2-58834.)
10.2 Agreement dated as of October 1, 1979 among the parties to the
Joint Venture Agreement referred to in Exhibit 10.1 above.
(Incorporated herein by reference to Exhibit 5.2 to Registration
Statement No. 2-66661.)
10.3 Production Sharing Contract, dated August 8, 1968, between
Pertamina, Huffington, and Virginia International Company, as
amended. (Incorporated herein by reference to Exhibit 6.5 to
Registration Statement No. 2-58834.)
10.4 Amendment dated as of January 1, 1978, to Production Sharing
Contract referred to in Exhibit 10.3 above. (Incorporated herein
by reference to Exhibit 5.4 to Registration Statement No.
2-66661.)
10.5 LNG Sales Contract, dated November 3, 1973, between Pertamina,
The Chubu Electric Power Co., Inc., The Kansan Electric Power
Co., Inc., Kyushu Electric Power Co., Inc., Nippon Steel
Corporation and Osaka Gas Company, Ltd., as amended.
(Incorporated herein by reference to Exhibit 6.8 to Registration
Statement No. 2-58834.)
10.6 Form of Agreement for Sale of Additional Cargoes, draft of
November 19, 1979, between the parties to the LNG Sales Contract
referred to in Exhibit 10.5 above. (Incorporated herein by
reference to Exhibit 5.6 to Registration Statement No. 2-66661.)
10.7 Supply Agreement, dated as of December 3, 1974, between
Pertamina and the parties to the Joint Venture Agreement referred
to in Exhibit 10.1 above. (Incorporated herein by reference to
Exhibit 6.7 to Registration Statement No. 2-58834.)
10.8 Amendment, dated as of August 15, 1977, to Supply Agreement,
dated as of December 3, 1974, between Pertamina and the parties
to the Joint Venture Agreement referred to in Exhibit 10.1 above.
(Incorporated herein by reference to Exhibit 5.5.1 to
Registration Statement No. 2-64347.)
10.9 Form of Supply Agreement for Additional Sales of Liquefied
Natural Gas from Badak Liquefaction Facility, draft of November
16, 1979, between the parties to the Supply Agreement referred to
in Exhibit 10.7 above. (Incorporated herein by reference to
Exhibit 5.9 to Registration Statement No. 2-66661.)
10.10 Transportation Agreement dated as of September 23, 1973, between
Burmast East Shipping Corporation and Pertamina, as amended.
(Incorporated herein by reference to Exhibit 6.11 to Registration
Statement No. 2-58834.) May 1, 1995
10.11 Amendment No. 1 to Transportation Agreement referred to in
Exhibit 10.10 above, dated as of August 31, 1976, between Burmah
Gas Transport Limited and Pertamina. (Incorporated herein by
reference to Exhibit 5.11 to the Annual Report on Form 20-F for
the year ending December 31, 1979 (the "1979 20-F"), of the U.K.
Company.)
10.12 Badak LNG Sales Contract, dated April 14, 1981, between
Perusahaan Pertambangan Minyak Dan Gas Bumi Negara ("Pertamina")
as "Seller" and the Chubu Electric Power Co., Inc., The Kansan
Electric Power Co., Inc., Osaka Gas Company, Ltd., and Toho Gas
Company, Ltd. as "Buyers." (Incorporated herein by reference to
Exhibit (10)-23 to the Annual Report on Form 20-F for the year
ending December 31, 1981, of Virginia International Company.)
65
<PAGE> 69
10.13 Royalty Incentive Plan, as amended. (Incorporated herein by
reference to Exhibit 1.4 to the Annual Report on Form 20-F for
the year ending December 31, 1981 (the "1981 20-F"), of the U.K.
Company.)
10.14 Natural Resources Corporation Supplemental Retirement Plan, as
amended by the Board of Directors effective December 12, 1985.
(Incorporated herein by reference to Exhibit 10.17 to the 1985
10-K.)
10.15 Arctic Lands Farm Out Agreement made as of the 29th day of
November, 1983, between Global Natural Resources Canada Limited
and Thomson-Jensen Energy. (Incorporated herein by reference to
Exhibit 2 to Global's report on Form 8-K dated December 8, 1983.)
10.16 Global-TJE Agency Agreement made as of the 29th day of
November, 1983, between Global Natural Resources Canada Limited
and Thomson-Jensen Energy. (Incorporated herein by reference to
Exhibit 3 to Global's report on Form 8-K dated December 8, 1983.)
10.17 Settlement Agreement dated July 13, 1986 between Amoco Production
Company, Douglas Energy Company, Inc. and Global Natural
Resources Corporation. (Incorporated by reference to Exhibit
10.25 to the 1986 10-K.)
10.18 Farm Out Contract dated July 1, 1986 between Amoco Production
Company, Douglas Energy Company, Inc. and Global Natural
Resources Corporation. (Incorporated herein by reference to
Exhibit 10.26 to the 1986 10-K.)
10.19 Joint Exploration and Development Agreement dated November 5,
1986 between Barnes Hugoton Corporation and Global Natural
Resources Corporation. (Incorporated herein by reference to
Exhibit 10.27 to the 1986 10-K.)
10.20 Global/Smith Participation Agreement (with exhibit).
(Incorporated herein by reference to Exhibit 2 to the September
30, 1987 Form 10-Q.)
10.21 First Amendment to Claims Purchase Agreement. (Incorporated
herein by reference to Exhibit 3 to the September 30, 1987 Form
10-Q.)
10.22 San Pedro Ranch Venture Agreement (with exhibits) dated July 1,
1984 between Scicomp Inc., Galaxy Oil Company and SPR Energy
Corporation. (Incorporated herein by reference to Exhibits to the
December 31, 1987 Form 10-K.)
10.23 San Pedro Ranch Agreement (with exhibits) dated April 1, 1988
between Global Natural Resources Corporation of Nevada and Global
Nevada-Galaxy I, Ltd. (Incorporated herein by reference to
Exhibits to the December 31, 1987 Form 10-K.)
10.24 Trust Agreement (with exhibits) dated March 31, 1988 between
Galaxy Oil Company, Global Natural Resources Corporation of
Nevada and MTrust Corp., N.A. (Incorporated herein by reference
to Exhibits to the December 31, 1987 Form 10-K.)
10.25 Agreement of Limited Partnership (with exhibits) dated April 1,
1988 between Global Nevada-Galaxy I, Ltd. and the Partners.
(Incorporated herein by reference to Exhibits to the December 31,
1987 Form 10-K.)
10.27 Settlement Agreement between Global Natural Resources Corporation
of Nevada, Global Nevada-Galaxy, Inc., Global Nevada-Galaxy I,
Ltd., SPR Energy Corporation and Valero Transmission, L.P.
(Incorporated herein by reference to Exhibit 3 to the June 30,
1989 Form 10-Q.)
10.28 Indemnification Agreement and Agreement to Keep Registration
Statement Effective dated July 19, 1989 between Noel Group, Inc.
and Global Natural Resources Inc. (Incorporated herein by
reference to Exhibit 4.6 to Registration Statement No. 33-31536.)
66
<PAGE> 70
* 10.29 Global Natural Resources Inc. Key Employees Stock Option Plan.
(1989) (Incorporated herein by reference to Exhibit 4.1 to
Registration Statement No. 33-31537)
* 10.30 Form of Stock Option Agreement. (Incorporated herein by reference
to Exhibit 4.2 to Registration Statement No. 33-31537.)
10.31 Amendment to Agreement of Limited Partnership of Global
Nevada-Galaxy I, Ltd. (Incorporated herein by reference to
Exhibit 10.41 to the 1989 Form 10-K.)
10.32 Concession Purchase Agreement between Global Natural Resources
Corporation of Nevada and Chuska Energy Company. (Incorporated
herein by reference to Exhibit 10.43 to the 1989 Form 10-K.)
10.33 Stock Exchange Agreement by and between Noel Group, Inc. and
Global Natural Resources Inc. (Incorporated herein by reference
to Exhibit 2 to the September 30, 1990 Form 10-Q.)
10.34 USAgas Pipeline Company General Partnership Agreement.
(Incorporated herein by reference to Exhibit 1 to the September
30, 1990 Form 10-Q.)
10.35 San Pedro Ranch Purchase and Sale Agreement. (Incorporated
herein by reference to Exhibit 10.51 to the Company's Form 10-k
for the year ended December 31, 1991.)
10.36 Alabama Ferry Field Purchase and Sale Agreement. (Incorporated
herein by reference to Exhibit 10.52 to the Company's Form 10-k
for the year ended December 31, 1991.)
* 10.37 Global Natural Resources Inc. 1992 Stock Option Plan.
(Incorporated herein by reference to Exhibit 10.47 to the June
30, 1992 Form 10-Q)
* 10.38 Form of Stock Option Agreement. (Incorporated herein by reference
to Exhibit 10.48 to the June 30, 1992 Form 10-Q)
10.39 Assignment of Partnership Interests and Mutual Release Agreement.
(Incorporated herein by reference to Exhibit 10.50 to the
September 30, 1992 Form 10-Q)
10.40 Acquisition Agreement dated May 17, 1993 between UMIC Cote
D'Ivoire Corporation and G.N.R. (Cote D'Ivoire) Ltd. Ivory Coast
Production Sharing Contract - Block CI-11. (Incorporated herein
by reference to 10.40 to the Company's Form 10-K for the year
ended December 31, 1994.)
10.41 Farmout Agreement dated July 25, 1994 between GNR (Egypt) Ltd.
And Apache Oil Egypt, Inc. Qarun Concession Egypt.
(Incorporated herein by reference to 10.41 to the Company's Form
10-K for the year ended December 31, 1994.)
11.1 Computation of Per Share Earnings
18 Letter of KPMG Peat Marwick LLP Regarding a Change in Accounting
method. (Incorporated herein by reference to Exhibit 18 to the
Company's Form 10-Q for the quarter ended June 30, 1994.)
21.1 Subsidiaries of Global Natural Resources Inc.
23.1 Consent of KPMG Peat Marwick LLP.
23.2 Consent of Ryder Scott Company Petroleum Engineers
23.3 Consent of Netherland, Sewell & Associates, Inc.
67
<PAGE> 71
24.1 Powers of Attorney of certain directors of the Company.
27 Financial Data Schedule for the year ended December 31, 1994.
- ------------------
* Management contract or compensatory plan or arrangement required to be
filed as an exhibit to this Form 10-K pursuant to Item 14(c) of this
report.
68
<PAGE> 1
GLOBAL NATURAL RESOURCES INC. EXHIBIT 11.1
COMPUTATION OF PER SHARE EARNINGS PAGE 1 OF 1
(IN THOUSANDS EXCEPT SHARE AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------------------------------
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
Primary:
Net Income (loss): . . . . . . . . . . . . . ($8,253) $4,487 ($2,846)
========== ========== ==========
Weighted average common shares:
Outstanding . . . . . . . . . . . . . . . . 29,660,578 28,360,697 23,593,288
Assuming conversion of:
Stock options, net of treasury
shares(1) . . . . . . . . . . . . - - -
---------- ---------- ----------
Total: . . . . . . . . . . . . . . . . . . . 29,660,578 28,360,697 23,593,288
========== ========== ==========
Net Income (loss) per share: . . . . . . . . . . ($0.28) $0.16 ($0.12)
========== ========== ==========
Fully-diluted:
Net income (loss): . . . . . . . . . . . . . ($8,253) $4,487 ($2,846)
========== ========== ==========
Weighted average common shares:
Outstanding . . . . . . . . . . . . . . . . 29,660,578 28,360,697 23,593,288
Assuming conversion of:
Prudential's preferred stock into common
stock January 1, 1993 . . . . . . - 1,542,694 -
---------- ---------- ----------
Stock options, net of treasury
shares(1) . . . . . . . . . . . . - - -
---------- ---------- ----------
Total: . . . . . . . . . . . . . . . . . . . 29,660,578 29,903,391 23,593,288
========== ========== ==========
Net income (loss) per share: . . . . . . . . . . ($0.28) $0.15 ($0.12)
========== ========== ==========
</TABLE>
(1) The effect of the assumed exercise of stock options on the primary and
fully-diluted earnings per share calculations for the three periods ended
December 31, 1994, is not significant.
<PAGE> 1
EXHIBIT 21.1
GLOBAL NATURAL RESOURCES INC.
LIST OF SUBSIDIARIES
<TABLE>
<CAPTION>
JURISDICTION OF
NAME INCORPORATION
---- -------------
<S> <C>
Global Natural Resources Corporation of Nevada ("GNRC") Nevada, U.S.A.
GNR Investment Corporation Nevada, U.S.A.
GNR Eastern Russia
Global Noteholder Inc. (wholly - owned subsidiary of GNRC) Texas, U.S.A.
GNR International (Argentina), Inc. (wholly - owned subsidiary of GNRC) Texas, U.S.A.
GNR International (Turkey), Inc. (wholly - owned subsidiary of GNRC) Nevada, U.S.A.
Texneft Inc. (90% owned by GNRC) Texas, U.S.A.
Tatex (50% owned by Texneft Inc.) Russia
USAgas Pipeline Inc. (wholly - owned subsidiary of GNRC) Texas, U.S.A.
GNR (Cote d'Ivoire) Ltd. (wholly - owned subsidiary of GNRC) Grand Cayman,
Cayman Islands
GNR (Malaysia) Ltd. (wholly - owned subsidiary of GNRC) Grand Cayman,
Cayman Islands
GNR (Egypt) Ltd. (wholly - owned subsidiary of GNRC) Grand Cayman,
Cayman Islands
Unless otherwise stated, all subsidiaries are wholly - owned by the Company.
</TABLE>
<PAGE> 1
EXHIBIT 23.1
PAGE 1 OF 1
ACCOUNTANTS' CONSENT
The Board of Directors
Global Natural Resources Inc.:
We consent to the incorporation by reference in the Registration
Statements (No. 33-62106 on Form S-8 and No. 33-31537 on Form S-8)
of our report dated February 28, 1995, except as to notes 1, 2, 6, 7 and 10,
which are as of May 10, 1995, relating to the consolidated balance sheets of
Global Natural Resources Inc. and subsidiaries as of December 31, 1994 and 1993
and the related consolidated statements of operations, stockholders' equity and
cash flows for each of the years in the three-year period ended December 31,
1994, which report appears in December 31, 1994 annual report on Form 10-K/A-1
of Global Natural Resources Inc. Our report refers to changes in methods of
accounting for certain investments, natural gas revenues, income taxes and the
restatement of the consolidated financial statements for all periods to present
the Russian joint venture operations as part of the consolidated group.
KPMG Peat Marwick LLP
Houston, Texas
May 12, 1995
<PAGE> 1
EXHIBIT 23.2
PAGE 1 OF 1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
As independent petroleum engineers, Ryder Scott Company
Petroleum Engineers hereby consent to (i) the reference to our firm as
experts and (ii) the summarization of our report in the Form 10-K/A-1 for the
fiscal year ended December 31, 1994 of Global Natural Resources Inc. (the
"Company") as filed with the Securities and Exchange Commission (the
"Commission") which 10-K/A-1 has been incorporated by reference in the
Company's Registration Statement on Form S-8 (Registration No. 33-62106) and
the Company's Registration Statement on Form S-8 (Registration No. 33-31537).
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
/s/Joe P. Allen
------------------------------------
Joe P. Allen, P.E.
Senior Vice President
Houston, Texas
May 5, 1995
<PAGE> 1
EXHIBIT 23.3
PAGE 1 OF 1
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent petroleum engineers and geologists, Netherland,
Sewell & Associates, Inc. hereby consents to (i) the reference to
our firm as experts and (ii) the summarization of our report in the Form
10-K/A-1 for the fiscal year ended December 31, 1994 of Global Natural
Resources Inc. (the "Company") as filed with the Securities and Exchange
Commission (the "Commission") which 10-K/A-1 has been incorporated by
reference in the Company's Registration Statement on Form S-8 (Registration No.
33-62106) and the Company's Registration Statement on Form S-8 (Registration
No. 33-31537).
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ Frederic D. Sewell
--------------------------
Frederic D. Sewell
President
Dallas, Texas
May 4, 1995
<PAGE> 1
EXHIBIT 24.1
PAGE 1 OF 5
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned,
an officer or director or both, of Global Natural Resources Inc.,
a New Jersey corporation (the "Company") does hereby constitute and appoint
Robert F. Vagt and Eric Lynn Hill their true and lawful attorneys and agents
(each with authority to act alone), with power and authority to sign for and on
behalf of the undersigned the name of the undersigned as officer or director or
both, of the Company to the Company's Annual Report to the Securities and
Exchange Commission on Form 10-K/A-1 for the fiscal year of the Company ending
December 31, 1994 or to any amendments thereto filed with the Securities and
Exchange Commission, and to any instrument or document filed as part of, as an
exhibit to or in connection with said Report or amendments; and the undersigned
does hereby ratify and confirm as his own act and deed all that said attorney
and agent shall do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has subscribed these presents
this 9th day of May, 1995.
/s/ John A. Brock
---------------------------------------
JOHN A. BROCK
<PAGE> 2
EXHIBIT 24.1
PAGE 2 OF 5
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned,
an officer or director or both, of Global Natural Resources Inc.,
a New Jersey corporation (the "Company") does hereby constitute and appoint
Robert F. Vagt and Eric Lynn Hill their true and lawful attorneys and agents
(each with authority to act alone), with power and authority to sign for and on
behalf of the undersigned the name of the undersigned as officer or director or
both, of the Company to the Company's Annual Report to the Securities and
Exchange Commission on Form 10-K/A-1 for the fiscal year of the Company ending
December 31, 1994 or to any amendments thereto filed with the Securities and
Exchange Commission, and to any instrument or document filed as part of, as an
exhibit to or in connection with said Report or amendments; and the undersigned
does hereby ratify and confirm as his own act and deed all that said attorney
and agent shall do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has subscribed these presents
this 9th day of May, 1995.
/s/ Paul E. Carlton
----------------------------------
PAUL E. CARLTON
<PAGE> 3
EXHIBIT 24.1
PAGE 3 OF 5
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned,
an officer or director or both, of Global Natural Resources Inc.,
a New Jersey corporation (the "Company") does hereby constitute and appoint
Robert F. Vagt and Eric Lynn Hill their true and lawful attorneys and agents
(each with authority to act alone), with power and authority to sign for and on
behalf of the undersigned the name of the undersigned as officer or director or
both, of the Company to the Company's Annual Report to the Securities and
Exchange Commission on Form 10-K/A-1 for the fiscal year of the Company ending
December 31, 1994 or to any amendments thereto filed with the Securities and
Exchange Commission, and to any instrument or document filed as part of, as an
exhibit to or in connection with said Report or amendments; and the undersigned
does hereby ratify and confirm as his own act and deed all that said attorney
and agent shall do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has subscribed these presents
this 9th day of May, 1995.
/s/ J. Charles Hollimon
--------------------------
J. CHARLES HOLLIMON
<PAGE> 4
EXHIBIT 24.1
PAGE 4 OF 5
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned,
an officer or director or both, of Global Natural Resources Inc.,
a New Jersey corporation (the "Company") does hereby constitute and appoint
Robert F. Vagt and Eric Lynn Hill their true and lawful attorneys and agents
(each with authority to act alone), with power and authority to sign for and on
behalf of the undersigned the name of the undersigned as officer or director or
both, of the Company to the Company's Annual Report to the Securities and
Exchange Commission on Form 10-K/A-1 for the fiscal year of the Company ending
December 31, 1994 or to any amendments thereto filed with the Securities and
Exchange Commission, and to any instrument or document filed as part of, as an
exhibit to or in connection with said Report or amendments; and the undersigned
does hereby ratify and confirm as his own act and deed all that said attorney
and agent shall do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has subscribed these presents
this 9th day of May, 1995.
/s/ Patrick L. Macdougall
-------------------------------------
PATRICK L. MACDOUGALL
<PAGE> 5
EXHIBIT 24.1
PAGE 5 OF 5
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that the undersigned,
an officer or director or both, of Global Natural Resources Inc.,
a New Jersey corporation (the "Company") does hereby constitute and appoint
Robert F. Vagt and Eric Lynn Hill their true and lawful attorneys and agents
(each with authority to act alone), with power and authority to sign for and on
behalf of the undersigned the name of the undersigned as officer or director or
both, of the Company to the Company's Annual Report to the Securities and
Exchange Commission on Form 10-K/A-1 for the fiscal year of the Company ending
December 31, 1994 or to any amendments thereto filed with the Securities and
Exchange Commission, and to any instrument or document filed as part of, as an
exhibit to or in connection with said Report or amendments; and the undersigned
does hereby ratify and confirm as his own act and deed all that said attorney
and agent shall do or cause to be done by virtue hereof.
IN WITNESS WHEREOF, the undersigned has subscribed these presents
this 9th day of May, 1995.
/s/ Sidney R. Petersen
------------------------------------
SIDNEY R. PETERSEN
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 3,881
<SECURITIES> 33,279
<RECEIVABLES> 10,665
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 53,093
<PP&E> 151,883
<DEPRECIATION> 58,534
<TOTAL-ASSETS> 154,500
<CURRENT-LIABILITIES> 26,794
<BONDS> 18,742
<COMMON> 33,335
0
0
<OTHER-SE> 74,421
<TOTAL-LIABILITY-AND-EQUITY> 154,500
<SALES> 61,823
<TOTAL-REVENUES> 62,943
<CGS> 16,852
<TOTAL-COSTS> 66,122
<OTHER-EXPENSES> 602
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 124
<INCOME-PRETAX> (1,597)
<INCOME-TAX> 6,656
<INCOME-CONTINUING> (8,253)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (8,253)
<EPS-PRIMARY> (.28)
<EPS-DILUTED> (.28)
</TABLE>
