<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON NOVEMBER 22, 2000
REGISTRATION NO. 333-
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--------------------------------------------------------------------------------
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
------------------
FORM S-1
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
------------------
CMS OIL AND GAS COMPANY
(Exact name of Registrant as specified in its charter)
------------------
<TABLE>
<S> <C> <C>
MICHIGAN 1311 38-1859381
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
1021 MAIN STREET
SUITE 2800
HOUSTON, TEXAS 77002-6606
(713) 651-1700
(Address, including zip code, and telephone number, including area code, of
Registrant's principal executive offices)
------------------
<TABLE>
<S> <C>
WILLIAM H. STEPHENS III ALAN M. WRIGHT
EXECUTIVE VICE PRESIDENT, GENERAL COUNSEL SENIOR VICE PRESIDENT AND CHIEF FINANCIAL OFFICER
AND SECRETARY CMS ENERGY CORPORATION
CMS OIL AND GAS COMPANY FAIRLANE PLAZA SOUTH
1021 MAIN STREET SUITE 1100
SUITE 2800 330 TOWN CENTER DRIVE
HOUSTON, TEXAS 77002-6606 DEARBORN, MICHIGAN 48126
(713) 651-1700 (313) 436-9560
</TABLE>
(Name, address, including zip code, and telephone number, including area code,
of agent for service)
------------------
Copies to:
<TABLE>
<S> <C> <C>
MICHAEL D. VAN HEMERT, ESQ. ANDREW H. SHAW, ESQ. S. KINNIE SMITH, ESQ.
ASSISTANT GENERAL COUNSEL SIDLEY & AUSTIN SKADDEN, ARPS, SLATE,
CMS ENERGY CORPORATION BANK ONE PLAZA MEAGHER & FLOM LLP
FAIRLANE PLAZA SOUTH, SUITE 1100 10 SOUTH DEARBORN STREET FOUR TIMES SQUARE
330 TOWN CENTER DRIVE CHICAGO, ILLINOIS 60603 NEW YORK, NEW YORK 10036
DEARBORN, MICHIGAN 48126 (312) 853-7000 (212) 735-3000
(313) 436-9602
</TABLE>
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after the effective date of this Registration Statement.
IF ANY OF THE SECURITIES BEING REGISTERED ON THIS FORM ARE TO BE OFFERED ON
A DELAYED OR CONTINUOUS BASIS PURSUANT TO RULE 415 UNDER THE SECURITIES ACT OF
1933, CHECK THE FOLLOWING BOX. [ ]
If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]
------------
If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
------------
If this Form is a post-effective amendment filed pursuant to Rule 462(d)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]
------------
If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
CALCULATION OF REGISTRATION FEE
<TABLE>
<CAPTION>
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PROPOSED MAXIMUM
TITLE OF EACH CLASS OF AGGREGATE OFFERING AMOUNT OF
SECURITIES TO BE REGISTERED PRICE(1)(2) REGISTRATION FEE(2)
--------------------------------------------------------------------------------------------------------------
<S> <C> <C>
Common stock, no par value.................................. $300,000,000 $79,200
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</TABLE>
(1) Estimated solely for purposes of calculating the registration fee pursuant
to Rule 457 of the Securities Act of 1933.
(2) Excludes $100,000,000 maximum aggregate initial offering price of common
stock previously registered pursuant to a registration statement filed by
the registrant on Form S-1 (File No. 33-63693) under which no securities
have been issued; the filing fee of $34,483 associated with such securities
was previously paid with that registration statement.
THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(a) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE COMMISSION, ACTING PURSUANT TO SAID SECTION 8(a),
MAY DETERMINE.
Pursuant to Rule 429 under the Securities Act, this registration statement
contains a combined prospectus that also relates to $100,000,000 maximum
aggregate initial offering price of common stock previously registered pursuant
to a registration statement filed by the registrant (then named CMS NOMECO Oil &
Gas Company) on Form S-1 (File No. 33-63693) under which no securities have been
issued. The filing fee of $34,483 associated with such securities was previously
paid with that registration statement.
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<PAGE> 2
THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. WE
MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION STATEMENT FILED WITH
THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS PROSPECTUS IS
NOT AN OFFER TO SELL THESE SECURITIES AND IS NOT SOLICITING AN OFFER TO
BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.
SUBJECT TO COMPLETION, DATED NOVEMBER 22, 2000
SHARES
[LOGO]
CMS OIL AND GAS COMPANY
COMMON STOCK
------------------
We are selling shares of common stock and the selling shareholder, CMS
Enterprises Company, our parent company, is selling shares of common stock.
We will not receive any of the proceeds from the shares of common stock sold by
the selling shareholder.
The underwriters have an option to purchase a maximum of
additional shares from us and/or the selling shareholder to cover
over-allotments of shares.
Prior to this offering, there has been no public market for our common
stock. The initial public offering price of the common stock is expected to be
between $ and $ per share. We will apply to list our common stock on The
New York Stock Exchange under the symbol "CGS."
Concurrently with this offering, we plan to issue $200,000,000 aggregate
principal amount of our senior subordinated notes in either the public or
private markets. Neither offering is contingent upon the other.
Following this offering, CMS Enterprises Company and CMS Energy
Corporation, its parent company, will continue to beneficially own approximately
% of our common stock and will be able to determine, or have significant
influence over, the outcome of all corporate actions requiring shareholder
approval.
INVESTING IN THE COMMON STOCK INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE
9.
<TABLE>
<CAPTION>
UNDERWRITING PROCEEDS TO PROCEEDS TO
PRICE TO DISCOUNTS AND CMS OIL SELLING
PUBLIC COMMISSIONS AND GAS SHAREHOLDER
-------- ------------- ----------- -----------
<S> <C> <C> <C> <C>
Per Share................................. $ $ $ $
Total..................................... $ $ $ $
</TABLE>
Delivery of our shares of common stock will be made on or about
, 2001.
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY OTHER REGULATORY
BODY HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
CREDIT SUISSE FIRST BOSTON
The date of this prospectus is , 2001.
<PAGE> 3
[Maps illustrating the location of international and domestic oil and gas
properties]
<PAGE> 4
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
PROSPECTUS SUMMARY.................... 1
RISK FACTORS.......................... 9
SPECIAL NOTE REGARDING FORWARD-
LOOKING STATEMENTS.................. 21
USE OF PROCEEDS....................... 22
DIVIDEND POLICY....................... 22
DILUTION.............................. 23
CAPITALIZATION........................ 24
SELECTED HISTORICAL CONSOLIDATED
FINANCIAL DATA...................... 25
UNAUDITED PRO FORMA CONSOLIDATED
FINANCIAL DATA...................... 27
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS....................... 33
BUSINESS AND PROPERTIES............... 48
MANAGEMENT............................ 73
OWNERSHIP OF CAPITAL STOCK............ 81
RELATIONSHIP AND CERTAIN TRANSACTIONS
WITH CMS ENERGY AND AFFILIATES...... 82
</TABLE>
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
DESCRIPTION OF CAPITAL STOCK.......... 90
SHARES ELIGIBLE FOR FUTURE SALE....... 92
UNDERWRITING.......................... 94
NOTICE TO CANADIAN RESIDENTS.......... 96
MATERIAL U.S. FEDERAL INCOME TAX
CONSIDERATIONS FOR NON-U.S. HOLDERS
OF
OUR COMMON STOCK.................... 97
LEGAL MATTERS......................... 99
EXPERTS............................... 99
INDEPENDENT PETROLEUM ENGINEERS....... 99
WHERE YOU CAN FIND MORE INFORMATION... 100
GLOSSARY OF OIL AND NATURAL GAS
TERMS............................... 101
INDEX TO CONSOLIDATED FINANCIAL
STATEMENTS.......................... F-1
REPORT OF INDEPENDENT PETROLEUM
ENGINEERS........................... A-1
</TABLE>
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YOU SHOULD RELY ONLY ON THE INFORMATION CONTAINED IN THIS DOCUMENT OR TO
WHICH WE HAVE REFERRED YOU. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
INFORMATION THAT IS DIFFERENT. THIS DOCUMENT MAY ONLY BE USED WHERE IT IS LEGAL
TO SELL THESE SECURITIES. THE INFORMATION IN THIS DOCUMENT MAY ONLY BE ACCURATE
ON THE DATE OF THIS DOCUMENT, AS THIS DOCUMENT MAY BE AMENDED OR SUPPLEMENTED
AFTER THAT DATE IN THE EVENT OF ANY SUBSEQUENT MATERIAL CHANGES DURING THE
PROSPECTUS DELIVERY PERIOD SPECIFIED BELOW.
DEALER PROSPECTUS DELIVERY OBLIGATION
UNTIL , 2001 (25 DAYS AFTER THE COMMENCEMENT OF THE
OFFERING), ALL DEALERS THAT EFFECT TRANSACTIONS IN THESE SECURITIES, WHETHER OR
NOT PARTICIPATING IN THIS OFFERING, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE DEALER'S OBLIGATION TO DELIVER A PROSPECTUS WHEN
ACTING AS AN UNDERWRITER AND WITH RESPECT TO UNSOLD ALLOTMENTS OR SUBSCRIPTIONS.
ii
<PAGE> 5
PROSPECTUS SUMMARY
This summary highlights selected information from this prospectus, but does
not contain all information that may be important to you. We encourage you to
read this prospectus in its entirety before making an investment decision. CMS
Oil and Gas Company is currently a wholly-owned subsidiary of CMS Enterprises
Company, which in turn is a wholly-owned subsidiary of CMS Energy Corporation.
Unless the context otherwise requires, references to (1) "CMS Oil and Gas,"
"we," "us" or "our" refers to CMS Oil and Gas Company and its subsidiaries; (2)
"CMS Enterprises" refers to CMS Enterprises Company; and (3) "CMS Energy" refers
to CMS Energy Corporation and its subsidiaries, other than CMS Oil and Gas.
Unless otherwise indicated, this prospectus assumes that the underwriters' over-
allotment option is not exercised. The September 30, 2000 estimated reserve data
included throughout this prospectus are based on the report of Ryder Scott
Company, L.P., independent petroleum engineers. We have provided definitions for
some of the oil and natural gas industry terms used in this prospectus in
"Glossary of Oil and Natural Gas Terms" beginning on page 101.
ABOUT CMS OIL AND GAS COMPANY
CMS Oil and Gas Company is an independent energy company engaged in oil and
natural gas acquisition, exploration and development activities principally in
Africa, the U.S. and South America. Formed in 1967, we have grown our operations
through acquisition and exploration and are currently one of the larger U.S.
based independent oil and natural gas companies. Our strategy is to increase
reserves, production, cash flow and earnings by committing our resources to
regions with significant growth prospects and properties that allow us to
leverage our extensive operating and technical expertise.
On a pro forma basis, excluding our Michigan and Ecuador properties which
we recently sold, we have grown our production and estimated proved reserves at
annualized rates of 12.4% and 25.4%, respectively, from January 1, 1995 through
September 30, 2000. We have achieved these impressive growth rates by employing
a lower-risk, disciplined international and domestic acquisition, exploration
and development strategy. Internationally, we have been active in Africa and
South America for over a decade and currently have concessions which have
significant production, reserves and, we believe, reserve growth potential. We
are actively exploiting our properties in Equatorial Guinea, Colombia, Venezuela
and the Republic of Congo (Brazzaville). Domestically, we have built an
attractive reserve base and acreage holdings located principally in the Powder
River Basin of Wyoming and Montana and the Permian Basin of West Texas. We are
actively exploring and developing these domestic properties which have
increasing production and, we believe, significant reserve growth potential. We
expect to spend approximately $166.0 million in 2001 to further develop our
existing reserves and to pursue attractive exploration opportunities. We believe
that our regional operating philosophy, acreage and reserve positions and
management expertise provide us with significant opportunities for growth.
As of September 30, 2000, we had estimated proved reserves of 212.0 million
barrels of oil equivalent, or MMBoe, with a net present value (before taxes) of
$1,164.7 million. Of these reserves, 92% were classified as proved developed. We
operate properties accounting for approximately 91% of these estimated proved
reserves, allowing us to better manage expenses, capital allocation and the
timing of exploration and development activities. On a pro forma basis,
excluding our recently sold Michigan and Ecuador properties and after giving
effect to the acquisition in October 1999 of an additional interest in the Bioko
Permit offshore Equatorial Guinea, we produced 7.1 MMBoe in 1999 and 6.3 MMBoe
for the nine months ended September 30, 2000.
1
<PAGE> 6
The following table summarizes by region our estimated proved reserves as
of September 30, 2000 and our average daily net production during the three
months ended September 30, 2000:
<TABLE>
<CAPTION>
AVERAGE DAILY NET PRODUCTION
ESTIMATED PROVED RESERVES DURING THE THREE MONTHS ENDED
AS OF SEPTEMBER 30, 2000 SEPTEMBER 30, 2000
---------------------------------------------- ------------------------------------------
% OF % OF
OIL AND NATURAL TOTAL PROVED OIL AND NATURAL TOTAL
CONDENSATE GAS TOTAL RESERVES CONDENSATE GAS TOTAL PRODUCTION
(MMBBLS)(1) (BCF) (MMBOE) (MMBOE) (MBBLS)(1) (MMCF) (MBOE) (MBOE)
----------- ------- ------- ------------ ---------- ------- ------ ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
INTERNATIONAL:
Africa:
Equatorial Guinea...... 50.8 587.1 148.6 70.1% 4.3 4.8 5.1 19.8%
Congo.................. 14.7 -- 14.7 6.9 5.7 -- 5.7 22.2
Tunisia................ 3.2 36.0 9.2 4.3 1.0 8.5 2.4 9.3
South America:
Venezuela.............. 12.5 6.4 13.6 6.4 5.4 2.9 5.9 23.0
Colombia............... 4.3 -- 4.3 2.0 1.7 -- 1.7 6.6
---- ----- ----- ----- ---- ---- ---- -----
Total
International.... 85.5 629.5 190.4 89.8 18.1 16.2 20.8 80.9
DOMESTIC:
Powder River Basin...... -- 33.8 5.6 2.6 -- 4.2 0.7 2.7
West Texas.............. 5.3 48.3 13.5 6.4 0.8 9.2 2.4 9.4
Louisiana............... 0.3 10.8 2.1 1.0 0.1 9.5 1.7 6.6
Other Domestic.......... 0.3 1.4 0.4 0.2 0.1 0.3 0.1 0.4
---- ----- ----- ----- ---- ---- ---- -----
Total Domestic....... 5.9 94.3 21.6 10.2 1.0 23.2 4.9 19.1
---- ----- ----- ----- ---- ---- ---- -----
Total.............. 91.4 723.8 212.0 100.0% 19.1 39.4 25.7 100.0%
==== ===== ===== ===== ==== ==== ==== =====
</TABLE>
---------------
(1) For purposes of this table, oil and condensate reserves includes 12.2
million barrels, or MMBbls, of international natural gas liquids, or NGLs,
and oil and condensate production includes 0.9 thousand barrels, or MBbls,
of international NGLs.
OUR STRATEGY
Our strategy is to increase reserves, production, cash flow and earnings by
committing our resources to regions with significant growth potential and
properties that allow us to leverage our extensive operating experience and
focused technical expertise. We intend to achieve an attractive return on
capital while seeking to diversify our geologic, geographic and political risks.
We intend to implement our strategy as follows:
FOCUS ON PROPERTIES WITH SIGNIFICANT GROWTH POTENTIAL. We focus on known
hydrocarbon provinces with significant growth potential. Internationally, we
hold properties which we believe have significant growth potential in West
Africa, Colombia and Venezuela. Domestically, our activities are concentrated in
the high-growth areas of the Powder River Basin in Wyoming and Montana and the
Permian Basin in West Texas.
TARGET SPECIFIC REGIONS AND LARGE ACREAGE POSITIONS. We believe that
ownership of significant working interests in large acreage positions in
targeted regions allows us to achieve economies of scale in the utilization of
our geologic, engineering, exploration and production expertise. We own at least
a 50% working interest in substantially all of our properties. The concentration
of our operations permits us to manage a larger asset base with fewer staff,
enabling us to add production at relatively low incremental cost. Moreover, we
believe that the collective expertise we acquire as we explore and develop
hydrocarbon systems containing multiple prospects should improve our drilling
success rates while reducing our finding costs and diminishing our overall
drilling and operating risk profile.
MANAGE COST STRUCTURE, CAPITAL ALLOCATION AND RISK PROFILE BY SERVING AS
OPERATOR. We have operations in seven countries on three continents, and we
operate all but one of our major projects. Our operated properties accounted for
approximately 91% of our estimated proved reserves as of September 30, 2000. As
operator, we can better manage production performance and more effectively
control costs, the allocation of capital and the timing of exploration and
development of our properties.
2
<PAGE> 7
EXPAND OUR POSITION IN DOMESTIC NATURAL GAS. We hold 273,813 net acres in
the Powder River Basin, which makes us one of the larger holders of coal bed
methane acreage in this basin. By year-end 2000, we will have participated in
the drilling of 500 wells in this basin. For the three months ended September
30, 2000, our aggregate net production from this basin averaged 4.2 million
cubic feet, or MMcf, per day of natural gas. We expect this production to
increase as we plan to participate in the drilling of approximately another 510
wells in 2001 and 700 wells in 2002. In the Permian Basin of West Texas, as of
September 30, 2000 we held 44,750 net undeveloped acres and we have options on
an additional 43,400 net undeveloped acres. Since June 1999 we have spudded 43
wells, of which 34 were producing, eight were in the process of being drilled or
completed and one was a salt water disposal well. For the three months ended
September 30, 2000 our aggregate net production from the Permian Basin averaged
9.2 MMcf per day of natural gas. We will continue to seek natural gas
exploration, development and acquisition opportunities in these and other
gas-prone areas of North America, including western Canada, in order to attain a
more balanced portfolio and capitalize on the strength of the domestic gas
market.
LEVERAGE MANAGEMENT AND TECHNICAL EXPERTISE AND EXPERIENCE. We employ
seasoned managers and technical personnel who have many years' experience
operating in our targeted geographic regions. We have 38 professionals dedicated
to our West Africa properties with over 246 cumulative years of area-specific
management and technical experience and 26 professionals dedicated to our South
American properties with over 140 cumulative years of area-specific management
and technical experience. Furthermore, at least in part due to our former Antrim
Shale operations in Michigan and other domestic operations, our Powder River
Basin and West Texas operations employ dedicated personnel with over 55
cumulative years of domestic experience in the exploitation of tight gas sands
and unconventional reservoirs. We believe that our seasoned managers and
technical personnel have contributed to a significant reduction in our per-foot
drilling costs over the past five years.
ACQUISITIONS AND DISPOSITIONS OF PROPERTIES
We continually reevaluate our portfolio of property holdings in order to
maintain a disciplined adherence to our business strategy. As a result, we have
sought to make acquisitions of reserves which complement our business objectives
and to divest properties that dilute those objectives.
Acquisition of Additional Working Interest in Equatorial Guinea
In October 1999, we purchased an additional 11.5% working interest in the
Bioko Permit in Equatorial Guinea for approximately $53.3 million in cash,
increasing our working interest in this property from 42.5% to 54.0%.
Acquisition of Methanol Production Facility
We have agreed to purchase, prior to the completion of this offering, a 50%
interest in Atlantic Methanol Capital Company, which owns an indirect 90%
interest in a 2,500 metric ton per day methanol production facility currently in
the late stages of construction on Bioko Island in Equatorial Guinea. We will
purchase this interest from CMS Gas Transmission Company, a subsidiary of CMS
Enterprises, by issuance of a note in the principal amount of approximately
$137.0 million, which will be repaid with a portion of the aggregate proceeds
from this offering and our concurrent offering of senior subordinated notes.
Atlantic Methanol Capital has issued $125.0 million of limited recourse
indebtedness, which is secured by, among other things, a pledge of 60% of the
interest we expect to acquire.
We believe that ownership of an interest in this methanol facility will
allow us to further enhance the value of our natural gas reserves in Equatorial
Guinea. Prior to our agreement to acquire this facility, our return on this
natural gas was limited by the $0.25 per MMBtu selling price under a 20-year
contract to sell up to 126,500 MMBtu per day of natural gas to the facility.
Given that natural gas is typically the largest cost component in the production
of methanol, we believe this gas sales contract will position this facility to
be one of the lowest cost methanol producers in world markets.
3
<PAGE> 8
Recent Dispositions of Non-Strategic Assets
In the first half of 2000, we sold our Michigan and Ecuador properties for
aggregate cash consideration of approximately $258.7 million. We sold these
properties because they had lower growth potential than our other properties,
our working interest was relatively small and, with respect to Ecuador, we did
not serve as operator.
OUR RELATIONSHIP WITH CMS ENERGY
Pending completion of this offering, we are an indirect wholly-owned
subsidiary of CMS Energy Corporation. CMS Enterprises Company owns all of our
outstanding stock, and CMS Energy owns all of the outstanding common stock of
CMS Enterprises. CMS Energy is a major international energy company with
electric and natural gas utility operations; independent power production;
natural gas pipelines, gathering, processing and storage; energy marketing,
services and trading; and, through us, oil and natural gas exploration and
development.
After completion of this offering, CMS Energy will continue to own
indirectly approximately %, or approximately % if the underwriters exercise
their over-allotment option in full, of the outstanding shares of our common
stock.
OUR EXECUTIVE OFFICES
Our principal executive offices are located at 1021 Main Street, Suite
2800, Houston, Texas, 77002, and our telephone number is (713) 651-1700.
THE OFFERING
Common stock offered by us.......... shares
Common stock offered by CMS
Enterprises......................... shares
Common stock to be outstanding after
this offering(1).................... shares
Common stock to be held by CMS
Enterprises after this offering..... shares
Use of proceeds..................... We intend to use the net proceeds to us
from this offering, together with the
net proceeds from our concurrent
offering of $200.0 million aggregate
principal amount of our senior
subordinated notes, for repayment of
debt under our bank credit facility and
repayment of intercompany notes payable
to CMS Energy. In the aggregate, CMS
Energy will generate funds of
approximately $ million from these
transactions. Any remaining proceeds
will be used for general corporate
purposes.
Proposed New York Stock Exchange
symbol.............................. "CGS"
---------------
(1) Excludes (a) shares of common stock issuable upon exercise of options
we expect to grant to our executive officers in connection with this
offering at an exercise price equal to the initial public offering price and
(b) restricted shares of common stock we expect to issue to our
outside directors in connection with this offering.
4
<PAGE> 9
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table presents our summary historical and pro forma
consolidated financial data as of the dates and for the periods shown. The data
presented in these tables are derived from "Selected Historical Consolidated
Financial Data," "Unaudited Pro Forma Consolidated Financial Data" and our
historical consolidated financial statements and related notes included
elsewhere in this prospectus. You should read those sections for a further
explanation of the data summarized here.
The pro forma income statement and other data for the year ended December
31, 1999 and for the nine months ended September 30, 2000 give effect to the
transactions noted below as if these transactions had been completed on January
1 of the relevant period:
- our acquisition in October 1999 of an additional 11.5% interest in the
Bioko Permit offshore Equatorial Guinea and the disposition of our
properties in Michigan and Ecuador in March 2000 and June 2000,
respectively; and
- the application of the estimated net proceeds to us of $140.3 million
from shares sold by us in this offering and of $194.0 million from our
concurrent offering of $200.0 million aggregate principal amount of our
senior subordinated notes with an assumed annual interest rate of 9.5%.
The pro forma balance sheet data give effect to the transactions noted
below as if these transactions had been completed on September 30, 2000:
- our proposed distribution of a $39.0 million note payable to our parent,
CMS Enterprises; and
- our pending acquisition of an indirect 45% interest in a methanol
production plant for a note in the principal amount of approximately
$137.0 million.
The pro forma as adjusted balance sheet data give effect to these two
transactions, as well as our sale of shares of common stock in this
offering and our concurrent offering of $200.0 million aggregate principal
amount of our senior subordinated notes and the application of the estimated net
proceeds to us from these offerings of $140.3 million and $194.0 million,
respectively, as if these transactions had been completed on September 30, 2000.
The pro forma financial data are not necessarily indicative of the
financial position or results of operations that would have been achieved if the
pro forma transactions had occurred on the dates indicated or the financial
position or results of operations that will be achieved in the future. The
consolidated financial position and results of operations as of and for the nine
months ended September 30, 2000 are not necessarily indicative of the financial
position or results of operations that may be achieved as of and for the full
year ending December 31, 2000.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------- ---------------------------------------
PRO FORMA PRO FORMA
1997 1998 1999 1999 1999 2000 2000
-------- -------- -------- ----------- ----------- ----------- -----------
(UNAUDITED) ------- (UNAUDITED) -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating Revenues:
Oil and condensate..................... $ 91,364 $ 66,821 $ 82,560 $ 64,097 $ 58,858 $ 76,311 $ 66,772
Natural gas............................ 56,369 56,103 54,664 17,498 39,590 35,684 26,009
Other operating........................ 8,472 4,395 5,538 4,455 2,828 6,506 6,076
-------- -------- -------- -------- -------- -------- --------
Total operating revenues(1)...... 156,205 127,319 142,762 86,050 101,276 118,501 98,857
Operating Expenses:
Depreciation, depletion and
amortization......................... 48,129 38,067 43,786 21,740 31,812 28,505 22,126
Operating and maintenance.............. 44,169 44,322 51,985 35,762 37,685 40,882 34,566
Exploration costs...................... 27,747 18,976 9,456 7,914 6,142 6,160 5,822
General and administrative............. 16,517 14,250 16,819 16,294 11,056 14,775 14,945
Production taxes and other............. 5,470 5,315 4,029 571 2,484 3,289 2,169
-------- -------- -------- -------- -------- -------- --------
Total operating expenses......... 142,032 120,930 126,075 82,281 89,179 93,611 79,628
-------- -------- -------- -------- -------- -------- --------
</TABLE>
5
<PAGE> 10
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------- ---------------------------------------
PRO FORMA PRO FORMA
1997 1998 1999 1999 1999 2000 2000
-------- -------- -------- ----------- ----------- ----------- -----------
(UNAUDITED) ------- (UNAUDITED) -------
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
Pretax operating income.................. 14,173 6,389 16,687 3,769 12,097 24,890 19,229
Other income (expense)................... 13,146 1,233 712 (1,632) 879 32,842 (2,120)
Interest expense, net of capitalized
interest............................... 15,723 16,069 13,606 19,600 10,004 11,369 14,700
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes........ 11,596 (8,447) 3,793 (17,463) 2,972 46,363 2,409
Total income tax provision (benefit)..... (6,982) (13,881) (14,082) (8,458) (9,854) (2,516) (1,853)
-------- -------- -------- -------- -------- -------- --------
Net income............................... $ 18,578 $ 5,434 $ 17,875 $ (9,005) $ 12,826 $ 48,879 $ 4,262
======== ======== ======== ======== ======== ======== ========
Net income per common share.............. $ $ $ $ $ $ $
======== ======== ======== ======== ======== ======== ========
Average common shares outstanding........
OTHER DATA:
EBITDAX(2)............................... $ 90,049 $ 63,432 $ 69,929 $ 33,423 $ 50,051 $ 59,555 $ 47,177
Capital expenditures(3).................. 120,774 142,196 153,253 142,743 55,321 85,503 83,843
</TABLE>
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
------------------------------------
PRO FORMA
HISTORICAL PRO FORMA AS ADJUSTED
---------- --------- -----------
------- (UNAUDITED) -------
(IN THOUSANDS)
<S> <C> <C> <C>
BALANCE SHEET DATA:
Working capital(4).......................................... $ 71,309 $(104,691) $102,388
Investment and other assets................................. 10,026 147,026 153,026
Property, plant and equipment, net.......................... 421,735 421,735 421,735
Total assets................................................ 693,045 830,045 867,124
Long-term debt, including current portion................... 130,514 130,514 203,343
Stockholder's equity........................................ 403,969 364,969 505,219
</TABLE>
---------------
(1) Total operating revenues include the effect of settlement of various hedging
transactions to which we have been a party. Excluding the impact of these
hedging transactions, total operating revenues for the years ended December
31, 1997, 1998 and 1999 and pro forma 1999 would have been $175.4 million,
$124.4 million, $163.8 million and $109.5 million, respectively. Excluding
the impact of hedging transactions, total operating revenues for the nine
months ended September 30, 1999 and 2000 and pro forma 2000 would have been
$108.5 million, $162.3 million and $131.3 million, respectively. For a
discussion of our recent hedging activities and the expected adoption of new
policies applicable to our hedging, we refer you to "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Hedging
Transactions" and "Business and Properties -- Hedging Objectives,"
respectively.
(2) EBITDAX is earnings before interest, income taxes, depreciation, depletion
and amortization, other income (expense), extraordinary item and exploration
costs. EBITDAX is presented to provide additional information about our
ability to meet our future requirements for debt service, capital
expenditures and working capital. EBITDAX should not be considered as an
alternative to net income as an indicator of operating performance or as an
alternative to cash flows as a measure of liquidity.
(3) Costs incurred for exploration, development and acquisition activities,
including such of those costs as are expensed under the successful efforts
method of accounting.
(4) Excludes current maturities of long-term debt.
6
<PAGE> 11
SUMMARY OIL AND NATURAL GAS RESERVE DATA
The following table summarizes our estimated proved oil and natural gas
reserves as of the dates indicated. The reserve estimates as of September 30,
2000 have been prepared by Ryder Scott Company, L.P., our independent petroleum
engineers. The reserve estimates as of January 1, 1998, 1999 and 2000 have been
prepared based on reports prepared by Ryder Scott Company and/or Lee Keeling and
Associates, Inc., independent petroleum engineers, and adjusted by us to exclude
our reserves in Michigan and Ecuador, which we sold in March 2000 and June 2000,
respectively. For additional information relating to our oil and natural gas
reserves, you should read the risk factor relating to our reserves under "Risk
Factors," "Business and Properties -- Reserves" and "Supplemental
Information -- Oil and Gas Producing Activities" in the notes to our
consolidated financial statements included elsewhere in this prospectus.
Attached to this prospectus as Appendix A is a letter from Ryder Scott Company
relating to its report on our estimated proved reserves as of September 30,
2000.
<TABLE>
<CAPTION>
AS OF JANUARY 1,
------------------------- AS OF
1998(1) 1999(1) 2000 SEPTEMBER 30, 2000
------- ------- ----- ------------------
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil and condensate (MMBbls)(2)............. 83.9 78.3 91.6 91.4
Natural gas (Bcf).......................... 107.8 468.5 616.8 723.8
Total (MMBoe).............................. 101.9 156.4 194.4 212.0
</TABLE>
---------------
(1) Includes additional interest in the Bioko Permit offshore Equatorial Guinea,
which we acquired in October 1999.
(2) Includes NGLs.
The following table summarizes the net present value of future cash flows
and the standardized measure of discounted future net cash flows attributable to
our estimated proved reserves as of September 30, 2000, discounted at 10% per
annum. The net present value of future cash flows has been prepared by Ryder
Scott Company using the September 30, 2000 prices of $5.13 per million British
thermal units, or MMBtu, of natural gas at the Henry Hub Index and $30.83 per
barrel of oil at the Cushing spot market, except where we have fixed and
determinable prices or service fees provided by contracts. The standardized
measure of discounted future net cash flows has been prepared by us using the
net present value information prepared by Ryder Scott.
<TABLE>
<CAPTION>
AS OF
SEPTEMBER 30, 2000
------------------
<S> <C>
Net present value(millions)(1).............................. $1,164.7
Standardized measure of discounted future net cash flows
(millions)(2)............................................. $ 894.9
</TABLE>
---------------
(1) Net present value represents the net present value of future cash flows on a
pre-tax basis calculated in accordance with SEC guidelines. Net present
value is sometimes also known as PV 10.
(2) The standardized measure of discounted future net cash flows represents the
net present value of future cash flows attributable to our reserves after
income tax, calculated in accordance with the provisions of Statement of
Financial Accounting Standards No. 69. For further details concerning this
calculation, see "Business and Properties -- Reserves."
7
<PAGE> 12
SUMMARY OPERATING DATA
The following table presents our summary operating data for the periods
shown. The pro forma operating data for the year ended December 31, 1999 give
effect to the transactions noted below as if these transactions had been
completed on January 1, 1999:
- our acquisition in October 1999 of an additional 11.5% interest in the
Bioko Permit offshore Equatorial Guinea; and
- the disposition of our properties in Michigan and Ecuador in March 2000
and June 2000, respectively.
The pro forma operating data for the nine months ended September 30, 2000
give effect to the disposition of our properties in Michigan and Ecuador as if
these transactions had been completed on January 1, 2000.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------------- -----------------------------
PRO FORMA PRO FORMA
1997 1998 1999 1999 1999 2000 2000
------- ------- ------- --------- ------- ------- ---------
<S> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION:
Oil and condensate (MBbls).................... 6,564 7,309 7,288 5,382 5,445 5,510 4,611
Natural gas (MMcf)............................ 27,157 26,495 26,412 8,902 19,431 13,840 9,561
NGLs (MBbls).................................. 321 413 396 274 276 236 199
AVERAGE SALES PRICE(1):
Oil and condensate (per Bbl).................. $ 13.92 $ 9.14 $ 11.33 $ 11.91 $ 10.81 $ 13.85 $ 14.48
Natural gas (per Mcf)......................... 2.08 2.12 2.07 1.97 2.04 2.58 2.72
NGLs (per Bbl)................................ 15.87 6.70 9.38 12.65 7.56 19.97 22.03
OPERATING EXPENSES (PER BOE):
Depreciation, depletion and amortization...... $ 4.22 $ 3.14 $ 3.62 $ 3.04 $ 3.55 $ 3.54 $ 3.50
Operating and maintenance expense............. 3.87 3.65 4.30 5.01 4.21 5.08 5.47
General and administrative.................... 1.45 1.17 1.39 2.28 1.23 1.83 2.36
</TABLE>
---------------
(1) Adjusted to reflect amounts received or paid under contracts entered into to
hedge the price of production.
8
<PAGE> 13
RISK FACTORS
You should carefully consider the following risk factors before deciding to
purchase shares of our common stock. We have separated the risks into three
categories:
- risks relating to our business, properties and industry;
- risks relating to our relationship with CMS Energy; and
- risks relating to the securities markets and ownership of our common
stock.
RISKS RELATING TO OUR BUSINESS, PROPERTIES AND INDUSTRY
Oil, natural gas and methanol prices fluctuate widely, and low prices could
harm our business.
Our revenues, operating results and future growth are highly dependent upon
the prevailing prices of, and demand for, oil and natural gas. Prices also
affect the amount of cash flow available for capital expenditures and our
ability to raise additional capital. Historically, the markets for oil and
natural gas have been volatile, and they are likely to continue to be volatile
in the future. The prices of oil and natural gas are subject to wide
fluctuations in response to relatively minor changes in the supply of and demand
for oil and natural gas, market uncertainty and a variety of additional factors
that are beyond our control. These factors include:
- the level of consumer product demand;
- weather conditions;
- domestic and foreign governmental regulations and taxes;
- the price and availability of alternative fuels;
- transportation costs;
- political conditions in the Middle East and other petroleum producing
areas;
- the domestic and foreign supply of oil and natural gas;
- the price of foreign imports; and
- overall economic conditions.
It is impossible to predict future oil and natural gas price movements with
any certainty.
Declines in oil or natural gas prices could also reduce the amount of oil
and natural gas that we can produce economically.
Upon our acquisition of CMS Gas Transmission's interest in a methanol
production facility and the expected commencement of operations of this plant in
the first half of 2001, the price of methanol will also significantly influence
our financial condition and results of operations. There is significant
volatility in the price of methanol.
Our price hedging may result in diminished financial performance or losses.
In order to reduce our exposure to the price risks to which we are subject
in the sale of our oil and natural gas, we enter into hedging arrangements from
time to time. Our hedging arrangements apply to only a portion of our production
and provide only limited price protection against fluctuations in the oil and
natural gas markets. To the extent that we engage in hedging activities, we may
not realize the benefits of price increases for natural gas or oil above the
levels of the hedges.
If we choose not to engage in hedging arrangements, we may be more
adversely affected by changes in natural gas and oil prices than if we did
engage in hedging arrangements.
9
<PAGE> 14
Hedging arrangements also expose us to risk of financial loss in some
circumstances, including:
- lower production than expected; or
- default by the counterparty to the hedging contract, which may be an
affiliate of CMS Energy, on its contractual obligations.
For a discussion of our recent hedging activities and the expected adoption
of new policies applicable to our hedging, we refer you to "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions" and "Business and Properties -- Hedging
Objectives," respectively.
Reserve estimates are inherently uncertain and depend on many assumptions that
may be inaccurate. Any material inaccuracies in our reserve estimates or
underlying assumptions could cause the quantities and net present value of our
reserves to be overstated.
The reserve data set forth in this prospectus represent only estimates.
Estimates of economically recoverable oil and natural gas reserves and of future
net cash flows necessarily depend upon a number of variable interpretations and
assumptions, including:
- the interpretation of available technical data;
- the assumed effects of regulation by governmental agencies and
assumptions concerning future oil and natural gas prices;
- future operating costs;
- severance and excise taxes;
- development costs; and
- workover and remedial costs.
Any significant inaccuracies in these interpretations or assumptions could
cause the estimated quantities and net present value of reserves shown in this
prospectus to be overstated. Please read "Business and Properties -- Reserves"
for a discussion of our proved natural gas and oil reserves.
We often hold reserves located outside the U.S. pursuant to complex
contractual arrangements with foreign governments. Under these arrangements, the
relative sharing of benefits between us and the foreign government may vary
depending on prices received for production, volume of production or costs.
These contractual provisions further complicate estimating reserves and net
present value. Moreover, some of the producing wells included in our reserve
report, such as those in the Powder River Basin and in West Texas, have produced
for a relatively short period of time as of September 30, 2000. Because some of
our reserve estimates are not based on lengthy production histories, these
estimates are less reliable than estimates based on lengthy production
histories. For these reasons, estimates of economically recoverable quantities
of oil and natural gas attributable to any particular group of properties,
classifications of reserves based on risk of recovery and estimates of expected
future cash flows prepared by different engineers or by the same engineers at
different times may vary substantially, and reserve estimates may be subject to
downward or upward adjustments, based upon these factors. Actual production,
revenues and expenditures with respect to our reserves will likely vary from
estimates, and these variances may be material.
You should not assume that the net present value of future cash flows
referred to in this prospectus is the current market value of our estimated oil
and natural gas reserves. In accordance with SEC requirements, we generally base
the net present value of future cash flows from our proved reserves on prices
and costs as of the date of the estimate. Estimates included in this prospectus
are based in large
10
<PAGE> 15
part on prices that are at or near the highest they have been in a decade.
Actual future prices and costs may be materially different. Actual future net
cash flows also will be affected by factors such as:
- the amount and timing of actual production;
- supply and demand for oil and natural gas;
- curtailments or increases in consumption by oil and natural gas
purchasers;
- changes in governmental regulations or taxation; and
- the operation of contractual provisions under varying prices, production
volumes and costs.
The timing of both the production and the incurrence of expenses in
connection with development and production of oil and natural gas properties
will affect the amount and timing of actual future net cash flows and
standardized measure data from proved reserves. In addition, the calculation of
the net present value of future cash flows using a 10% annual discount rate as
required by the SEC is not necessarily the most appropriate discount factor
based on interest rates in effect from time to time and risks associated with
our reserves or the oil and natural gas industry in general.
Our future oil and natural gas production and, therefore, our future cash
flows are dependent upon our success in finding or acquiring additional
reserves.
In general, the rate of production from oil and natural gas properties
declines as reserves are depleted. The rate of decline depends on reservoir
characteristics and other factors. Unless we acquire properties containing
proved reserves or conduct successful exploration and development activities, or
both, our estimated proved reserves will decline as we produce those reserves.
Our future oil and natural gas production and, therefore, our future cash flows
and income are highly dependent upon our degree of success in finding or
acquiring additional reserves.
Our acquisition, exploration and development activities require substantial
amounts of capital, and we may be unable to obtain needed financing on
satisfactory terms.
Our future oil and natural gas exploration, development and acquisition
activities are highly dependent upon our ability to obtain funds for these
activities. The business of acquiring, exploring for and developing reserves is
capital intensive. We intend to finance our capital expenditures with cash flow
from operations and financing arrangements expected to be in place as of the
date of completion of this offering. Additional financing sources may be
required in the future. Financing may not continue to be available under
existing or new financing arrangements and we may not be able to obtain
necessary financing on acceptable terms, if at all. In particular, our credit
facility as we expect it to be in place as of the completion of this offering
will likely impose limitations on our ability to borrow under the facility which
relate to the value of our asset base as determined by market prices of oil and
natural gas. Our international properties, which are a very significant part of
our assets, are included in our asset base at reduced values for this purpose.
If we experience a reduction in cash flow from operations or cannot freely
access external sources of capital, we may have to curtail our acquisition,
drilling or other plans or sell some assets on an unfavorable basis.
Exploration, development and production operations are high-risk activities.
Our oil and natural gas operations are subject to the economic risks
typically associated with exploration, development, production and marketing
activities, including significant expenditures required to locate and acquire
producing properties and to drill exploratory, appraisal and development wells.
In conducting exploration and development activities, we may drill unsuccessful
wells and experience investment losses. We may not be able to produce
economically or market satisfactorily discovered oil or natural gas. Moreover,
the presence of unanticipated pressure or irregularities in formations or
accidents may cause our exploration, development and production activities to be
unsuccessful and could result in a
11
<PAGE> 16
total loss of our investment in affected properties. Our operations may be
materially curtailed as a result of a number of factors, including:
- lack of infrastructure;
- bad weather;
- land title problems;
- failure to obtain, or changes in, necessary governmental or regulatory
permits or approvals; and
- labor or other shortages.
In addition, some of our producing properties are subject to production
limitations imposed by governmental or regulatory authorities or under
contracts. Consequently, our actual future production may be substantially
affected by factors beyond our control, any of which could have a material
adverse effect on our financial results.
Our drilling success will depend, in part, on our ability to attract and
retain experienced geologists, geophysicists, engineers and other professional
personnel. Competition for such experienced professional personnel is extremely
intense. If we cannot retain our current personnel or attract additional
experienced personnel, our ability to successfully pursue exploration,
development and production activities could be adversely affected.
Our ability to market our oil and natural gas may be impaired by capacity
constraints on the gathering systems and pipelines that transport our oil and
natural gas.
A substantial portion of our oil and most of our natural gas are
transported through gathering systems and pipelines which we do not own.
Transportation capacity on gathering systems and pipelines is occasionally
limited and at times unavailable due to repairs or improvements being made to
these facilities or due to capacity being utilized by other oil or natural gas
shippers that may have priority transportation agreements. Aggregate methane gas
production from the Powder River Basin in Wyoming and Montana is likely to
increase significantly over the next few years. We believe that, commencing
sometime in 2001, production may exceed the existing interstate gas
transportation capacity. A pipeline expansion and a new pipeline have been
proposed, although we cannot assure you that either will be built or built soon
enough to avoid capacity constraints. We may have to curtail production, pay
significantly higher transportation costs or receive a lower price for at least
a portion of our Powder River Basin production if pipeline transportation
capacity increases do not keep pace with increased overall production in this
region. If transportation capacity is materially restricted or is unavailable in
the future, our ability to market our oil or natural gas could be impaired and
cash flow from the affected properties could be reduced, which could have a
material adverse effect on our financial condition or results of operation.
We could be liable under tax indemnities relating to potential recapture of
dual consolidated losses.
We could take various actions in the future which would require our
affiliated group or an unrelated affiliated group of corporations to recapture
or include in income an amount equal to certain losses, referred to as dual
consolidated losses, that may have been used previously to offset taxable income
for U.S. federal income tax purposes. These actions generally are within our
control and we do not intend to take them. Nonetheless, if we did, we could be
liable directly or under tax indemnity agreements for substantial U.S. federal
income taxes that could total in excess of $71.0 million plus interest. We could
also be liable for this amount if, in contrast to our expectation, we and CMS
Energy fail to obtain a closing agreement from the Internal Revenue Service in
connection with this offering and if, contrary to its contractual obligations,
CMS Energy fails to pay the taxes and interest that result. We could also be
liable for an amount currently estimated to be in excess of $44.5 million plus
interest if, contrary to our expectations, a party unrelated to us fails to
fulfill its obligations under indemnity agreements relating to dual consolidated
losses associated with assets held by the unrelated party. Finally, we could be
liable for an amount currently estimated to be in excess of $11.5 million plus
interest if, again contrary to our
12
<PAGE> 17
expectations, a party unrelated to us fails to fulfill its obligations under
indemnity agreements relating to dual consolidated losses and other parties fail
in their indemnity obligations to us.
We could incur high effective combined rates of tax on future foreign earnings
generated by our domestic affiliates and substantial additional taxes upon
repatriation of earnings from our foreign affiliates.
U.S. corporations generally are entitled to a foreign tax credit that
reduces the U.S. federal income tax burden on foreign earnings generated
directly or by domestic affiliates and on the repatriation of earnings from
foreign subsidiaries. However, this credit is subject to various limitations,
including limitations arising from the prior use of foreign losses to offset
domestic income. Some of these limitations are applicable to us and may
substantially increase the U.S. federal income tax burden on the future foreign
earnings of our domestic affiliates and on earnings repatriated from our foreign
affiliates.
We could be required to record a U.S. income tax provision as to prior years'
earnings from foreign affiliates.
Although we have no current plans to do so, if we change our policy and
decide against indefinitely reinvesting our unrepatriated foreign earnings
offshore, we may be required for financial accounting purposes to record
additional deferred taxes with respect to all of our prior years' unrepatriated
foreign earnings. It is estimated that, if we were required to do so as of
September 30, 2000, the additional deferred taxes could be approximately $32.0
million.
Our international operations may be subject to political and economic
uncertainties and other risks beyond our control.
Almost 90% of our estimated proved reserves, as well as the methanol
production facility in which we have agreed to acquire an interest, are located
outside the U.S. Our international oil and natural gas exploration, development
and production activities and our methanol production business are subject to:
- political and economic uncertainties, including changes in energy
policies or the personnel administering them;
- expropriation of property;
- cancellation or modification of contract rights;
- difficulty enforcing contract rights, either within or outside of the
jurisdiction in which we have assets;
- foreign exchange restrictions;
- currency fluctuations;
- royalty and tax increases; and
- other risks arising out of foreign governmental sovereignty over the
areas in which our operations are conducted.
Additional risks include loss due to civil strife, acts of war, guerrilla
activities, insurrection, border disputes and leadership succession turmoil.
These risks may be higher in the developing countries in which we conduct our
exploration, development and production activities and our methanol production
business. We generally do not fully insure against these risks. Consequently,
our international exploration, development and production activities and our
methanol production business may be substantially affected by factors beyond our
control, any of which could have a material adverse effect on our financial
condition or results of operations. Furthermore, in the event of a dispute
arising from our international operations, we may be subject to the exclusive
jurisdiction of courts outside the U.S. or may not be successful in subjecting
non-U.S. persons to the jurisdiction of courts in the U.S., which could
adversely affect the outcome of such a dispute.
13
<PAGE> 18
In late 1995, the Hydrocarbons Ministry of the government of the Republic
of Congo (Brazzaville) notified us as operator of the Marine I Exploration
Permit offshore Congo, which includes the Yombo Field, that it would like to
convert the concession governing the participants' interests in this project to
a production sharing contract. The Congolese government has significant leverage
to request changes due to its broad governmental and regulatory powers.
Discussions with the Congolese government concerning its request began in March
1996 but were subsequently suspended. The discussions recently resumed and will
likely continue into 2001. Although the Congolese government has indicated that
it desires to achieve economic parity in effecting the contract conversion, we
cannot currently predict what impact, if any, these discussions will have on the
project's economics, and we cannot assure you that these discussions or their
outcome will not have a material adverse effect on our estimated reserves or
financial results.
There are uncertainties associated with conducting our businesses in the
Republic of Equatorial Guinea.
The Alba Field within the Bioko Permit, which represents 70.1% of our
estimated proved reserves, and the methanol production plant in which we have
agreed to acquire an interest are both located in the territory of the Republic
of Equatorial Guinea in West Africa. As with many emerging markets, there are
uncertainties associated with conducting business in this Republic, including
expropriation, renegotiation or nullification of existing contracts, that could
affect the ownership of and operation of our assets there. The U.S. Government
and the United Nations have raised concerns regarding human rights issues in the
Republic, and the International Monetary Fund has raised concerns regarding
financial transparency issues in the Republic. We understand that these
organizations are currently working with the government of Equatorial Guinea to
address these issues.
We face various operating hazards typical of the oil and natural gas business,
some of which are not insurable.
The oil and natural gas business involves various operating hazards such
as:
- well blowouts;
- cratering;
- explosions;
- uncontrollable flows of underground natural gas, oil or formulation
water;
- fires;
- formation with abnormal pressures;
- pollution;
- releases of toxic gas; and
- other environmental hazards and risks.
We could experience substantial losses from any of these hazards. Our
offshore operations also are subject to the additional hazards of marine
operations, such as severe weather, capsizing and collision. In addition, we may
be legally responsible for environmental damages caused by previous owners of
property which we have purchased or leased. As a result, we may incur
substantial liabilities to third parties or governmental entities. The insurance
we maintain may not cover all of these risks and losses. The occurrence of such
an event not fully covered by insurance could have a material adverse effect on
our financial condition or results of operations.
The methanol plant in which we have agreed to acquire an indirect interest has
construction and operating risks and no operating history.
Completion of construction of the methanol plant in which we have agreed to
acquire an indirect interest is currently scheduled for May 2001. However,
completion of construction could be delayed or otherwise adversely affected by
factors such as shortages of material and labor, work stoppages, labor
14
<PAGE> 19
disputes, weather interferences, unforeseen engineering or environmental
problems, unanticipated cost overruns or other similar events which are beyond
our reasonable control.
Operation of the methanol plant will involve many risks that are typical in
the manufacturing of a chemical product. These risks include:
- the breakdown or failure of equipment or processes;
- the performance of the plant below expected levels of output or
efficiency;
- difficulties or delays in obtaining spare parts or equipment;
- interruptions in the supply of natural gas;
- the costs of shipping and handling methanol;
- labor disputes and strikes;
- industrial accidents;
- catastrophic events such as fires, tornadoes, typhoons, earthquakes,
floods or other similar events;
- changes in economic conditions; and
- changes in laws, such as environmental laws, tax laws or permit
requirements.
The occurrence of these or other events could significantly reduce or eliminate
revenues generated by sales of natural gas to the plant or by operation of the
plant and significantly increase the plant's operating and maintenance expenses.
The methanol plant has no operating history upon which to evaluate its
performance. The performance of the plant will depend on its management's
ability to address the risks encountered by development-stage companies and to
implement the business plan of the joint venture which owns the plant. The
methanol plant may not be successful in implementing the business plan, and if
it is not, its as well as our financial position and results of operations could
be adversely affected. Even if the joint venture is successful in implementing
its business plan, the financial position or results of operations of the
methanol plant may not meet expectations.
The notes issued by Atlantic Methanol Capital, in which we have agreed to
acquire an interest, may be accelerated by events outside of our control, and
if that happens we could be required to fund the repayment of these notes or
lose up to 60% of our interest in the methanol production plant.
Under the indenture relating to the notes of Atlantic Methanol Capital
issued to finance a portion of CMS Gas Transmission's investment in the methanol
production plant, if these notes are not repaid, the occurrence of various
trigger events, many of which are related to the stock price and credit quality
of CMS Energy, will allow the indenture trustee to exercise its remedies with
respect to the security for the notes. These remedies include foreclosure on 60%
of our interest in the methanol facility, which has been pledged to secure the
notes. In addition, we have agreed to indemnify CMS Energy for any costs or
expenses incurred by it in connection with the repayment of the principal of or
interest on these notes.
Our operations are subject to extensive governmental regulation, which may
adversely affect our ability to conduct our business or increase our costs.
Our operations are subject to regulation at the federal, state and local
levels in the U.S. and by other countries in which we conduct business,
including regulation relating to matters such as the exploration for and the
development, production, marketing, pricing, transmission and storage of oil and
natural gas, as well as environmental and safety matters. Failure to comply with
these regulations could result in substantial liabilities to third parties or
governmental entities, the payment of which could have a material adverse effect
on our financial condition or results of operations. Moreover, laws or
regulations enacted in the future or the modification of existing laws or
regulations could adversely affect our exploration for or development,
production or marketing of oil or natural gas or our production of methanol.
15
<PAGE> 20
Our operations are subject to significant environmental laws and regulations,
which may adversely affect our ability to conduct our business or increase our
costs.
Extensive federal, state and local laws and regulations relating to health
and environmental quality in the U.S., as well as environmental laws and
regulations of other countries in which we operate, affect nearly all of our
operations. These laws and regulations set various standards regulating various
aspects of health and environmental quality, provide for penalties and other
liabilities for the violation of these standards and in some circumstances
establish obligations to remediate current and former facilities and off-site
locations. We could incur significant liability for damages, clean-up costs
and/or penalties in the event of discharges into the environment, environmental
damage caused by us or previous owners of our property or non-compliance with
environmental laws or regulations. This liability may include response costs
under the Comprehensive Environmental Response, Compensation and Liability Act
or state counterparts. In addition to actions brought by governmental agencies,
we could face actions brought by private parties or citizens groups. This
liability could have a material adverse effect on our financial results.
Moreover, we cannot predict what environmental legislation or regulations will
be enacted in the future or how existing or future laws or regulations will be
administered, enforced or made more stringent. Our Powder River Basin coal bed
methane drilling results in the discharge of large volumes of water into
adjacent lands and waterways. While current activities are done under permits,
the environmental soundness of this practice is coming under increased scrutiny.
Moratoriums on issuance of additional permits, or more costly methods of
handling these produced waters, may affect future well development. Compliance
with more stringent laws or regulations, or more vigorous enforcement policies
of the regulatory agencies, or difficulties in negotiating required surface use
agreements with land owners, could delay our Powder River Basin drilling program
and/or require us to make material expenditures for the installation and
operation of systems and equipment for remedial measures, all of which could
have a material adverse effect on our financial condition or results of
operations.
About one-third of our acreage in the Powder River Basin is U.S. federal
land and therefore subject to the environmental impact statement, or EIS,
process under the National Environmental Policy Act. In addition, Montana has
its own EIS process applicable to non-federal lands. The EIS for the Wyoming
portion of the Powder River Basin federal lands was completed in the fall of
1999, but is in the process of being supplemented to support a substantially
larger number of wells. The Montana EIS process, which is being coordinated
between the federal Bureau of Land Management and Montana authorities, is just
getting under way. The EIS process, once completed, may not support all
potential coal bed methane production well prospects. Moreover, public
opposition to new drilling may cause relevant state or federal authorities to
impose production limits or other permit restrictions. For example, an
environmental organization recently challenged the ongoing permitting of coal
bed methane wells in Montana without completion of any site-specific or
programmatic environmental impact statement. We do not believe additional
environmental assessments are required under applicable legal requirements, and
we have moved to intervene in the lawsuit. However, in the event that additional
studies are required, this litigation could negatively impact our planned future
development activity in Montana. Any delays, limitations or denials with respect
to environmental or other approvals necessary for us to develop our acreage in
the Powder River Basin could adversely affect our financial condition or results
of operations.
In March 1999, the State of California ordered the phase-out of MTBE
(methyl tertiary-butyl ether) from reformulated gasoline by the end of 2002 in
accordance with an Executive Order of the Governor. MTBE, for which methanol is
an ingredient, is an oxygenate and octane enhancer for gasoline. The phase-out
is the result of concerns that MTBE may contaminate drinking water supplies due
to gasoline leaking from underground storage tanks. California's legislative
initiative and potentially similar legislative initiatives in other states or at
the federal level could materially reduce demand for MTBE throughout the U.S.
and elsewhere. Reduced demand for methanol resulting from reduced demand for
MTBE could adversely affect our financial position or results of operations.
16
<PAGE> 21
We face significant competition in all areas of our business.
The oil and natural gas industry is highly competitive. We face competition
in all aspects of our business, including:
- acquiring reserves, leases, licenses and concessions;
- obtaining the equipment and labor needed to conduct our operations; and
- marketing our oil and natural gas.
Our competitors include multinational energy companies, government-owned
oil and natural gas companies, other independent oil and natural gas concerns
and individual producers and operators. Because both oil and natural gas are
fungible commodities, the principal form of competition with respect to product
sales is price competition. Many competitors have financial and other resources
substantially greater than those available to us and, accordingly, may be better
positioned to acquire and exploit prospects, hire personnel and market
production. In addition, many of our larger competitors may be better able to
respond to factors such as changes in worldwide oil or natural gas prices or
levels of production, the cost and availability of alternative fuels or the
application of government regulations, which affect demand for our oil and
natural gas production and which are beyond our control. Moreover, many
competitors have established strategic long-term positions and maintain strong
governmental relationships in countries in which we may seek new entry. We
expect this high degree of competition to continue.
The methanol business in which we intend to engage through our acquisition
of an interest in Atlantic Methanol Capital is also highly competitive. Many of
the competitors are larger and have greater financial resources than the
methanol facility. These competitors of the methanol facility of Atlantic
Methanol Capital also may operate multiple plants, offsetting some risks to
which a single-plant producer such as the methanol facility may be subject.
Methanol consumers, additionally, may prefer the security of purchasing from a
multiple-plant producer. As a result, any level of demand established for the
methanol facility's product may not be maintained. In addition, the methanol
facility's business is based upon widely available technology. Accordingly,
barriers to entry, apart from capital availability, may be low, and the entrance
of new competitors into the industry may reduce the methanol facility's ability
to capture improving profit margins in circumstances where overcapacity in the
industry is diminishing. Developments such as these could have a negative impact
on the methanol facility's, and our, financial position or results of
operations.
Recent increases in the prices of oil and natural gas may make it more
difficult and costly for us to grow.
Our industry is currently experiencing a rapid and significant increase in
exploration, development, acquisition and production activity as a result of
recent increases in the prices of oil and natural gas. As competition in the
industry for labor, materials, including drilling rigs, services and acreage
intensifies, we may be forced to implement our plans at a substantially
increased cost or to postpone or forego expansion of our operations. We cannot
be certain that we will be able to implement our plans on a timely basis or at a
cost that is acceptable to us.
Acquisition prospects may be difficult to assess and may pose additional risks
to our operations.
After this offering, we expect to evaluate and, where appropriate, pursue
acquisition opportunities on terms our management considers favorable. In
particular, we expect to pursue acquisitions that have the potential to increase
our domestic natural gas reserves. The successful acquisition of producing
properties requires an assessment of:
- recoverable reserves;
- exploration potential;
- future oil and natural gas prices;
- operating costs;
17
<PAGE> 22
- potential environmental and other liabilities and other factors; and
- permitting and other environmental authorizations required for our
operations.
In connection with such an assessment, we would expect to perform a review
of the subject properties that we believe to be generally consistent with
industry practices. Nonetheless, the resulting conclusions are necessarily
inexact and their accuracy inherently uncertain, and such an assessment may not
reveal all existing or potential problems, nor will it necessarily permit a
buyer to become sufficiently familiar with the properties to fully assess their
merits and deficiencies. Inspections may not always be performed on every
platform or well, and structural and environmental problems are not necessarily
observable even when an inspection is undertaken.
Future acquisitions could pose numerous additional risks to our operations
and financial results, including:
- problems integrating the purchased operations, personnel or technologies;
- unanticipated costs;
- diversion of resources and management attention from our core business;
- entry into regions or markets in which we have limited or no prior
experience; and
- potential loss of key employees, particularly those of the acquired
organization.
RISKS RELATING TO OUR RELATIONSHIP WITH CMS ENERGY
Upon completion of this offering, CMS Energy will have significant influence
over our affairs, and our other shareholders will have little or no ability to
affect the outcome of shareholder voting during this time.
Upon completion of this offering, CMS Enterprises will own approximately
%, or approximately % if the underwriters exercise their over-allotment
option in full, of our outstanding common stock. As a result, unless CMS
Enterprises sells additional shares, CMS Enterprises and its parent company, CMS
Energy, will be able to elect, or have a significant influence over the election
of, all members of our board of directors and to have significant influence over
all matters submitted to a vote of our shareholders. CMS Enterprises and CMS
Energy will have significant influence over certain decisions with respect to:
- the composition of our board of directors and, through it, any
determination with respect to our business direction and policies,
including the appointment and removal of officers;
- approval of our exploration, development, capital, operating and
acquisition expenditure plans;
- any determination with respect to mergers or other business combinations;
- the acquisition or disposition of assets or businesses by us;
- our debt or equity financing, including future issuances of our common
stock or other securities;
- our capital structure and the amount and timing of any dividend payments;
and
- amendments to our Restated Articles of Incorporation and Restated Bylaws.
This concentration of ownership of our common stock may have an adverse
effect on the market price of the common stock.
Potential conflicts may arise between us and CMS Energy and its other
affiliates that may not be resolved in our favor.
The relationship between us and CMS Energy and its other affiliates may
give rise to conflicts of interest with respect to, among other things,
transactions and agreements among us and CMS Energy and its other affiliates,
issuances of additional shares of voting securities, the election of directors
or the payment of dividends, if any, by us. When the interests of CMS Energy and
its other affiliates diverge
18
<PAGE> 23
from our interests, CMS Energy may exercise its influence in favor of its own
interests or the interests of another of its affiliates over our interests.
Moreover, after completion of this offering and the election of three
independent directors, our board of directors will consist of seven members,
including one of our officers and three directors and/or officers of CMS Energy
or CMS Enterprises. As the individuals affiliated with CMS Energy perform their
duties to CMS Energy and to us, conflicts of interest and conflicting demands on
the amount of time these individuals will have available for our affairs may
arise. These conflicts may not be resolved in our favor.
Our intercompany agreements with CMS Energy and its other affiliates are not
the result of arm's-length negotiations with third parties.
We have entered or will enter into various agreements with CMS Energy and
some of its other affiliates which govern various transactions between us and
our ongoing relationship following completion of this offering, including
agreements relating to:
- management and other services;
- registration rights;
- tax separation;
- tax indemnities;
- transfer to us of CMS Gas Transmission's interest in Atlantic Methanol
Capital and related companies;
- provision of administrative support and brokerage services relating to
our hedging program;
- oil marketing;
- gas sales;
- gathering and field services; and
- conflicts of interest.
All of these agreements were or will be entered into in the context of a
parent-subsidiary relationship and were negotiated in the overall context of
this offering. These agreements may have terms and conditions that may be less
favorable to us than agreements that we might have negotiated at arm's-length
with independent parties. The prices charged by or to us pursuant to those
agreements under which we will provide a product or service to, or receive a
product or service from, CMS Energy may be different from the prices that we
might be able to receive from, or the prices that we may be required to pay to,
third parties for similar products or services. We and CMS Energy and its other
affiliates may enter into other material transactions and agreements from time
to time in the future.
A substantial portion of the proceeds from this offering inure to the benefit
of CMS Energy.
A substantial portion of the net proceeds from this offering will be paid
to CMS Enterprises as the selling shareholder. In addition, a substantial
portion of the net proceeds payable to us from this offering, together with the
estimated net proceeds from our concurrent offering of $200.0 million aggregate
principal amount of senior subordinated notes, will be used to repay
intercompany notes payable to CMS Energy.
RISKS RELATING TO THE SECURITIES MARKETS AND OWNERSHIP OF OUR COMMON STOCK
We will not pay dividends in the foreseeable future.
Except for our proposed distribution in December 2000 of a note payable to
our parent, CMS Enterprises, in the principal amount of $39.0 million, we have
not paid cash dividends or made any other distributions on our common stock
since 1989 and have no current plans to pay cash dividends on our common stock
in the foreseeable future. We currently intend to retain our cash for the
continued expansion of our business, including exploration, development and
acquisition activities. In addition, our credit facility as we expect it to be
in place as of the completion of this offering, as well as our senior
19
<PAGE> 24
subordinated notes, will likely contain customary financial and other covenants
that could have the effect of limiting our ability to pay dividends.
There is no prior market for our common stock, and our stock price may be
volatile.
Prior to this offering, there has been no public market for shares of our
common stock. Although we have applied to list our common stock on The New York
Stock Exchange, we cannot assure you that an active public market for our common
stock will develop or be sustained. Furthermore, the market price for our common
stock could decline below the public offering price set forth on the cover page
of this prospectus. We and the representative of the underwriters will determine
the initial public offering price based on the factors described under
"Underwriting." This determination may not necessarily equal the intrinsic
value, or fix the market value, of our common stock. The trading prices of our
common stock could be subject to significant fluctuations in response to
variations in results of operations and other factors.
The sale of shares of our common stock eligible for future sale may adversely
affect the price of our common stock.
Sales of substantial amounts of our common stock in the public market
following this offering could adversely affect the market price of the common
stock. We, CMS Enterprises, CMS Energy and each of our directors and executive
officers have agreed, for a period of days after the date of this
prospectus, not to offer, pledge, sell, contract to sell or otherwise dispose of
any shares of our common stock or other securities convertible or exchangeable
into our common stock (other than pursuant to employee stock incentive plans
existing or contemplated on the date of this prospectus and for other specified
purposes), without the prior written consent of Credit Suisse First Boston
Corporation. Upon expiration of this period, all shares of our common stock
held by CMS Enterprises will be eligible for sale in the public market, subject
to compliance with the volume and other limitations of Rule 144 under the
Securities Act of 1933, as amended. In addition, we intend to enter into a
registration rights agreement with CMS Enterprises pursuant to which CMS
Enterprises at any time may cause us to register under the Securities Act all or
any part of its shares of our common stock for sale into a public market or
otherwise. The sale of shares upon the expiration of this period, or the
perception of the availability of shares for sale, could adversely affect the
prevailing market price of our common stock.
Provisions in our organizational documents and state law could prevent or
delay a change of control of our company that a shareholder may consider
favorable.
Various provisions of our Restated Articles of Incorporation, Restated
Bylaws and change of control severance agreements which we have entered into
with some of our executive officers could delay, defer or prevent a change of
control of our company without further action by our shareholders, could
discourage potential investors from bidding for our common stock at a premium
over the market price of the common stock and could adversely affect the market
price of, and the voting and other rights of the holders of, the common stock.
In addition, the Michigan Business Corporation Act contains some provisions
which, among other things, restrict the ability of shareholders to cause a
merger or business combination with or obtain control of us. These provisions
may be considered disadvantageous by a shareholder.
20
<PAGE> 25
SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
Some of the information in this prospectus contains forward-looking
statements. Forward-looking statements give our current expectations or
forecasts of future events and are based on our management's beliefs, as well as
assumptions made by and information currently available to them. You can
identify these statements by the fact that they do not relate strictly to
historical or current facts. These statements may include the words
"anticipate," "believe," "budget," "estimate," "expect," "intend," "objective,"
"plan," "possible," "potential," "project" and other words and terms of similar
meaning in connection with any discussion of future operating or financial
performance.
Any or all of our forward-looking statements in this prospectus may turn
out to be wrong. They can be affected by inaccurate assumptions or by known or
unknown risks and uncertainties. Many of these factors, including the risks
outlined under "Risk Factors," will be important in determining our actual
future results, which may differ materially from those contemplated in any
forward-looking statements. These factors include, among others, the following:
- oil, natural gas and methanol price volatility;
- uncertainties in the estimates of proved reserves and in the projection
of future rates of production and timing of development expenditures;
- our ability to find and acquire additional reserves;
- risks associated with acquisitions, exploration, development and
production;
- operating hazards attendant to the oil and natural gas business;
- potential constraints on our ability to market reserves due to limited
transportation space;
- risks associated with the financing, construction and operation of the
methanol plant in which we expect to acquire an interest;
- climatic conditions;
- availability and cost of labor, material, equipment and capital;
- ability to employ and retain key managerial and technical personnel;
- international, national, regional or local political and economic
uncertainties, including changes in energy policies, foreign exchange
restrictions and currency fluctuations;
- adverse regulatory or legal decisions, including those under
environmental laws and regulations;
- the strength and financial resources of our competitors; and
- general economic conditions.
When you consider these forward-looking statements, you should keep in mind
these risk factors and other cautionary statements in this prospectus. Our
forward-looking statements speak only as of the date made.
21
<PAGE> 26
USE OF PROCEEDS
We estimate that the net proceeds to us from our sale of shares of
common stock will be approximately $140.3 million ($ million if the
underwriters exercise their over-allotment option in full), assuming an initial
public offering price of $ per share and after deducting underwriting
discounts and commissions and the portion of estimated offering expenses payable
by us. We further estimate that the net proceeds from our concurrent offering of
$200.0 million aggregate principal amount of senior subordinated notes will be
approximately $194.0 million, after deducting transaction expenses and issuance
discount.
We intend to use our net proceeds from this offering, together with our net
proceeds from our concurrent offering of senior subordinated notes, for
repayment of the outstanding balance under our credit facility and repayment of
three intercompany notes payable to CMS Energy or its affiliates, with any
remaining net proceeds to be used for general corporate purposes. As of
September 30, 2000, the amount of debt outstanding under our credit agreement
was $65.0 million and the amount due under one currently outstanding
intercompany note payable to CMS Energy was $62.2 million. Prior to the
completion of this offering, we expect to issue two additional intercompany
notes in the respective amounts of $39.0 million and approximately $137.0
million. For a description of these notes, as well as our currently outstanding
note payable to CMS Energy, please see "Relationship and Certain Transactions
with CMS Energy and Affiliates -- Contractual Arrangements -- Acquisition of
Methanol Plant," "-- Contractual Arrangements -- Note Payable to CMS
Enterprises" and "-- Certain Transactions -- CMS Notes." Following application
of the net proceeds of these offerings, we anticipate that the total amount of
our outstanding debt will be $203.3 million, consisting of $200.0 million of our
senior subordinated notes and $3.3 million of capitalized lease obligations.
Our current credit facility terminates on May 26, 2002 and the entire
unpaid principal balance and accrued interest are due and payable on that date.
At September 30, 2000, the average interest rate on borrowings under our credit
facility was approximately 7.63% per annum. Substantially all of the borrowings
under our credit facility were used for working capital and general corporate
purposes.
We will not receive any of the proceeds from the sale of common stock
offered by the selling shareholder. In the aggregate, CMS Energy will generate
funds of approximately $ million from these transactions, derived from a
combination of selling its shares of our common stock ($ million) and the
repayment of loans from CMS Energy to us (aggregating approximately $238.2
million).
DIVIDEND POLICY
Except for our proposed distribution in December 2000 of a note payable to
our parent, CMS Enterprises, in the principal amount of $39.0 million, we have
not declared or paid any cash dividends or made any other distributions on our
common stock since 1989, and we have no current plans to declare or pay cash
dividends on our common stock in the foreseeable future. We currently intend to
retain our future earnings and other cash resources for the continued expansion
of our business, including exploration, development and acquisition activities.
The payment and amount of any future cash dividends will be at the discretion of
our board of directors and will depend upon our future earnings, results of
operations, capital requirements, financial condition and other factors as our
board of directors deems relevant. In addition, our credit facility as we expect
it to be in place upon completion of this offering and the indenture governing
our concurrent offering of senior subordinated notes will likely contain
customary financial and other covenants that could have the effect of limiting
our ability to pay dividends.
22
<PAGE> 27
DILUTION
Our net tangible book value as of September 30, 2000 was approximately
$404.0 million, or $ per share of common stock. Net tangible book value per
share as of any date represents the amount of total tangible assets less total
liabilities as of that date, divided by the number of shares of common stock
then outstanding. Without taking into account any changes in the net tangible
book value after September 30, 2000, other than to give effect to our sale of
the shares of common stock offered hereby and our receipt of the estimated
net proceeds therefrom, our adjusted net tangible book value as of September 30,
2000 would have been approximately $ million, or $ per share of common
stock. This represents an immediate increase in net tangible book value of
$ per share to our existing shareholder and an immediate dilution of $
per share to investors in this offering. The following table illustrates this
dilution:
<TABLE>
<CAPTION>
PER SHARE
-------------
<S> <C> <C>
Assumed initial public offering price....................... $
Net tangible book value before this offering................ $
Increase attributable to new investors......................
-----
As adjusted net tangible book value after this offering.....
-----
Dilution to new investors.........................
=====
</TABLE>
The following table summarizes, on an adjusted basis as of September 30,
2000, the differences between CMS Enterprises and investors in this offering
with respect to the number of shares of common stock purchased from us, the
total consideration paid and the average price per share paid, based on an
assumed initial public offering price of $ per share and before deducting
the underwriting discounts and commissions and the portion of estimated offering
expenses payable by us.
<TABLE>
<CAPTION>
TOTAL
SHARES PURCHASED CONSIDERATION AVERAGE
---------------- ---------------- PRICE PER
NUMBER PERCENT AMOUNT PERCENT SHARE
------ ------- ------ ------- ---------
<S> <C> <C> <C> <C> <C>
CMS Enterprises...........................
New investors.............................
Total........................... 100.0% 100.0%
</TABLE>
These tables do not include shares of common stock reserved for
issuance under our stock option plan, under which we expect to grant options to
purchase shares of common stock to our executive officers and other key
employees upon completion of this offering at an exercise price equal to the
initial public offering price.
23
<PAGE> 28
CAPITALIZATION
The following table sets forth our capitalization as of September 30, 2000.
Our capitalization is presented:
- on an actual basis;
- on a pro forma basis to give effect to:
- our proposed distribution in December 2000 of a $39.0 million note
payable to our parent, CMS Enterprises; and
- our proposed acquisition of an indirect 45% interest in a methanol
production plant for a note in the principal amount of approximately
$137.0 million; and
- on a pro forma as adjusted basis to give effect to:
- our sale of shares of common stock in this offering at an assumed
initial public offering price of $ per share;
- our concurrent offering of $200.0 million aggregate principal amount of
our senior subordinated notes; and
- the application of the estimated net proceeds of $140.3 million and
$194.0 million, respectively, from this offering and our concurrent
offering of senior subordinated notes.
You should read this information in conjunction with "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
our historical consolidated financial statements and unaudited pro forma
consolidated financial statements and the related notes included elsewhere in
this prospectus.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 2000
--------------------------------
PRO FORMA
ACTUAL PRO FORMA AS ADJUSTED
------ --------- -----------
(UNAUDITED)
(IN MILLIONS)
<S> <C> <C> <C>
TOTAL DEBT, INCLUDING CURRENT MATURITIES:
Note payable to CMS Energy.............................. $ 62.2 $ 62.2 $ --
Note payable to CMS Gas Transmission.................... -- 137.0 --
Note payable to CMS Enterprises......................... -- 39.0 --
Credit facility......................................... 65.0 65.0 --
Senior subordinated notes............................... -- -- 200.0
Other(1)................................................ 3.3 3.3 3.3
------ ------ ------
Total debt, including current maturities................ 130.5 306.5 203.3
STOCKHOLDER'S EQUITY:
Preferred stock, no par value, 5,000,000 shares
authorized; no shares issued and outstanding, actual,
pro forma and pro forma as adjusted................... -- -- --
Common stock, no par value, 55,000,000 shares
authorized; shares issued and outstanding, actual
and pro forma; shares issued and outstanding, pro
forma as adjusted(2).................................. 267.1 267.1 407.4
Retained earnings....................................... 136.9 97.9 97.9
------ ------ ------
Total stockholder's equity.............................. 404.0 365.0 505.3
------ ------ ------
Total capitalization.................................. $534.5 $671.5 $708.6
====== ====== ======
</TABLE>
---------------
(1) "Other" debt consists of capitalized lease obligations in Equatorial Guinea.
(2) Excludes shares of our common stock issuable upon exercise of options
we expect to grant in connection with this offering and restricted
shares of common stock we expect to issue to our outside directors in
connection with this offering.
24
<PAGE> 29
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following table presents our selected historical consolidated financial
data as of the dates and for the periods indicated. The historical consolidated
financial data as of and for each of the five years in the period ended December
31, 1999 are derived from our consolidated financial statements which have been
audited by Arthur Andersen LLP, independent public accountants. The historical
consolidated financial data as of and for the nine months ended September 30,
1999 and 2000 are derived from our unaudited consolidated financial statements
which, in the opinion of management, contain all adjustments (consisting of
normal recurring adjustments) necessary for a fair presentation thereof. You
should read the following data in conjunction with "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and our historical
consolidated financial statements and unaudited pro forma consolidated financial
statements and related notes included elsewhere in this prospectus. The results
for the nine months ended September 30, 2000 are not necessarily indicative of
the results that may be achieved for the full year ending December 31, 2000.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
-------------------------------------------------------- --------------------
1995 1996 1997 1998 1999 1999 2000
--------- -------- -------- --------- --------- -------- ---------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Operating Revenues:
Oil and condensate................. $ 59,734 $ 79,694 $ 91,364 $ 66,821 $ 82,560 $ 58,858 $ 76,311
Natural gas........................ 50,056 61,904 56,369 56,103 54,664 39,590 35,684
Other operating.................... 6,952 8,503 8,472 4,395 5,538 2,828 6,506
--------- -------- -------- --------- --------- -------- ---------
Total operating
revenues(1)................ 116,742 150,101 156,205 127,319 142,762 101,276 118,501
Operating Expenses:
Depreciation, depletion and
amortization..................... 36,192 40,605 48,129 38,067 43,786 31,812 28,505
Operating and maintenance
expense.......................... 34,344 42,397 44,169 44,322 51,985 37,685 40,882
Exploration costs.................. 21,899 14,818 27,747 18,976 9,456 6,142 6,160
General and administrative......... 9,757 14,190 16,517 14,250 16,819 11,056 14,775
Production taxes and other......... 4,308 6,131 5,470 5,315 4,029 2,484 3,289
Cost of products sold.............. 1,057 -- -- -- -- -- --
--------- -------- -------- --------- --------- -------- ---------
Total operating expenses....... 107,557 118,141 142,032 120,930 126,075 89,179 93,611
--------- -------- -------- --------- --------- -------- ---------
Pretax operating income.............. 9,185 31,960 14,173 6,389 16,687 12,097 24,890
Other income......................... 10,736 3,934 13,146 1,233 712 879 32,842
Interest expense, net of capitalized
interest........................... 11,948 14,729 15,723 16,069 13,606 10,004 11,369
--------- -------- -------- --------- --------- -------- ---------
Income (loss) before income taxes.... 7,973 21,165 11,596 (8,447) 3,793 2,972 46,363
Total income tax provision
(benefit).......................... (7,403) 503 (6,982) (13,881) (14,082) (9,854) (2,516)
--------- -------- -------- --------- --------- -------- ---------
Income before extraordinary item..... 15,376 20,662 18,578 5,434 17,875 12,826 48,879
Extraordinary item, early retirement
of debt, net of income taxes....... (987) -- -- -- -- -- --
--------- -------- -------- --------- --------- -------- ---------
Net income........................... $ 14,389 $ 20,662 $ 18,578 $ 5,434 $ 17,875 $ 12,826 $ 48,879
========= ======== ======== ========= ========= ======== =========
Net income per common share.......... $ $ $ $ $ $ $
========= ======== ======== ========= ========= ======== =========
Average common shares outstanding....
OTHER DATA:
EBITDAX(2)........................... $ 67,276 $ 87,383 $ 90,049 $ 63,432 $ 69,929 $ 50,051 $ 59,555
Capital expenditures(3).............. 139,284(4) 76,313 120,774 142,196 153,253 55,321 85,503
Cash flow:
From operating activities.......... 46,500 72,400 75,431 89,516 66,756 15,420 (1,118)
From investing activities.......... (139,284) (76,313) (74,556) (142,196) (150,980) (54,106) 174,113
From financing activities.......... 99,200 9,900 (9,362) 52,014 88,687 45,074 (139,490)
</TABLE>
25
<PAGE> 30
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF SEPTEMBER 30,
---------------------------------------------------- -------------------
1995 1996 1997 1998 1999 1999 2000
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital(5)........................ $ 42,877 $ 52,606 $ 50,134 $ 44,592 $ 32,431 $ 60,868 $ 71,309
Investments and other assets.............. 28,958 26,278 16,758 22,993 25,281 16,538 10,026
Property, plant and equipment, net........ 288,838 311,524 332,591 424,970 526,464 446,192 421,735
Total assets.............................. 431,299 471,598 502,406 607,438 698,956 645,621 693,045
Long-term debt, including current
portion................................. 192,158 203,783 191,321 230,384 236,417 195,739 130,514
Stockholder's equity...................... 198,521 219,232 238,107 278,769 355,149 341,593 403,969
</TABLE>
---------------
(1) Total operating revenues include the effect of settlement of various hedging
transactions to which we have been a party. Excluding the impact of these
hedging transactions, total operating revenues for the years ended December
31, 1995, 1996, 1997, 1998 and 1999 would have been $113.8 million, $161.7
million, $175.4 million, $124.4 million and $163.8 million, respectively.
Excluding the impact of hedging transactions, total operating revenues for
the nine months ended September 30, 1999 and 2000 would have been $108.5
million and $162.3 million, respectively.
(2) EBITDAX is earnings before interest, income taxes, depreciation, depletion
and amortization, other income (expense), extraordinary item and exploration
costs. EBITDAX is presented to provide additional information about our
ability to meet our future requirements for debt service, capital
expenditures and working capital. EBITDAX should not be considered as an
alternative to net income as an indicator of operating performance or as an
alternative to cash flow as a measure of liquidity.
(3) Costs incurred for exploration, development and acquisition activities,
including such of those costs as are expensed under the successful efforts
method of accounting.
(4) Includes non-cash capital expenditures of $81.4 million relating to two
acquisitions completed in 1995.
(5) Excludes current maturities of long-term debt.
26
<PAGE> 31
UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL DATA
The following tables present our unaudited pro forma consolidated financial
data as of the dates and for the periods indicated.
The pro forma income statement and other data for the year ended December
31, 1999 and for the nine months ended September 30, 2000 give effect to the
transactions noted below as if these transactions had been completed on January
1 of the relevant period:
- our acquisition in October 1999 of an additional 11.5% interest in the
Bioko Permit offshore Equatorial Guinea and the disposition of our
properties in Michigan and Ecuador in March 2000 and June 2000,
respectively; and
- the application of the estimated net proceeds to us of $140.3 million
from shares sold by us in this offering and of $194.0 million from our
concurrent offering of $200.0 million aggregate principal amount of our
senior subordinated notes with an assumed annual interest rate of 9.5%.
The pro forma balance sheet data give effect to the transactions noted
below as if these transactions had been completed on September 30, 2000:
- our proposed distribution of a $39.0 million note payable to our parent,
CMS Enterprises; and
- our pending acquisition of an indirect 45% interest in a methanol
production plant for a note in the principal amount of approximately
$137.0 million.
The pro forma as adjusted balance sheet data give effect to these two
transactions, as well as our sale of shares of common stock in this
offering and our concurrent offering of $200.0 million aggregate principal
amount of our senior subordinated notes and the application of the estimated net
proceeds to us of $140.3 million and $194.0 million, respectively, from these
offerings, as if these transactions had been completed on September 30, 2000.
You should read the following data together with our historical
consolidated financial statements and related notes included elsewhere in this
prospectus. Our pro forma consolidated financial data are not necessarily
indicative of the financial position or results of operations that would have
been achieved if the pro forma transactions had occurred on the dates indicated
or the financial position or results of operations that will be achieved in the
future. The consolidated financial position and results of operations as of and
for the nine months ended September 30, 2000 are not necessarily indicative of
the financial position or results of operations that may be achieved as of and
for the full year ending December 31, 2000.
27
<PAGE> 32
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1999
<TABLE>
<CAPTION>
FINANCING PRO FORMA
HISTORICAL ACQUISITION DISPOSITIONS PRO FORMA TRANSACTIONS AS ADJUSTED
---------- ----------- ------------ --------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION DATA)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate........ $ 82,560 $ 3,005(1) $ 21,468(2) $ 64,097 $ -- $ 64,097
Natural gas............... 54,664 61(1) 37,227(2) 17,498 -- 17,498
Other operating........... 5,538 464(1) 1,547(2) 4,455 -- 4,455
-------- ------- -------- -------- -------- --------
Total operating
revenues............. 142,762 3,530 60,242 86,050 -- 86,050
-------- ------- -------- -------- -------- --------
Costs and Expenses:
Depreciation, depletion
and amortization........ 43,786 513(1) 22,559(2) 21,740 -- 21,740
Exploration costs......... 9,456 117(1) 1,659(2) 7,914 -- 7,914
Operating and
maintenance............. 51,985 964(1) 17,187(2) 35,762 -- 35,762
General and
administrative.......... 16,819 -- 525(2) 16,294 -- 16,294
Production taxes and
other................... 4,029 -- 3,458(2) 571 -- 571
-------- ------- -------- -------- -------- --------
Total operating
expenses............. 126,075 1,594 45,388 82,281 -- 82,281
-------- ------- -------- -------- -------- --------
Pretax operating
income (loss)............. 16,687 1,936 14,854 3,769 -- 3,769
Other income (expense)...... 712 -- 2,344(3) (1,632) -- (1,632)
Interest expense, net of
capitalized interest...... 13,606 2,813(4) 14,914(5) 1,505 18,095(9) 19,600
-------- ------- -------- -------- -------- --------
Income (loss) before income
taxes..................... 3,793 (877) 2,284 632 (18,095) (17,463)
Total income tax provision
(benefit)................. (14,082) (532)(6) (12,489)(6) (2,125) (6,333)(6) (8,458)
-------- ------- -------- -------- -------- --------
Net income (loss)........... $ 17,875 $ (345) $ 14,773 $ 2,757 $(11,762) $ (9,005)
======== ======= ======== ======== ======== ========
Net income (loss) per
common share.............. $ $ $ $ $ $
======== ======= ======== ======== ======== ========
Average common shares
outstanding...............
======== ======= ======== ======== ======== ========
Production:
Oil and gas condensate
(MMBbls)................ 7.3 0.2 2.1 5.4 -- 5.4
Gas (Bcf)................. 26.4 0.2 17.8 8.8 -- 8.8
NGLs (MMBbls)............. 0.4 0.1 0.2 0.3 -- 0.3
Total production
(MMBoe)................. 12.1 0.3 5.2 7.2 -- 7.2
Other Data:
EBITDAX(7)................ $ 69,929 $ 2,566 $ 39,072 $ 33,423 $ -- $ 33,423
Capital expenditures(8)... 153,253 -- 10,510 142,743 -- 142,743
</TABLE>
The accompanying notes are an integral part of these statements.
28
<PAGE> 33
UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
FINANCING PRO FORMA
HISTORICAL ACQUISITION DISPOSITIONS PRO FORMA TRANSACTIONS AS ADJUSTED
---------- ----------- ------------ --------- ------------ -----------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS AND PRODUCTION DATA)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate....... $ 76,311 $ -- $ 9,539(2) $66,772 $ -- $66,772
Natural gas.............. 35,684 -- 9,675(2) 26,009 -- 26,009
Other operating.......... 6,506 -- 430(2) 6,076 -- 6,076
-------- ---- ------- ------- ------- -------
Total operating
revenues............ 118,501 -- 19,644 98,857 -- 98,857
-------- ---- ------- ------- ------- -------
Costs and Expenses:
Depreciation, depletion
and amortization....... 28,505 -- 6,379(2) 22,126 -- 22,126
Exploration costs........ 6,160 -- 338(2) 5,822 -- 5,822
Operating and
maintenance............ 40,882 -- 6,316(2) 34,566 -- 34,566
General and
administrative......... 14,775 -- (170)(2) 14,945 -- 14,945
Production taxes and
other.................. 3,289 -- 1,120(2) 2,169 -- 2,169
-------- ---- ------- ------- ------- -------
Total operating
expenses............ 93,611 -- 13,983 79,628 -- 79,628
-------- ---- ------- ------- ------- -------
Pretax operating
income (loss)............ 24,890 -- 5,661 19,229 -- 19,229
Other income (expense)..... 32,842 -- 34,962(3) (2,120) -- (2,120)
Interest expense, net of
capitalized interest..... 11,369 -- 5,402(5) 5,967 8,733(9) 14,700
-------- ---- ------- ------- ------- -------
Income (loss) before income
taxes.................... 46,363 -- 35,221 11,142 (8,733) 2,409
Total income tax provision
(benefit)................ (2,516) -- (3,720)(6) 1,204 (3,057)(6) (1,853)
-------- ---- ------- ------- ------- -------
Net income (loss).......... $ 48,879 $ -- $38,941 $ 9,938 $(5,676) $ 4,262
======== ==== ======= ======= ======= =======
Net income (loss) per
common share............. $ $ $ $ $ $
======== ==== ======= ======= ======= =======
Average common shares
outstanding..............
======== ==== ======= ======= ======= =======
Production:
Oil and gas condensate
(MMBbls)............... 5.5 -- 0.9 4.6 -- 4.6
Gas (Bcf)................ 13.8 -- 4.2 9.6 -- 9.6
NGLs (MMBbls)............ 0.2 -- -- 0.2 -- 0.2
Total production
(MMBoe)................ 8.0 -- 1.6 6.4 -- 6.4
Other Data:
EBITDAX(7)............... $ 59,555 -- $12,378 $47,177 -- $47,177
Capital
expenditures(8)........ 85,503 -- 1,660 83,843 -- 83,843
</TABLE>
The accompanying notes are an integral part of these statements.
29
<PAGE> 34
UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
ISSUANCE OF FINANCING PRO FORMA
HISTORICAL ACQUISITION AFFILIATE NOTE PRO FORMA TRANSACTIONS AS ADJUSTED
---------- ----------- -------------- --------- ------------ -----------
(IN THOUSANDS, EXCEPT SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
ASSETS
Current Assets:
Cash................................. $ 39,925 $ -- $ -- $ 39,925 $ 31,079(10)(11) $ 71,004
Temporary cash investments........... 8,099 -- -- 8,099 -- 8,099
Accounts Receivable:
Joint interest, revenues and
other............................ 73,943 -- -- 73,943 -- 73,943
Income tax benefits................ 35,000 -- -- 35,000 -- 35,000
Notes receivable from affiliate...... 32,469 -- -- 32,469 -- 32,469
Inventories:
Crude oil.......................... 22,280 -- -- 22,280 -- 22,280
Materials and supplies............. 7,144 -- -- 7,144 -- 7,144
Other................................ 3,376 -- -- 3,376 -- 3,376
-------- -------- -------- -------- --------- --------
222,236 -- -- 222,236 31,079 253,315
-------- -------- -------- -------- --------- --------
Property, plant and equipment at cost,
successful efforts method............ 577,006 -- -- 577,006 -- 577,006
Less accumulated depreciation,
depletion and amortization......... 155,271 -- -- 155,271 -- 155,271
-------- -------- -------- -------- --------- --------
421,735 -- -- 421,735 -- 421,735
-------- -------- -------- -------- --------- --------
Investments and other assets........... 10,026 137,000(12) -- 147,026 6,000(10) 153,026
Deferred tax asset..................... 39,048 -- -- 39,048 -- 39,048
-------- -------- -------- -------- --------- --------
49,074 137,000 -- 186,074 6,000 192,074
-------- -------- -------- -------- --------- --------
Total Assets................... $693,045 $137,000 $ -- $830,045 $ 37,079 $867,124
======== ======== ======== ======== ========= ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term
debt............................... $ -- $ -- $ -- $ -- $ -- $ --
Accounts payable..................... 131,000 -- -- 131,000 -- 131,000
Accrued interest..................... 2,223 -- -- 2,223 -- 2,223
Notes payable to affiliates.......... 2,519 137,000(12) 39,000(13) 178,519 (176,000)(10) 2,519
Accrued taxes and other.............. 15,185 -- -- 15,185 -- 15,185
-------- -------- -------- -------- --------- --------
150,927 137,000 39,000 326,927 (176,000) 150,927
-------- -------- -------- -------- --------- --------
Long-term debt......................... 130,514 -- -- 130,514 72,829 203,343
-------- -------- -------- -------- --------- --------
Postretirement benefits and other
deferred charges..................... 7,635 -- -- 7,635 -- 7,635
-------- -------- -------- -------- --------- --------
Stockholder's Equity:
Preferred stock, no par value,
authorized 5,000,000 shares, no
shares issued and outstanding,
actual, pro forma and pro forma
adjusted........................... -- -- -- -- -- --
Common stock, no par value,
authorized 55,000,000 shares,
issued and outstanding actual
and pro forma, and pro forma as
adjusted........................... 266,466 -- -- 266,466 140,250(11) 406,716
Comprehensive income................. 651 -- -- 651 -- 651
Retained earnings.................... 136,852 -- (39,000)(13) 97,852 -- 97,852
-------- -------- -------- -------- --------- --------
403,969 -- (39,000) 364,969 140,250 505,219
-------- -------- -------- -------- --------- --------
Total Liabilities and
Stockholder's Equity......... $693,045 $137,000 $ -- $830,045 $ 37,079 $867,124
======== ======== ======== ======== ========= ========
</TABLE>
The accompanying notes are an integral part of these statements.
30
<PAGE> 35
NOTES TO UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS
(1) Represents the additional 11.5% interest acquired in the Bioko Permit
offshore Equatorial Guinea.
(2) Reflects actual revenues (net of hedging), direct operating expenses,
direct general and administrative expenses (net of Council of Petroleum
Accountants Societies (COPAS) reimbursements) and depletion and
depreciation associated with the Michigan and Ecuador properties that
were sold.
(3) Reflects the pretax gain on the sale of the Michigan and Ecuador
properties and interest income earned on unrepatriated cash proceeds
from the sale of the Ecuador properties, which is invested in an
interest bearing note with an affiliate.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, 1999 SEPTEMBER 30, 2000
----------------- ------------------
(IN THOUSANDS)
<S> <C> <C>
Related to:
Michigan sale............................... $ -- $ 9,400
Ecuador sale................................ -- 24,740
Interest income............................. 2,095 1,048
Other....................................... 249 (226)
------ -------
Adjustment............................... $2,344 $34,962
====== =======
</TABLE>
(4) Reflects the interest expense for the assumed cost of increased
borrowing on our credit facility for the acquisition of the additional
11.5% interest acquired in the Bioko Permit offshore Equatorial Guinea.
(5) Reflects the reduction of interest expense for the assumed pay down on
our credit facility.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, 1999 SEPTEMBER 30, 2000
----------------- ------------------
(IN THOUSANDS)
<S> <C> <C>
Related to:
Michigan sale............................... $11,140 $3,073
Ecuador sale................................ 3,774 2,329
------- ------
Adjustment............................... $14,914 $5,402
======= ======
</TABLE>
(6) Represents the pro forma adjustment for the income taxes, at our
effective income tax rate (including Section 29 tax credits) in the
applicable taxing jurisdiction.
(7) EBITDAX is earnings before interest, income taxes, depreciation,
depletion and amortization, other income (expense), extraordinary item
and exploration costs. EBITDAX is presented to provide additional
information about our ability to meet our future requirements for debt
service, capital expenditures and working capital. EBITDAX should not
be considered as an alternative to net income as an indicator of
operating performance or as an alternative to cash flow as a measure of
liquidity.
(8) Costs incurred for exploration, development and acquisition activities,
including such of those costs as are expensed under the successful
efforts method of accounting.
31
<PAGE> 36
(9) Reflects the adjustment to interest expense for the issuance of the
senior subordinated notes with an assumed annual interest rate of 9.5%:
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, 1999 SEPTEMBER 30, 2000
----------------- ------------------
(IN THOUSANDS)
<S> <C> <C>
Related to:
Interest on historical debt................. $(13,606) $(11,369)
Reduction of interest expense from property
sales.................................... 12,101 5,402
Interest expense on new borrowing........... 19,000 14,250
Amortization of debt financing costs........ 600 450
-------- --------
Adjustment............................... $ 18,095 $ 8,733
======== ========
</TABLE>
(10) Reflects our proposed issuance of $200.0 million aggregate principal
amount of senior subordinated notes ($194.0 million estimated net
proceeds) to pay down existing debt and provide cash for operating
purposes.
(11) Reflects the proceeds from the primary issuance of common stock
($140.3 million estimated net proceeds) to pay down existing debt and
provide cash for operating purposes.
(12) Reflects the pending acquisition of an indirect 45% interest in a
methanol production plant and a 50% interest in two affiliated
companies for a non-interest bearing note to an affiliate.
(13) Reflects our proposed distribution of a non-interest bearing note
payable to CMS Enterprises.
32
<PAGE> 37
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of our
historical financial position and results of operations for each of the three
years in the period ended December 31, 1999 and our unaudited historical
financial data as of and for the nine months ended September 30, 1999 and 2000.
Our historical consolidated financial statements and notes thereto included
elsewhere in this prospectus contain detailed information that should be
referred to in conjunction with the following discussion. Additional financial
information appears in this prospectus under "Unaudited Pro Forma Consolidated
Financial Data."
GENERAL
We are an independent oil and natural gas company engaged in the
exploration, development and acquisition of oil and natural gas properties in
the U.S. and six other countries. Our oil-producing assets are concentrated in
Africa (Equatorial Guinea, the Republic of Congo (Brazzaville) and Tunisia) and
South America (Venezuela and Colombia), and our gas-producing assets are
concentrated in the U.S. (Texas, Wyoming and Louisiana), Tunisia and Equatorial
Guinea.
The following events have recently had, and will continue to have, a
significant impact on our results of operations and financial condition:
- our acquisition in October 1999 of an additional 11.5% interest in the
Bioko Permit offshore Equatorial Guinea and the initiation of an
accelerated development project related to the Alba Field;
- our pending acquisition from CMS Gas Transmission of an indirect 45%
interest in a methanol production plant under construction in Equatorial
Guinea for a note in the principal amount of approximately $137.0 million
and the expected commencement in May 2001 of gas sales to the plant and
production of methanol by the plant;
- the disposition in March 2000 of our Michigan oil and gas producing
properties, consisting principally of Antrim Shale natural gas
properties, for approximately $162.9 million in cash;
- the disposition in June 2000 of our oil-producing interests in Ecuador,
consisting of Block 16 and related fields in the Oriente Basin of the
Ecuadorian Amazon region, for approximately $95.8 million in cash;
- our exploration and development activities relating to our Powder River
Basin and West Texas properties and related expected increases in
production;
- our development activities in the Marine Exploration I Permit offshore
the Republic of Congo (Brazzaville);
- our acquisition of a 100% working interest in the Torbellino Block in
Colombia, adjacent to the Espinal and Abanico Blocks in which we have
interests, and the drilling of an aggregate of four new producing
development wells and one new producing exploration well since January
1999 in the latter two blocks; and
- the anticipated drilling of four new development wells in the La Palma
Field and one exploration well in the Socuavo Field in the Colon Block in
Venezuela.
See "Business and Properties -- Recent Developments" "-- International Oil
and Gas Operations" and "-- Domestic Oil and Gas Operations."
We follow the successful efforts method of accounting for our oil and gas
activities. Under the successful efforts method, lease acquisition costs and all
development costs are capitalized. Proved properties are reviewed whenever
events or changes in circumstances indicate that the value of that
33
<PAGE> 38
property on our books may not be recoverable. Unproved properties are reviewed
quarterly to determine if there has been impairment of the carrying value, with
any such impairment charged to expense in the period. Exploratory drilling costs
are capitalized until the results are determined. If proved reserves are not
discovered, the exploratory costs are expensed. Other exploratory costs are
expensed as incurred. The provision for depreciation, depletion and amortization
is based on the capitalized costs as determined above, plus future costs to
abandon offshore wells and platforms, and is on a cost center by cost center
basis using the units of production method.
We periodically utilize hedging arrangements, such as options, futures and
swap agreements, with respect to portions of our oil and natural gas production
to achieve more predictable cash flows and to reduce our exposure to
fluctuations in oil and natural gas prices. We may employ these hedging
arrangements with respect to some or all of that portion of our annual oil and
natural gas production which is sold at variable or market-sensitive pricing
when we view market prices as favorable compared to our projections of future
prices. For the nine months ended September 30, 2000, the portion of our oil and
natural gas production sold at variable pricing was approximately 4.0 MMBbls
(73% of our oil production) and 10.3 Bcf (75% of our natural gas production). In
connection with this offering, we expect to adopt new policies and procedures to
govern our hedging. Under these policies and procedures, the objective of our
hedging program will be to protect the amount of our cash flow required for debt
service and firm capital expenditures. The hedging plan will be approved by our
board of directors based on recommendations by our management. For purposes of
these procedures, firm capital expenditures are considered those:
- which, if not made, would expose us to material loss, including legal
liability for breach of contract or penalty or property forfeiture; or
- associated with projects expected to pay out in two years or less.
The risks to be managed are commodity price and basis risks.
For a more detailed description of our hedging arrangements, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions." To the extent utilized, these hedging
arrangements tend to have the effect of decreasing susceptibility of our cash
flows to fluctuations in oil and natural gas prices. However, these arrangements
also limit the benefits we realize if prices increase.
With respect to the Marine I Permit in the Congo, we have entered into a
price sharing agreement with BP Amoco Corporation providing for the sharing of
revenues upon oil prices exceeding a benchmark price, which is currently set at
$15.19 per barrel for 2000 and is adjusted annually by changes in the Consumer
Price Index.
The license governing our properties in Venezuela is an oil service
contract whereby we receive a fee per barrel produced and delivered to Petroleos
de Venezuela S.A. Additionally, we receive a fee for reimbursement of various
capital expenditures. Our per barrel fees relating to this production are
generally significantly lower than market prices for oil. The volumes presented
represent actual production with respect to which we are paid a per barrel fee.
Through March 2000, we generated significant amounts of nonconventional
fuels (Section 29) tax credits as a result of the sale of natural gas produced
from Antrim Shale and, to a lesser extent, tight sands wells. For instance, for
the year 1999, we generated approximately $13.0 million of Section 29 tax
credits; for the first quarter of 2000, we generated Section 29 tax credits of
approximately $3.0 million. Due to the sale of our Michigan Antrim Shale
properties in March 2000, we do not expect that we will generate significant
Section 29 tax credits thereafter.
See "Risk Factors" for more information to assist in an understanding of
our results of operations and financial position.
34
<PAGE> 39
RESULTS OF OPERATIONS
Nine Months Ended September 30, 1999 Compared to Nine Months Ended September
30, 2000
The following table sets forth our selected oil and gas operating
statistics for the nine-month periods ended September 30, 1999 and 2000:
Selected Oil and Gas Operating Statistics
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
----------------- % INCREASE
1999 2000 (DECREASE)
------- ------- ----------
<S> <C> <C> <C>
Oil sales volumes (MBbls):
International........................................ 5,095 5,170 1
Domestic............................................. 350 340 (3)
Total........................................ 5,445 5,510 1
Average oil price (per Bbl):
Overall(1)........................................... $ 10.81 $ 13.85 28
Natural gas sales volumes (MMcf):
International........................................ 2,383 3,520 48
Domestic............................................. 17,048 10,320 (39)
Total........................................ 19,431 13,840 (29)
Average natural gas price (per Mcf)
Overall(1)........................................... $ 2.04 $ 2.58 26
NGL volumes (MBbls):
International........................................ 159 199 25
Domestic............................................. 117 37 (68)
Total........................................ 276 236 (14)
Average NGL price (per Bbl)
Overall.............................................. $ 7.56 $ 19.97 164
Operating expenses (per Boe):
Depreciation, depletion and amortization............. $ 3.55 $ 3.54 --
Operating and maintenance............................ 4.21 5.08 21
General and administrative........................... 1.23 1.83 49
</TABLE>
---------------
(1) Adjusted to reflect amounts received or paid under contracts entered into to
hedge the price of a portion of production, including $8.0 million and $41.5
million paid for settlement of oil hedging contracts in the nine-month
periods ended September 30, 1999 and 2000, respectively, and $1.1 million
received and $2.3 million paid for settlement of natural gas hedging
contracts in the nine-month periods ended September 30, 1999 and 2000,
respectively. Without giving effect to this price hedging, the overall
average oil price per barrel would have been $12.27 and $21.38, and the
overall average natural gas price per Mcf would have been $1.98 and $2.75,
for the nine-month periods ended September 30, 1999 and 2000, respectively.
See note 9 to our consolidated financial statements included elsewhere in
this prospectus.
Revenues
Oil and Condensate. Oil and condensate revenues increased $17.5 million,
or 30%, to $76.3 million for the nine months ended September 30, 2000 over the
comparable period in 1999 as a result of the average market price of oil and
condensate (adjusted for hedging) increasing $3.04, or 28%. We reported oil and
condensate production of 5,510 MBbls for the nine months ended September 30,
2000, an increase of 65 MBbls from 5,445 MBbls for the nine months ended
September 30, 1999. Production was higher in Venezuela (by 276 MBbls) due to the
completion of the two wells in the La Palma Field, West Texas (by 188 MBbls) due
to the completion of 34 wells in the Devonian and Spraberry formations, Colombia
(by 151 MBbls) due to the completion of three wells in the Espinal Block,
Equatorial Guinea (by 132 MBbls)
35
<PAGE> 40
due to the additional interest we acquired in October 1999 and the completion of
two Alba wells, and other (by 3 MBbls), partially offset by lower production
from Ecuador (by 513 MBbls) and Michigan (by 172 MBbls) due to the sale of those
assets during the period.
Natural Gas. Natural gas revenues decreased $3.9 million, or 10%, to $35.7
million for the nine months ended September 30, 2000 over the comparable period
in 1999 as a result of a 5.6 Bcf, or 29%, decline in production, which was
partially offset by the overall average net natural gas price (adjusted for
hedging) increasing $0.54 per Mcf. The decrease in volumes was due to lower
production from Michigan (by 8.9 Bcf) due to the sale of those assets and
Freshwater Bayou (by 0.8 Bcf), which was partially offset by increased
production in West Texas (by 2.4 Bcf) due to the drilling in the Devonian and
Spraberry prospects, Venezuela (by 0.7 Bcf) due to the drilling of the Espinal
Block wells, Powder River (by 0.6 Bcf) due to our drilling program there, and
other (by 0.4 Bcf).
Other Operating. Other operating revenues increased $3.7 million, or 132%,
to $6.5 million for the nine months ended September 30, 2000, from $2.8 million
for the nine months ended September 30, 1999. Other operating revenues includes
$4.7 million and $2.1 million of NGL revenues for the nine-month periods ending
September 30, 2000 and 1999, respectively. The increase was due to (1) a $12.41,
or 164%, per barrel increase in the average NGL price, which was partially
offset by reduced volume due to the sale of the Michigan assets, and (2) an
increase in other income in Tunisia (by $0.7 million) and Congo (by $0.2
million).
Cost and Expenses
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization, or DD&A, expenses decreased $3.3 million, or 10%, to $28.5 million
for the nine months ended September 30, 2000, from $31.8 million for the nine
months ended September 30, 1999, due primarily to reduced production volumes as
a result of the sale of the Michigan and Ecuador assets. Our overall DD&A rate
for the nine months ended September 30, 2000 was $3.54 per Boe, which did not
change materially from the comparable period in 1999.
Exploration Expense. Exploration costs increased $0.1 million, or 2%, to
$6.2 million for the nine months ended September 30, 2000, compared to the
comparable period in 1999. The increase in exploration costs was due primarily
to higher impairments of non-producing leasehold (by $0.9 million) which was
partially offset by lower geological and geophysical costs (by $0.8 million).
Operating and Maintenance. Operating and maintenance, or O&M, expenses
increased $3.2 million, or 8%, to $40.9 million for the nine months ended
September 30, 2000 compared to the comparable period in 1999. The increase was
due primarily to our increased working interest and production in Equatorial
Guinea (by $2.6 million), initial production in the Powder River Basin (by $1.6
million) and West Texas (by $1.1 million), increased activity in Venezuela (by
$1.0 million), and increased operations overhead costs (by $0.8 million) and
plug and abandonment costs (by $0.5 million), which were partially offset by
reduced costs due to the sale of our Michigan (by $4.1 million) and Ecuador (by
$0.1 million) properties and other reductions (by $0.2 million).
General and Administrative. General and administrative, or G&A, expenses
of $14.8 million for the nine months ended September 30, 2000 was $3.7 million,
or 34%, higher than the comparable period in 1999. The increase in G&A was due
primarily to higher information services costs (by $1.6 million) and reduced G&A
costs billed to third parties (by $1.9 million) in the nine months ended
September 30, 2000, due to the sale of our Michigan assets, and due to other
costs (by $0.2 million).
Production and Other Taxes. Production and other taxes increased $0.8
million, or 32%, to $3.3 million for the nine months ended September 30, 2000 as
compared to the comparable period in 1999, primarily due to an adjustment of a
potential state tax liability recorded in 1999.
Other Income and Expense. Other income and expense increased $32.0 million
to $32.8 million for the nine months ended September 30, 2000 as compared to the
comparable period in 1999. The increase was due to recording gains on the sale
of our Ecuador ($24.7 million) and Michigan ($9.4 million) assets
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<PAGE> 41
and increased interest income on affiliate loans (by $0.5 million), which was
partially offset by losses on the sale of other assets and other non-operating
costs (by $2.6 million).
Interest Expense, Net of Capitalized Interest. Interest expense increased
$1.4 million, or 14%, for the nine months ended September 30, 2000 as compared
to the comparable period in 1999. The increase was due to higher average
interest rates of 7.47% for the period ended September 30, 2000, as compared to
6.15% for the nine months ended September 30, 1999, and a reduction of interest
capitalized by $1.3 million, which was partially offset by lower borrowings
under our credit facility. Our long-term debt balance as of September 30, 2000
was $130.5 million, compared to $195.7 million as of September 30, 1999.
Income Taxes. Income tax benefit of $2.5 million decreased $7.3 million,
or 74%, for the nine months ended September 30, 2000 as compared to the
comparable period in 1999. The decrease in the tax benefit was due to reduced
Section 29 tax credits (by $5.9 million) as a result of the sale of our Michigan
assets, as well as an increase in taxable domestic income.
Pretax Operating Income and Earnings
Our pretax operating income for the nine months ended September 30, 2000
increased $12.8 million, or 106%, to $24.9 million, from $12.1 million for the
nine months ended September 30, 1999. Net income increased $36.1 million, or
282%, to $48.9 million in the nine months ended September 30, 2000 from $12.8
million for the nine months ended September 30, 1999.
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
The following table sets forth our selected oil and natural gas operating
statistics for 1998 and 1999:
Selected Oil and Gas Operating Statistics
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, %
----------------- INCREASE
1998 1999 (DECREASE)
------- ------- ----------
<S> <C> <C> <C>
Oil Sales Volumes (MBbls):
International........................................ 6,811 6,800 --
Domestic............................................. 498 488 (2)
Total........................................ 7,309 7,288 --
Average oil price (per Bbl):
Overall(1)........................................... $ 9.14 $ 11.33 24
Natural gas sales volumes (MMcf):
International........................................ 1,891 3,327 76
Domestic............................................. 24,604 23,085 (6)
Total........................................ 26,495 26,412 --
Average natural gas price (per Mcf)
Overall(1)........................................... $ 2.12 $ 2.07 (2)
NGL volumes (MBbls):
International........................................ 213 230 8
Domestic............................................. 200 166 (17)
Total........................................ 413 396 (4)
Average NGL price (per Bbl)
Overall.............................................. $ 6.70 $ 9.38 40
Operating expenses (per Boe):
Depreciation, depletion and amortization............. $ 3.14 $ 3.62 15
Operating and maintenance............................ 3.65 4.30 18
General and administrative........................... 1.17 1.39 19
</TABLE>
---------------
(1) Adjusted to reflect amounts received or paid under contracts entered into to
hedge the price of a portion of production, including $20.3 million paid for
settlement of oil hedging contracts in the year ended December 31, 1999 and
$2.9 million received and $0.1 million paid for settlement of natural gas
hedging contracts in the years ended December 31, 1998 and 1999,
respectively. Without giving effect to this price hedging, and the overall
average oil price per barrel would have been $9.14 and
37
<PAGE> 42
$14.12, and the overall average natural gas price per Mcf would have been
$2.01 and $2.07, for the years ended December 31, 1998 and 1999,
respectively. See note 9 to our consolidated financial statements included
elsewhere in this prospectus.
Revenues
Oil and Condensate. Oil and condensate revenues of $82.6 million in 1999
increased $15.8 million, or 24%, over 1998 revenues of $66.8 million due to a
$2.19, or 24%, per barrel increase in the overall oil price, net of hedging. We
reported oil and condensate production of 7,288 MBbls in 1999, a decrease of 21
MBbls over the prior year's volumes of 7,309 MBbls. Production was lower due to
normal production declines in Colombia (by 233 MBbls), Venezuela (by 221 MBbls),
Ecuador (by 181 MBbls) and the U.S. (by 12 MBbls), partially offset by higher
production due to the completion of new wells in Congo (by 375 MBbls), Tunisia
(by 168 MBbls) and Equatorial Guinea (by 83 MBbls).
Natural Gas. Natural gas revenues decreased $1.4 million, or 3%, in 1999
to $54.7 million, compared to $56.1 million in 1998, as a result of a 0.1 Bcf
decline in production and a $0.05 per Mcf decline in overall gas price, net of
hedging. The decrease in volumes was due to lower production due to normal
production declines in Michigan (by 1.6 Bcf), partially offset by increased
production due to new wells in Tunisia (by 1.2 Bcf) and start-up production in
West Texas (by 0.3 Bcf).
Other Operating. Other operating revenues of $5.5 million increased $1.1
million, or 26%, in 1999 from the prior year. Other operating revenue includes
$3.7 million and $2.8 million from the sale of NGLs for 1999 and 1998,
respectively. The increase was due to a $2.68, or 40%, per barrel increase in
the average NGL price (by $0.9 million) and an increase in other revenues (by
$0.2 million).
Cost and Expenses
Depreciation, Depletion and Amortization. DD&A expenses increased $5.7
million, or 15%, to $43.8 million in 1999, from $38.1 million the prior year due
primarily to higher depletion rates. Our overall 1999 DD&A rate of $3.62 per Boe
increased $0.48 per Boe, or 15%, compared to $3.14 per Boe in 1998.
Exploration Expense. Exploration costs decreased $9.5 million, or 50%, to
$9.5 million in 1999, from $19.0 million in 1998, due primarily to our
successful exploratory program in 1999. In 1998, we expensed $13.7 million of
exploratory dry holes compared to no dry hole costs in 1999. Partially
offsetting the decrease in exploratory dry holes was an increase in delay
rentals and lease expense of $3.2 million over 1998, which included a $2.0
million write-off of undeveloped leasehold in the Cote d'Ivoire and higher
exploration overhead costs ($0.6 million).
Operating and Maintenance. O&M expenses increased $7.7 million, or 17%, to
$52.0 million in 1999, from $44.3 million the prior year. The higher O&M costs
reflect increased costs in Ecuador (by $2.5 million) due to higher operating
costs, Tunisia (by $1.7 million) due to a new well beginning production in
mid-1998, Equatorial Guinea (by $1.5 million) due to our increased interest in
the project, and Colombia (by $0.3 million), and higher operational overheads of
$3.6 million due to setup costs of new district offices in Midland, Texas,
Denver, Colorado and Gillette, Wyoming, which were partially offset by lower O&M
costs incurred in the U.S. (by $0.9 million), Venezuela (by $0.8 million) and
Congo (by $0.2 million).
General and Administrative. G&A expenses of $16.8 million increased $2.5
million, or 18%, from $14.3 million in 1998. The increase in G&A costs primarily
reflects the higher costs related to shared corporate services provided by our
parent, costs related to relocate processes performed by our Traverse City
office to Houston and other general and administrative costs.
Production and Other Taxes. Production and other taxes decreased $1.3
million, or 25%, to $4.0 million in 1999, compared to $5.3 million in 1998, due
primarily to an adjustment of a potential state tax liability.
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<PAGE> 43
Other Income. Other income decreased $0.5 million, or 42%, to $0.7 million
in 1999, compared to $1.2 million in 1998, due primarily to an increase in the
recording of non-operating reserves of $1.2 million, which was partially offset
by a increase in gains on the sale of miscellaneous oil and gas assets of $0.7
million.
Interest Expense, Net of Capitalized Interest. Net interest expense of
$13.6 million decreased $2.5 million, or 16%, in 1999 from $16.1 million in 1998
reflecting certain months with higher debt levels. Interest expense capitalized
in 1999 increased by $1.6 million, from $0.4 million in 1998, to $2.0 million in
1999, due to ongoing development in the Powder River Basin in Wyoming and in
West Texas. The average interest rate per annum before capitalized interest was
7.0% compared to 6.6% per annum in 1998.
Income Taxes. Income tax benefit of $14.1 million increased $0.2 million,
or 1%, in 1999 compared to $13.9 million in 1998, due primarily to changes in
pre-tax income of our domestic corporations.
Pretax Operating Income and Earnings.
Our 1999 pretax operating income increased $10.3 million, or 161%, to $16.7
million, from $6.4 million in 1998. Net income of $17.9 million in 1999
increased $12.5 million, or 231%, compared to $5.4 million in 1998 as a result
of increased operating revenues.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
The following table sets forth our selected oil and natural gas operating
statistics for 1997 and 1998.
Selected Oil and Gas Operating Statistics
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
---------------- % INCREASE
1997 1998 (DECREASE)
------ ------- ----------
<S> <C> <C> <C>
Oil Sales Volumes (MBbls):
International......................................... 6,078 6,811 12
Domestic.............................................. 486 498 2
Total......................................... 6,564 7,309 11
Average oil price (per Bbl):
Overall(1)............................................ $13.92 $ 9.14 (34)
Natural gas sales volumes (MMcf):
International......................................... 707 1,891 167
Domestic.............................................. 26,450 24,604 (7)
Total......................................... 27,157 26,495 (2)
Average natural gas price (per Mcf)
Overall(1)............................................ $ 2.08 $ 2.12 2
NGL volumes (MBbls):
International......................................... 145 213 47
Domestic.............................................. 176 200 14
Total......................................... 321 413 29
Average NGL price (per Bbl)
Overall............................................... $15.87 $ 6.70 (58)
Operating expenses (per Boe):
Depreciation, depletion and amortization.............. $ 4.22 $ 3.14 (26)
Operating and maintenance............................. 3.87 3.65 (6)
General and administrative............................ 1.45 1.17 (19)
</TABLE>
---------------
(1) Adjusted to reflect amounts received or paid under contracts entered into to
hedge the price of a portion of production, including $1.8 million received
for settlement of oil hedging contracts in the year ended December 31, 1997
and $7.4 million paid and $2.9 million received for settlement of
39
<PAGE> 44
natural gas hedging contracts in the years ended December 31, 1997 and 1998,
respectively. Without giving effect to this price hedging, the overall
average oil price per barrel would have been $13.65 and $9.14, and the
overall average natural gas price per Mcf would have been $2.35 and $2.00,
for the years ended December 31, 1997 and 1998, respectively. See note 9 to
our consolidated financial statements included elsewhere in this prospectus.
Revenues
Oil and Condensate. Oil and condensate revenues decreased $24.5 million,
or 27%, to $66.8 million in 1998 over 1997 as a result of a $4.78, or 34%, per
barrel decrease in the overall average market price for oil to $9.14 per barrel
in 1998, from $13.92 per barrel (adjusted for hedging) in 1997, which was
partially offset by an increase in production of 0.7 MMBbls. Production was
higher in Venezuela (by 0.5 MMBbls), Equatorial Guinea (by 0.1 MMBbls) and
Tunisia (by 0.1 MMBbls).
Natural Gas. Natural gas revenues decreased $0.3 million in 1998 to $56.1
million, from $56.4 million in 1997 as a result of a 0.7 Bcf, or 2%, decrease in
natural gas production, partially offset by a $0.04, or 2%, per Mcf greater
average natural gas price, net of hedging.
Other Operating. Other operating revenues decreased by $4.1 million, or
48%, in 1998 from 1997. Other revenue includes NGL revenues of $2.8 million and
$5.1 million in 1998 and 1997, respectively. The decline in other revenue was
due primarily to the $9.17, or 58%, per barrel decline in the average NGL price
and the decline of miscellaneous income of $1.8 million.
Cost and Expenses
Depreciation, Depletion and Amortization. DD&A expenses decreased $10.0
million, or 21%, to $38.1 million in 1998, compared to $48.1 million in 1997,
due to an overall depletion rate of $3.14 per Boe in 1998, compared to $4.22 per
Boe in 1997.
Exploration Expenses. Exploration costs declined in 1998 by $8.7 million,
or 31%, to $19.0 million, from $27.7 million in 1997. The decline in exploration
costs was due primarily to a decline in exploratory dry holes being expensed in
1998 of $3.5 million, or 20%, to $13.7 million from $17.2 million in 1997, along
with a decline in geological and geophysical costs being expensed, per the
successful efforts method of accounting, of $1.5 million in 1998, from $6.9
million being expensed in 1997.
Operating and Maintenance. O&M expenses of $44.3 million in 1998 reflect
an increase of $0.1 million over 1997. Expenses increased in the LPG plant in
Equatorial Guinea and due to start up costs in Tunisia, which was partially
offset by lower operating costs in Ecuador as a result of switching from diesel
to gas powered generators.
General and Administrative. G&A expenses decreased $2.3 million, or 14%,
to $14.3 million in 1998 compared to 1997. The decrease was due primarily to the
costs associated with the relocation of our corporate offices from Jackson,
Michigan to Houston, Texas in 1997.
Production and Other Taxes. Production and other taxes decreased $0.2
million, or 4%, in 1998 compared to $5.5 million in 1997, due primarily to lower
domestic gas production.
Other Income. Other income decreased $11.9 million, or 91%, to $1.2
million in 1998 compared to 1997. The decrease was due primarily to gains on the
sale of our interests in Yemen ($9.3 million), Thunder Bay Pipeline ($1.1
million) and Wellcorps ($0.5 million) and a transfer fee earned on the sale of
an office building in Houston ($1.1 million) recognized in 1997.
Interest Expense, Net of Capitalized Interest. Net interest expense
increased $0.4 million, or 3%, to $16.1 million in 1998, compared to $15.7
million in 1997, due to higher debt levels and slightly higher interest rates.
Interest rates averaged 6.6% per annum in 1998 compared to 6.3% per annum in
1997. Our ending long-term debt balance of $230.4 million in 1998 increased
$39.1 million, or 20%, compared to $191.3 million in 1997.
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<PAGE> 45
Income Taxes. The income tax benefit of $13.9 million in 1998 was $6.9
million higher than the $7.0 million tax benefit in 1997. Lower income in 1998
was the primary cause of the higher tax benefit.
Pretax Operating Income and Earnings.
In 1998, our pretax operating income decreased $7.8 million, or 55%, to
$6.4 million, from $14.2 million in 1997. Net income decreased $13.2 million, or
71%, to $5.4 million, from $18.6 million in 1997, reflecting lower operating
income and an increase in net interest expense, partially offset by increase in
tax benefit.
LIQUIDITY AND CAPITAL RESOURCES
General
Our primary needs for capital, in addition to the funding of ongoing
operations, have been for the exploration, development and acquisition of oil
and natural gas properties and the repayment of principal and interest on debt.
Our primary sources of liquidity have been net cash provided by operating
activities, borrowings under our credit facility and borrowings and equity
infusions from our parent, CMS Enterprises, as needed. We budget our exploration
and development, or E&D, expenditures based upon projected cash flows, and
subject to contractual commitments, routinely adjust our E&D expenditures in
response to changes in projected cash flows.
We believe that cash generated from operations, the aggregate estimated net
proceeds to us from this offering and our concurrent offering of senior
subordinated notes and borrowing capacity under our credit facility as we expect
it to be in place upon completion of this offering will be sufficient to meet
our liquidity and capital requirements through the end of 2001. However, we may
need to access the public or private capital markets to fund our growth and
capital expenditures thereafter. In particular, we may need to access these
markets or to repatriate offshore income, with resultant triggering of U.S.
income taxes and increases to our deferred tax account, to fund our domestic
activities and debt repayment.
Operating Activities
Net cash provided by (used in) operating activities was $(1.1) million for
the nine months ended September 30, 2000, $66.8 million, $89.5 million and $75.4
million in the years ended December 31, 1999, 1998 and 1997, respectively. The
decline in 2000 of net cash provided by operating activities was due to
increased receivables due to higher oil and natural gas prices, timing of
payment of income tax receivables and an increase in deferred tax asset due to
the sale of the Michigan and Ecuador assets. The decline in net cash provided by
operating activities in 1999 was due to lower oil prices in December 1999 and
timing of crude oil liftings in the Congo. The increase in net cash provided by
operating activities in 1998 was due to an increase in current liabilities
associated with Powder River and our Michigan assets.
Financing Activities
Our total debt outstanding at September 30, 2000 was $130.5 million, a
decrease of $105.9 million, or 45%, from $236.4 million at December 31, 1999,
which was an increase of $6.0 million, or 3%, from $230.4 million at December
31, 1998.
Credit Facility. Our credit agreement with Bank One, N.A., as agent, which
we call our credit facility, currently provides a maximum lending commitment of
$225.0 million. The credit facility is subject to an aggregate borrowing base
limitation equal to the estimated loan value of our oil and natural gas
reserves, subject to exclusions, including exclusions for most of our
international reserves, based upon forecast rates of production and commodity
pricing factors, as periodically redetermined by the banks which are parties to
the credit facility. The banks have broad discretion in determining which of our
reserves to include in the borrowing base. As of September 30, 2000, the
borrowing base, and thus the total amount available for borrowing, was $100.0
million. Of that amount, $65.0 million in borrowings and a $5.0 million undrawn
letter of credit were outstanding at September 30, 2000. As of December 31,
1999,
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<PAGE> 46
the borrowing base, and accordingly, the total amount available for borrowing
under the credit facility, was $210.0 million. Of that amount, $175.0 million in
borrowings was outstanding at December 31, 1999. We expect that, in connection
with the concurrent offering of our senior subordinated notes, our borrowings
under the credit facility will be repaid in full and that the credit facility
will be renegotiated or replaced with a credit facility having a maximum lending
commitment of $75.0 million.
Under the terms of the credit facility, we must maintain: (1) a ratio of
total indebtedness to total capitalization of no more than 0.60 to 1; (2) a
minimum tangible net worth, as defined, of $275 million, plus 50% of positive
net income commencing with the quarter ended June 30, 1999, plus 50% of the net
proceeds of any equity sale, as defined; (3) a ratio of EBITDA to interest
greater than 2.75 to 1; and (4) a ratio of consolidated debt to adjusted cash
flow of no greater than 4.25 to 1 for any fiscal quarter ending at any time on
or after December 31, 1999 to and including September 30, 2000, or 3.75 to 1 for
any fiscal quarter thereafter. Restrictive covenants under the credit facility
include limitations on our indebtedness and contingent obligations, as well as
restrictions on liens, investments, affiliate transactions and sales of assets.
In addition, the banks have the right to require us to repay all advances under
the credit facility within 90 days after notification to the banks that (1) CMS
Energy no longer beneficially owns a majority of our outstanding voting stock or
(2) all or substantially all of our assets are sold.
The following table sets forth our status with respect to the financial
covenants under the credit facility as described above as of the dates
indicated:
<TABLE>
<CAPTION>
SEPTEMBER 30, 2000 DECEMBER 31, 1999
------------------ -----------------
<S> <C> <C>
Total indebtedness to total capitalization(1)....... 0.24 to 1 0.40 to 1
Tangible net worth(1)............................... $403.5 million $350.1 million
EBITDA to interest coverage(1)...................... 7.21 to 1 4.8 to 1
Consolidated debt to adjusted cash flow(1).......... .87 to 1 2.4 to 1
</TABLE>
---------------
(1) As defined in the credit facility.
CMS Energy Note. In 1995, we issued a note, which we call the CMS Energy
Note, in the principal amount of approximately $61.3 million to CMS Enterprises,
which in turn assigned it to CMS Energy in connection with the transfer of the
common stock of Terra Energy Ltd. by CMS Energy to CMS Enterprises and then by
CMS Enterprises to us. Also in 1995, we issued another note in the principal
amount of approximately $6.5 million to CMS Energy in connection with borrowings
made to repay $6.5 million of indebtedness of a subsidiary immediately upon our
acquisition of the subsidiary. In 1997, we made payments totaling $10.0 million
to extinguish the latter note and to reduce the CMS Energy Note. In 1999, the
CMS Energy Note was amended to extend its maturity to April 15, 2009 and to
suspend cash interest payments until April 14, 2004. Until that date, interest
accrues and is added to the outstanding debt balance. This note bears interest
at the three-month London Interbank Offered Rate, or LIBOR, plus 2.0% per year.
Amounts outstanding under this note are subordinate to the credit facility, and
we are subject to limitations on our obligation to make payments on it in the
event of a default under the terms of the credit facility. As of September 30,
2000 and December 31, 1999, $62.2 million and $58.5 million, respectively, of
principal and $1.2 million and $1.0 million, respectively, of accrued interest
were outstanding on the CMS Energy Note. We intend to use a portion of the
aggregate net proceeds to us from this offering and our concurrent offering of
senior subordinated notes to repay this note.
Acquisition of Methanol Plant. We have agreed to purchase, prior to
completion of this offering, CMS Gas Transmission's 50% voting interest in
Atlantic Methanol Capital and two affiliated companies. Through Atlantic
Methanol Capital, CMS Gas Transmission indirectly owns a 45% interest in a
methanol production facility currently in the late stages of construction on
Bioko Island in Equatorial Guinea. We will purchase these interests by issuance
to CMS Gas Transmission of a note in the principal amount of approximately
$137.0 million. We intend to use a portion of the aggregate net proceeds to us
from this offering and our concurrent offering of senior subordinated notes to
repay this note.
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<PAGE> 47
Atlantic Methanol Capital was established for the purpose of, among other
things:
- issuing $125.0 million of 10 7/8% Series A-1 Senior Secured Notes
relating to the financing of CMS Gas Transmission's indirect interest in
the plant; and
- issuing $125.0 million of 8.95% Series A-2 Senior Secured Notes relating
to the financing of Noble Affiliates, Inc.'s indirect interest in the
plant.
Each of the Series A-1 Notes and the Series A-2 Notes are limited recourse and
independent of each other, and holders of the notes have recourse only to the
respective security for the notes.
Atlantic Methanol Capital used a portion of the proceeds of the sale of the
Series A-1 Notes and the Series A-2 Notes to purchase a portion of the
respective ownership interests in CMS Methanol Company and Samedan Methanol,
which prior to this transaction were wholly-owned subsidiaries of CMS Gas
Transmission and Noble, respectively. CMS Gas Transmission and Noble contributed
to Atlantic Methanol Company the remainder of their respective ownership
interests in CMS Methanol Capital and Samedan Methanol as equity for their
ownership in Atlantic Methanol Capital. CMS Methanol Company and Samedan
Methanol each have an indirect 45% ownership interest in Atlantic Methanol
Production Company, LLC, which is constructing and will operate the methanol
plant.
Although the Series A-1 Notes are not our direct obligations, we expect to
make payment of interest on these notes, which will amount to approximately
$13.6 million per year, using our available sources of capital. Under the terms
of our acquisition of CMS Gas Transmission's indirect interest in the methanol
facility, CMS Gas Transmission will be responsible for interest accrued on the
Series A-1 Notes through April 30, 2001.
We expect Atlantic Methanol Production to refinance the Series A-1 Notes at
or prior to their maturity from the proceeds of a project financing. If Atlantic
Methanol Production were unable to refinance the Series A-1 Notes, we expect to
access the public or private capital markets to retire these notes.
The occurrence of certain events will constitute a "trigger event" under
the indenture relating to the Series A-1 Notes, including:
- at least 120 days prior to the maturity date, which will be in December
2004 at the latest, an amount equal to the repayment amount has not been
deposited with the indenture trustee;
- a downgrading of CMS Energy unsecured senior debt to "B2" or below by
Moody's Investor Service or "B+" or below by Standard & Poor's
Corporation and a decline in the closing price of the CMS Energy common
stock, which continues for three consecutive trading days, to below
$24.00, after adjustment to reflect any stock split, stock dividend or
certain other events occurring with respect to that common stock;
- default by CMS Energy resulting in the acceleration of any of its
indebtedness in an aggregate amount in excess of $25.0 million, which
acceleration has not been rescinded within ten days after written notice
of default; or
- entry of final judgments against CMS Energy or any restricted CMS Energy
subsidiary aggregating in excess of $25.0 million which remain
undischarged or unbonded for a period of 60 days.
Upon the occurrence of a trigger event, the indenture trustee for the
Series A-1 Notes, with some exceptions, so long as those notes have not been
repaid may, or at the direction of holders of not less than 25% in aggregate
principal amount of all notes outstanding will, cause the remarketing of shares
of CMS Energy preferred stock, which have been placed in a share trust to secure
the notes, through a mandatory remarketing arrangement and to use the net
proceeds thereof to repay the Series A-1 Notes. In addition, the holders of the
notes have the right to look to the other security for the notes for repayment.
The security for the notes includes, in addition to the proceeds from the
remarketing of the CMS Energy preferred stock, CMS Energy's guarantee of all
interest payments due on the notes, subject to a $75.0 million aggregate limit,
and 60% of our stock of CMS Methanol Company, which indirectly owns our interest
in the methanol production facility.
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<PAGE> 48
We have agreed to indemnify CMS Energy and CMS Gas Transmission for any
costs or expenses incurred by either of them in connection with repayment of the
principal of or interest on the Series A-1 Notes.
Note Payable to CMS Enterprises. Prior to the completion of this offering,
we expect to distribute to our parent company, CMS Enterprises, a note payable
in the principal amount of $39.0 million. This note will not bear interest and
will become due and payable upon completion of this offering. We intend to use a
portion of the aggregate net proceeds to us from this offering and our
concurrent offering of senior subordinated notes to repay this note.
Senior Subordinated Notes. Concurrently with the completion of this
offering, we expect to issue and sell, in the public or private markets, $200.0
million aggregate principal amount of senior subordinated notes. We expect that
the net proceeds of this offering, after deducting transaction expenses and
issuance discount, will be approximately $194.0 million. We expect that the
indenture under which the senior subordinated notes will be issued will contain
limitations on incurrence of additional debt, payment of dividends or
distributions, sale or pledge of assets and other ordinary covenants. For a
discussion of our expected use of the proceeds from this offering, we refer you
to "Use of Proceeds."
Investing Activities
Our recent E&D investments have focused on a balance of acquisitions and
the development of existing properties, acquiring proved producing reserves in
established core areas (for example, the acquisition of our additional interest
in Equatorial Guinea), as well as establishing new producing leasehold positions
in core areas (Devonian, Spraberry and Clearfork plays in West Texas and the
Powder River Basin in Wyoming and Montana) for our development. For the
nine-month periods ended September 30, 2000 and 1999, our E&D expenditures were
$85.5 million and $55.3 million, respectively, excluding $259.6 million and $1.2
million, respectively, in proceeds from asset sales. Our E&D expenditures of
$151.0 million (net of $2.3 million in proceeds from asset sales) in 1999
represented an increase of $8.8 million, or 6%, over 1998. Our E&D expenditures
of $142.2 million for the year ended December 31, 1998 were $67.6 million, or
91%, higher than E&D expenditures of $74.6 million for 1997.
We have budgeted to spend approximately $152.6 million during 2000 and
$166.0 million during 2001 for exploration, development, leasehold acquisitions
and other capital expenditures.
Our budget includes development costs that are contingent on the success of
future exploratory drilling. We do not anticipate that our budgeted leasehold
acquisition activities will include the acquisition of producing properties. We
do not anticipate any significant abandonment or dismantlement costs through
2001. Actual levels of capital expenditures may vary significantly due to many
factors, including drilling results, natural gas and oil prices, industry
conditions, decisions of operators and partners and the prices of oil field
materials and services.
HEDGING TRANSACTIONS
We currently sell most of our natural gas and oil production under
contracts that call for payment of a purchase price that is based on a published
market reference price. To reduce our risk that market prices will fall, we
have, from time to time, entered into hedging contracts. These hedging contracts
take the form of swaps or other hedge contracts which we enter into with CMS
Enterprises, CMS MST or another affiliate.
The hedging contracts take several forms. Some are straight swaps (which
fix a price for a specified expiration date and a specified quantity of
product), some are collars (put options purchased by us matched to call options
sold by us establishing a floor and ceiling price) and some are put options. We
pay a premium for the put options (which when purchased by us permit us to sell
at the stated floor price).
Hedging contracts protect us from declines in prices but, except for puts,
they also limit the benefit we would otherwise have experienced from rising
prices. Put contracts allow us to benefit from price increases but involve a
premium expense. We generally have followed the practice of hedging some portion
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<PAGE> 49
of the anticipated production from our proved developed producing reserves but
have not hedged any part of anticipated production from our undeveloped or
unproved reserves.
For the nine months ended September 30, 2000, increasing prices have
allowed us to sell oil and gas at higher prices but have also produced losses on
the hedge positions of approximately $43.8 million. With respect to the
production that we have hedged, the net result of the prices we have received on
sales and the hedge losses have approximated the results of sales at the prices
fixed in the hedge contracts. We did not enter into any put option hedges (other
than in connection with collars) during the period.
The following chart summarizes the hedging contracts in place with respect
to production in future periods. WTI refers to the market for West Texas
Intermediate Crude Oil. Brent refers to the Brent market for North Sea oil.
Heating oil refers to the #6 fuel oil 1% market. One MMBtu approximates one Mcf
of gas.
<TABLE>
<CAPTION>
FOURTH FIRST SECOND THIRD FOURTH
QUARTER 2000 QUARTER 2001 QUARTER 2001 QUARTER 2001 QUARTER 2001
------------ -------------- ------------ ------------ ------------
<S> <C> <C> <C> <C> <C>
WTI HEDGES
Bbls Hedged.................. 6,435 30,000/225,000 30,000 30,000 30,000
Hedge Price ($ per barrel)... 17.51 29.35/26.60 29.35 29.35 29.35
HEATING OIL HEDGES (#6)
Bbls Hedged.................. 511,223 75,000 -- -- --
Hedge Price ($ per barrel)... 14.00 26.25 -- -- --
BRENT HEDGES
Bbls Hedged.................. 305,339 75,000 -- -- --
Hedge Price ($ per barrel)... 15.30 25.97 -- -- --
BRENT COLLARS
Bbls Hedged.................. -- 150,000 150,000 150,000 150,000
Floor Price ($ per barrel)... -- 23.80 23.80 23.80 23.80
Ceiling Price ($ per
barrel).................... -- 28.85 28.85 28.85 28.85
GAS HEDGES
MMBtu Hedged................. 763,500 -- -- -- --
Hedge Price ($ per MMBtu).... 2.44 -- -- -- --
GAS PUTS
MMBtu Hedged................. -- 750,000 755,000 760,000 760,000
Floor Price ($ per MMBtu).... -- 4.00 4.00 4.00 4.00
</TABLE>
We account for these contracts as hedges; accordingly, any changes in
market value and gains or losses from settlements are deferred and recognized at
the time the hedged transaction is completed.
For a discussion of expected changes in the policies applicable to our
hedging, we refer you to "Business and Properties -- Hedging Objectives."
YEAR 2000
We estimate that the total direct cost for the Year 2000 effort through
September 30, 2000 was approximately $0.6 million. Approximately $0.4 million
and $0.2 million were expensed in 1999 and the nine months ended September 30,
2000, respectively. We had no Year 2000-related costs for the years ended
December 31, 1997 and 1998. Replacement equipment and software were capitalized
or expensed in accordance with our normal accounting policies. The effect of
writing off the net book value of equipment or software that was not Year 2000
compliant is included in the above estimates.
INFLATION AND CHANGE IN PRICES
Our revenues and the value of our oil and natural gas properties have been
and will be affected by changes in oil and natural gas prices. Our ability to
obtain additional capital on satisfactory terms is also substantially dependent
on oil and natural gas prices, which are subject to seasonal and other
fluctuations
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<PAGE> 50
that are beyond our ability to control or predict. Although some of our costs
and expenses are affected by the level of inflation, inflation has not had a
significant effect on our results of operations during any of the three years in
the period ended December 31, 1999.
NEW ACCOUNTING POLICIES
In June 1998, the Financial Accounting Standards Board, or FASB, issued
SFAS No. 133, "Accounting for Derivative Investments and Hedging Activities."
SFAS 133 establishes accounting and reporting standards requiring that every
derivative instrument (including certain derivative instruments embedded in
other contracts) be recorded in the balance sheet as either an asset or
liability measured at its fair market value. The statement requires that changes
in the derivative's fair value be recognized currently in earnings unless
specific hedge criteria are met. Special accounting for qualifying hedges allows
a derivative's gains and losses to offset related results on the hedged item in
the income statement, and requires that a company must formally document,
designate and assess the effectiveness of transactions that receive hedge
accounting.
In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date of SFAS 133 to fiscal years beginning after June 15, 2000. A company may
implement SFAS 133 as of the beginning of any fiscal quarter after issuance,
however, the statement cannot be applied retroactively. We do not plan to adopt
SFAS 133 early. We have not yet assessed the effectiveness of our September 30,
2000 derivative contracts and therefore cannot quantify the impact of adoption
of SFAS 133. If we assume that all the derivative contracts at September 30,
2000 were ineffective, we would have recorded a current liability of
approximately $25.2 million, representing the fair value of all derivatives at
that date.
QUALITATIVE AND QUANTITATIVE DISCLOSURE ABOUT MARKET RISK
Commodity Risk
Our major commodity risk exposure is the pricing applicable to our oil and
natural gas production. Realized commodity prices received for our production
are primarily driven by the prevailing worldwide price for crude oil and spot
prices applicable to natural gas. Historically, prices received for oil and gas
production have been volatile and unpredictable and we expect price volatility,
and the effects of this volatility, to continue. For the nine months ended
September 30, 2000 a 10% fluctuation in the prices received for oil and gas
production would have had an approximate $4.0 million impact on our revenues and
operating income.
We periodically enter into hedging activities on a portion of our projected
proved developed oil and natural gas production through a variety of financial
and physical arrangements intended to support oil and natural gas prices as
targeted levels and to manage our exposure to oil and natural gas price
fluctuation. We may use futures contracts, swaps, options and fixed-price
physical contracts to hedge commodity prices. Realized gains or losses from our
price risk management activities are recognized in oil, condensate and natural
gas production revenues when the associated production occurs. We do not hold or
issue derivative instruments for trading purposes. In 1999, and in the
nine-month period ending September 30, 2000, we recognized a net loss of $20.3
million and $41.5 million, respectively, from hedging activities that decreased
oil and condensate production revenues and $0.1 million and $2.3 million,
respectively, from hedging activities that decreased natural gas production
revenues.
For a discussion of our recent hedging activity and expected changes in the
policies applicable to our hedging, we refer you to "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Hedging
Transactions" and "Business and Properties -- Hedging Objectives," respectively.
Interest Rate Risk
The carrying value of our debt approximates fair value. At December 31,
1999 and September 30, 2000, we had $235.6 million and $130.5 million,
respectively, of long-term debt, primarily represented by an unsecured revolving
credit facility totaling $175.0 million and $65.0 million, respectively, and
notes to
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<PAGE> 51
our indirect parent, CMS Energy, totaling $58.5 million and $62.2 million,
respectively. The notes payable to CMS Energy are expressly subordinated to the
credit facility. The credit facility matures May 25, 2002 and bears interest at
LIBOR plus a percentage based on the percentage of the borrowing base
outstanding and also requires a facility fee. The notes payable to CMS Energy
bear interest at the three-month LIBOR rate plus 200 basis points and mature
April 15, 2009. In regard to the credit facility and the notes payable to CMS
Energy, the results of a 10% fluctuation in short-term interest rates would have
had an approximate $1.4 million and $0.9 million impact on our cash flow for the
year ended December 31, 1999 and the nine months ended September 30, 2000,
respectively.
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<PAGE> 52
BUSINESS AND PROPERTIES
OVERVIEW
We are an independent energy company engaged in oil and natural gas
acquisition, exploration and development activities principally in Africa, the
U.S. and South America. Formed in 1967, we have grown our operations through
acquisition and exploration and are currently one of the larger U.S. based
independent oil and natural gas companies. Our strategy is to increase reserves,
production, cash flow and earnings by committing our resources to regions with
significant growth prospects and properties that allow us to leverage our
extensive operating and technical expertise.
On a pro forma basis, excluding our Michigan and Ecuador properties which
we recently sold, we have grown our production and estimated proved reserves at
annualized rates of 12.4% and 25.4%, respectively, from January 1, 1995 through
September 30, 2000. We have achieved these impressive growth rates by employing
a lower-risk, disciplined international and domestic acquisition, exploration
and development strategy. Internationally, we have been active in Africa and
South America for over a decade and currently have concessions which have
significant production, reserves and, we believe, reserve growth potential. We
are actively exploiting our properties in Equatorial Guinea, Colombia, Venezuela
and the Republic of Congo (Brazzaville). Domestically, we have built an
attractive reserve base and acreage holdings located principally in the Powder
River Basin of Wyoming and Montana and the Permian Basin of West Texas. We are
actively exploring and developing these domestic properties which have
increasing production and, we believe, significant reserve growth potential. We
expect to spend approximately $166.0 million in 2001 to further develop our
existing reserves and to pursue attractive exploration opportunities. We believe
that our regional operating philosophy, acreage and reserve positions and
management expertise provide us with significant opportunities for growth.
As of September 30, 2000, we had estimated proved reserves of 212.0 million
barrels of oil equivalent, or MMBoe, with a net present value (before taxes) of
$1,164.7 million. Of these reserves, 92% were classified as proved developed. We
operate properties accounting for approximately 91% of these estimated proved
reserves, allowing us to better manage expenses, capital allocation and the
timing of exploration and development activities. On a pro forma basis,
excluding our recently sold Michigan and Ecuador properties and after giving
effect to the acquisition in October 1999 of an additional interest in the Bioko
Permit offshore Equatorial Guinea, we produced 7.1 MMBoe in 1999 and 6.3 MMBoe
for the nine months ended September 30, 2000.
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<PAGE> 53
The following table summarizes by region our estimated proved reserves as
of September 30, 2000 and our average daily net production during the three
months ended September 30, 2000:
<TABLE>
<CAPTION>
AVERAGE DAILY NET PRODUCTION DURING THE
ESTIMATED PROVED RESERVES AS OF SEPTEMBER 30, 2000 THREE MONTHS ENDED SEPTEMBER 30, 2000
-------------------------------------------------- ------------------------------------------
% OF % OF
OIL AND NATURAL TOTAL PROVED OIL AND NATURAL TOTAL
CONDENSATE GAS TOTAL RESERVES CONDENSATE GAS TOTAL PRODUCTION
(MMBBLS)(1) (BCF) (MMBOE) (MMBOE) (MBBLS)(1) (MMCF) (MBOE) (MBOE)
------------ -------- -------- ------------- ---------- ------- ------ ----------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
INTERNATIONAL:
Africa:
Equatorial Guinea..... 50.8 587.1 148.6 70.1% 4.3 4.8 5.1 19.8%
Congo................. 14.7 -- 14.7 6.9 5.7 -- 5.7 22.2
Tunisia............... 3.2 36.0 9.2 4.3 1.0 8.5 2.4 9.3
South America:
Venezuela............. 12.5 6.4 13.6 6.4 5.4 2.9 5.9 23.0
Colombia.............. 4.3 -- 4.3 2.0 1.7 -- 1.7 6.6
---- ----- ----- ----- ---- ---- ---- -----
Total
International... 85.5 629.5 190.4 89.8 18.1 16.2 20.8 80.9
DOMESTIC:
Powder River Basin...... -- 33.8 5.6 2.6 -- 4.2 0.7 2.7
West Texas.............. 5.3 48.3 13.5 6.4 0.8 9.2 2.4 9.4
Louisiana............... 0.3 10.8 2.1 1.0 0.1 9.5 1.7 6.6
Other Domestic.......... 0.3 1.4 0.4 0.2 0.1 0.3 0.1 0.4
---- ----- ----- ----- ---- ---- ---- -----
Total Domestic.... 5.9 94.3 21.6 10.2 1.0 23.2 4.9 19.1
---- ----- ----- ----- ---- ---- ---- -----
Total........... 91.4 723.8 212.0 100.0% 19.1 39.4 25.7 100.0%
==== ===== ===== ===== ==== ==== ==== =====
</TABLE>
---------------
(1) For purposes of this table, oil and condensate reserves includes 12.2 MMBbls
of international NGLs, and oil and condensate production includes 0.9 MBbls
of international NGLs.
ACQUISITIONS AND DISPOSITIONS OF PROPERTIES
Acquisition of Additional Working Interest in Equatorial Guinea
In October 1999, we purchased an additional 11.5% working interest in the
Bioko Permit offshore Equatorial Guinea for cash of approximately $53.3 million,
increasing our working interest in this property from 42.5% to 54.0%.
Acquisition of Methanol Production Facility
We have agreed to purchase, prior to the completion of this offering, a 50%
interest in Atlantic Methanol Capital, which owns an indirect 90% interest in a
2,500 metric ton per day methanol production facility currently in the late
stages of construction on Bioko Island in Equatorial Guinea. We will purchase
this interest from CMS Gas Transmission, a subsidiary of CMS Enterprises, by
issuance of a note in the principal amount of approximately $137.0 million,
which will be repaid with a portion of the aggregate proceeds from this offering
and our concurrent offering of senior subordinated notes. Atlantic Methanol
Capital has issued $125.0 million of limited recourse indebtedness, which is
secured by, among other things, a pledge of 60% of the interest we expect to
acquire.
We believe that ownership of an interest in this methanol facility will
allow us to further enhance the value of our natural gas reserves offshore
Equatorial Guinea. Prior to our agreement to acquire this facility, our return
on this natural gas was limited by the $0.25 per MMBtu selling price under a
20-year contract to sell up to 126,500 MMBtu per day of natural gas to the
facility. Given that natural gas is typically the largest cost component in the
production of methanol, we believe this gas sales contract will position this
facility to be one of the lowest cost methanol producers in world markets.
Recent Dispositions of Non-Strategic Assets
Michigan Properties. In March 2000, we sold substantially all of our
Michigan oil and gas properties for cash of approximately $162.9 million. The
properties consisted principally of natural gas wells in the
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<PAGE> 54
Devonian Antrim Shale formation in the northern portion of Michigan's lower
peninsula, most of which we operated, but in which we held only an average 20%
working interest. The properties had estimated net proved reserves as of January
1, 2000 of 167.0 Bcf of gas (27.8 MMBoe) and 0.8 MMBbls of oil, condensate and
NGLs, representing approximately 11.3% of our estimated total proved reserves on
that date. During the three months ended March 31, 2000, average daily net
production from these properties was approximately 47.0 MMcf of gas.
Ecuador Properties. In June 2000, we sold all of our 14% non-operated
working interest in our Ecuador oil assets, consisting of Block 16 and related
oil fields in the Oriente Basin of the Ecuadorian Amazon region. We received
cash consideration of approximately $95.8 million for these properties. These
properties had estimated net proved reserves as of June 30, 2000 of 23.5 MMBbls
of oil, representing 11.0% of our estimated total proved reserves on that date.
During the three months ended June 30, 2000, average daily net production from
these properties was 4.0 MBbls.
INTERNATIONAL OIL AND GAS OPERATIONS
Africa
Republic of Equatorial Guinea. Our interests in Equatorial Guinea in West
Africa represented 70.1% of our estimated proved reserves as of September 30,
2000 and contributed 19.8% of our production for the three months ended
September 30, 2000. We own a 54.0% working interest in the Bioko Permit, which
we operate offshore Equatorial Guinea from our West Africa regional offices
located in the city of Malabo on Bioko Island. We have a net 138,854 undeveloped
acres in this permit. We have participated in the drilling of seven gross wells
in the Alba Field located on the block, all of which have encountered
hydrocarbons and five of which are producing gas/condensate. We extract
liquefied petroleum gas, or LPG, from an LPG extraction plant located on Bioko
Island. Average daily gross production for the three months ended September 30,
2000 was 7,300 barrels of condensate (3,400 barrels net to us), 2,093 barrels of
LPG plant products (900 barrels net to us), and 9.5 MMcf of natural gas (4.8
MMcf net to us), exclusive of flared gas, or an aggregate of 11.0 MBoe (5.1 MBoe
net to us). As of September 30, 2000, estimated gross proved reserves in the
field totaled 89.7 MMBbls of condensate (38.6 MMBbls net to us), 28.3 MMBbls of
plant products (12.2 MMBbls net to us) and 1,363.7 Bcf of natural gas (587.1 Bcf
net to us), or an aggregate of 345.3 MMBoe (148.6 MMBoe net to us).
In 1999, we initiated a $115.0 million accelerated development project with
respect to the Alba Field. We have constructed and installed two new drilling
platforms, drilled four wells, all of which were successful, and constructed an
additional pipeline to plant facilities on Bioko Island. Two of the wells are
gas/condensate producers, and two are gas injection wells.
By early 2001, we expect gross natural gas production to increase from 90
MMcf per day, including flared gas, to up to 225 MMcf per day, with up to
126,500 MMBtu per day of production to be sold for $0.25 per MMBtu under a
20-year contract with Atlantic Methanol Production Company LLC, in which we have
agreed to acquire an indirect 45% interest from CMS Gas Transmission. The gas
will be used as feed stock for a 2,500 metric ton per day methanol plant
currently under construction on Bioko Island. This gas is "stranded" and
otherwise would be flared or reinjected into the reservoir. We plan to reinject
any unused gas into the reservoir.
The limits on the Alba Field have not yet been defined by drilling. We
expect to drill one additional appraisal well in early 2001. We also have under
way engineering studies that could result in additional facilities enhancements
to the Alba project which would have the objective of increasing our production
of condensate and LPG plant products.
Our exploration group has identified several additional prospects on the
Bioko Block. One of these prospects will be drilled and tested by early 2001.
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Other participants in the Bioko Permit are Samedan of North Africa, Inc.
(an affiliate of Noble Affiliates, Inc.) and GLOBEX International. The
production sharing contract governing the Alba Field has a term of 50 years
commencing May 2, 1990.
In August 2000, we acquired farm-in rights from Ocean Equatorial Guinea
Corporation to its Block D offshore Equatorial Guinea, which is a 199,781 acre
block adjacent to and immediately west of the Bioko Block. Under the farm-in, we
are required to drill one exploratory well. By drilling this exploratory well,
which our personnel in Equatorial Guinea expect to do in early 2001, we will
earn a 50% operating working interest in any oil and gas discoveries on the
block, except that, with respect to one prospect on the block, our working
interest will be 100%. However, by virtue of the election of our Bioko Block co-
venturers regarding their participation in the farm-in, our working interests
will be reduced to 40% in the block generally and 80% with respect to the one
prospect on the block. We have identified a number of additional prospects on
this block, and we may drill up to two additional exploratory wells on the block
later in 2001.
Republic of Congo (Brazzaville). Our interests in the Congo in West Africa
represented 6.9% of our estimated proved reserves as of September 30, 2000 and
contributed 22.2% of our production for the three months ended September 30,
2000. We own a 50% working interest in, and we operate from our Pointe Noire,
Congo offices, the Marine I Exploration Permit offshore the Congo. Average daily
gross production during the three months ended September 30, 2000 was 13,174
barrels of oil (5,665 barrels net to us). As of September 30, 2000, estimated
gross proved reserves totaled 40.1 MMBbls of oil (14.7 MMBbls net to us).
The Marine I Exploration Permit covers three discoveries: the Yombo Field
and the Masseko and Youbi discoveries. There are currently 32 wells located in
the Yombo Field: 26 oil wells, five water injection wells and one shut-in well.
Oil is produced into our self-contained floating production, storage and
off-loading vessel, or FPSO, the tanker Conkouati, anchored on site. The oil is
processed into No. 6 fuel oil on the Conkouati. The vessel's storage capacity is
over one million barrels of oil. Every 30 to 45 days, the processed fuel oil is
offloaded from the Conkouati to another vessel for transportation to market.
By mid-year 2001, we plan to further develop the Yombo Field by drilling
five horizontal wells, which may include high-angle side tracks of existing
wells.
Other participants in this project are The Nuevo Congo Company, Nuevo
Congo, Ltd. and Societe Nationale des Petroles du Congo, or SNPC, the state oil
company, whose interest is being carried by the other participants.
The convention governing the Marine I Permit has a maximum term of 30
years, commencing March 15, 1989. We also have an agreement with BP Amoco
Corporation providing for sharing of revenues upon oil prices exceeding $15.19
per barrel. Under the terms of the convention, our interest will revert to 25%
once costs spent on behalf of SNPC are recovered.
In late 1995, the Hydrocarbons Ministry of the government of the Republic
of Congo (Brazzaville) notified us as operator of the Marine I Exploration
Permit offshore Congo, which includes the Yombo Field, that it would like to
convert the concession governing the participants' interests in this project to
a production sharing contract. The Congolese government had significant leverage
to request changes due to its broad governmental and regulatory powers.
Discussions with the Congolese government concerning its request began in March
1996 but were subsequently suspended. The discussions recently resumed and will
likely continue into 2001. Although the Congolese government has indicated that
it desires to achieve economic parity in effecting the contract conversion, we
cannot currently predict what impact, if any, these discussions will have on the
project's economics, and we cannot assure you that these discussions or their
outcome will not have a material adverse effect on our estimated reserves or
financial results.
Republic of Tunisia. Our interests in Tunisia represented 4.3% of our
estimated proved reserves as of September 30, 2000 and contributed 9.3% of our
production for the three months ended September 30, 2000. We operate five wells
in two concession areas in Tunisia from our Tunis offices. One of the wells is
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<PAGE> 56
located on the El Franig Concession, where we have a 55% working interest, and
four are located on the Baguel Concession, where we have a 49% working interest.
Average daily gross production for the three months ended September 30, 2000 was
1,940 barrels of oil (1,016 barrels net to us) and 17.6 MMcf of natural gas (8.5
MMcf net to us), or an aggregate of 4,856 Boe (2,432 Boe net to us). As of
September 30, 2000, estimated gross proved reserves in the El Franig and the
Baguel Concessions totaled 7.9 MMBbls of oil (3.2 MMBbls net to us) and 83.6 Bcf
of natural gas (36.0 Bcf net to us), or an aggregate of 21.8 MMBoe (9.3 MMBoe
net to us).
Two wells, one gas well and one oil well, were drilled in 1998 and 1999,
respectively, on the Baguel Concession. The remaining three wells are gas wells
with high condensate yields. All of our gas wells are connected to production
facilities. The oil well is currently under long-term test and evaluation. We
also plan to evaluate other opportunities in the area.
The other participant in the concessions is Entreprise Tunisienne
d'Activites Petrolieres, or ETAP, the state oil company. The association
contract governing these concessions has a term of 50 years, commencing June
1987 for Baguel and January 1984 for El Franig.
Republic of Cameroon. We own a 37.5% working interest in Blocks 1 and 6,
known as the Kombe Permit, located onshore in the Douala Basin of the Republic
of Cameroon. We are the operator of this permit, which has 183,636 net
undeveloped acres. The permit area includes the M'Via, N'Koudou and Benda oil
and gas discoveries, which were made before we acquired our interest. In 1998
and 1999, we re-entered the M'Via No. 1 well, an oil well, which tested at a
rate of 1,090 barrels of oil per day. Also in 1999, we drilled one additional
M'Via well, a 4,900 foot offset to the first M'Via discovery. This field remains
under evaluation. We expect to drill an offset delineation well in the M'Via
Field and an exploration well on the permit in 2001.
During 1999, we completed the acquisition of aeromagnetic and aerogravity
surveys and completed the reprocessing of 1,300 miles of 2-D seismic data. To
date, in 2000, we have obtained an additional 125 miles of 2-D seismic data. In
addition, we applied for a permit covering 296,768 acres in Block OLHP-2, which
is adjacent to and immediately northwest of the Kombe Permit. If acquired, we
will operate and own a 37.5% working interest in this permit. As a result of
encouraging test data on the M'Via discovery well and remapping of the
surrounding area, we have identified a number of exploration prospects on Block
OLHP-2.
Other participants in the Kombe Permit are GLOBEX Cameroon, L.L.C. and
Societe Nationale des Hydrocarbures, the state oil company. The convention
governing the permit has a term of 25 years from first commercial production of
hydrocarbons, which has not yet occurred.
South America
Republic of Venezuela. Our interests in Venezuela represented 6.4% of our
estimated proved reserves as of September 30, 2000 and contributed 23.0% of our
production for the three months ended September 30, 2000. We own a 43.8% working
interest in the Colon Block, which we acquired in 1994 in the second bid round
of Venezuela's Marginal Fields Reactivation Program. There are seven productive
fields on this 789,168 acre block: West Tarra, Los Manueles, Las Cruces, Bonito,
Socuavo, Rosario and La Palma. Average daily gross production for the three
months ended September 30, 2000 was 12,421 barrels of oil (5,434 barrels net to
us), and 8.5 MMcf of gas (2.9 MMcf net to us), or an aggregate of 13.1 MBoe (5.9
MBoe net to us). As of September 30, 2000, estimated gross proved reserves in
the block totaled 28.6 MMBbls of oil (12.5 MMBbls net to us) and 12.5 Bcf of gas
(6.4 Bcf net to us), or an aggregate of 31.0 MMBoe (13.6 MMBoe net to us).
The operator of this block has acquired 3-D seismic data covering the La
Palma structure and has begun further development drilling.
The other participants in the Colon Block are Tecpetrol de Venezuela, S.A.,
as operator, and Coparex Latina de Petroleos S.A. The operating services
agreement governing the block currently has a term of 20 years and expires
December 31, 2015. Under this agreement, we receive a fee per barrel produced
and
52
<PAGE> 57
delivered to Petroleos de Venezuela S.A. Additionally, we receive a fee for
reimbursement of various capital expenditures. Our per barrel fees relating to
this production are generally significantly lower than market prices for oil.
Republic of Colombia. Our interests in Colombia represented 2.0% of our
estimated proved reserves as of September 30, 2000 and contributed 6.6% of our
production for the three months ended September 30, 2000. We own interests in
two adjacent onshore blocks in the Upper Magdelena Valley, the Espinal Block and
the Abanico Block. We own a 15% working interest in the Espinal Block and a 100%
working interest (subject to government participation at 50%) in the Abanico
Block. Average daily gross production for these blocks for the three months
ended September 30, 2000 was 13,679 barrels of oil (1,699 barrels net to us). As
of September 30, 2000, estimated gross proved reserves in the area totaled 21.6
MMBbls of oil (4.3 MMBbls net to us).
The Espinal Block contains three producing fields: the Matachin Norte
Field, the Matachin Sur Field and the Purificacion Field. At the end of 1998,
there were eight producing wells on this 48,230 acre block, two in the Matachin
Norte Field, three in the Matachin Sur Field and three in the Purificacion
Field. Since then, three additional horizontal wells have been drilled and
successfully completed in the Matachin Norte Field. All of the wells in the
Espinal Block are oil wells, and all are operated by Petrobras Colombia Limited,
which owns a 30% interest in the block. Empresa Colombiana de Petroleos, or
Ecopetrol, the state oil company, owns the remaining working interest in the
block. The operator of this block has recently obtained additional 3-D seismic
data. The participation risk contract governing the Espinal Block has a maximum
term of 28 years, commencing October 1987.
We are the operator of the Abanico Block, which covers 251,680 acres. In
1999, we drilled and tested a successful exploration well on this block. During
2000, we began production of the well, transporting the oil by truck to
facilities owned and operated by Ecopetrol. In addition, we drilled two offset
wells to further define the structure, one of which is currently producing. The
other well will be used for water injection. We expect to drill one additional
Abanico well and to construct a gathering system in 2001. We also expect to
reprocess 2-D seismic data, as well as obtain new 2-D seismic data, in 2001. The
association contract governing the Abanico Block has a six-year exploration term
and a maximum term of 28 years, commencing October 1996.
In January 2000, we acquired a 100% working interest (subject to government
participation at 30%) in an adjacent third block, the Torbellino Block. The
Torbellino Block covers 79,600 acres. It is located north of and on trend with
our producing fields in the Espinal Block and is likewise on trend with and
southwest of a significant recent oil discovery, the Guando Field, operated by
Petrobras Colombia Limited on the Boqueron Block. We believe that the Torbellino
Block holds significant exploration potential, and we expect to commence
drilling on it in 2001. We also expect to reprocess 2-D seismic data, as well as
obtain new 2-D seismic data, in 2001. The association contract governing the
Torbellino Block has a six-year exploration term and a maximum term of 28 years,
commencing March 28, 2000.
DOMESTIC OIL AND GAS OPERATIONS
Powder River Basin
The Powder River Basin represented 2.6% of our estimated proved reserves as
of September 30, 2000 and contributed 2.7% of our production for the three
months ended September 30, 2000. In late 1998, we acquired a 50% undivided
interest in approximately 497,000 undeveloped acres in this basin, which spans
the Wyoming-Montana border. This acreage is owned jointly with Pennaco Energy,
Inc. and we each operate approximately 50% of it. In 1999, we acquired an
additional 32,000 undeveloped net acres. We are now one of the larger holders in
this region, which is estimated to hold up to 25 trillion cubic feet, or Tcf, of
recoverable natural gas. As of September 30, 2000, we had participated in the
drilling of 491 coal bed methane gas wells in the basin, of which 223 were
producing. We expect production from most or all of the remaining wells to
commence upon dewatering and/or completion of additional gathering lines and
facilities. We operate 183 of the producing wells in which we have an interest.
Average daily gross
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<PAGE> 58
production on our acreage for the three months ended September 30, 2000 was 8.1
MMcf (4.2 MMcf net to us). Estimated gross proved reserves at September 30, 2000
were 84.0 Bcf of gas (33.8 Bcf net to us).
Our strategy with respect to the Powder River Basin is to continue coal bed
methane gas drilling by project area, with each of the undeveloped project areas
in which we own an interest tested through a limited pilot drilling program.
Based upon expected spacing regulations, more than 3,000 gross (1,500 net to us)
coal bed methane wells could ultimately be drilled on our acreage. Our drilling
to date has been in five of 13 project areas in which we have an interest.
Drilling, completion and facility costs in the basin have averaged approximately
$80,000 per well and reserve additions have averaged over 280 MMcf per well. We
plan to participate in the drilling of an additional 40 wells in the fourth
quarter of 2000. Our Powder River Basin coal bed methane project is managed
through our Denver and Gillette offices, both of which opened in July 1999.
West Texas
The Permian Basin in West Texas represented 6.4% of our estimated proved
reserves as of September 30, 2000 and contributed 9.4% of our production for the
three months ended September 30, 2000. We currently hold, have under option or
have the right to earn by drilling 3,724 developed and 76,380 undeveloped net
acres in this area. We have interests in 35 gross producing Devonian,
Pennsylvanian, Mississippian Spraberry and Clearfork formation wells (32.3 net
to us). We operate all of these wells. Average daily gross production on our
acreage for the three months ended September 30, 2000 was 14.2 MMcf of gas (9.2
MMcf net to us), and 1,248 barrels of oil or condensate, (827 barrels net to
us), or an aggregate of 3,615 Boe (2,391 Boe net to us). Estimated gross proved
reserves at September 30, 2000 were 65.5 Bcf of gas (48.3 Bcf net to us) and 7.2
MMBbls of condensate (5.3 MMBbls net to us), or an aggregate of 18.1 MMBoe (13.5
MMBoe net to us).
Horizontal drilling program. The successful application of horizontal
drilling technology in the Permian Basin has made the development of low
permeability reservoirs known to contain hydrocarbons very economic. We believe
that the acreage we currently hold or have the option to lease is sufficient to
support an active horizontal drilling program for at least the next three years.
We believe this technology has a wide application in low permeability reservoirs
throughout the Permian Basin, and we plan to continue to acquire prospective
acreage throughout the basin in pursuit of these opportunities.
Since late 1999, we have drilled 16 horizontal natural gas wells in the
Devonian formation in Midland and Upton Counties, each drilled to a vertical
depth of approximately 12,000 feet and then extending horizontally varying
distances ranging from 4,000 to 9,500 feet. As of September 30, 2000, 13 of
these wells were producing, two were awaiting completion and one was shut in. We
own an average 87.7% working interest in these wells.
In July 2000, we drilled our first horizontal well to the Pennsylvanian
formation, about 1,000 feet above the Devonian, in Midland County. The well
tested at a rate of 480 barrels of condensate per day. Since then, we have
drilled one additional Pennsylvanian horizontal well. We hold an average working
interest of 95% in these wells.
In August 2000, we acquired 1,920 net leasehold acres, with an option to
acquire an additional 21,000 acres, in Lynn County for horizontal well
development in the Mississippian formation. We hold a 100% working interest in
the acreage. We completed our first Mississippian well in November 2000 and
anticipate drilling several more development wells in order to define the
capability of the field.
Spraberry/Clearfork drilling program. We own and operate 20 oil wells in
the Spraberry and Clearfork formations in the SRH Field in Reagan County. We own
a 100% working interest in these wells and hold leasehold rights to 13,960 net
undeveloped acres, which we plan to further develop in 2001 and thereafter.
In July 2000, we entered into an agreement with Texaco Land Company
covering 14,880 undeveloped acres in Midland County. The agreement gives us the
right to earn the acreage by drilling Spraberry wells on 160 acre units. Through
September 30, 2000, we have drilled four successful Spraberry wells, all of
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<PAGE> 59
which have been completed, on this acreage. Currently, we have three rigs
drilling on the acreage. We plan to drill up to 150 wells through 2005 to fully
develop and earn the acreage.
We manage our Permian Basin program from our Midland, Texas office, which
we opened in 1998.
Louisiana
Our Louisiana properties, consisting principally of our interest in the
Freshwater Bayou Field operated by Unocal Corporation, represented 1.0% of our
estimated proved reserves as of September 30, 2000 and contributed 6.6% of
production for the three months ended September 30, 2000. We currently hold
4,134 net leasehold acres and have interests in 19 gross producing wells (5.3
net to us). Our average daily net production for this area for the three months
ended September 30, 2000 was 9.5 MMcf of natural gas and 107 net barrels of oil.
As of September 30, 2000, we had 2.1 MMBoe of estimated proved reserves in
Louisiana.
METHANOL PRODUCTION AND MARKETING
We have agreed to purchase, prior to the completion of this offering, CMS
Gas Transmission's 50% interest in each of Atlantic Methanol Capital and two
affiliated companies. Atlantic Methanol Capital, incorporated in the Cayman
Islands, owns a 90% interest in a 2,500 metric ton per day methanol production
facility currently in the late stages of construction on Bioko Island in
Equatorial Guinea. We believe that ownership of an interest in this methanol
facility will allow us to further enhance the value of our natural gas reserves
in Equatorial Guinea. We will purchase CMS Gas Transmission's interest in
Atlantic Methanol Capital by issuance of a note in the principal amount of
approximately $137.0 million, which is equal to CMS Gas Transmission's cost in
its interest, inclusive of funds necessary to complete the facility and accrued
interest on the Series A-1 Notes through April 30, 2001. We and CMS Gas
Transmission have agreed that this amount represents the fair market value of
this interest inclusive of these items. We will repay this note with a portion
of the aggregate proceeds from this offering and our concurrent offering of
senior subordinated notes. Atlantic Methanol Capital has issued $125.0 million
of limited recourse indebtedness which is secured by, among other things, a
pledge of 60% of the interest we expect to acquire in the plant.
CMS Gas Transmission currently owns a 50% voting interest in each of
Atlantic Methanol Capital, AMPCO Marketing LLC and AMPCO Services LLC. An
affiliate of Noble Affiliates, Inc., or Noble, owns the other 50% voting
interest in each of these three companies, with management of these companies
shared by CMS Gas Transmission and Noble or their respective affiliates.
Atlantic Methanol Capital, through CMS Methanol Company and Samedan Methanol,
owns indirectly a 90% interest in Atlantic Methanol Production Company, LLC,
which is constructing and will operate the methanol production facility. The
other 10% of Atlantic Methanol Production is owned by Guinea Equatorial Oil and
Gas Marketing Ltd., a corporation controlled by the Republic of Equatorial
Guinea.
The methanol production facility is currently scheduled for completion in
May 2001. Construction costs are estimated to total approximately $448 million
plus $38 million of capitalized interest and other corporate costs relating to
CMS Gas Transmission's ownership interest. Upon completion, the methanol
facility is expected to be one of the lowest cost methanol producers in the
world. Natural gas is typically the largest cost component in the production of
methanol, and Atlantic Methanol Production has entered into a long-term natural
gas supply agreement which provides the facility with up to 126,500 MMBtu per
day of natural gas for 20 years at a fixed price of $0.25 per MMBtu. The source
of the natural gas is the Alba Field, in which we and an affiliate of Noble have
respective 54.0% and 34.8% working interests. As of September 30, 2000, Ryder
Scott Company, L.P., our independent petroleum engineers, estimated the Alba
Field's gross proved reserves at 1.36 Tcf of natural gas and 104.1 MMBbls of
oil, condensate and NGLs.
Methanol is a commodity, and therefore it is difficult for producers of
methanol to distinguish their production to the consumer on any basis other than
price. Given the importance of natural gas in the production of methanol, we
believe this facility will have significant pricing flexibility to cope with the
cyclical nature of the methanol business due to the favorable terms of the
natural gas supply agreement.
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<PAGE> 60
Accordingly, we understand that Atlantic Methanol Production intends to
capitalize on the facility's competitive cost structure.
Atlantic Methanol Production has contracted with Mitsui OSK Lines, Ltd. for
the construction and time chartering of two approximately 45,000 dead weight
metric ton methanol transport vessels for terms of approximately 15 years
commencing in the first and second quarter of 2001, respectively. These tankers
will transport methanol from the production facility to market.
AMPCO Marketing LLC, a Michigan limited liability company, intends to enter
into an agreement with Atlantic Methanol Production whereby it will purchase
some of the methanol from the production facility and resell it in U.S. markets.
Atlantic Methanol Production is entering into an agreement with a European
broker to provide methanol to European customers. AMPCO Marketing LLC and
Atlantic Methanol Production may, from time to time, enter into additional
marketing contracts or arrangements to sell methanol.
AMPCO Services LLC, a Michigan limited liability company, has agreed to
provide management consulting services to Atlantic Methanol Production and AMPCO
Marketing LLC.
RESERVES
The following table sets forth our net interest in estimated quantities of
developed and undeveloped proved oil and natural gas reserves at September 30,
2000 as prepared by Ryder Scott Company, our independent petroleum engineers.
<TABLE>
<CAPTION>
OIL AND CONDENSATE
(MMBBLS) (1) NATURAL GAS (BCF) TOTAL (MMBOE)
------------------------------- ------------------------------- -------------------------------
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL
--------- ----------- ----- --------- ----------- ----- --------- ----------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Africa............... 64.8 4.0 68.8 623.0 -- 623.0 168.5 4.0 172.5
South America........ 11.3 5.4 16.7 6.5 -- 6.5 12.4 5.5 17.9
U.S.................. 2.0 3.9 5.9 68.2 26.1 94.3 13.4 8.2 21.6
---- ---- ---- ----- ---- ----- ----- ---- -----
Total......... 78.1 13.3 91.4 697.7 26.1 723.8 194.3 17.7 212.0
<CAPTION>
PERCENT
DEVELOPED
---------
<S> <C>
Africa............... 97.7%
South America........ 69.3
U.S.................. 61.9
Total......... 91.7
</TABLE>
---------------
(1) For purposes of this table, oil and condensate includes 12.2 MMBbls of
international NGLs.
We retained Ryder Scott Company to prepare the above reserve estimates at
September 30, 2000. A letter from Ryder Scott relating to their reserve report,
dated November 10, 2000, is included as Appendix A to this prospectus.
Proved developed reserves are proved reserves that are expected to be
recovered from existing wells with existing equipment and operating methods.
Proved undeveloped reserves are reserves that are expected to be recovered from
new wells drilled to known reservoirs on undrilled acreage for which the
existence and recoverability of those reserves can be estimated with reasonable
certainty, or from existing wells where a relative major expenditure is required
to establish production.
There are numerous uncertainties inherent in estimating quantities of
proved oil and natural gas reserves and in projecting future rates of production
and timing of development expenditures, including many factors beyond the
control of the producer. The reserve data set forth in this prospectus represent
only estimates. Reserve engineering is a subjective process of estimating
underground accumulations of oil and natural gas that cannot be measured in an
exact manner. The accuracy of any reserve estimate is a function of the quality
of available data and of engineering and geological interpretation and judgment.
As a result, estimates of different engineers, including those used by us, may
vary. In addition, results of drilling, testing and production subsequent to the
date of an estimate may justify revision of the estimates, and these revisions
may be material. Accordingly, reserve estimates are generally different from the
quantities of oil and natural gas that are ultimately recovered.
As an operator of domestic oil and natural gas properties, we have filed
Department of Energy Form EIA-23, "Annual Survey of Oil and Gas Reserves," as
required by Public Law 93-275. There are differences between the reserves as
reported on Form EIA-23 and as reported in this prospectus. The
56
<PAGE> 61
differences are attributable to the fact that Form EIA-23 requires that an
operator report on the total reserves attributable to wells which are operated
by it, without regard to ownership (i.e., reserves are reported on a gross
operated basis, rather than on a net interest basis).
The following table sets forth, at September 30, 2000, the standardized
measure of discounted future cash flows attributable to our estimated proved
reserves as of September 30, 2000:
<TABLE>
<CAPTION>
AFRICA &
TOTAL MIDDLE EAST SOUTH AMERICA U.S.
---------- ----------- ------------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Future cash flows
Revenues........................... $2,953,266 $2,099,652 $278,435 $575,179
Less:
Production costs................... 603,180 433,075 88,889 81,216
Development costs.................. 114,579 46,131 23,139 45,309
---------- ---------- -------- --------
Future net cash flows before
income taxes....................... 2,235,507 1,620,446 166,407 448,654
Less discount to present value at 10%
annual rate........................ 1,070,781 841,285 62,087 167,409
---------- ---------- -------- --------
Present value of future net cash
flows before income taxes.......... 1,164,726 779,161 104,320 281,245
Future income taxes discounted at 10%
annual rate........................ 269,863 181,790 9,780 78,293
---------- ---------- -------- --------
Standardized measure of discounted
future cash net flows.............. $ 894,863 $ 597,371 $ 94,540 $202,952
========== ========== ======== ========
</TABLE>
The standardized measure of discounted future cash flows from estimated
production of our proved oil and gas reserves is presented in accordance with
the provisions of Statement of Financial Accounting Standards No. 69,
"Disclosures about Oil and Gas Producing Activities" (SFAS No. 69). In computing
this data, we have used assumptions and estimates, and we cannot assure you that
these assumptions and estimates will be indicative of future economic
conditions. We caution you against interpreting this information as a forecast
of future economic conditions or revenues. We determined future net cash flows
by using estimated quantities of proved reserves and the periods in which they
are expected to be developed and produced based on September 30, 2000 economic
conditions. We used September 30, 2000 prices of $5.13 per MMBtu of natural gas
at the Henry Hub Index and $30.83 per barrel of oil at the Cushing spot market,
except where we have fixed and determinable prices provided by contract. We
reduced the resulting estimated future cash flows by estimated future costs to
develop and produce the proved reserves based on September 30, 2000 cost levels,
but not for debt service and general and administrative expenses.
For additional information on our reserves, the net present value of future
cash flows and the standardized measure of discounted future net cash flows to
be derived from our reserves, see the risk factor relating to our reserves under
"Risk Factors" and Supplemental Information -- Oil and Gas Producing Activities
in our consolidated financial statements included elsewhere in this prospectus.
WELLHEAD VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth information on our net wellhead production
volumes and average wellhead prices received for sales of oil and condensate,
natural gas and natural gas liquids, and average production costs of sales
volumes during the years ended December 31, 1997, 1998 and 1999 and the nine-
month periods ended September 30, 1999 and 2000 and pro forma for the year ended
December 31, 1999
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<PAGE> 62
and the nine months ended September 30, 2000, giving effect to the dispositions
of our Michigan and Ecuador properties as if these transactions had occurred on
the first day of each period.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS ENDED SEPTEMBER 30,
------------------------------------ ---------------------------------
PRO FORMA PRO FORMA
1997 1998 1999 1999 1999 2000 2000
------ ------ ------ --------- -------- -------- -----------
<S> <C> <C> <C> <C> <C> <C> <C>
SALES VOLUME:
Oil and Condensate (MMBbls):
Africa................................. 2.3 2.3 3.2 3.3 2.3 2.5 2.5
South America.......................... 3.8 4.5 3.6 1.9 2.7 2.7 1.8
U.S. .................................. 0.5 0.5 0.5 0.2 0.4 0.3 0.3
------ ------ ------ ------ ------ ------ ------
Total........................... 6.6 7.3 7.3 5.4 5.4 5.5 4.6
====== ====== ====== ====== ====== ====== ======
Natural Gas (Bcf):
Africa................................. 0.7 1.9 3.3 3.6 2.4 2.8 2.9
South America.......................... -- -- -- -- -- 0.7 0.7
U.S. .................................. 26.5 24.6 23.1 5.3 17.0 10.3 6.0
------ ------ ------ ------ ------ ------ ------
Total........................... 27.2 26.5 26.4 8.9 19.4 13.8 9.6
====== ====== ====== ====== ====== ====== ======
NGLs (MMBbls):
Africa................................. 0.1 0.2 0.2 0.3 0.2 0.2 0.2
U.S. .................................. 0.2 0.2 0.2 -- 0.1 -- --
------ ------ ------ ------ ------ ------ ------
Total........................... 0.3 0.4 0.4 0.3 0.3 0.2 0.2
====== ====== ====== ====== ====== ====== ======
AVERAGE SALES PRICES:
Oil and Condensate (per Bbl):
Africa................................. $16.06 $11.21 $16.60 $16.60 $14.33 $23.37 $23.37
South America.......................... 11.57 7.53 11.57 10.13 10.20 18.78 17.81
U.S.................................... 18.78 12.94 17.88 19.13 15.57 28.15 28.36
Composite(1)......................... 13.92 9.14 11.33 11.91 10.81 13.85 14.48
Natural Gas (per Mcf):
Africa................................. $ 0.25 $ 0.79 $ 1.41 $ 1.41 $ 1.26 $ 2.02 $ 2.02
South America.......................... -- -- -- -- -- 0.65 0.65
U.S. .................................. 2.42 2.11 2.17 2.40 2.09 3.09 3.64
Composite(1)......................... 2.08 2.12 2.07 1.97 2.04 2.58 2.72
NGLs (per Bbl):
Africa................................. $12.40 $ 6.86 $12.65 $12.65 $10.81 $22.03 $22.03
U.S. .................................. 18.73 6.55 4.82 -- 3.11 8.81 --
Composite............................ 15.87 6.70 9.38 12.65 7.56 19.97 22.03
AVERAGE PRODUCTION COSTS (PER BOE):
Africa................................. $ 5.99 $ 6.03 $ 5.43 $ 5.43 $ 5.53 $ 6.17 $ 6.17
South America.......................... 3.45 2.94 4.01 8.68 3.57 3.73 3.30
U.S. .................................. 2.61 2.29 2.24 6.11 2.29 2.79 6.65
Composite............................ 3.87 3.65 4.30 5.01 4.21 5.08 5.47
</TABLE>
---------------
(1) Adjusted to reflect amounts received or paid under our hedging arrangements.
58
<PAGE> 63
ACREAGE
The following table sets forth the developed and undeveloped acreage in
which we held a leasehold, mineral or other interest at September 30, 2000.
Excluded is acreage in which our interest is limited to owned royalty,
overriding royalty and other similar interests.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
---------------- --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
------- ------ --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
INTERNATIONAL:
Africa:
Equatorial Guinea.............. 45,195 24,405 257,137 138,854 302,332 163,259
Congo.......................... 2,000 875 41,688 17,364 43,688 18,239
Tunisia........................ 4,690 2,431 125,781 64,761 130,471 67,192
Cameroon....................... -- -- 500,363 183,636 500,363 183,636
South America:
Colombia....................... 48,230 7,235 331,378 331,378 379,608 338,613
Venezuela...................... 13,120 5,740 789,168 339,521 802,288 345,261
------- ------ --------- --------- --------- ---------
Total International........ 113,235 40,686 2,045,515 1,075,514 2,158,750 1,116,200
DOMESTIC:
Wyoming........................ 6,486 974 492,687 177,058 499,173 178,032
Montana........................ -- -- 213,684 95,781 213,684 95,781
Texas.......................... 20,924 4,624 75,878 44,750 96,802 49,374
Louisiana...................... 24,639 2,247 6,115 1,887 30,754 4,134
------- ------ --------- --------- --------- ---------
Total Domestic............. 52,049 7,845 788,364 319,476 840,413 327,321
------- ------ --------- --------- --------- ---------
Total................... 165,284 48,531 2,833,879 1,394,990 2,999,163 1,443,521
======= ====== ========= ========= ========= =========
</TABLE>
The following table sets forth the developed and undeveloped acreage in
which we held a contractual right to earn an interest by drilling as of
September 30, 2000:
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------ ----------------- -----------------
GROSS NET GROSS NET GROSS NET
----- ---- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Equatorial Guinea (Block D)...... -- -- 199,781 99,891 199,781 99,891
Texas............................ -- -- 43,400 43,400 43,400 43,400
---- ---- ------- ------- ------- -------
Total.................. -- -- 243,181 143,291 243,181 143,291
==== ==== ======= ======= ======= =======
</TABLE>
The tables above do not reflect the undeveloped acreage set forth in the
table below in which we do not yet have an interest but with respect to which we
hold exclusive negotiating rights with the countries noted. We expect
negotiations on these new areas to be completed by March 31, 2001.
<TABLE>
<CAPTION>
DEVELOPED UNDEVELOPED TOTAL
------------ --------------------- ---------------------
GROSS NET GROSS NET GROSS NET
----- ---- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Cameroon (OLHP-2).......... -- -- 296,768 111,288 296,768 111,288
Tunisia (Takrouna E-3)..... -- -- 1,110,962 1,110,962 1,110,962 1,110,962
---- ---- --------- --------- --------- ---------
Total............ -- -- 1,407,730 1,222,250 1,407,730 1,222,250
==== ==== ========= ========= ========= =========
</TABLE>
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<PAGE> 64
PRODUCING WELL SUMMARY
The following table sets forth the number of gross and net producing oil
and natural gas wells in which we have ownership interests at September 30,
2000:
<TABLE>
<CAPTION>
OIL GAS TOTAL
------------ ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
INTERNATIONAL:
Africa:
Equatorial Guinea........................ -- -- 4 2.1 4 2.1
Congo.................................... 26 13.0 -- -- 26 13.0
Tunisia.................................. 1 0.5 4 2.0 5 2.5
--- ---- --- ----- --- -----
27 13.5 8 4.1 35 17.6
South America:
Colombia................................. 15 4.8 -- -- 15 4.8
Venezuela................................ 63 27.6 -- -- 63 27.6
--- ---- --- ----- --- -----
78 32.4 -- -- 78 32.4
--- ---- --- ----- --- -----
Total International.............. 105 45.9 8 4.1 113 50.0
DOMESTIC:
Powder River Basin....................... -- -- 321 160.5 321 160.5
West Texas............................... 23 23.0 15 15.0 38 38.0
Freshwater Bayou......................... -- -- 8 0.8 8 0.8
All Other Domestic....................... 34 7.5 28 1.8 62 9.3
--- ---- --- ----- --- -----
Total Domestic...................... 57 30.5 372 178.1 429 208.6
--- ---- --- ----- --- -----
Total............................ 162 76.4 380 182.2 542 258.6
=== ==== === ===== === =====
</TABLE>
Producing wells consist of producing wells and wells capable of production,
including natural gas wells awaiting pipeline connections to commence deliveries
and oil wells awaiting connection to production facilities. We had no multiple
completions.
DRILLING ACTIVITIES
During the years ended December 31, 1997, 1998 and 1999, and the nine
months ended September 30, 2000, we spent approximately $117.8 million, $100.8
million, $98.9 million and $85.5 million, respectively, for exploratory and
development drilling. We drilled or participated in the
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drilling of gross and net wells as set out in the table below for the periods
indicated (with our participation in Michigan Antrim gas and Powder River Basin
coal bed methane gas drilling shown separately):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS
----------------------------------------------- ENDED
1997 1998 1999 SEPTEMBER 30, 2000
------------- ------------- ------------- ------------------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ------- -------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
AFRICA:
Development Wells Completed:
Gas............................ 2 1.0 1 0.4 -- -- 3 1.6
Oil............................ -- -- 1 0.5 8 4.5 -- --
Exploratory Wells Completed:
Gas............................ 1 0.4 1 1.0 -- -- -- --
Oil............................ 1 0.4 -- -- -- -- -- --
Dry............................ 1 0.4 1 0.2 -- -- -- --
SOUTH AMERICA:
Development Wells Completed:
Oil............................ 11 2.7 9 2.5 8 2.3 5 1.6
Dry............................ -- -- -- -- 1 0.4 -- --
Exploratory Wells Completed:
Oil............................ 3 1.0 1 0.5 5 2.2 -- --
U.S.:
Development Wells Completed:
Gas............................ 4 0.9 2 0.2 3 3.0 13 13.0
Oil............................ 7 4.3 4 4.0 12 12.0 12 10.1
Dry............................ 2 0.5 -- -- -- -- -- --
Exploratory Wells Completed:
Gas............................ -- -- -- -- -- -- -- --
Oil............................ -- -- 1 0.3 -- -- -- --
Dry............................ 2 0.3 6 2.5 -- -- -- --
OTHER(1):
Development Wells Completed:
Gas............................ 7 3.5 4 2.4 1 -- 14 12.6
Oil............................ -- -- -- -- -- -- 15 9.7
Dry............................ 3 -- 3 -- 1 -- -- --
Exploratory Wells Completed:
Dry............................ -- -- -- -- -- -- -- --
--- ---- -- ---- --- ---- --- -----
Total.................. 44 15.4 34 14.5 39 24.4 62 48.6
=== ==== == ==== === ==== === =====
MICHIGAN ANTRIM:
Development Wells Completed:
Gas............................ 122 24.4 78 21.0 6 3.0 -- --
POWDER RIVER BASIN:
Development Wells Completed:
Gas............................ -- -- -- -- 137 67.3 354 174.0
</TABLE>
---------------
(1) Includes properties we formerly owned in Indiana and Ohio.
Due to the success rates typically associated with drilling Michigan Antrim
gas and Powder River Basin coal bed methane gas wells, the table above sets
forth separately our participation in these drilling activities. We also
participated in other wells through farm-outs, acreage contributions and other
nonpaying interests.
All of our drilling activities are conducted on a contract basis with
independent drilling contractors. We own no material drilling equipment.
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Excluding the drilling of Powder River Basin methane gas wells, at
September 30, 2000, we were participating in the drilling or completion of one
gross (0.5 net) wells in Africa, and eight gross (eight net) wells in the U.S.
On that date, we were participating in the drilling of four Powder River Basin
coal bed methane gas wells.
MARKETING
Natural Gas
All of our domestic natural gas production is sold to various buyers on a
spot market basis or under contracts providing for variable or market sensitive
pricing. All of our Powder River Basin gas has been sold to CMS Field Services
or an affiliate at market sensitive prices. During the three months ended
September 30, 2000, sales to CMS Field Services or an affiliate accounted for
approximately 1.1% of our consolidated revenues. We expect that, upon completion
of this offering, a substantial part of our domestic gas production will be sold
to CMS MST. For a discussion of the agreements expected to govern these sales,
we refer you to "Relationship and Certain Transactions with CMS Energy and
Affiliates -- Contractual Arrangements -- Gas Sales Agreements."
We do not believe the loss of any purchaser of our domestic natural gas
would have a material adverse effect on our financial condition or results of
operations due to the likely availability of other purchasers for our production
at comparable prices.
Our Tunisian natural gas production is sold under a long-term contract at
indexed prices tied to regional oil prices to La Societe Tunisienne de
l'Electricite et du Gas, the state electric and gas utility. Our natural gas
production in Venezuela is sold to Petroleos de Venezuela S.A. under a long-term
contract at fixed prices tied to volumes produced. We have entered into a
long-term contract to sell up to 126,500 MMBtu per day of our natural gas
production in Equatorial Guinea to our affiliate, Atlantic Methanol Production,
at $0.25 per MMBtu as feed gas for the methanol plant currently under
construction on Bioko Island.
Oil
We market our oil and condensate production from our Equatorial Guinea and
Congo properties under contracts based on market index prices on a cargo lot
basis. Oil production from our Colombian and Permian Basin properties is sold
under contracts based on market index prices. All of our oil production from
Equatorial Guinea, Congo and Colombia is currently brokered by Texon L.P., which
is a 50% owned subsidiary of CMS MST. We expect that, upon completion of this
offering, all of this oil production, as well as our Permian Basin oil
production, will be marketed by CMS MST. For a discussion of the agreements
expected to govern these sales, we refer you to "Relationship and Certain
Transactions with CMS Energy and Affiliates -- Contractual Arrangements -- Oil
Marketing Agreement." Oil production from our Venezuelan project is owned and
delivered by us to Petroleos de Venezuela S.A. We have not experienced any
material inability to market our oil as a result of limited access to
transportation space.
HEDGING OBJECTIVES
We periodically enter into oil and natural gas price hedge arrangements to
mitigate our exposure to price fluctuations on the sale of oil and natural gas.
Prior to the adoption of the hedging policies and procedures discussed below,
our hedging arrangements have been directed primarily by CMS Energy with a view
to benefiting the entire CMS Energy group of affiliated companies. In connection
with this offering, we expect to adopt new policies and procedures to govern our
hedging. Under these policies and procedures, the objective of our hedging
program will be to protect the amount of our cash flow required for debt service
and firm capital expenditures. The hedging plan will be approved by our board of
directors based on recommendations by our management. For purposes of these
procedures, firm capital expenditures are considered those:
- which, if not made, would expose us to material loss, including legal
liability for breach of contract or penalty or property forfeiture; or
- associated with projects expected to pay out in two years or less.
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The risks to be managed are commodity price and basis risks.
For a description of our recent hedging activity, we refer you to
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Hedging Transactions." For a description of agreements we expect
to enter into with CMS MST relating to the execution of our hedging objectives,
we refer you to "Relationship and Certain Transactions with CMS Energy and
Affiliates -- Contractual Arrangements -- Hedging Agreements."
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, we make only a limited
review of title to farmout acreage and to undeveloped domestic oil and natural
gas leases upon execution of the contracts and leases. Prior to the commencement
of drilling operations, we order a thorough title examination and curative work
with respect to significant defects. To the extent title opinions or other
investigations reflect title defects, we or the other operator of the project,
rather than the seller of the undeveloped property, is typically responsible for
curing any of these title defects at our expense. If we or the other operator
were unable to remedy or cure any title defect of a nature such that it would
not be prudent to commence drilling operations on the property, we could suffer
a loss of a portion of, or our entire investment in, the property. We have
obtained title opinions on substantially all of our domestic producing
properties and believe that we have satisfactory title to these properties in
accordance with standards generally accepted in the oil and natural gas
industry. Our oil and natural gas properties are subject to customary royalty
interests, liens for current taxes and other burdens which we believe do not
materially interfere with the use or affect the value of the properties. In the
case of our international interests, the host government generally owns the
minerals. We contract with the government to explore, develop and produce oil
and natural gas, and it is not customary to obtain title opinions on these
properties.
COMPETITION
The oil and natural gas industry is highly competitive. We face competition
in all aspects of our business, including acquiring reserves, leases, licenses
and concessions, obtaining the equipment and labor needed to conduct our
operations and marketing our oil and natural gas. Our competitors include
multinational energy companies, government-owned oil and natural gas companies,
other independent oil and natural gas concerns and individual producers and
operators. Because both oil and natural gas are fungible commodities, the
principal form of competition with respect to product sales is price
competition. We believe that our competitive position is also affected by our
geological and geophysical capabilities and ready access to markets for
production. Many competitors have financial and other resources substantially
greater than those available to us and, accordingly, may be better positioned to
acquire and exploit prospects, hire personnel and market production. In
addition, many of our larger competitors may be better able to respond to
factors such as changes in worldwide oil or natural gas prices or levels of
production, the cost and availability of alternative fuels or the application of
government regulations, which affect demand for oil and natural gas production
and which are beyond our control. Moreover, many competitors have established
strategic long-term positions and maintain strong governmental relationships in
countries in which we may seek entry. We expect this high degree of competition
to continue.
The methanol business in which we intend to engage through our acquisition
of an interest in Atlantic Methanol Capital is also highly competitive. Many of
the competitors are larger and have greater financial resources than the
methanol facility. These competitors of the methanol facility of Atlantic
Methanol Capital also may operate multiple plants, offsetting some risks to
which a single-plant producer such as the methanol facility may be subject.
Methanol consumers, additionally, may prefer the security of purchasing from a
multiple-plant producer. As a result, any level of demand established for the
methanol facility's product may not be maintained. In addition, the methanol
facility's business is based upon widely available technology. Accordingly,
barriers to entry, apart from capital availability, may be low, and the entrance
of new competitors into the industry may reduce the methanol facility's ability
to capture improving profit margins in circumstances where overcapacity in the
industry is diminishing.
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GOVERNMENTAL REGULATION
Our exploration, development, production and marketing operations are
subject to regulation at the federal, state and local levels in the U.S. and by
other countries in which we conduct business, including regulation relating to
matters such as the exploration for and the development, production, marketing,
pricing, transmission and storage of oil and natural gas, as well as
environmental and safety matters. Failure to comply with these regulations could
result in substantial liabilities to third parties or governmental entities, the
payment of which could have a material adverse effect on our financial condition
or results of operations. We believe that we are in substantial compliance with
these laws and regulations. However, we cannot assure you that laws or
regulations enacted in the future or the modification of existing laws or
regulations will not adversely affect our exploration for or development,
production or marketing of oil or natural gas. In addition, international
properties, operations or investments may be adversely affected by:
- local political and economic developments;
- exchange controls;
- currency fluctuations;
- royalty and tax increases;
- retroactive tax claims;
- import and export regulations;
- other foreign laws or policies; and
- preparation of environmental impact statements and compliance with
findings thereunder for wells on lands subject to these requirements,
as well as by laws and policies of the U.S. affecting foreign trade, taxation
and investment. Furthermore, in the event of a dispute arising from
international operations, we may be subject to the exclusive jurisdiction of
courts outside the U.S. or may not be successful in subjecting non-U.S. persons
to the jurisdiction of courts in the U.S. We may also be hindered or prevented
from enforcing our rights with respect to a governmental instrumentality because
of the doctrine of sovereign immunity.
U.S. Regulation
The oil and natural gas industry is subject to various types of regulation
by federal, state and local authorities in the U.S. Legislation affecting the
oil and natural gas industry is under constant review for amendment or
expansion. Further, numerous departments and agencies, both federal and state,
have issued rules and regulations affecting the oil and natural gas industry and
its individual members, compliance with which is often difficult and costly and
some of which may carry substantial penalties for non-compliance. The regulatory
burden on the oil and natural gas industry increases its cost of doing business
and, consequently, affects its profitability. Inasmuch as these laws and
regulations are frequently expanded, amended or reinterpreted, we are unable to
predict the future cost or impact of complying with these regulations.
Exploration and Production. Our exploration and production operations are
subject to various types of regulation at the federal, state and local levels.
This regulation includes:
- requiring permits for the drilling of wells;
- maintaining bonding requirements in order to drill or operate wells;
- regulating the location of wells, the method of drilling and casing
wells, the surface use and restoration of properties upon which wells are
drilled and the plugging and abandoning of wells; and
- satisfactory completion of an environmental impact statement for wells on
lands subject to these requirements.
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Our operations are also subject to various conservation laws and regulations.
These include the regulation of the size of drilling and spacing units or
proration units and the density of wells which may be drilled and the
unitization or pooling of oil and natural gas properties. In this regard, some
states allow the forced pooling or integration of tracts to facilitate
exploration while other states rely on voluntary pooling of lands and leases. In
addition, state conservation laws establish maximum rates of production from oil
and natural gas wells, generally prohibit the venting or flaring of natural gas
and impose certain requirements regarding the ratability of production. The
effect of these regulations is to limit the amounts of oil and natural gas we
may produce from our wells, and to limit the number of wells or the locations at
which we may drill.
A portion of our oil and natural gas leases are granted by the federal
government and administered by the Bureau of Land Management, or BLM, and the
Minerals Management Service, or MMS, both of which are federal agencies. These
leases are issued through competitive bidding, contain relatively standardized
terms and require compliance with detailed BLM and MMS regulations and orders
which regulate, among other matters, drilling and operations on these leases,
calculation of royalty payments to the federal government and bonding
requirements (and which are subject to change by the BLM and the MMS).
The Mineral Lands Leasing Act of 1920 places limitations on the number of
acres under federal leases that we may own in any one state. While subject to
this law, we do not have sufficient federal lease acreage positions in any state
or in the aggregate to be likely to be subject to these limitations in the
foreseeable future.
Sales of crude oil, condensate, and natural gas liquids by us are not
currently regulated and are made at market prices, but these sales are affected
by the cost of interstate pipeline transportation, which is regulated by the
Federal Energy Regulatory Commission, or FERC. Effective as of January 1, 1995,
the FERC implemented regulations establishing an indexing system for
transportation rates, which may affect transportation costs and delivered
prices, and the FERC is presently reconsidering the appropriate index to
utilize. In recent years, the FERC has also permitted interstate oil pipelines
to charge market-based rates instead of cost-based rates upon a showing that
markets are sufficiently competitive.
Natural Gas Marketing and Transportation. Federal legislation and
regulatory controls in the U.S. have historically affected the price of our
natural gas production and the manner in which we may market our production. In
the past, the federal government has regulated the prices at which natural gas
could be sold. Deregulation of natural gas sales by producers began with the
enactment of the Natural Gas Policy Act of 1978. Later, in 1989, Congress
enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining
price and non-price controls affecting producer sales of natural gas effective
January 1, 1993.
Our natural gas sales are affected by the availability, terms, and cost of
interstate pipeline transportation, which is regulated by the FERC under the
Natural Gas Act and the Natural Gas Policy Act. In an attempt to restructure the
interstate pipeline industry with the goal of providing enhanced access to, and
competition among, alternative natural gas suppliers, the FERC, commencing in
April 1992, issued Order No. 636 and a series of related orders, which
collectively we call Order No. 636, which have altered significantly the
interstate transportation and sale of natural gas. Among other things, Order No.
636 required interstate pipelines to unbundle the various services that they had
provided in the past, such as sales, transmission and storage, and to offer
these services individually to their customers. By requiring interstate
pipelines to "unbundle" their services and to provide their customers with
direct access to pipeline capacity held by them, Order No. 636 has enabled
pipeline customers to choose the levels of transportation and storage service
they require, as well as to purchase natural gas directly from third-party
merchants other than the pipelines and to obtain transportation of that gas on a
non-discriminatory basis. The effect of Order No. 636 has been to enable us to
market our natural gas production to a wider variety of potential purchasers. We
believe that these changes generally have improved our access to transportation
and have enhanced the marketability of our natural gas production. We believe
that Order No. 636 has not had any material adverse effect on our ability to
market and transport our natural gas
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production. However, we cannot predict what new regulations may be adopted by
the FERC and other regulatory authorities, or what effect subsequent regulations
may have on our activities.
In Order No. 637 and a related series of orders issued in 2000, the FERC
revised its open access regulations to improve the efficiency of the gas market
and to provide captive customers with the opportunity to reduce their cost of
holding interstate pipeline capacity. Among other things, those FERC orders
removed price ceilings for short-term released capacity, permitted pipelines to
file for peak/off-peak and term differentiated rate structures, and revised
regulations relating to scheduling procedures, capacity segmentation, and
pipeline penalties to improve the efficiency and competitiveness of the pipeline
grid.
The FERC has reformulated its test for distinguishing between
jurisdictional transportation facilities and gathering facilities, which are
exempt from regulation under the Natural Gas Act. In the Sea Robin decision,
issued on June 30, 1999 on remand from a Fifth Circuit opinion rendered in 1997,
the FERC held that pipeline facilities previously classified as jurisdictional
transportation facilities should be reclassified as gathering facilities. This
decision could increase gas transmission costs and the regulatory scrutiny of
natural gas gathering by state agencies.
Non-U.S. Regulation
Our international exploration, development and production of oil and
natural gas are also subject to various types of governmental regulation. In
addition, international projects in which we have an interest generally involve
complex contractual relationships with the host government which often contain
extensive provisions governing the operation of these projects. We may also be
asked to comply with, and in some cases have committed to comply with, voluntary
international standards developed by non-governmental entities, such as those
promulgated by the International Standards Organization and the World Bank, in
connection with obtaining financing for our operations. The matters addressed by
these regulations, contractual provisions and standards include:
- spacing and location of wells;
- maximum rates of production from wells;
- access to transportation facilities;
- permissible volumes for transport;
- well abandonment procedures; and
- environmental protection.
In addition, host governments often seek to insure that the local communities in
the areas of activity are strengthened and developed with the view to a better
social environment and that off-shore and coastal waters and on-shore areas
remain suitable for other resource development projects.
ENVIRONMENTAL MATTERS
Extensive federal, state and local laws and regulations relating to health
and environmental quality in the U.S. as well as environmental laws and
regulations of other countries in which we operate affect nearly all of our
operations. These laws and regulations:
- set various standards regulating various aspects of health and
environmental quality;
- provide for penalties and other liabilities for the violation of those
standards; and
- establish, in certain circumstances, obligations to remediate current and
former facilities and off-site locations.
We believe that our policies and procedures in the area of pollution
control, product safety and occupational health are adequate to prevent
unreasonable risk of environmental and other damage, and of resulting material
financial liability, in connection with our business. However, we could incur
significant liability for damages, clean-up costs and/or penalties in the event
of discharges into the environment,
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environmental damage caused by previous owners of property purchased by us or
non-compliance with environmental laws or regulations. This liability could have
a material adverse effect on our financial condition or results of operations.
Moreover, we cannot predict what environmental legislation or regulations will
be enacted in the future or how existing or future laws or regulations will be
administered or enforced. Compliance with more stringent laws or regulations, or
more vigorous enforcement policies of regulatory agencies, could in the future
require us to make material expenditures for the installation and operation of
systems and equipment for remedial measures, all of which could have a material
adverse effect on our financial condition or results of operations.
For instance, legislation has been proposed in the U.S. Congress from time
to time that would reclassify certain oil and natural gas exploration and
production wastes as "hazardous wastes," which would make the reclassified
wastes subject to more stringent handling, disposal and clean-up requirements.
If this legislation were to be enacted, it could have a significant impact on
our operating costs, as well as the oil and natural gas industry in general.
State initiatives to further regulate the disposal of oil and natural gas wastes
are also pending in various states, and these initiatives could have a similar
impact. In addition, the issues of water withdrawal and discharge in the Powder
River Basin is coming under increasing scrutiny. Citizens groups have become
increasingly opposed to the development of new wells and are seeking to
influence federal, state and local regulators to increasingly regulate this
activity. This has prompted a temporary moratorium on issuance of new water
discharge permits in Montana while the issue is further studied. MTBE, of which
methanol is a component, is subject to a phase-out in California and is subject
to similar scrutiny in other states and at the federal level. Finally,
environmental regulations are becoming increasingly stringent and more
vigorously enforced in other countries where we operate, raising similar
concerns.
Spill Control and Response Legislation
The United States Oil Pollution Act of 1990, or OPA, and its related
regulations impose a variety of requirements on persons who are or may be
responsible for oil spills in waters of the U.S. Among other things, OPA
requires owners and operators of facilities and vessels that may be the source
of an oil spill to develop plans for responding to an oil spill and to acquire
or have available equipment necessary to respond to a reasonably foreseeable oil
spill. This act also requires owners and operators of "offshore facilities" to
establish $150 million in financial responsibility to cover environmental
cleanup and restoration costs likely to be incurred in connection with an oil
spill. Proposals are under consideration that could amend OPA to define
"offshore facilities" to include all oil and natural gas facilities that have
the potential to affect "waters of the United States." The term "waters of the
United States" has been broadly defined to include inland waterbodies, including
wetlands, playa lakes and intermittent streams. Since we own or operate many oil
and natural gas facilities that could affect "waters of the United States," we
could become subject to the financial responsibility rule if it is proposed as
described. Under OPA, financial responsibility could be established through
insurance, guaranty, indemnity, surety bond, letter of credit, qualification as
a self-insurer or a combination thereof. It is unclear whether insurance
coverage will be available as a practical matter because the statute provides
for direct lawsuits against insurers who provide financial responsibility
coverage, and most insurers have strongly protested this requirement. We cannot
predict the final form of the financial responsibility rule that may be proposed
by the MMS under the act or whether pending legislation may affect it, but if
such a rule were adopted and were to apply to us, we cannot assure you that we
would be able to comply with the rule or as to the costs of our compliance.
The Federal Water Pollution Control Act, also known as the Clean Water Act,
and regulations promulgated thereunder, require containment of potential
discharges of oil or hazardous substances and preparation of oil spill
contingency plans. We believe that we have adequate procedures that address
containment of potential discharges and spill contingency planning. The U.S.
Environmental Protection Agency, or EPA, has recently increased its efforts to
enforce compliance with spill containment and contingency planning requirements.
The failure to comply with ongoing requirements or inadequate cooperation during
a spill event may subject a responsible party to civil or criminal enforcement
actions.
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Required Environmental Impact Statements
About one-third of our acreage in the Powder River Basin is U.S. federal
land and therefore subject to the environmental impact statement, or EIS,
process under the National Environmental Policy Act. In addition, Montana has
its own EIS process applicable to non-federal lands. The EIS for the Wyoming
portion of the Powder River Basin federal lands was completed in the fall of
1999, but is in the process of being supplemented to support a substantially
larger number of wells. The Montana EIS process, which is being coordinated
between the BLM and Montana authorities, is just getting under way. We cannot
assure you that the EIS process, once completed, will support all potential coal
bed methane production well prospects. Moreover, public opposition to new
drilling may cause relevant state or federal authorities to impose production
limits or other permit restrictions.
Currently, the Northern Plains Resource Council, Inc. has challenged the
ongoing permitting of coal bed methane wells by the Montana Board of Oil and Gas
Conservation without completion of any site-specific or programmatic
environmental assessment, or EIS, addressing coal bed methane development in
Montana. We have moved to intervene based upon our oil and gas leasehold
interests within the area affected by the lawsuit. Some of these leases contain
drilling date obligations that could either expire or trigger additional payment
obligations if the wells cannot be permitted and drilled within the specified
time frames. A settlement agreement has been submitted to the deciding court
that would allow for some drilling to proceed while an EIS is being conducted.
However, in the event that additional studies are required, this litigation
could negatively impact our future development activity in Montana.
Any delays, limitations or denials with respect to environmental or other
approvals necessary for us to develop our acreage in the Powder River Basin
could adversely affect our financial condition or results of operations.
Liabilities and Obligations Relating to Remediation and Cleanup
The Comprehensive Environmental Response, Compensation and Liability Act,
as amended, also known as the Superfund law, imposes liability, without regard
to fault or the legality of the original conduct, on certain classes of persons
who are considered to have contributed to the release of a "hazardous substance"
into the environment. These persons include the owner or operator of the
disposal site or sites where the release occurred and companies that disposed or
arranged for the disposal of the hazardous substances. Under the Superfund law,
these persons may be subject to joint and several liability for the costs of
cleaning up the hazardous substances that have been released into the
environment and for damages to natural resources. Furthermore, it is not
uncommon for neighboring landowners and other third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances
released into the environment. Most states have comparable strict liability
programs to address environmental contamination. We have been named a
potentially responsible party for the Casmalia Disposal Superfund Site in Santa
Barbara, California. We have been grouped, along with other viable companies,
into the second tier generator category by EPA. EPA is seeking a total of $75
million for the pending phase of cleanup from the second-tier generators as a
whole. Based on our relative position with respect to other companies in this
category, we anticipate that our share of the cost of this phase of the cleanup
will not be material. We cannot estimate at this time the total cleanup costs,
or our resulting share, for this site.
In California, the California Department of Toxic Substances Control has
alleged that we are one of numerous companies that have contributed to
contamination at a disposal site known as the EPC Eastside Landfill located near
Bakersfield, California. The state alleges that the companies generated and
shipped hazardous waste materials to the site and that releases from the site
have contaminated soil and groundwater at and in the vicinity of the site. We
have been placed into the second tier of potentially liable parties. We are
unable to estimate at this time the total cleanup costs for this site, or our
proportional share of them.
With respect to our former operations in Michigan, we are engaged in, or
are potentially secondarily responsible for, certain remediation activities at
our formerly operated sites. We sold our Michigan
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properties, with the exception of one site, in the early part of 2000 to
Quicksilver Resources Inc., which has agreed to assume the liabilities and
obligations associated with the continued remediation of these sites. We
continue to own one site, and currently are conducting remediation at this site.
Despite the fact that these sites have been sold, and Quicksilver has agreed to
contractually to assume the liabilities and obligations, we continue to hold the
permits for operations at the sites until the Michigan Department of
Environmental Quality approves our applications for permit transfers. Until the
permits have been transferred, there can be no assurance that we may not be held
liable for environmental liabilities associated with these sites.
Based upon our current understanding of remedial obligations at the sites
discussed above, and taking into account the total estimated cost of cleanup,
preliminary determinations of our allocated share, and the viability of other
potentially responsible parties, we would not expect remedial costs for these
matters to be material.
Non-U.S. Operations
Our international exploration, development and production activities are
also generally subject to environmental controls which, although often not as
precisely expressed by statute or regulation as those in the U.S., we view as
generally establishing standards comparable to those in the U.S. Most of our
international projects involve complex contractual relationships with the host
government, and the sources of environmental regulation applicable to our
international projects are often contractual rather than statutory or
regulatory. Host governments generally require projects within their
jurisdiction to employ technologically advanced methods for preventing,
monitoring and remediating environmental disturbances and discharges. During the
preparation of plans of development, the project operator is often required to
prepare a comprehensive environmental management plan and to submit emergency
preparedness and discharge clean-up contingency procedures. We may also be asked
to comply with, and in some cases have committed to comply with, voluntary
international standards developed by non-governmental entities, such as those
promulgated by the International Standards Organization and the World Bank, in
connection with obtaining financing for our operations.
Our management believes that we are in substantial compliance with
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse effect on us. Of course,
the effect of new, or more stringent, regulations on our operations is not
possible to predict.
OPERATIONAL RISKS AND INSURANCE
The oil and natural gas business involves certain operating hazards, any of
which could result in substantial losses, including:
- well blowouts;
- cratering;
- explosions;
- uncontrollable flows of oil, natural gas or well fluids;
- fires;
- formations with abnormal pressures;
- pollution;
- releases of toxic gas; and
- other environmental hazards and risks.
Our offshore operations also are subject to the additional hazards of marine
operations, such as severe weather, capsizing and collision. These hazards can
cause personal injury and loss of life, severe damage to and destruction of
property and equipment, pollution or environmental damages and suspension of
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<PAGE> 74
operations. The availability of a ready market for our oil and natural gas
production also depends on the proximity of reserves to, and the capacity of,
oil and natural gas gathering systems, pipelines, shipping, trucking and
terminal facilities. In addition, we may be legally responsible for
environmental damages caused by previous owners of property which we purchase or
lease. As a result, we could incur substantial liabilities to third parties or
governmental entities, the payment of which could reduce or eliminate the funds
available for exploration, development or acquisitions or result in the loss of
our properties.
In accordance with customary industry practices, we maintain insurance
against some, but not all, of these risks and losses. We currently maintain
coverage with respect to general liability, commercial property, workers'
compensation, automotive liability and electronic equipment. We also maintain
insurance against political risk with respect to some, but not all, of our
properties, and with respect to a portion, but not all, of our invested capital.
With respect to the methanol plant, we have obtained operating insurance
coverage which is limited to a monetary amount and has exclusions. The coverage
and proceeds of our insurance may not be adequate to cover the plant's lost
revenues or increased expenses in the event of a significant operation problem.
We also maintain an umbrella liability policy and operator's extra expense
policies. All of our insurance is subject to normal deductible levels.
Among other things, coverage is not obtainable for various types of
environmental hazards. Insurance covering the risk of contamination is hard to
obtain, costly and very restrictive. It is generally limited to sudden,
accidental events that must be reported in a very limited period of time after
occurrence to the insurer.
The occurrence of a significant adverse event, the risks of which are not
fully covered by insurance, could have a material adverse effect on our
financial condition or results of operation. Moreover, we cannot assure you that
our insurance will be adequate to cover any losses or exposure to liability or
that we will be able to maintain adequate insurance in the future at rates we
consider reasonable.
TAX MATTERS
Dual Consolidated Losses
Our subsidiaries own assets located in various foreign countries that have
given rise to tax losses for U.S. federal income tax purposes. These losses have
been utilized to offset taxable income of current or former domestic affiliates
of our subsidiaries. These losses have been the subject of an annual protective
election permitted under U.S. tax law. The election permits deduction of these
losses for U.S. tax purposes under certain conditions. Among the conditions are
that these losses may not be used to offset taxable income for foreign tax
purposes, and that the taxpayer must agree that certain future events, or
triggering events, would cause the recapture of the losses. These losses are
referred to as dual consolidated losses, or DCLs. A triggering event would
occur, for example, on the sale of the underlying assets or of the stock of an
entity directly or indirectly holding these assets. Upon a triggering event, the
affiliated group of corporations which utilized the losses on its consolidated
U.S. federal income tax return must include an amount equal to the losses in its
taxable income and in addition pay an interest rate charge on the resulting tax.
In cases in which the relevant affiliated group is CMS Energy, we are primarily
and/or secondarily liable for the tax liabilities associated with the recapture.
We estimate that our total current DCL exposure in these regards is $71.0
million.
In other cases in which the relevant consolidated group is a group now
unrelated to CMS Energy or to us, for example, we remain indirectly liable for
recapture of DCLs under indemnity agreements. We estimate that our total current
DCL exposure in these regards is $56.0 million.
Absent a closing agreement with the Internal Revenue Service, or IRS, this
offering will constitute a triggering event. We and CMS Energy expect to enter
into a closing agreement with the IRS which will prevent the transaction from
resulting in recapture of DCLs. We and CMS Energy have agreed that in the event
a closing agreement is not reached as to this offering notwithstanding our
cooperation, then CMS Energy will indemnify us for the recapture. We have also
agreed to an indemnification arrangement in the event of future triggering
events. Under this arrangement, we will be responsible for the recapture of
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any DCLs from a post-deconsolidation triggering event whether directly or under
indemnity agreements with other parties. However, we believe that the triggering
events generally are within our control and thus we do not anticipate that the
DCLs will have to be recaptured. Nonetheless, we cannot assure you that this
will be the case.
Moreover, we have two separate DCL-related exposures that are not within
our control. Under an agreement with BP America, Inc., we remain secondarily
liable to BP America if (1) Nuevo Energy Corporation, an unrelated company,
takes actions that cause DCL recapture, (2) Nuevo fails to pay the tax and
interest due with respect to that recapture, (3) BP America is required by the
IRS to honor its agreement to be jointly and severally liable with respect to
Nuevo's DCL recapture and (4) Nuevo fails to make required indemnity payments to
BP America. While we believe this series of events is unlikely, our estimate of
our current exposure if these events would occur is $44.5 million plus interest.
Under an agreement with Shell Petroleum Inc., we remain secondarily liable to
Shell if (1) Comeco Petroleum, Inc., an unrelated company, takes actions that
cause DCL recapture, (2) Comeco fails to pay the tax and interest due with
respect to that recapture, (3) Shell is required by the IRS to honor its
agreement to be jointly and severally liable with respect to Comeco's DCL
recapture and (4) Pine Resources, an unrelated company to which our Comeco
shares were sold in 1997, fails to indemnify us under an agreement reached in
connection with the sale of those shares. While we believe this series of events
is unlikely, our estimate of our current exposure if these events would occur is
$11.5 million plus interest.
International Operations
We operate some of our international oil and natural gas businesses though
direct and indirect wholly-owned U.S. subsidiaries which operate outside the
U.S. The income or loss from these subsidiaries is taxable or deductible, as the
case may be, for U.S. federal income tax purposes on a current basis. Our
operations outside the U.S. may be subject to foreign income taxes as well. The
U.S. federal income tax law allows a credit for foreign income taxes on income
that is subject to both foreign and U.S. income taxes, thereby avoiding a double
tax on foreign source income. However, substantial losses from foreign
operations were utilized in past years to offset other income. As a result,
special rules, including the "overall foreign loss" and the "foreign oil and gas
extraction income" provisions, affect the general operation of the credit. The
credit, as so affected, will operate in a manner that may subject our future
foreign income to tax at a combined foreign and U.S. income tax rate
significantly higher than the rate applicable to corporations that conduct only
domestic operations.
In addition, we conduct many of our operations outside the U.S. through
non-U.S. entities. We believe that income from these entities will not be
subject to U.S. income taxes until repatriated to the U.S. through dividends.
Nonetheless, because of the operation of the foreign tax credit referred to
above, the combined foreign and U.S. tax rate on income generated by these
foreign affiliates and repatriated to the U.S. may exceed the generally
applicable tax rate on corporations which conduct only domestic operations. In
addition, any losses that these entities, or the other foreign entities owned by
us, realize will not be currently deductible for U.S. federal income tax
purposes.
Deferred Taxes
Under U.S. generally accepted accounting principles, a deferred tax
liability is not recognized for certain temporary differences unless it becomes
apparent that these differences will reverse in the foreseeable future. One
difference is the excess of the earnings for financial reporting purposes over
the amounts subjected to U.S. income tax with respect to an investment in a
foreign subsidiary that is essentially permanent in duration. Through the end of
2000, we estimate that we have $91.0 million in earnings for which no U.S. taxes
have been provided in our financial statements. Should these funds actually be
repatriated or a decision be made not to indefinitely reinvest these funds
offshore, then approximately an additional $32.0 million in U.S. taxes would
need to be charged against earnings.
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Tax Sharing and Tax Separation Agreements
For information concerning our tax sharing and tax separation agreements
with CMS Energy, see "Relationship and Certain Transactions with CMS Energy and
Affiliates -- Contractual Arrangements -- Tax Sharing and Tax Separation
Agreements."
LEGAL PROCEEDINGS
In 1998, our former subsidiary, Terra Energy Ltd., filed a lawsuit
captioned Terra Energy Ltd. v. Star Energy, Inc., et al., Case No. 98-7490-CK,
in the 13th Judicial Circuit Court in Antrim County, Michigan to collect
approximately $294,000 of unpaid costs incurred in connection with the North
Kitchen Farms and South Kitchen Farms projects. Terra claimed that the
defendants breached agreements to pay a percentage of the costs incurred in
developing these projects. On March 19, 1999, one of the defendants in the
above-referenced matter filed a lawsuit against Terra in a case captioned White
Pine Enterprises, L.L.C. v. Terra Energy Ltd., Case No. 99-7582-CK, in the same
court, alleging that Terra breached a number of implied and express covenants as
operator of the Kitchen Farms projects. In April 1999, these two lawsuits were
consolidated into Terra Energy Ltd. Plaintiff and Counterdefendant v. White Pine
Enterprises, L.L.C. and Star Energy, Inc., Defendants and Counterplaintiffs,
Case No. 99-7582-CK. Counterplaintiffs claimed damages in the amount of $4.7
million. A mediation panel awarded counterplaintiffs damages of $225,000.
Counterplaintiffs refused to accept the mediation award. In June 2000, a jury
trial was held which resulted in a verdict against Terra in the amount of $7.6
million. We have agreed to indemnify the purchaser of Terra for liability
resulting from this action. Terra has filed a notice of appeal.
We believe that there are meritorious grounds on which the verdict in this
lawsuit should be overturned or significantly reduced, and Terra intends
vigorously to prosecute these grounds. We cannot predict the ultimate resolution
of these matters, but we believe the resulting liabilities, if any, will not
have a material adverse effect upon our financial position or results of
operations or cash flows.
We are named defendant in various other unrelated lawsuits and are a party
in governmental proceedings from time to time arising in the ordinary course of
business. While the outcome of these lawsuits and other proceedings against us
cannot be predicted with certainty, management does not currently believe that
these matters will have a material adverse effect on our financial condition or
results of operations.
OFFICES
Our principal executive offices are located at 1021 Main Street, Suite
2800, Houston, Texas 77002-6606 in approximately 107,680 square feet of leased
space. We also maintain leased district offices in Midland, Texas; Denver,
Colorado; and Gillette, Wyoming; and international offices in Douala, Cameroon;
Bogota, Colombia; Pointe Noire, the Congo; Malabo, Equatorial Guinea; and Tunis,
Tunisia. All offices are managed by professional geologists or petroleum
engineers. Replacement of any of our offices would not result in material
expenditures and alternative locations to its leased space are anticipated to be
readily available.
EMPLOYEES
As of September 30, 2000, we had 185 employees. We believe that our
relationships with our employees are satisfactory. None of our employees is
covered by a collective bargaining agreement. From time to time, we engage
independent consultants and contractors to perform various professional
services, particularly in the areas of construction, design, well-site
surveillance, permitting and environmental assessment. Independent contractors
often perform field and on-site production operation services for us, including
pumping, maintenance, dispatching, inspection and testing.
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MANAGEMENT
EXECUTIVE OFFICERS AND DIRECTORS
The following table sets forth the names, ages and positions of our
executive officers and directors as of November 20, 2000. Our directors will be
elected annually at each annual meeting of shareholders. Upon completion of this
offering, we will add three independent directors who are unaffiliated with us
or CMS Energy to our board.
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
---- --- -----------
<S> <C> <C>
Bradley W. Fischer........................ 54 President, Chief Executive Officer and
Director
William H. Stephens III................... 51 Executive Vice President, General Counsel
and Secretary
Paul A. Doyle............................. 48 Vice President -- Operations
W. Kenneth Keag........................... 50 Vice President -- Africa
Robert C. Olson........................... 57 Vice President -- Exploration
Mark E. Stirl............................. 45 Vice President and Controller
Victor J. Fryling......................... 52 Chairman of the Board
William T. McCormick, Jr. ................ 56 Director
Alan M. Wright............................ 55 Director
</TABLE>
Set forth below is certain biographical information relating to each of our
executive officers and directors.
Bradley W. Fischer. Mr. Fischer is our President and Chief Executive
Officer. He earned a Bachelor of Science degree in Mechanical Engineering from
the University of Nebraska in 1972 and completed the Program for Management
Development at Harvard Graduate School of Business in 1991. Mr. Fischer has 28
years of experience in the oil industry. He has held executive management and
operations assignments with Ashland Exploration, Inc., Mitchell Energy
Corporation, Tenneco Oil Company and Texaco prior to joining us. He has both
domestic and international operations experience, including management
responsibility for Ashland's international operations. He joined us in August
1997 as Vice President -- Western Hemisphere and assumed his current position in
August 1998. He is a member of the Society of Petroleum Engineers and is a
registered professional engineer in the State of Colorado.
William H. Stephens III. Mr. Stephens is our Executive Vice President,
General Counsel and Secretary. He received an A.B. Degree with Distinction in
All Subjects from Cornell University in 1971. In 1974 he received his J.D. from
Cornell Law School. From 1974 through June 1980, he was engaged in the private
practice of law concentrating in the oil and gas area. From June 1980 through
July 1981, he was our General Attorney, in August 1981 he was promoted to the
position of General Counsel and in October 1983 he assumed the position of Vice
President Land and Legal. In October 1993, Mr. Stephens was promoted to the
position of Senior Vice President and General Counsel and assumed his current
position March 1, 1995. He was formerly a Director of the Michigan Oil and Gas
Association and Chairman of its Industry Economics and Taxation Committee. He is
a member of the Michigan, Ohio and Texas Bar Associations and a former Chairman
of the Oil and Gas Committee of the Michigan Bar Association.
Paul A. Doyle. Mr. Doyle is our Vice President -- Operations. He received
a B.S. with honors in Civil Engineering from Georgia Institute of Technology in
1975. Mr. Doyle is a 25-year oil industry veteran who has held management and
operations assignments with IP Petroleum, Tenneco Oil Company and Texaco prior
to joining us in 1998. He joined our company in October 1998 as Vice President
of Engineering and was made Vice President -- Operations in August 1999. He is a
member of the Society of Petroleum Engineers and American Petroleum Institute
and is a licensed professional engineer in the State of Texas.
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W. Kenneth Keag. Mr. Keag is our Vice President -- Africa. He earned both
his Bachelor's and Master's degrees in Mineralogy, Petrology, and Geology from
Cambridge University. He began his career in 1972 as Geologist for Burmah Oil
Trading Ltd. in London. He then joined Arco International Oil and Gas Company in
1981 as Senior Geologist and Geological Team Leader in Jakarta, Indonesia and
was promoted to Senior Staff Geologist and Exploration Coordinator in Los
Angeles in 1987. In 1989, he was named New Opportunities Director for ARCO in
Plano, Texas and Resident Manager of ARCO Oriente Inc., Ecuador in 1991. He
joined Premier Oil in London in 1996 as General Manager of Emerging Business and
served as Vice President, Exploration of Premier Oil Natuna Sea Ltd., in
Jakarta, Indonesia from 1998 to January 2000. On February 23, 2000, he assumed
his current position as Vice President -- Africa and resides in Malabo,
Equatorial Guinea. He is a Fellow of the Geological Society of London and active
member of the American Association of Petroleum Geologists, the Petroleum
Exploration Society of Great Britain, and Geological Society of Glasgow.
Robert C. Olson. Mr. Olson is our Vice President -- Exploration. He
received both a Bachelor of Science and Master of Science in Geology from San
Jose State University in 1966 and 1970, respectively. During the period from
1966 through 1970, he also worked for the United States Geological Survey on
Regional Potential Field Studies of Alaska and California. He has more than 30
years of worldwide petroleum exploration and development experience. From 1970
to 1974, he was a geophysicist with Humble Oil/Exxon USA concentrating on oil
and gas exploration in Alaska, California and the Gulf of Mexico. From 1974
through 1996, he was with ARCO International Oil and Gas Company in various
positions of increasing responsibility including Chief Geophysicist for ARCO's
North Sea ventures and Exploration Manager of Europe, Africa and Latin America.
In 1996 and 1997, he was Exploration Manager for VANCO Energy charged with Deep
Water West Africa exploration and Netherlands marginal field development
projects. In July 1997, he assumed his current position as Vice President --
Exploration. He is an active member of the American Association of Petroleum
Geologist, the Society of Exploration Geophysicists, the Petroleum Exploration
Society of Great Britain, the European Association of Geoscientists and
Engineers, and the Geological Society of Houston.
Mark E. Stirl. Mr. Stirl is our Vice President -- Controller. He received
a BSBA degree in 1977 in Accounting and a Master of Business Administration
degree in Finance in 1983, both from the University of Houston. From 1977
through mid-1980, he was engaged in public accounting concentrating in auditing
and consulting. He joined us as Controller in March 1997, after serving the
previous 17 years with Sonat Exploration Company in Houston in various
accounting and financial functions, including the last seven years as
Controller. In May 1998, he was promoted to his present position of Vice
President -- Controller. He is a member of the Petroleum Accountants Society of
Houston, the Houston Chapter of the Texas Society of Certified Public
Accountants, the Texas Society of Certified Public Accountants and the American
Institute of Certified Public Accountants.
Victor J. Fryling. Mr. Fryling is the Chairman of our board of directors
and has served as a director since 1987. Mr. Fryling has been Chief Operating
Officer of CMS Energy since January 1996 and President of CMS Energy since
January 1992. He has been Vice Chairman of Consumers Energy Company, a
subsidiary of CMS Energy, since January 1992 and President of Consumers since
August 1997. He has been a director of CMS Energy and Consumers since 1990. Mr.
Fryling is currently a director and has been President and Chief Executive
Officer of CMS Enterprises since May 1995.
William T. McCormick, Jr. Mr. McCormick has been a director of ours since
1985. From December 1985 to February 1992, he served as the Chairman of our
board of directors. Mr. McCormick has been the Chairman of the board of
directors and Chief Executive Officer of CMS Energy since December 1987, the
Chairman of the board of directors of Consumers since November 1985 and the
Chairman of the board of directors of CMS Enterprises since May 1995. In
addition, Mr. McCormick serves on the boards of directors of Bank One
Corporation, Rockwell International Corporation and Schlumberger Ltd. He is also
a director of the Edison Electric Institute and the National Petroleum Council.
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Alan M. Wright. Mr. Wright has served as a director of ours since 1993.
Mr. Wright has been Senior Vice President and Chief Financial Officer of CMS
Energy since January 1992. He has been Senior Vice President and Chief Financial
Officer of Consumers since January 1992. In addition, Mr. Wright has been Senior
Vice President and Chief Financial Officer of CMS Enterprises since May 1998.
COMMITTEES
After this offering, our board of directors will establish four standing
committees: an audit committee, a compensation committee, a nominating committee
and an executive committee. Currently, the functions of these committees are
being performed by the board of directors.
Audit Committee
The audit committee will recommend the employment of our independent
auditors and review with management and the independent auditors our financial
statements, basic accounting and financial policies and practices, audit scope
and competency of control personnel. After the offering is completed, we will
appoint three directors to our audit committee. Each member of the audit
committee will be an "independent director" within the meaning of the rules of
The New York Stock Exchange, Inc.
Compensation Committee
The compensation committee will review and recommend to the board of
directors the compensation and promotion of our officers, the terms of any
proposed employee benefit arrangements and the making of awards under these
arrangements. The compensation committee will be appointed after the offering is
completed and will consist of at least two members who will be "non-employee
directors" within the meaning of Rule 16b-3 under the Securities Exchange Act of
1934, as amended, and "outside directors" within the meaning of Section 162(m)
of the Internal Revenue Code of 1986, as amended.
Nominating Committee
The nominating committee will review and recommend to the board of
directors modifications to director tenure policy and board size and
compensation and will aid in seeking out and attracting qualified board
candidates. The nominating committee will be comprised of four directors, at
least two of whom are not officers of our company or other CMS Energy
affiliates.
Executive Committee
The executive committee will exercise the power and authority of the board
of directors as may be necessary during the intervals between board meetings,
subject to limitations as are provided by law or resolution of the board. The
executive committee will be comprised of three or four directors, at least one
of whom is not an officer of our company or other CMS Energy affiliates.
DIRECTOR COMPENSATION
We expect that each director who is not an employee of our company or other
CMS Energy affiliates will receive an annual retainer fee of $20,000 and a fee
of $2,000 for each board meeting attended. In addition, we expect that, at the
time of election to our board, each director who is not an employee of our
company or other CMS Energy affiliates will be granted 5,000 restricted shares
of our common stock, which will vest at the rate of 1,000 shares at the time of
the annual meeting of shareholders in each year he or she continues to serve as
a director. Directors who are employees of our company or other CMS Energy
affiliates will not receive additional compensation for serving on our board.
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EXECUTIVE COMPENSATION
Effective with the adoption of the stock option plan described below,
compensation for the executive officers will consist of a base salary, which is
intended to be competitive with amounts paid to executives with equivalent
positions at other oil and gas exploration and development companies of
comparable size, and substantial annual and long-term incentive compensation
closely tied to our success in achieving stock appreciation and other
performance goals. Annual incentive (bonus) compensation payments are based on
our success in meeting financial and operating goals as outlined below. In
addition, individual performance goals are established for each executive for
specific financial, operating and management achievements. The last element of
executive compensation is expected to be long-term incentive awards in the form
of stock option awards under our stock option plan as described below.
The following table sets forth compensation information for our Chief
Executive Officer and four other executive officers who, based on salary and
bonus compensation, were our most highly compensated officers for the fiscal
year ended December 31, 1999. Together, these five persons are referred to as
our "named executive officers." All information set forth in the table reflects
compensation earned by these individuals for services during the fiscal year
ended December 31, 1999.
SUMMARY COMPENSATION TABLE
<TABLE>
<CAPTION>
LONG-TERM
COMPENSATION
-----------------------
AWARDS PAYOUTS
---------- ----------
NUMBER OF
ANNUAL COMPENSATION SECURITIES
-------------------------- UNDERLYING LTIP ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY BONUS OPTIONS(1) PAYOUTS(2) COMPENSATION(3)
--------------------------- ---- -------- -------- ---------- ---------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Bradley W. Fischer
President, Chief Executive
Officer and Director.......... 1999 $273,667 $180,012 16,000 -- $8,210
William H. Stephens III
Executive Vice President, General
Counsel and Secretary......... 1999 $252,000 $142,204 12,000 -- $7,560
Robert C. Olson
Vice President -- Exploration.... 1999 $186,000 $102,336 8,000 -- $5,850
Paul A. Doyle,
Vice President -- Operations..... 1999 $180,000 $ 77,873 8,000 -- $5,400
Mark E. Stirl
Vice President and Controller.... 1999 $148,000 $ 66,814 8,000 -- $4,440
</TABLE>
---------------
(1) Shares of CMS Energy common stock.
(2) Certain awards of restricted stock which would have vested in 1999 failed to
achieve specified performance objectives for the relevant period.
(3) CMS Energy matching contributions to defined contribution plans.
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The following table sets forth information about grants of CMS Energy stock
options to the named executive officers during the fiscal year ended December
31, 1999.
OPTION GRANTS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
PERCENT OF TOTAL
NUMBER OF OPTIONS GRANTED
SECURITIES TO EMPLOYEES OF
UNDERLYING CMS ENERGY IN EXERCISE PRICE GRANT DATE
NAME OPTIONS GRANTED FISCAL YEAR ($/SHARE) EXPIRATION DATE PRESENT VALUE(1)
---- --------------- ---------------- -------------- --------------- ----------------
<S> <C> <C> <C> <C> <C>
Bradley W. Fischer........ 16,000 1.4% 39.0625 08/21/09 94,880
William H. Stephens III... 12,000 1.1% 39.0625 08/21/09 71,160
Robert C. Olson........... 8,000 0.7% 39.0625 08/21/09 47,440
Paul A. Doyle............. 8,000 0.7% 39.0625 08/21/09 47,440
Mark E. Stirl............. 8,000 0.7% 39.0625 08/21/09 47,440
</TABLE>
---------------
(1) The present value is based on the Black-Scholes Model, a mathematical
formula used to value options traded on securities exchanges. The model
utilizes a number of assumptions, including the exercise price, the
underlying stock's volatility of 16.81% using weekly closing prices for a
four and one-half year period prior to grant date, the dividend rate of
$0.365 per quarter with 5% annual dividend growth, the term of the option
and the level of interest rates at 5.65% (equivalent to the rate of
four-year Treasury Notes). However, the model does not take into account a
significant feature of options granted to employees under CMS Energy's
plans, the non-transferability of options awarded.
The following table sets forth information concerning each exercise of
stock options to purchase CMS Energy common stock by the named executive
officers during the fiscal year ended December 31, 1999 and the number and value
of unexercised options outstanding on December 31, 1999.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND
FISCAL YEAR-END OPTION VALUES
<TABLE>
<CAPTION>
NUMBER OF SECURITIES
UNDERLYING UNEXERCISED VALUE OF UNEXERCISED IN-
OPTIONS AT FISCAL THE-MONEY OPTIONS AT
SHARES ACQUIRED YEAR-END FISCAL YEAR-END
NAME ON EXERCISE VALUE REALIZED EXERCISABLE/UNEXERCISABLE EXERCISABLE/UNEXERCISABLE
---- --------------- -------------- ------------------------- -------------------------
<S> <C> <C> <C> <C>
Bradley W. Fischer........ 4,000 49,300 26,000/-- --/--
William H. Stephens III... -- -- 19,000/-- --/--
Robert C. Olson........... -- -- 20,000/-- --/--
Paul A. Doyle............. -- -- 8,000/-- --/--
Mark E. Stirl............. -- -- 12,000/-- --/--
</TABLE>
The following table sets forth information regarding long-term incentive
plan awards granted by CMS Energy to the named executive officers in the fiscal
year ended December 31, 1999.
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LONG-TERM INCENTIVE PLANS -- AWARDS IN LAST FISCAL YEAR
<TABLE>
<CAPTION>
PERFORMANCE OR ESTIMATED FUTURE PAYOUTS UNDER
NUMBER OF SHARES, OTHER PERIOD NON-STOCK PRICE-BASED PLANS
UNITS OR OTHER UNTIL MATURATION -------------------------------
NAME RIGHTS OR PAYOUT THRESHOLD TARGET MAXIMUM
---- ----------------- ---------------- ---------- ------- --------
<S> <C> <C> <C> <C> <C>
Bradley W. Fischer................ 4,000 2-5 years 1,000 4,000 6,000
William H. Stephens III........... 3,000 2-5 years 750 3,000 4,500
Robert C. Olson................... 2,000 2-5 years 500 2,000 3,000
Paul A. Doyle..................... 2,000 2-5 years 500 2,000 3,000
Mark E. Stirl..................... 2,000 2-5 years 500 2,000 3,000
</TABLE>
EXECUTIVE INCENTIVE COMPENSATION PLAN
Our current annual executive incentive compensation plan provides our
officers and selected key employees cash bonus payments based on the achievement
of certain performance objectives established by the organization and
compensation committee of CMS Energy's board of directors. The specified
performance objectives are based on a combination of net income of CMS Energy
and pre-tax operating income, production levels and finding costs of our
company.
After completion of this offering, we expect that this plan will provide
cash bonus payments for participants based on our achievement of annual
performance objectives established by the compensation committee of our board.
Cash awards under the plan will be based generally on a percentage of the
participant's salary, subject to a maximum award of 135% if 120% of the
performance goal is achieved. Our board of directors will have the ability to
amend, suspend or terminate the executive incentive compensation plan, subject
to any requirement of shareholder approval required by applicable law.
STOCK OPTION PLAN
In connection with this offering, our board of directors will adopt a stock
option plan. The objective of the stock option plan is to link the financial
interests of our executive officers and other key employees directly with those
of our shareholders.
The stock option plan will make available stock options for executive
officers (currently six individuals) and other key employees. The aggregate
number of shares of common stock which may be issued pursuant to awards granted
under the stock option plan may not exceed 5% of the outstanding shares of our
common stock, and the maximum number of shares of common stock covered by awards
granted to any one individual in any one calendar year is 200,000.
After the offering is completed, the stock option plan will be administered
by the compensation committee, which will have final authority to determine the
persons to whom awards shall be granted, to determine the types of awards and
the number of shares covered by awards, to determine the terms, conditions and
other provisions of each award and to adopt rules and regulations for carrying
out the stock option plan.
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We expect to grant to our executive officers, at the time of this offering,
options to purchase shares of our common stock as follows:
<TABLE>
<CAPTION>
NAME OPTIONS
---- -------
<S> <C>
Bradley W. Fischer.........................................
William H. Stephens III....................................
Robert C. Olson............................................
Paul A. Doyle..............................................
Mark E. Stirl..............................................
W. Kenneth Keag............................................
</TABLE>
Each of these options is expected to have an exercise price equal to the
initial public offering price of the common stock in this offering and to have a
ten-year term.
PENSION PLAN AND SERP TABLE
We are a participating employer in the pension plan for employees of CMS
Energy, which is a noncontributory defined benefit pension plan intended to
qualify under Section 401(a) of the Internal Revenue Code. We are also a
participating employer in the supplemental executive retirement plan for
employees of CMS Energy. The supplemental executive retirement plan for
employees of CMS Energy is a non-qualified plan under the Internal Revenue Code
providing supplemental retirement income for our officers and selected
executives, based on their years of service and final pay, as defined in the
supplemental executive retirement plan. The following table shows the aggregate
annual pension benefits at normal retirement presented on a straight life
annuity basis under the pension plan and supplemental executive retirement plan
(offset by a portion of Social Security benefits).
<TABLE>
<CAPTION>
YEARS OF SERVICE
----------------------------------------------------
COMPENSATION 15 20 25 30 35
------------ -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
$100,000........................ $ 31,500 $ 42,000 $ 49,500 $ 57,000 $ 64,500
$300,000........................ 94,500 126,000 148,500 171,000 193,500
$500,000........................ 157,500 210,000 247,500 285,000 322,500
$700,000........................ 220,500 294,000 346,500 399,000 451,500
</TABLE>
Regular, straight-time salary as shown in the summary compensation table
during the five years of highest earnings is used in computing benefits under
the pension plan. In addition, bonuses under the executive incentive
compensation plan as shown in the summary compensation table during the five
years of highest earnings are used in computing benefits under the supplemental
executive retirement plan. As of December 31, 1999, the estimated years of
service for each named executive officer are: Mr. Fischer, 4.98 years; Mr.
Stephens, 29.72 years; Mr. Olson, 5.13 years; Mr. Doyle, 2.55 years; and Mr.
Stirl, 5.99 years.
CHANGE OF CONTROL SEVERANCE AGREEMENTS
We have entered into change of control severance agreements with Messrs.
Fischer, Stephens, Stirl, Olson, Doyle and Keag which guarantee specific
payments and benefits upon termination of employment or an adverse change in
responsibilities following a "change of control," as defined in the agreement.
These agreements provide that if, after a change of control, there is an adverse
change in the individual's responsibilities or the individual is involuntarily
terminated other than for "cause," as defined in the agreement, then the
individual will be entitled to a lump sum payment equal to three times his
annual cash compensation, in the case of Messrs. Fischer and Stephens, or two
times his annual cash compensation, in the case of Messrs. Stirl, Olson, Doyle
and Keag. In addition, the agreements we have entered into with Messrs. Fischer
and Stephens provide that the individual will be entitled to a lump sum payment
equal to his annual cash compensation if the individual is involuntarily
terminated by us, other than for cause, prior to a change of control.
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A "change of control" is defined in the change of control severance
agreements as occurring if:
- a change of control of our company takes place that would be required to
be reported in a current report on form 8-K filed with the SEC, whether
or not we are then subject to those reporting requirements;
- a person or group (1) acquires more than 30% of our then outstanding
voting securities and (2) has combined voting power of our then
outstanding voting securities equal to or exceeding the combined voting
power of CMS Energy;
- the incumbent directors or their permitted successors cease to constitute
a majority of our board of directors;
- within a three-year period, there is a sale of 50% or more of our assets,
as determined on a book value or market value basis; or
- a bidder files a tender offer statement with the SEC relating to our
company.
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OWNERSHIP OF CAPITAL STOCK
CMS Enterprises, 330 Town Center Drive, Suite 1100, Dearborn, MI 48126,
currently beneficially owns all of our outstanding common stock. Following
completion of this offering, CMS Enterprises will beneficially own
shares of our common stock, representing % of our outstanding common stock.
CMS Enterprises has sole voting and investment power with respect to all shares
beneficially owned by it.
CMS Energy owns all of the outstanding common stock, and Consumers Energy
Company, or Consumers, owns all of the outstanding preferred stock, of CMS
Enterprises. CMS Energy owns all of the outstanding common stock of Consumers.
As of November 15, 2000, 120,908,799 shares of CMS Energy common stock and
125,000 shares of CMS Energy preferred stock were outstanding. CMS Energy's
common stock is listed on The New York Stock Exchange. Holders of CMS Energy
common stock are entitled to one non-cumulative vote per share on each matter
voted upon by the shareholders of CMS Energy.
The following table sets forth certain information with respect to the
beneficial ownership of the common stock of CMS Energy as of November 15, 2000
by:
- each of our directors and executive officers; and
- all of our directors and executive officers as a group.
Shares shown as beneficially owned include (1) shares to which a person has
or shares voting power and/or investment power and (2) shares and share
equivalents represented by interests in the CMS Energy Employees' Savings and
Incentive Plan, the CMS Energy Deferred Salary Savings Plan, the CMS Energy
Performance Incentive Stock Plan and the CMS Energy Directors' Deferred
Compensation Plan.
<TABLE>
<CAPTION>
SHARES
BENEFICIALLY
NAME OWNED(1) PERCENT
---- ------------ -------
<S> <C> <C>
Bradley W. Fischer.......................................... 40,365 *
William H. Stephens III..................................... 41,949 *
Paul A. Doyle............................................... 22,475 *
Robert C. Olson............................................. 35,000 *
W. Kenneth Keag............................................. 2,027 *
Mark E. Stirl............................................... 26,000 *
William T. McCormick, Jr. .................................. 784,668 *
Victor J. Fryling........................................... 442,185 *
Alan M. Wright.............................................. 127,338 *
All Directors and Executive Officers as a group (9
persons).................................................. 1,522,007 *
</TABLE>
---------------
* Less than 1%.
(1) Includes option exercisable within the next 60 days as follows: Mr. Fischer,
26,000 shares; Mr. Stephens, 31,000 shares; Mr. Doyle, 16,000 shares; Mr.
Olson, 28,000 shares; Mr. Stirl, 20,000 shares; Mr. McCormick, 549,000
shares; Mr. Fryling, 322,000 shares; Mr. Wright, 90,000 shares; and all
directors and executive officers as a group, 1,082,000 shares.
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RELATIONSHIP AND CERTAIN TRANSACTIONS WITH CMS ENERGY AND AFFILIATES
VOTING CONTROL
Upon completion of this offering, CMS Enterprises will own approximately
% ( % if the underwriters exercise their over-allotment option in full) of
our issued and outstanding common stock. As a result, CMS Enterprises and CMS
Energy, indirectly by virtue of its control of CMS Enterprises, will be able to
elect, or have a significant influence over the election of, all of the members
of our board of directors and have a significant influence over our affairs and
policies, including our exploration, development, capital, operating and
acquisition expenditure plans. Following completion of this offering and the
election of three independent directors, our board of directors will be composed
of seven members, three of whom are directors or current or former officers of
CMS Energy or CMS Enterprises.
CONTRACTUAL ARRANGEMENTS
We have entered or will enter into a number of agreements with CMS Energy
or its subsidiaries for the purpose of defining our ongoing relationship
following completion of this offering. These agreements were or will be
developed in connection with this offering while we are a wholly-owned
subsidiary of CMS Enterprises and, therefore, were and will not be the result of
arm's-length negotiation between independent parties. As a result, there can be
no assurance that these agreements or the transactions provided for in these
agreements have been or will be effected on terms at least as favorable to us as
could have been from unaffiliated third parties.
Services Agreements
Prior to the completion of this offering, we expect to enter into various
agreements with each of CMS Energy, CMS Enterprises and Consumers pursuant to
which those entities will make or cause to be made available to us, from time to
time, management and consulting services, including administrative, clerical,
managerial, professional and/or technical services as we may from time to time
agree. In addition, we expect to enter into various agreements with each of CMS
Enterprises, CMS MST and Panhandle Eastern Pipe Line Company pursuant to which
we will make or cause to be made available to those entities, from time to time,
information systems and technology support, facilities management, leasing of
space and travel management services as we may from time to time agree.
In the past, we have entered into various agreements with CMS Energy, CMS
Enterprises, CMS MST and Consumers pursuant to which those entities have
provided us, from time to time, with management and consulting services,
including administrative, clerical, managerial, professional and/or technical
services. For services provided under those agreements, we have paid the
following amounts for the years ended December 31, 1997, 1998 and 1999:
- to CMS Energy, $0.7 million, $2.1 million and $2.0 million, respectively;
- to CMS Enterprises, $0.9 million, $1.4 million and $0.7 million,
respectively;
- to CMS MST, $0.2 million, $0.4 million and $0.6 million, respectively;
and
- to Consumers, $0.6 million, $0.6 million and $0.6 million, respectively.
Registration Rights Agreement
Prior to the completion of this offering, we expect to enter into a
registration rights agreement with CMS Enterprises under which we will agree,
upon the request of CMS Enterprises, to file one or more registration statements
under the Securities Act of 1933, as amended, or take other appropriate action
under the laws of foreign jurisdictions in order to permit CMS Enterprises to
offer and sell, domestically or abroad, the shares of our common stock or other
securities that it holds. CMS Enterprises will pay all costs relating to the
exercise of its registration rights, as well as any underwriting discounts and
commissions relating to any such offering, except that we will pay the fees and
expenses of our
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accountants and any trustees, transfer agents or other agents appointed in
connection with an offering under the registration rights agreement.
There is no limitation on the number or frequency of requests that CMS
Enterprises may make to register its shares, except that we will not be required
to comply with any registration request unless, in the case of a class of equity
securities, the request involves at least the lesser of:
- one million shares; or
- 1% of the total number of shares of any class then outstanding.
We will also grant to CMS Enterprises the right, if we file a registration
statement, to require us to include the securities it owns in that registration
statement. We will pay all costs relating to any such registration, other than
incremental costs attributable to the inclusion of securities owned by CMS
Enterprises in the registration statement. CMS Enterprises will pay the fees and
expenses of its counsel and all underwriting discounts and commissions with
respect to the securities offered by it.
We will have the right to delay any registration of securities owned by CMS
Enterprises for a period of up to 90 days if, in our judgment, that registration
would materially adversely affect any underwritten offering then being conducted
or about to be conducted by us. In addition, we will have the right to exclude
from any registration securities owned by CMS Enterprises which, in the judgment
of the managing underwriters, would materially adversely affect our offering of
securities.
We will agree to indemnify CMS Enterprises, its officers and directors,
each underwriter, if any, and each person who controls CMS Enterprises or any
underwriter against certain liabilities, including liabilities under the
Securities Act, in connection with any registration under the registration
rights agreement. CMS Enterprises may transfer any of its rights under the
registration rights agreement to non-affiliates.
Tax Sharing and Tax Separation Agreements
Until this offering is completed, we will be a member of the CMS Energy
affiliated group of corporations that files its U.S. federal income tax returns
on a consolidated basis. As a member of the CMS Energy affiliated group, we are
subject to a tax sharing agreement dated as of January 1, 1994. This agreement
governs our current relationship with CMS Energy on various tax matters.
Upon completion of this offering, we will cease to be a member of the CMS
Energy affiliated group and will become our own affiliated group for U.S.
federal income tax purposes. In recognition of this fact, we and CMS Energy have
entered into a tax separation agreement. This agreement, which becomes effective
upon the date of completion of this offering, governs tax matters between the
parties. In general, it provides that:
- the current tax sharing agreement to which we are subject will be
terminated and we will have no further rights or obligations under it;
- within sixty days of the date of completion of this offering we will make
an estimated tax payment to CMS Energy to cover taxes covered by combined
returns with CMS Energy for periods ending prior to or on the day of
completion; and
- thereafter, we will be responsible only for (1) federal income taxes
relating to periods beginning after the completion of this offering; (2)
state and local income taxes reportable on a combined return relating to
periods beginning after completion of this offering; (3) all state, local
and foreign taxes as initially reported on all separate returns for years
ending on or before December 31, 2000 (with CMS Energy liable for any
taxes arising from audit adjustments or amendments relating to those
periods); and (4) all other state, local, and foreign taxes relating to
taxable years ending after December 31, 2000.
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The agreement also generally provides that CMS Energy will be responsible
for any taxes resulting from the completion of this offering. Finally, under the
tax separation agreement and pursuant to applicable tax law, we will be entitled
to potential tax benefits, including minimum tax credit carryovers. These
potential tax benefits will only be of use to us if we generate sufficient
taxable income.
A closing agreement between CMS Energy, the Internal Revenue Service and us
will be required upon our leaving the CMS Energy affiliated group. This closing
agreement avoids dual consolidated loss recapture, and specifies that CMS Energy
and we will be jointly and severally liable to the Internal Revenue Service in
the event of an unremedied future dual consolidated loss triggering event.
In connection with the closing agreement described above, an
indemnification agreement will become effective between CMS Energy and us upon
our leaving the CMS Energy affiliated group. Although the closing agreement
specifies joint and several liability between CMS Energy and us in favor of the
Internal Revenue Service, the indemnification agreement generally places the
economic burden on us in the event of a dual consolidated loss triggering event
occurring after deconsolidation.
BP Amoco Indemnification Agreement and Related CMS Tax Indemnity Agreement
In connection with our acquisition of CMS Oil and Gas (International)
Company in 1995, we, CMS Energy and our subsidiaries have agreed to be jointly
and severally liable for CMS Oil and Gas (International) Company's obligation to
indemnify BP Amoco for tax liabilities attributable to the recapture of dual
consolidated losses utilized by BP Amoco for tax purposes in prior years, if a
triggering event, as defined under U.S. federal income tax laws relating to dual
consolidated losses, were to occur with respect to the assets or with respect to
the stock of these entities or of their subsidiaries.
CMS Energy has agreed to indemnify us for liability relating to recapture
of our dual consolidated losses or those of any of our subsidiaries or separate
units if a triggering event results from (1) any act or omission occurring prior
to deconsolidation or (2) a failure to obtain a closing agreement with respect
to this offering not caused by us. We have agreed to indemnify CMS Energy for
the recapture of any dual consolidated losses from a post-deconsolidation
triggering event unless directly caused by an action of CMS Energy other than in
its capacity as our shareholder.
For additional information concerning our indemnification obligations, see
"Business and Properties -- Tax Matters -- Dual Consolidated Losses."
Acquisition of Methanol Plant
We have agreed to purchase, prior to the completion of this offering, CMS
Gas Transmission's 50% interest in Atlantic Methanol Capital, which owns an
indirect 90% interest in a 2,500 metric ton per day methanol production facility
currently in the late stages of construction on Bioko Island in Equatorial
Guinea. We will purchase this interest by issuance of a note payable to CMS Gas
Transmission in the principal amount of approximately $137.0 million (which
includes estimated funds necessary to complete the facility and accrued interest
on the Atlantic Methanol Capital Series A-1 Notes through April 30, 2001), which
will be repaid with the aggregate proceeds from this offering and our concurrent
offering of senior subordinated notes. Atlantic Methanol Capital has issued
$125.0 million of limited recourse indebtedness, which is secured by, among
other things, a pledge of 60% of the interest we expect to acquire in the plant.
Note Payable to CMS Enterprises
Prior to the completion of this offering, we expect to distribute to our
parent company, CMS Enterprises, a note payable in the principal amount of $39.0
million. This note will not bear interest and will become due and payable upon
completion of this offering. We intend to use a portion of the aggregate net
proceeds to us from this offering and our concurrent offering of senior
subordinated notes to repay this note.
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Oil Marketing Agreement
Prior to the completion of this offering, we expect to enter into a master
oil marketing agreement with CMS MST pursuant to which it will serve as the
exclusive marketer of all our available domestic and international oil,
including condensate and NGLs, but excluding:
- oil produced in Venezuela or in any other country in which we are
obligated to sell our production to a state agency or other entity
designated by the state;
- plant products that are marketed by a plant operator other than us;
- oil produced from properties not operated by us when we have elected to
have the operator market our production; and
- oil production where CMS MST marketing activities would, in our
reasonable, good faith judgment, cause us to breach any of our third
party agreements or arrangements, unless CMS MST obtains an appropriate
release from that third party.
We will pay to CMS MST a fee of $0.05 per barrel for all sales for which
CMS MST provides marketing services. This price will be renegotiated every two
years so as to reflect the current market price for the services. If we and CMS
MST are unable to agree upon a price, we will have the right to market our oil
through a third party, although CMS MST will have preferential rights to match
any third party terms offered to us. The oil marketing agreement will have an
initial term of ten years.
Gas Sales Agreements
Master Gas Sales Agreement. Prior to the completion of this offering, we
expect to enter into a master gas sales agreement with CMS MST pursuant to which
it will purchase all of our gas that is produced in the Powder River Basin and
the Freshwater Bayou Field and have a preferential right to match any third
party terms offered to us to purchase any of our other natural gas produced in
the U.S., Canada or Mexico. We will not, however, be committed to sell gas to
CMS MST if it would violate any contract we have with a third party. The term of
this agreement will be for ten years. This agreement will not apply to:
- gas under any existing sales contracts between us and a third party until
that contract is terminated or otherwise ceases to be in force and
effect;
- gas used or consumed by us or the operator for field use; or
- gas attributable to interests in acreage farmed out by us to third
parties.
Powder River. Pursuant to the master gas sales agreement, we expect to
enter into a gas sales agreement with CMS MST under which it will purchase all
of our production from the Powder River Basin. Under this agreement, we will
nominate monthly the firm quantity of gas to be delivered daily by us during the
following month. In addition to this firm quantity, CMS MST will be obligated to
purchase from us a variable quantity of gas not to exceed 20% of the total
quantity nominated. The price for the firm quantity of gas will be equal to the
Cheyenne Index Price for the month during which the delivery is made and the
price for the variable quantity will be equal to the Gas Daily Index Price
applicable to the relevant delivery points on the day the variable quantity of
gas is delivered. The pricing formula will be subject to renegotiation after 180
days and annually thereafter. If, upon renegotiation we and CMS MST are unable
to agree upon a pricing formula, we will have the right to sell our gas to a
third party, although CMS MST will have preferential rights to match any third
party terms offered to us.
Freshwater Bayou. Pursuant to the master gas sales agreement, we expect to
enter into a gas sales agreement with CMS MST under which it will purchase all
of our gas production from the Freshwater Bayou Field in Louisiana. Under this
agreement, we will nominate monthly the firm quantity of gas to be delivered
daily by us during the following month. In addition to this firm quantity, CMS
MST will be obligated to purchase from us a variable quantity of gas not to
exceed 20% of the total quantity nominated.
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The price for the firm quantity of gas will be equal to the index price for that
month's gas published by "Inside FERC" for Texas Gas Zone SC and the price for
the variable quantity will be equal to the Gas Daily Index Price applicable to
the relevant delivery points on the day the variable quantity of gas is
delivered. The pricing formula will be subject to annual renegotiation. If upon
renegotiation we and CMS MST are unable to agree upon a pricing formula, we will
have the right to sell our gas to a third party, although CMS MST will have
preferential rights to match any third party terms offered to us.
Trailblazer Pipeline Agreement
To improve CMS MST's ability to take all the gas we are able to deliver
from the Powder River Basin, we have agreed to guarantee recovery by CMS MST of
a portion of the capacity charge which it has agreed to pay for capacity on the
expanded Trailblazer pipeline system serving the Powder River area. When the
expansion is complete, which is expected to occur in late 2002, CMS MST will be
obligated to pay a fee for 100,000 Mcf of daily capacity calculated at the rate
of $0.24 per Mcf. Under our agreement with CMS MST, we will prepay to CMS MST
each month a fee of $0.048 per Mcf for 100,000 Mcf, or a total monthly payment
of $144,000. CMS MST will reimburse us under a formula intended to measure the
market value of Trailblazer capacity for each month. If this value, as so
determined each month, exceeds $0.24 per Mcf, we will be reimbursed in full for
that month's payment and we will be reimbursed 20% of the value in excess of
$0.24 per Mcf. If this value is between $0.192 per Mcf and $0.24 per Mcf, we
will be reimbursed the difference between this value and $0.192 per Mcf. If this
value is $0.192 per Mcf or less, we will not be reimbursed that month.
Gathering and Processing Agreements
Master Field Services Agreement. Prior to the completion of this offering,
we expect to enter into a master field services and support agreement with CMS
Field Services. This agreement grants CMS Field Services first offer rights with
respect to all of our oil and field gas gathering, processing, treating,
compressing and certain other field service requirements as they may arise from
time to time. If we are unable to reach mutual agreement with CMS Field Services
on the terms for those services, we are entitled to seek offers for the services
from third parties, although CMS Field Services will have preferential rights to
match any third party terms offered to us. CMS Field Services will not have
preferential rights, however, if these rights would violate any agreements, such
as joint operating agreements, with third parties. The master field services
agreement will have a term of ten years.
West Texas. We have entered into a gas gathering agreement with CMS Field
Services pursuant to which it will gather some of our West Texas gas production.
Under this agreement, CMS Field Services has constructed gathering, compression
and other facilities to receive our gas production from the area south of
Midland, Texas. We pay a gathering fee sufficient to allow CMS Field Services to
recover, over a five year period, operating costs and its capital invested in
gathering facilities, plus a 20% pretax annual rate of return.
Powder River. We have entered into two agreements with affiliates of CMS
Field Services pursuant to which they provide compression and gathering services
for our Powder River production. For these services, we pay a fee of either
$0.74 per Mcf or $0.88 per Mcf depending on the distance between the point of
production and the point of redelivery. Each of these agreements has a term of
20 years, beginning in 1999.
Hedging Agreements
Hedging Administrative Support, Information and Advisory Services. Prior
to the completion of this offering, we expect to enter into a hedging
administrative support, information and advisory services agreement with CMS MST
pursuant to which it will provide to us the following services:
- provision of historical and current energy market and related data (e.g.,
weather data);
- analysis of historical and current data and development of projections
for future prices; and
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- identification of hedging strategies consistent with our hedging policy.
We will pay to CMS MST, subject to renegotiation every two years, a fee of
$4,000 per month for the base service level of 1,040 person hours per annum and
$100 per person hour in excess of that base service level. This agreement will
have an initial term of ten years.
Hedging Brokerage Services. Prior to the completion of this offering, we
also expect to enter into a hedging brokerage services agreement with CMS MST
pursuant to which it will provide to us the following services:
- administrative support services (e.g., contract administration, invoicing
and accounting, and counterparty credit analysis) for hedging activities;
- broker services (e.g., identifying and negotiating with counterparties);
and
- the arrangement of derivative transactions that we will enter into
directly with CMS Enterprises.
We expect CMS Enterprises to be the counterparty in most of our hedging
transactions, provided that it accepts the competitive terms as determined by
CMS MST and subject to our review. We will pay to CMS MST, subject to
renegotiation every two years, a fee of $0.005 per MMBtu of gas volumes hedged
and $0.05 per barrel of oil volumes hedged. This agreement will have an initial
term of ten years.
CONFLICTS OF INTEREST
Our relationship with CMS Energy and its affiliates may give rise to
conflicts of interest with respect to, among other things:
- transactions and agreements between us and CMS Energy and its affiliates;
- issuances of additional shares of our equity securities; and
- the election of directors or the payment of dividends, if any, by us.
When the interests of CMS Energy and its other subsidiaries diverge from
our interests, CMS Energy may exercise its influence in favor of its own
interests or the interests of another subsidiary over our interests.
CMS Energy has advised us that it does not intend to engage in the
exploration for or development or production of natural gas and oil, except
through its indirect ownership of our common stock and except that it may engage
in exploration, development and production for domestic natural gas to the
extent necessary to provide natural gas feedstock or as a natural hedge for its
other energy businesses. Circumstances may thus arise that would result in CMS
Energy, by itself or through one of its affiliated entities, engaging in the
exploration for or development or production of natural gas.
Moreover, after completion of this offering and the election of three
independent directors, our board of directors will consist of seven members,
three of whom are directors and/or officers of CMS Energy. As the individuals
affiliated with CMS Energy perform their duties to CMS Energy and to us,
conflicts of interest and conflicting demands on the amount of time these
individuals will have available for our affairs may arise. We cannot assure you
that any of these conflicts will be resolved in our favor.
From time to time, we and CMS Energy and its other subsidiaries have
entered into significant transactions and agreements incident to our respective
businesses, and we intend to enter into similar transactions and agreements in
the future. We cannot assure you that any of these transactions or agreements
have been or will be effected on, or will in the future result in our obtaining,
terms at least as favorable to us as could have been obtained from unaffiliated
third parties.
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CERTAIN TRANSACTIONS
Assignment of Midland Cogeneration Venture Gas Sale Agreement and Related Gas
Purchase Hedge Agreements
In April 2000, we entered into an agreement with CMS MST pursuant to which
CMS MST has agreed to assume all the economic benefits and costs associated with
the performance of our obligations:
- to sell a minimum of 7,500 MMBtu of natural gas to Midland Cogeneration
Venture Limited Partnership, or MCV, through December 31, 2006 under a
contract dated May 1, 1989;
- under various gas purchase agreements we had entered into to assist in
meeting our obligation under the MCV gas sales agreement; and
- under a hedge agreement we had entered into with Louis Dreyfus Natural
Gas to purchase the economic equivalent of 10,000 MMBtu per day at fixed,
escalating prices starting at $2.82 per MMBtu in 2001.
Under the agreement with Louis Dreyfus, if the floating price of natural
gas for a period is higher than the fixed price, the seller would pay to us the
difference, and if the fixed price for a period is higher than the floating
price, we would pay to the seller the difference. At September 30, 2000 the fair
market value of the contract reflected a payment due to CMS MST in the amount of
$6.6 million.
Although CMS MST has assumed our obligations under the agreements described
above, we have not been released from our obligations under them; accordingly we
remain liable for all of CMS MST's obligations if CMS MST should fail to fulfill
its obligation under these agreements and we will have recourse against CMS MST.
CMS Notes
CMS Energy Note. In August 1995, we issued a note in the principal amount
of approximately $61.3 million to CMS Enterprises, which in turn assigned it to
CMS Energy, in connection with the transfer of the common stock of Terra Energy
Ltd. by CMS Energy to CMS Enterprises, and then by CMS Enterprises to us. In
1999, this note was amended to extend the maturity to April 15, 2009 and to
suspend the interest payments until April 4, 2004. Interest will accrue and will
be added to the outstanding debt balance. The note bears interest at the
three-month LIBOR plus 2% per annum. Amounts outstanding under the note are
expressly subordinate to borrowings under our credit facility, and we are
subject to limitations on our obligation to make payments on the note in the
event of default under the terms of the credit facility. As of September 30,
2000, $63.4 million of principal and interest was outstanding under the CMS
Energy note. We expect to repay this note in full upon completion of this
offering and our concurrent offering of senior subordinated notes.
Note Receivable from Western Australia Gas Transmission. In July 2000, we
loaned $32.0 million of the net proceeds we received from the sale of our
Ecuador properties to Western Australia Gas Transmission Company I, an affiliate
of CMS Energy. On October 9, 2000, that note became payable and Western
Australia Gas Transmission paid this note by entering into an additional note
with us. This additional note, dated October 10, 2000, has a principal of
$32,515,200 and bears interest at a rate of 6.44% per annum, compounded daily
based on a 360-day-year. The term of the note is 90 days and is scheduled to
mature on January 8, 2001. We expect this note to be repaid in full by December
31, 2000.
Contributions to Capital
During the years ended December 31, 1998 and 1999, we received equity
contributions from CMS Enterprises in the amounts of $35.0 million and $58.3
million, respectively.
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Repurchase of Interests Under Employee Well Participation Program
In 1996, we entered into an agreement with William H. Stephens III, our
Executive Vice President, General Counsel and Secretary, pursuant to which we
agreed to purchase overriding royalty interests previously owned by Mr. Stephens
for cash and phantom stock units relating to CMS Energy common stock. Pursuant
to the terms of the agreement, in each of the years 1997 through 2000, we paid
to Mr. Stephens in cash amounts equal to $113,284, $138,890, $133,723 and
$56,744, respectively, representing:
- a stipulated percentage of the value of his phantom stock units at that
time (including appreciation, if any, on the securities underlying the
phantom stock units); and
- an amount equal to any dividends paid on the securities underlying the
phantom stock units at the time those dividends were paid.
We currently estimate that the final payment of cash to Mr. Stephens, on or
about March 1, 2001, will be in the amount of $64,550, of which $63,691
represents payment for his phantom stock units and $859 represents the amount
equal to dividends on the securities underlying the phantom stock units.
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DESCRIPTION OF CAPITAL STOCK
The following summary description of our capital stock is qualified in its
entirety by reference to our Restated Articles of Incorporation and Restated
Bylaws, a copy of each of which is filed as an exhibit to the registration
statement of which this prospectus is a part.
Our authorized capital stock consists of 55,000,000 shares of common stock,
no par value per share, and 5,000,000 shares of preferred stock, no par value
per share. As of the date hereof, shares of common stock, all of which are
owned by CMS Enterprises, and no shares of preferred stock are outstanding. Upon
completion of the offering, shares of common stock will be outstanding, of
which shares will be owned by CMS Enterprises, assuming no exercise of the
underwriters' over-allotment option. We have reserved shares of common
stock for issuance pursuant to our stock option plan.
OUR COMMON STOCK
Voting Rights. The holders of common stock are entitled to one vote per
share on all matters submitted to a vote of shareholders. Holders of common
stock do not have cumulative voting rights with respect to the election of
directors. Generally, all matters submitted to a vote of shareholders must be
approved by a majority (or, in the case of election of directors, by a
plurality) of the shares of common stock present in person or represented by
proxy and entitled to vote, subject to any voting rights granted to holders of
any preferred stock. After the offering, CMS Enterprises will hold approximately
% of our issued and outstanding common stock, or % if the over-allotment
option is exercised in full, and therefore will hold the voting power to
determine all matters upon which our shareholders vote, including the election
of directors. See "Relationship and Certain Transactions with CMS Energy and
Affiliates."
Dividends. Holders of common stock are entitled to receive ratably such
dividends, if any, as may be declared from time to time by the board of
directors out of funds legally available therefor.
Other Rights. In the event of a liquidation, dissolution or winding up of
our company, holders of common stock are entitled to share ratably in all net
assets available for distribution to common shareholders. Holders of common
stock have no preemptive, subscription, redemption or conversion rights. All
outstanding shares of common stock, including the shares being issued in the
offering, are fully paid and nonassessable.
We will apply to list our common stock on The New York Stock Exchange under
the symbol "CGS."
OUR PREFERRED STOCK
Our board of directors has the authority, without further action by
shareholders, to issue up to 5,000,000 million shares of preferred stock in one
or more series and to fix and determine the relative rights and preferences of
the preferred stock, including, among others, dividend rights, voting rights,
redemption and sinking fund provisions, liquidation preferences and conversion
rights.
The issuance of preferred stock, while providing desirable flexibility in
connection with possible acquisitions and other corporate purposes, could
adversely affect the voting power of holders of our common stock and could have
the effect of delaying, deferring or preventing a change in control of our
company.
CERTAIN PROVISIONS OF MICHIGAN CORPORATE LAW
We are subject to the business combination provisions of the Michigan
Business Corporation Act. In general, those provisions prohibit a publicly held
Michigan corporation from engaging in various business combination transactions
with any interested shareholder unless:
- the business combination transaction, or the transaction in which the
interested shareholder became an interested shareholder, is approved by
the board of directors prior to the time the interested shareholder
obtained such status;
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- on or subsequent to that date, the business combination is approved by
the board of directors and authorized by the affirmative vote of:
- at least 90% of the votes of each class of stock entitled to be cast by
the shareholders of the corporation; and
- at least 66 2/3% of the votes of each class of stock entitled to be cast
by the shareholders of the corporation, other than voting shares
beneficially owned by the interested shareholder or its affiliates or
associates; or
- all of the following conditions are met:
- the aggregate amount of consideration to be received by holders of
common stock in the business combination is at least equal to the higher
of:
- the highest per share price paid by the interested shareholder for
shares of common stock of the same class or series acquired by the
interested shareholder within the two-year period prior to the
announcement of the proposed business combination or in the
transaction in which the shareholder became an interested shareholder
(whichever is higher); and
- the market value per share of common stock of the same class or series
on the announcement date or determination date (whichever is higher);
- the aggregate amount of consideration to be received by holders of
shares of any class or series other than common stock is at least equal
to the higher of:
- the highest per share price paid by the interested shareholder for any
shares of the class of stock acquired by the interested shareholder
within the two-year period prior to the announcement of the proposed
business combination or in the transaction in which the shareholder
became an interested shareholder (whichever is higher);
- the highest preferential amount per share to which holders of the
class of stock are entitled in the event of liquidation, dissolution
or winding-up of the corporation; and
- the market value per share of the class of stock on the announcement
date or determination date (whichever is higher);
- the consideration to be received by holders of any class or series of
stock is in cash or the same form as the interested shareholder has
previously paid for shares of the same class or series of stock; and
- after the shareholder has become an interested shareholder and prior to
the consummation of the business combination:
- all full periodic dividends on any outstanding preferred stock of the
corporation shall have been paid;
- the annual rate of dividends paid on any class or series of stock
other than preferred stock shall not have been reduced;
- the interested shareholder shall not have received the benefit of any
loans, advances, guarantees or pledges provided by the corporation or
its subsidiaries; and
- the business combination does not occur until five years after the
date the shareholder became an interested shareholder.
A "business combination" is defined to include mergers, asset sales and
other transactions resulting in financial benefit to a shareholder. In general,
an "interested shareholder" is a person who, together with affiliates and
associates, owns 10% or more of a corporation's voting stock. The statute could
prohibit or delay mergers or other takeover or change in control attempts with
respect to our company and, accordingly, may discourage attempts to acquire us.
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LIMITATION ON PERSONAL LIABILITY OF DIRECTORS; INDEMNIFICATION PROVISIONS
Our Restated Articles of Incorporation contain a provision, authorized by
the Michigan Business Corporation Act, designed to eliminate the personal
liability of directors for monetary damages to us or our shareholders for breach
of their fiduciary duty as directors. This provision, however, does not limit
the liability of any director who breached his duty of loyalty to us or our
shareholders, failed to act in good faith, obtained an improper personal
benefit, or paid a dividend or approved a stock repurchase or redemption that
was prohibited under Michigan law. This provision will not limit or eliminate
our rights or those of any shareholder to seek an injunction or any other
non-monetary relief in the event of a breach of a directors' duty of care. In
addition, this provision applies only to claims against a director arising out
of his role as a director and does not relieve a director from liability
unrelated to his fiduciary duty of care or from a violation of statutory law
such as certain liabilities imposed on a director under the federal securities
laws.
Our Restated Articles of Incorporation and Restated Bylaws require us to
indemnify all of our directors and officers to the full extent permitted by the
Michigan Business Corporation Act. Under the provisions of the Michigan Business
Corporation Act, any director or officer who, in his capacity as such, is made
or threatened to be made a party to any suit or proceeding may be indemnified if
our board determines the director or officer acted in good faith and in a manner
he reasonably believed to be in or not opposed to our or our shareholders' best
interests.
In addition, our officers and directors and the officers and directors of
our subsidiaries are covered within specified monetary limits by insurance
against certain losses arising from claims made by reason of their acting as
such, and our officers and directors are also indemnified against losses by
reason of their being or having been directors of officers of another
corporation, partnership, joint venture, trust or other enterprise at our
request.
TRANSFER AGENT AND REGISTRAR
CMS Energy, 212 West Michigan Avenue, Jackson, MI 49201, attention:
Investor Services, is the transfer agent and registrar for our common stock.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the offering, we will have outstanding shares of
our common stock, assuming the underwriters' over-allotment option is not
exercised. All of the shares sold in the offering will be freely tradable
without restriction by persons other than our "affiliates," as that term is
defined under Rule 144 under the Securities Act of 1933, as amended. Persons who
may be deemed affiliates generally include individuals or entities that control,
are controlled by or are under common control with us and may include our
officers, directors and significant shareholders. The remaining shares of
common stock that will continue to be held by CMS Enterprises after the offering
will constitute "restricted securities" within the meaning of Rule 144 and may
not be sold other than through registration under the Securities Act or pursuant
to an exemption from registration. As described under "Relationship and Certain
Transactions With CMS Energy and Affiliates," pursuant to the registration
rights agreement, CMS Enterprises may cause us at any time to register all or a
portion of the common stock owned by it, in which event CMS Enterprises would be
able to sell those shares upon the effectiveness of that registration without
regard to the provisions of Rule 144.
As discussed under the heading "Underwriting," we, CMS Enterprises, CMS
Energy and each of our directors and executive officers have agreed not to
offer, sell, contract to sell, pledge or otherwise dispose of any shares of our
common stock or any securities convertible into or exchangeable or exercisable
for our common stock (other than pursuant to employee stock incentive plans
existing or contemplated on the date of this prospectus and for other specified
purposes), for a period of days after the date of this prospectus,
without the prior written consent of Credit Suisse First Boston Corporation.
Upon expiration of this period, all shares of common stock held by CMS
Enterprises will have been held
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for more than one year and will be available for sale in the public market,
subject to compliance with the volume and other limitations of Rule 144 as
described below.
In general, under Rule 144 as currently in effect, beginning 90 days after
the date of this prospectus, a person, or persons whose shares are aggregated,
who has beneficially owned restricted shares for at least one year, including
the holding period of any prior owner, other than an affiliate of ours, would be
entitled to sell within any three-month period a number of shares that does not
exceed the greater of:
- 1% of the number of shares of common stock then outstanding, which will
equal approximately shares immediately after this offering; or
- the average weekly trading volume of the common stock during the four
calendar weeks preceding the filing of a Form 144 with respect to the
sale.
Sales under Rule 144 also are subject to manner of sale provisions and
notice requirements and to the availability of current public information about
us. Under Rule 144(k), a person who is not deemed to have been an affiliate of
ours at any time during the three months preceding a sale and who has
beneficially owned the shares proposed to be sold for at least two years,
including the holding period of any prior owner, other than an affiliate of
ours, is entitled to sell those shares without complying with the manner of
sale, public information, volume limitation or notice provisions of Rule 144.
Rule 144A under the Securities Act permits resales of restricted securities
under certain conditions provided that the purchaser is a "qualified
institutional buyer," as defined therein, which generally refers to institutions
with over $100 million invested in securities. Rule 144A allows holders of
restricted securities to sell their shares to those purchasers without regard to
volume or any other restrictions.
We currently intend to file promptly after the completion of the offering a
registration statement on Form S-8 under the Securities Act to register shares
of common stock reserved for issuance under our stock option plan. Based on the
number of shares we expect to reserve for issuance under the plan, that
registration statement would cover up to shares issuable on exercise of
options, of which options to purchase shares will have been issued
effective as of the date of completion of this offering. The registration
statement on Form S-8 will become effective automatically upon filing.
Accordingly, subject to the exercise of those options, shares registered under
that registration statement will be available for sale in the open market
immediately after the expiration of the lock-up agreements described above.
Prior to the offering, there has been no public trading market for our
common stock. Sales of substantial amounts of common stock in the open market,
or the perception that those sales could occur, could adversely affect
prevailing market prices and could impair our ability to raise capital in the
future through the sale of our equity securities.
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UNDERWRITING
Under the terms and subject to the conditions contained in an underwriting
agreement dated , 2001, we and the selling shareholder have agreed
to sell to the underwriters named below, for whom Credit Suisse First Boston
Corporation is acting as representative, the following respective numbers of
shares of common stock:
<TABLE>
<CAPTION>
NUMBER OF
UNDERWRITER SHARES
----------- ---------
<S> <C>
Credit Suisse First Boston Corporation......................
--------
Total.............................................
========
</TABLE>
The underwriting agreement provides that the underwriters are obligated to
purchase all the shares of common stock in the offering if any are purchased,
other than those shares covered by the over-allotment option described below.
The underwriting agreement also provides that if an underwriter defaults, the
purchase commitments of non-defaulting underwriters may be increased or the
offering may be terminated.
We and/or the selling shareholder have granted to the underwriters a 30-day
option to purchase on a pro rata basis up to additional shares at the
initial public offering price less the underwriting discounts and commissions.
The option may be exercised only to cover any over-allotments of common stock.
The underwriters propose to offer the shares of common stock initially at
the public offering price on the cover page of this prospectus and to selling
group members at that price less a selling concession of $ per share. The
underwriters and selling group members may allow a discount of $ per share
on sales to other broker/dealers. After the initial public offering, the public
offering price and concession and discount to broker/dealers may be changed by
the representative.
The following table summarizes the compensation and estimated expenses we
and the selling shareholder will pay:
<TABLE>
<CAPTION>
PER SHARE TOTAL
------------------------------- -------------------------------
WITHOUT WITH WITHOUT WITH
OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT OVER-ALLOTMENT
-------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
Underwriting discounts and
commissions paid by us........ $ $ $ $
Expenses payable by us.......... $ $ $ $
Underwriting discounts and
commissions paid by the
selling shareholder........... $ $ $ $
Expenses payable by the selling
shareholder................... $ $ $ $
</TABLE>
The representatives of the underwriters have informed us that they do not
expect discretionary sales to exceed 5% of the shares of common stock being
offered.
We have agreed that we will not offer, sell, contract to sell, pledge or
otherwise dispose of, directly or indirectly, or file with the SEC a
registration statement under the Securities Act of 1933 relating to, any shares
of our common stock or securities convertible into or exchangeable or
exercisable for any shares of our common stock, or publicly disclose the
intention to make any such offer, sale, pledge, disposition or filing, without
the prior written consent of Credit Suisse First Boston Corporation for a period
of days after the date of this prospectus, except issuances pursuant
to the exercise of options outstanding on the date hereof and issuances of
options to our executive officers upon completion of this offering, as described
in this prospectus.
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CMS Enterprises, CMS Energy and each of our directors and executive
officers have agreed that they will not offer, sell, contract to sell, pledge or
otherwise dispose of, directly or indirectly, any shares of our common stock or
securities convertible into or exchangeable or exercisable for any shares of our
common stock, or enter into a transaction which would have the same effect, or
enter into any swap, hedge or other arrangement that transfers, in whole or in
part, any of the economic consequences of ownership of our common stock, whether
any of these transactions are to be settled by delivery of our common stock or
other securities, in cash or otherwise, or publicly disclose the intention to
make any such offer, sale, pledge or disposition, or to enter into any such
transaction, swap, hedge or other arrangement, without, in each case, the prior
written consent of Credit Suisse First Boston Corporation for a period of
days after the date of this prospectus.
The underwriters have reserved for sale, at the initial public offering
price, up to shares of the common stock for employees and directors of our
company and CMS Energy, and members of their immediate families, who have
expressed an interest in purchasing common stock in the offering. The number of
shares available for sale to the general public in the offering will be reduced
to the extent these persons purchase the reserved shares. Any reserved shares
not so purchased will be offered by the underwriters to the general public on
the same terms as the other shares.
We and the selling shareholder have agreed to indemnify the underwriters
against liabilities under the Securities Act, or to contribute to payments that
the underwriters may be required to make in that respect.
We will apply to list the shares of common stock on The New York Stock
Exchange under the symbol "CGS." In connection with the listing of the common
stock on The New York Stock Exchange, the underwriters will undertake to sell
round lots of 100 shares or more to a minimum of 2,000 beneficial owners.
Prior to this offering, there has been no established public trading market
for our common stock. Consequently, the initial public offering price will be
determined by negotiation among us, the selling shareholder and the
representative of the underwriters. Among the factors to be considered in
determining the initial public offering price, in addition to prevailing market
conditions, will be:
- current and historical oil and natural gas prices;
- current and prospective conditions in the supply and demand for oil and
natural gas;
- reserve and production quantities for our oil and natural gas properties;
- the history of and prospects for the industry in which we operate;
- the earnings multiples of publicly traded common stocks of comparable
companies;
- our cash flows and earnings and those of comparable companies in recent
periods; and
- our business potential and prospects for future cash flows and earnings.
We can offer no assurances that the initial public offering price will
correspond to the price at which our common stock will trade in the public
market subsequent to this offering or that an active trading market for our
common stock will develop and continue after this offering.
Some of the underwriters and their affiliates have from time to time
performed various investment banking and financial advisory services for CMS
Energy and CMS Enterprises, for which they have received customary fees and
reimbursement of their out-of-pocket expenses. These services include serving as
underwriter or private placement agent in connection with various securities
offerings.
In connection with the offering, the underwriters may engage in stabilizing
transactions, over-allotment transactions, syndicate covering transactions and
penalty bids.
- Stabilizing transactions permit bids to purchase the underlying security
so long as the stabilizing bids do not exceed a specified maximum.
- Over-allotment involves sales by the underwriters in excess of the number
of shares the underwriters are obligated to purchase, which creates a
syndicate short position. The short position
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may be either a covered short position or a naked short position. In a
covered short position, the number of shares over-allotted by the
underwriters is not greater than the number of shares they may purchase
in the over-allotment option. In a naked short position, the number of
shares involved is greater than the number of shares in the
over-allotment option. The underwriters may close out any short position
by either exercising their over-allotment option and/or purchasing shares
in the open market.
- Syndicate covering transactions involve purchases of the common stock in
the open market after the distribution has been completed in order to
cover syndicate short positions. In determining the source of shares to
close out the short position, the underwriters will consider, among other
things, the price of shares available for purchase in the open market as
compared to the price at which they may purchase shares through the
over-allotment option. If the underwriters sell more shares than could be
covered by the over-allotment option, a naked short position, the
position can only be closed out by buying shares in the open market. A
naked short position is more likely to be created if the underwriters are
concerned that there could be downward pressure on the price of the
shares in the open market after pricing that could adversely affect
investors who purchase in the offering.
- Penalty bids permit the representatives to reclaim a selling concession
from a syndicate member when the common stock originally sold by the
syndicate member is purchased in a stabilizing or syndicate covering
transaction to cover syndicate short positions.
These stabilizing transactions, syndicate covering transactions and penalty bids
may have the effect of raising or maintaining the market price of our common
stock or preventing or retarding a decline in the market price of the common
stock. As a result, the price of our common stock may be higher than the price
that might otherwise exist in the open market. These transactions may be
effected on The New York Stock Exchange or otherwise and, if commenced, may be
discontinued at any time.
A prospectus in electronic format may be made available on the web sites
maintained by one or more of the underwriters participating in this offering.
The representatives may agree to allocate a number of shares to underwriters for
sale to their online brokerage account holders. Internet distributions will be
allocated by the underwriters that will make internet distributions on the same
basis as other allocations.
NOTICE TO CANADIAN RESIDENTS
RESALE RESTRICTIONS
The distribution of the common stock in Canada is being made only on a
private placement basis exempt from the requirement that we and the selling
shareholder prepare and file a prospectus with the securities regulatory
authorities in each province where trades of common stock are made. Any resale
of the common stock in Canada must be made under applicable securities laws
which will vary depending on the relevant jurisdiction, and which may require
resales to be made under available statutory exemptions or under a discretionary
exemption granted by the applicable Canadian securities regulatory authority.
Purchasers are advised to seek legal advice prior to any resale of the common
stock.
REPRESENTATIONS OF PURCHASERS
By purchasing common stock in Canada and accepting purchase confirmation a
purchaser is representing to us, the selling shareholder and the dealer from
whom the purchase is received that:
- the purchaser is entitled under applicable provincial securities laws to
purchase the common stock without the benefit of a prospectus qualified
under those securities laws;
- where required by law, the purchaser is purchasing as principal and not
as agent; and
- the purchaser has reviewed the test above under Resale Restrictions.
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RIGHTS OF ACTION (ONTARIO PURCHASERS)
The securities being offered are those of a foreign issuer and Ontario
purchasers will not receive the contractual right of action prescribed by
Ontario securities law. As a result, Ontario purchasers must rely on other
remedies that may be available, including common law rights of action for
damages or rescission or rights of action under the civil liability provisions
of the U.S. federal securities laws.
ENFORCEMENT OF LEGAL RIGHTS
All of the issuer's directors and officers as well as the experts named
herein and the selling shareholder may be located outside of Canada and, as a
result, it may not be possible for Canadian purchasers to effect service of
process within Canada upon the issuer or such persons. All or a substantial
portion of the assets of the issuer and such persons may be located outside of
Canada and, as a result, it may not be possible to satisfy a judgment against
the issuer or such persons in Canada or to enforce a judgment obtained in
Canadian courts against the issuer or such persons outside of Canada.
NOTICE TO BRITISH COLUMBIA RESIDENTS
A purchaser of common stock to whom the Securities Act (British Columbia)
applies is advised that the purchaser is required to file with the British
Columbia Securities Commission a report within ten days after the sale of any
common stock acquired by the purchaser pursuant to this offering. The report
must be in the form attached to British Columbia Securities Commission Blanket
Order BOR #95/17, a copy of which may be obtained from us. Only one report must
be filed for common stock acquired on the same date and under the same
prospectus exemption.
TAXATION AND ELIGIBILITY FOR INVESTMENT
Canadian purchasers of common stock should consult their own legal and tax
advisors with respect to the tax consequences of an investment in the common
stock in their particular circumstances and about the eligibility of the common
stock for investment by the purchaser under relevant Canadian legislation.
MATERIAL U.S. FEDERAL INCOME TAX CONSIDERATIONS
FOR NON-U.S. HOLDERS OF OUR COMMON STOCK
This is a general discussion of U.S. federal tax consequences of the
acquisition, ownership and disposition of our common stock by a non-U.S. holder,
or a beneficial holder that, for U.S. federal income tax purposes, is a
nonresident alien individual, a foreign corporation, a foreign partnership or a
foreign estate or trust. We have based this summary upon the U.S. federal tax
laws in effect as of the date of this prospectus. These laws may change,
possibly retroactively. As noted below, some of these laws are expected to
change for periods beginning after December 31, 2000.
We do not discuss all aspects of U.S. federal taxation that may be
important to you in light of your particular circumstances, such as special tax
rules that apply if you are a financial institution, insurance company,
broker-dealer, tax-exempt organization or investor holding our common stock as
part of a "straddle" or other integrated investment. We urge you to consult your
tax advisor about the U.S. federal tax consequences of acquiring, holding and
disposing of our common stock, as well as any tax consequences that may arise
under the laws of any foreign, state, local or other taxing jurisdiction.
DIVIDENDS
Dividends paid to a non-U.S. holder will generally be subject to
withholding of U.S. federal income tax at the rate of 30%, or such lower rate as
may be provided by an applicable income tax treaty between the U.S. and the
country of which the non-U.S. holder is a tax resident. If, however, the
dividend is effectively connected with the conduct of a trade or business in the
U.S. by the non-U.S. holder, the dividend will be exempt from withholding
(subject to satisfaction of applicable certification procedures, including the
filing of Internal Revenue Service Form W-8ECI) and will instead be subject to
the
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U.S. federal income tax imposed on net income on the same basis that applies to
U.S. persons generally (assuming if required by an applicable tax treaty, the
dividends are attributable to a permanent establishment maintained by the
non-U.S. holder within the U.S.), and for corporate holders and under some
circumstances, the branch profits tax.
For purposes of determining whether tax is to be withheld at a reduced rate
as specified by a treaty, recently finalized Treasury regulations (which in
general are expected to apply to dividends that we pay after December 31, 2000)
require a non-U.S. holder generally to provide an Internal Revenue Service Form
W-8BEN certifying that non-U.S. holder's entitlement to treaty benefits. These
regulations also provide special rules to determine whether, for treaty
applicability purposes, dividends that we pay to a non-U.S. holder that is an
entity should be treated as paid to holders of interests in that entity.
GAIN ON DISPOSITION
A non-U.S. holder will generally not be subject to U.S. federal income tax,
including by way of withholding, on gain recognized on a sale or other
disposition of our common stock unless:
- the gain is effectively connected with the conduct of a trade or business
in the U.S. by the non-U.S. holder or
- in the case of a non-U.S. holder who is a nonresident alien individual
and who holds our common stock as a capital asset, that holder is present
in the U.S. for 183 or more days in the taxable year of the disposition
and certain other requirements are met.
Gain that is effectively connected with the conduct of a trade or business
in the U.S. by the non-U.S. holder will be subject to the U.S. federal income
tax imposed on net income on the same basis that applies to U.S. persons
generally, and, for corporate holders and under some circumstances, the branch
profits tax, but will not be subject to withholding. Non-U.S. holders should
consult any applicable income tax treaties that may provide for different rules.
U.S. FEDERAL ESTATE TAXES
Our common stock that is owned or treated as owned by an individual who is
not a citizen or resident of the U.S., as specially defined for U.S. federal
estate tax purposes, on the date of that person's death will be included in his
or her estate for U.S. federal estate tax purposes, unless an applicable estate
tax treaty provides otherwise.
INFORMATION REPORTING AND BACKUP WITHHOLDING
Generally, we must report annually to the U.S. Internal Revenue Service and
to each non-U.S. holder the amount of dividends that we paid to a holder and the
amount of tax that we withheld on those dividends. This information may also be
made available to the tax authorities of a country in which the non-U.S. holder
resides.
Pursuant to recently finalized Treasury regulations which in general are
expected to apply to payments we make after December 31, 2000, a non-U.S. holder
will be entitled to an exemption from information reporting requirements and
backup withholding tax on dividends that we pay on our common stock if the
non-U.S. holder provides a Form W-8BEN (or satisfies certain documentary
evidence requirements for establishing that it is a non-U.S. holder) or
otherwise establishes an exemption. Payments by a U.S. office of a broker of the
proceeds of a sale of our common stock are subject to both backup withholding at
a rate of 31% and information reporting, unless the holder certifies its
non-U.S. holder status under penalties of perjury or otherwise establishes an
exemption.
Information reporting requirements, but not backup withholding, will also
apply to payments of the proceeds from sales of our common stock by foreign
offices of U.S. brokers, or foreign brokers with certain types of relationships
to the U.S., unless the broker has documentary evidence in its records that the
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holder is a non-U.S. holder and certain other conditions are met, or the holder
otherwise establishes an exemption.
Backup withholding is not an additional tax. Any amounts that we withhold
under the backup withholding rules will be refunded or credited against the
non-U.S. holder's U.S. federal income tax liability, if the required information
is furnished to the U.S. Internal Revenue Service.
LEGAL MATTERS
Matters relating to the validity of the shares of common stock being
offered by this prospectus will be passed upon for us by William H. Stephens
III, our Executive Vice President, General Counsel and Secretary. As of November
15, 2000, Mr. Stephens beneficially owned approximately 41,949 shares of CMS
Energy common stock. Other legal matters in connection with the offering will be
passed upon for us by Sidley & Austin, Chicago, Illinois and William H. Stephens
III and for the underwriters by Skadden, Arps, Slate, Meagher & Flom LLP, New
York, New York. As of November 15, 2000, an attorney currently employed by
Skadden, Arps, Slate, Meagher & Flom LLP, and formerly employed by CMS Energy,
owned stock and other securities of CMS Energy and Consumers. His holdings
consisted of approximately 51,734 shares of CMS Energy common stock, 10 shares
of Consumers $4.50 Series preferred stock, $100 par value, and $50,000 aggregate
principal amount of certain debt securities of CMS Energy.
EXPERTS
The consolidated financial statements as of December 31, 1998 and 1999 and
for each of the three years in the period ended December 31, 1999 included in
this prospectus have been audited by Arthur Andersen LLP, independent public
accountants, as indicated in their report with respect thereto, and are included
herein in reliance upon the authority of said firm as experts in accounting and
auditing in giving said reports.
INDEPENDENT PETROLEUM ENGINEERS
The estimated reserve evaluations and related calculations of Ryder Scott
Company, L.P. and Lee Keeling and Associates, Inc. (with respect to our
Colombian reserves up to and including January 1, 2000), our independent
petroleum engineers, have been included in this prospectus in reliance upon the
authority of those firms as experts in petroleum engineering.
99
<PAGE> 104
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement on Form S-1 under the
Securities Act of 1933, as amended, with respect to the common stock offered by
this prospectus. This prospectus, which constituted part of the registration
statement, does not contain all of the information set forth in the registration
statement and the exhibits thereto. For further information with respect to us
and our common stock, reference is hereby made to the registration statement and
the exhibits thereto. Statements contained in this prospectus as to the contents
of any contract, agreement or other document referred to are not necessarily
complete, and in each instance, reference is made to the copy of the contract,
agreement or other document filed as an exhibit to the registration statement
for a more complete description of the matters involved, each such statement
being qualified in all respects by such reference. The registration statement
and the exhibits thereto may be inspected and copied at the public reference
facilities maintained by the SEC located at Room 1024, 450 Fifth Street, N.W.,
Washington, D.C. 20549, as well as at the regional offices of the SEC located at
Seven World Trade Center, Suite 1300, New York, New York 10048, and 500 West
Madison Street, Suite 1400, Chicago, Illinois 60661. Copies of this material can
also be obtained at prescribed rates by writing to the SEC's Public Reference
Section at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC
at 1-800-SEC-0330 for additional information about its public reference
facilities and copy charges. This information may also be accessed
electronically by means of the SEC's website on the Internet at
http://www.sec.gov.
As a result of this offering, we will be subject to the information
requirements of the Exchange Act of 1934, as amended, and, in accordance with
that Act, will file reports, proxy statements and other information with the SEC
on a periodic basis. The reports, proxy statements and other information that we
file with the SEC can be inspected and copied at the offices of the SEC, at the
website listed above and at the offices of The New York Stock Exchange, Inc., 20
Broad Street, New York, New York 10005.
We intend to furnish our shareholders with annual reports containing
audited financial statements examined by our independent auditors for each
fiscal year.
CMS Energy is subject to the information requirements of the Exchange Act.
You may obtain copies of the documents that CMS Energy files with the SEC at the
offices of the SEC or by means of the SEC's website listed above. The documents
filed with the SEC by CMS Energy are not deemed to be a part of this prospectus
or the registration statement of which it forms a part.
100
<PAGE> 105
GLOSSARY OF OIL AND NATURAL GAS TERMS
We have used the following terms relating to the oil and gas industry
throughout this prospectus:
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to oil or other liquid hydrocarbons.
Bcf. One billion cubic feet.
Boe or net equivalent barrels. Barrels of oil equivalent with natural gas
volumes converted to barrels of oil equivalents using the ratio of 6.0 Mcf of
natural gas to 1.0 barrel of crude oil.
Btu. British thermal unit; the amount of heat required to raise the
temperature of one pound of water one degree Fahrenheit. There are approximately
1,050 Btus in each standard cubic foot of natural gas.
Completion. The installation of permanent equipment for the production of
oil or gas, or in the case of a dry hole, the reporting of abandonment to the
appropriate agency.
Condensate. A hydrocarbon mixture that becomes liquid and separates from
natural gas when the gas is produced; similar to crude oil.
Development well. A well drilled within the proved area of an oil and gas
reservoir to the depth of a stratigraphic horizon known to be productive in an
attempt to recover proved undeveloped reserves or to economically accelerate
production of reserves classified as proved developed.
Dry hole or well. A well found to be incapable of producing hydrocarbons
in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
Exploratory well. A well drilled to find and produce oil or gas in an
unproved area or to find a new reservoir in a field previously found to be
productive of oil or gas in another reservoir.
Farm-in or Farm-out. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in" while
the interest transferred by the assignor is a "farm-out."
Field. An area consisting of single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Gross. "Gross" oil and gas wells or "gross" acres are the total number of
wells or acres in which we have an ownership interest, without regard to the
size of that ownership interest.
Horizontal drilling. A drilling technique that permits the operator to
contact and intersect a larger portion of the producing horizon than
conventional vertical drilling techniques and can result in both increased
production rates and greater ultimate recoveries of hydrocarbons.
LPG. Liquefied petroleum gas.
MBbls. One thousand barrels of oil or other liquid hydrocarbons.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet.
MMBbls. One million barrels of oil or other liquid hydrocarbons.
MMBoe. One million Boe.
MMBtu. One million Btus.
MMcf. One million cubic feet.
101
<PAGE> 106
Natural gas liquids (NGLs) or plant products. Butane, propane, ethane,
natural gasoline and other liquid hydrocarbons that are extracted from natural
gas.
Net. "Net" oil and gas wells or "net" acres are determined by multiplying
gross wells or acres by our working interest in those wells or acres.
Net present value. When used with respect to oil and gas reserves, the
estimated future gross revenue to be generated from the production of proved
reserves calculated in accordance with SEC guidelines, net of estimated
production and future development costs, using prices and costs as of the date
indicated, without giving effect to non-property related expenses such as
general and administrative expenses, debt service and future income tax expenses
or to depreciation, depletion and amortization, discounted using an annual
discount rate of 10%.
Net revenue interest. The percentage of production to which the owner of a
working interest is entitled. For example, the owner of a 100% working interest
in a well burdened only by a landowner's royalty of 12.5% would have an 87.5%
net revenue interest in that well.
Oil. Crude oil and condensate.
Operator. The individual or company responsible for conducting oil and gas
exploration, development and production activities on an oil and gas lease or
concession on its own behalf and, if applicable, for other working interest
owners, generally pursuant to the terms of a joint operating agreement or
comparable agreement.
Overriding royalty interest. An interest in an oil and gas property
entitling the owner to a share of oil and natural gas production free of certain
costs of production.
Producing well. A well that is producing oil or gas or that is capable of
production.
Proved (or proven) developed reserves. Reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods
under existing economic and operating conditions.
Proved (or proven) reserves. The estimated quantities of oil, natural gas,
natural gas liquids and oil which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions.
Proved (or proven) undeveloped reserves. Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Recompletion. Recompletion refers to the completion of an existing well
for production from a formation that exists behind the casing of the well.
Reserve life. The proved reserves divided by the average annualized
production volumes.
Reservoir. A porous and permeable underground formation containing a
natural accumulation of producible oil and/or gas that is confined by
impermeable rock or water barriers and is individual and separate from other
reservoirs.
Royalty interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs of production.
Seismic. The use of shock waves generated by controlled explosions of
dynamite or other means to ascertain the nature and contour of underground
geological structures.
Spud. To start to drill a well.
Tcf. One trillion cubic feet.
102
<PAGE> 107
Undeveloped acreage. Lease acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial quantities
of oil and gas regardless of whether such acreage contains proved reserves.
Working interest. The operating interest that gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production, subject to all royalties, overriding royalties and other burdens and
to all costs of exploration, development and operations and all risks in
connection therewith.
Workover. Operations on a producing well to restore or increase
production.
2-D seismic. Seismic that is run, acquired and processed to yield a
two-dimensional picture of the subsurface.
3-D seismic. Seismic that is run, acquired and processed to yield a
three-dimensional picture of the subsurface. Three dimensional seismic is
relatively expensive because it takes a considerable amount of computer time to
process the data.
103
<PAGE> 108
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Report of Independent Public Accountants.................... F-2
Consolidated Balance Sheets as of December 31, 1998 and 1999
and September 30, 2000 (unaudited)........................ F-3
Consolidated Statements of Income for the years ended
December 31, 1997, 1998 and 1999 and for the nine months
ended September 30, 1999 (unaudited) and 2000
(unaudited)............................................... F-4
Consolidated Statements of Stockholder's Equity for the
years ended December 31, 1997, 1998 and 1999 and for the
nine months ended September 30, 2000 (unaudited).......... F-5
Consolidated Statements of Cash Flows for the years ended
December 31, 1997, 1998 and 1999 and for the nine months
ended September 30, 1999 (unaudited) and 2000
(unaudited)............................................... F-6
Notes to Consolidated Financial Statements.................. F-7
Supplemental Information -- Oil and Gas Producing Activities
(unaudited)............................................... F-22
</TABLE>
F-1
<PAGE> 109
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors,
CMS Oil and Gas Company
We have audited the accompanying consolidated balance sheets of CMS Oil and
Gas Company (a Michigan corporation and wholly-owned subsidiary of CMS
Enterprises Company) and subsidiaries as of December 31, 1998 and 1999, and the
related consolidated statements of income, stockholder's equity and cash flows
for each of the three years in the period ended December 31, 1999. 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 auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the consolidated financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall consolidated 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 CMS Oil and
Gas Company and subsidiaries as of December 31, 1998 and 1999, and the results
of its operations and its cash flows for each of the three years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 28, 2000
F-2
<PAGE> 110
CMS OIL AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
AS OF DECEMBER 31, AS OF
------------------- SEPTEMBER 30,
1998 1999 2000
-------- -------- -------------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash..................................................... $ 6,690 $ 13,188 $ 39,925
Temporary cash investments............................... 3,366 1,331 8,099
Accounts Receivable:
Joint interest, revenues and other.................... 58,422 58,469 73,943
Income tax benefits................................... 21,473 27,575 35,000
Notes receivable from affiliates......................... 20,684 -- 32,469
Inventories:
Crude oil............................................. 3,783 12,181 22,280
Materials and supplies................................ 16,779 13,848 7,144
Other.................................................... 6,544 5,931 3,376
-------- -------- --------
137,741 132,523 222,236
-------- -------- --------
Property, plant and equipment at cost, successful efforts
method................................................... 670,029 816,880 577,006
Less accumulated depreciation, depletion and
amortization.......................................... 245,059 290,416 155,271
-------- -------- --------
424,970 526,464 421,735
-------- -------- --------
Investments and other assets............................... 22,993 25,281 10,026
Deferred tax asset......................................... 21,734 14,688 39,048
-------- -------- --------
44,727 39,969 49,074
-------- -------- --------
Total assets..................................... $607,438 $698,956 $693,045
======== ======== ========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt..................... $ 34,872 $ 828 $ --
Accounts payable......................................... 81,342 85,254 131,000
Accrued interest......................................... 526 4,711 2,223
Notes payable to affiliates.............................. -- 3,637 2,519
Accrued taxes and other.................................. 11,281 6,490 15,185
-------- -------- --------
128,021 100,920 150,927
-------- -------- --------
Long-term debt............................................. 195,512 235,589 130,514
-------- -------- --------
Postretirement benefits and other deferred credits......... 5,136 7,298 7,635
-------- -------- --------
Stockholder's Equity:
Preferred stock, no par value, authorized 5 million
shares, no shares issued or outstanding............... -- -- --
Common stock, no par value, authorized 55 million shares,
issued and outstanding 20 million shares.............. 208,132 266,465 266,466
Accumulated other comprehensive income................... 539 711 651
Retained earnings........................................ 70,098 87,973 136,852
-------- -------- --------
278,769 355,149 403,969
-------- -------- --------
Total liabilities and stockholder's equity....... $607,438 $698,956 $693,045
======== ======== ========
</TABLE>
The accompanying notes are an integral part of these statements.
F-3
<PAGE> 111
CMS OIL AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------ -------------------
1997 1998 1999 1999 2000
-------- -------- -------- -------- --------
(UNAUDITED)
(IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate.................... $ 91,364 $ 66,821 $ 82,560 $ 58,858 $ 76,311
Natural gas........................... 56,369 56,103 54,664 39,590 35,684
Other operating....................... 8,472 4,395 5,538 2,828 6,506
-------- -------- -------- -------- --------
156,205 127,319 142,762 101,276 118,501
-------- -------- -------- -------- --------
Operating Expenses:
Depreciation, depletion and
amortization....................... 48,129 38,067 43,786 31,812 28,505
Exploration costs..................... 27,747 18,976 9,456 6,142 6,160
Operating and maintenance............. 44,169 44,322 51,985 37,685 40,882
General and administrative............ 16,517 14,250 16,819 11,056 14,775
Production taxes and other............ 5,470 5,315 4,029 2,484 3,289
-------- -------- -------- -------- --------
142,032 120,930 126,075 89,179 93,611
-------- -------- -------- -------- --------
Pretax operating income................. 14,173 6,389 16,687 12,097 24,890
Other income............................ 13,146 1,233 712 879 32,842
Interest expense, net of capitalized
interest.............................. 15,723 16,069 13,606 10,004 11,369
-------- -------- -------- -------- --------
Income (loss) before income taxes....... 11,596 (8,447) 3,793 2,972 46,363
Income tax provision (benefit).......... (6,982) (13,881) (14,082) (9,854) (2,516)
-------- -------- -------- -------- --------
Net income.............................. $ 18,578 $ 5,434 $ 17,875 $ 12,826 $ 48,879
======== ======== ======== ======== ========
Net income per share.................... $ 0.93 $ 0.27 $ 0.89 $ 0.64 $ 2.44
======== ======== ======== ======== ========
Average shares outstanding.............. 20,000 20,000 20,000 20,000 20,000
======== ======== ======== ======== ========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-4
<PAGE> 112
CMS OIL AND GAS COMPANY
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
COMMON COMPREHENSIVE RETAINED
STOCK INCOME EARNINGS
-------- ------------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Balance at December 31, 1996.............................. $173,097 $ 49 $ 46,086
Net income.............................................. -- -- 18,578
Change in unrealized investment contributions from
parent............................................... -- 297 --
-------- ---- --------
Balance at December 31, 1997.............................. 173,097 346 64,664
Net income.............................................. -- -- 5,434
Change in unrealized investment contributions from
parent............................................... -- 193 --
Contributions from parent............................... 35,035 -- --
-------- ---- --------
Balance at December 31, 1998.............................. 208,132 539 70,098
Net income.............................................. -- -- 17,875
Change in unrealized investment contributions from
parent............................................... -- 172 --
Contributions from parent............................... 58,333 -- --
-------- ---- --------
Balance at December 31, 1999.............................. 266,465 711 87,973
Net income for the nine months (unaudited).............. -- -- 48,879
Change in unrealized investment contributions from
parent (unaudited)................................... -- (60) --
-------- ---- --------
Balance at September 30, 2000 (unaudited)................. $266,465 $651 $136,852
======== ==== ========
</TABLE>
The accompanying notes are an integral part of these statements.
F-5
<PAGE> 113
CMS OIL AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------- --------------------
1997 1998 1999 1999 2000
--------- --------- --------- -------- ---------
(UNAUDITED)
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash Flow from Operating Activities:
Net Income.................................. $ 18,578 $ 5,434 $ 17,875 $ 12,826 $ 48,879
Reconciliation to net cash provided by
operating activities:
Gain on the sale of assets................ (9,260) -- (619) -- (32,977)
Depreciation, depletion and
amortization............................ 48,129 38,067 43,786 31,812 28,505
Exploration and related expenses.......... 25,042 16,642 6,498 -- 4,167
Deferred income taxes, net................ 1,742 12,872 6,974 3,656 (24,342)
Net Change In:
Accounts receivable....................... 13,549 4,588 (6,149) (35,756) (28,777)
Inventories -- crude oil.................. (102) 308 (8,398) (5,661) (10,099)
Inventories -- materials and supplies..... (5,999) (381) 2,931 1,400 4,699
Other current assets...................... (136) (4,241) 613 (1,535) (3,236)
Accounts payable.......................... (12,391) 22,544 3,912 4,205 20,041
Accrued interest.......................... 114 (1,472) 4,185 2,508 (2,488)
Accrued taxes and other liabilities....... (2,731) 900 (4,791) (4,951) 13,441
Other net................................. (1,104) (5,745) (61) 6,916 (18,931)
--------- --------- --------- -------- ---------
Net Cash Provided by (Used in) Operating
Activities................................ 75,431 89,516 66,756 15,420 (1,118)
--------- --------- --------- -------- ---------
Cash Flow from Investing Activities:
Exploration and development expenditures.... (117,835) (100,842) (98,809) (53,703) (85,503)
Assets purchased............................ (2,939) (41,354) (54,444) (1,618) --
Proceeds from asset sales................... 25,633 -- 2,273 1,215 259,616
Sale of Investment in Yemen................. 20,585 -- -- -- --
--------- --------- --------- -------- ---------
Net Cash Provided By (Used in) Investing
Activities................................ (74,556) (142,196) (150,980) (54,106) 174,113
--------- --------- --------- -------- ---------
Cash Flow from Financing Activities:
Revolving credit borrowings (retirements),
net....................................... 2,000 44,000 7,000 (33,000) (110,000)
Equity contributions from Parent............ -- 35,035 58,333 50,000 --
Proceeds from (repayments of) CMS notes..... (10,000) -- 2,071 999 3,689
Repayment of OPIC loans..................... (5,544) (4,847) (3,185) (2,811) (750)
Loans (to) from affiliates.................. 1,400 (22,084) 24,321 29,719 (33,587)
Capital leases and other, net............... 2,782 (90) 147 167 1,158
--------- --------- --------- -------- ---------
Net Cash Provided by (Used in) Financing
Activities................................ (9,362) 52,014 88,687 45,074 (139,490)
--------- --------- --------- -------- ---------
Net Increase/(Decrease) in Cash and Temporary
Cash Investments............................ (8,487) (666) 4,463 6,388 33,505
Cash and Temporary Cash Investments:
Beginning of period......................... 19,209 10,722 10,056 10,056 14,519
--------- --------- --------- -------- ---------
End of period............................... $ 10,722 $ 10,056 $ 14,519 $ 16,444 $ 48,024
========= ========= ========= ======== =========
Supplementary Information:
Interest payments (net of amounts
capitalized).............................. $ 12,892 $ 15,363 $ 10,311 $ 2,842 $ 8,831
Income tax payments (net of refunds)........ $ (2,064) $ 2,528 $ (16,382) $ 2,579 $ 20,134
</TABLE>
The accompanying notes are an integral part of these statements.
F-6
<PAGE> 114
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(INCLUDING NOTES APPLICABLE TO UNAUDITED PERIODS)
1. SIGNIFICANT ACCOUNTING POLICIES
CMS Oil and Gas Company (the "Company") is a wholly-owned subsidiary of CMS
Enterprises Company (the "Parent") and a second-tier subsidiary of CMS Energy
Corporation ("CMS Energy"). The Company and its subsidiaries are engaged in the
exploration, development, acquisition and production of oil and natural gas,
including the extraction and sale of natural gas liquids. The Company's
oil-producing assets are concentrated in South America (Colombia and Venezuela)
and Africa (the Congo, Equatorial Guinea and Tunisia), and the Company's
gas-producing assets are concentrated in the U.S. (Texas, Wyoming, Montana and
Louisiana), Equatorial Guinea and Tunisia. In June 1997, the Company relocated
its headquarters to Houston, Texas from Jackson, Michigan. Certain
reclassifications have been reflected in the prior years' amounts to conform to
the 1999 presentation. A summary of significant accounting policies is set forth
below:
Basis of Presentation
The Consolidated Financial Statements include the Company and its
subsidiaries. All significant intercompany accounts and transactions have been
eliminated.
The unaudited consolidated financial statements as of September 30, 2000
and for the nine-month periods ended September 30, 1999 and 2000, and all
related footnote information for these periods have been prepared on the same
basis as the audited financial statements and, in the opinion of management,
include all adjustments, consisting of normal recurring adjustments necessary
for a fair presentation of financial position, results of operations and cash
flows in accordance with generally accepted accounting principles.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the Consolidated
Financial Statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Revenue Recognition
Oil and gas revenues are recognized as production takes place and the sale
is completed and the risk of loss transfers to a third party purchaser.
The Company follows the cash method of accounting for production imbalances
for all gas properties. Under this method, the Company recognizes revenues or
production as it is taken and delivered to its purchasers.
F-7
<PAGE> 115
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company and its parents (direct and indirect) have a price risk
management policy to reduce the price risk associated with the fluctuations in
oil and natural gas prices. Commodity derivatives utilized as hedges include
futures, swaps and option contracts, which are used to hedge oil and natural gas
prices. In order to qualify as a hedge price, movements in the underlying
commodity derivative must be highly correlated with the hedged commodity.
Realized gains and losses from the Company's price risk management activities
are recognized in oil and gas production revenues when the associated production
occurs. In these Consolidated Financial Statements, net hedging activity is
included in revenues from oil and condensate or natural gas sales, as
applicable. Net hedging activities have increased (decreased) oil and condensate
and natural gas sales by the following:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------
1997 1998 1999
------- ------ --------
(IN THOUSANDS)
<S> <C> <C> <C>
Oil and condensate...................................... $ 1,782 $ -- $(20,327)
Natural gas............................................. (7,360) 2,946 (99)
------- ------ --------
$(5,578) $2,946 $(20,426)
======= ====== ========
</TABLE>
Inventory
Crude oil and condensate inventory from the Company's Congo fields is
produced into a floating production, storage and off-loading system and sold
periodically as an economic vessel quantity is accumulated. The crude and
condensate inventory is carried at its estimated net realizable value.
Materials and supplies consist primarily of goods used in the Company's
operations and are stated at the lower of average cost or market.
Temporary Cash Investments
All highly liquid investments with an original maturity of three months or
less are considered temporary cash investments.
Oil and Gas Properties
The Company follows the successful efforts method of accounting for its oil
and gas activities. Under the successful efforts method, lease acquisition costs
and all development costs are capitalized. Proved properties are reviewed
whenever events or changes in circumstances indicate that the value of such
property on the Company's books may not be recoverable. Unproved properties are
reviewed quarterly to determine if there has been impairment of the carrying
value, with any such impairment charged to expense in the period. Exploratory
drilling costs are capitalized until the results are determined. If proved
reserves are not discovered, the exploratory costs are expensed. Other
exploratory costs are expensed as incurred. The provision for depreciation,
depletion and amortization is based on the capitalized costs as determined
above, plus future costs to abandon offshore wells and platforms, and is on a
cost center by cost center basis using the units of production method. Interest
costs relating to financing major oil and gas projects in progress are
capitalized until the projects are evaluated or until the production commences
if the projects are evaluated as successful.
Other properties are depreciated using a straight-line method in amounts
which in the opinion of management are adequate to allocate the cost of the
properties over their estimated useful lives.
F-8
<PAGE> 116
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
] Income Taxes
The Company follows Statement of Financial Accounting Standard ("SFAS") No.
109, "Accounting for Income Taxes." Under the asset and liability method of SFAS
No. 109, deferred tax assets and liabilities are recognized for the future tax
consequence, attributable to differences between the financial statement
carrying amounts of existing assets and liabilities and their respective tax
bases.
The Company has entered into a tax sharing agreement with CMS Energy. The
agreement generally provides that, for any taxable period in which the Company
is included in the CMS Energy consolidated tax return, the amount of income
taxes to be paid by the Company will be determined as if the Company had filed a
separate income tax return.
Comprehensive Income
In accordance with SFAS No. 130 "Reporting Comprehensive Income," the
Company has reported comprehensive income in the Consolidated Statement of
Stockholder's Equity. Comprehensive Income consists of the changes in value of
the Company's Supplemental Executive Retirement Plan.
Earnings per Share
Basic EPS is computed by dividing income available to common shareholders
by the weighted average number of common shares outstanding for the period. For
the years ended December 31, 1997, 1998 and 1999, the Company did not have any
potentially dilutive securities.
Foreign Currency
The U.S. dollar is the functional currency for all significant areas of
operations of the Company. Therefore, there are no exchange gains or losses
resulting from the translation of foreign financial statements in the Company's
consolidated financial statements. Certain foreign subsidiaries conduct
operations in the Country's local currency. Exchange gains or losses resulting
from these transactions are recognized currently in the Company's income
statement.
Accounting for Investments
The Company uses the proportionate consolidation method of accounting for
all of its working interest, while investments in less than majority owned
companies are accounted for on the equity method of accounting.
Pension Plan and Supplemental Executive Retirement Plan
The Company participates in an affiliate's trusteed noncontributory defined
benefit plan (the "Plan") covering full-time regular employees within specified
age limits and periods of service. Pension expenses amounted to approximately
$0.2 million for each of the years ended December 31, 1997, 1998 and 1999.
Company employees are not segregated in the Plan and it is not possible to
determine the vested benefit obligation and related Plan assets with respect to
Company employees. The affiliate has indicated that assets available for Plan
benefits are in excess of the accumulated benefit obligation.
The Company participates in CMS Energy's Supplemental Executive Retirement
Plan ("SERP") for certain management employees. SERP benefits, which are based
on an employee's years of service and earnings as defined in the SERP, are paid
from a trust established and funded in 1988. Because the SERP is a nonqualified
plan under the Internal Revenue Code, earnings of the trust are taxable and
trust assets are included in the consolidated assets of the Company.
F-9
<PAGE> 117
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Health Care and Life Insurance Benefits
The Company's health care and life insurance benefit plans for its
employees and retirees are self-insured by CMS Energy. The post-retirement plans
are noncontributory and currently underfunded. The Company accounts for the cost
of these plans on an accrual method as required by SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other than Pensions."
New Accounting Pronouncement
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Investments and Hedging Activities." SFAS 133
establishes accounting and reporting standards requiring that every derivative
instrument (including certain derivative instruments embedded in other
contracts) be recorded in the balance sheet as either an asset or liability
measured at its fair market value. The statement requires that changes in the
derivative's fair value be recognized currently in earnings unless specific
hedge criteria are met. Special accounting for qualifying hedges allows a
derivative's gains and losses to offset related results on the hedged item in
the income statement or other comprehensive income, and requires that a company
must formally document, designate and assess the effectiveness of transactions
that receive hedge accounting.
In June 1999, the FASB issued SFAS No. 137 which deferred the effective
date of SFAS 133 to fiscal years beginning after June 15, 2000. A company may
implement SFAS 133 as of the beginning of any fiscal quarter after issuance,
however, the statement cannot be applied retroactively. The Company does not
plan to early adopt SFAS 133. The Company has not yet assessed the effectiveness
of the Company's September 30, 2000 derivative contracts and therefore cannot
quantify the impact of adoption of SFAS 133. If the Company assumed all
derivative contracts at September 30, 2000 were ineffective, the Company would
have recorded a current liability and pretax net income would be reduced by
approximately $25.2 million, representing the fair value of all derivatives at
that date.
2. PURCHASES OF OIL AND GAS PROPERTIES
During 1997, the Company purchased an additional 14.58% working interest in
the Colon Block in Venezuela and also purchased an additional 33.33% working
interest in the Espinal Block in Colombia for an aggregate total of $2.9
million.
During 1998, the Company purchased an additional 6.25% working interest in
the Marine I Permit in the Congo for approximately $7.6 million. The Company
also acquired an additional 2.4% working interest in the Bioko Permit offshore
Equatorial Guinea for approximately $5.9 million. In late 1998, the Company also
acquired undeveloped, non-producing leasehold acreage in the Powder River Basin
for approximately $27.9 million.
In October 1999, the Company purchased an additional 11.5% working interest
in the Bioko Permit offshore Equatorial Guinea for approximately $53.3 million.
F-10
<PAGE> 118
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3. LONG-TERM DEBT
Long-term debt consisted of the following:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
$225 million revolving credit agreement, variable interest
rate, 6.9% average rate per annum for the year ended
December 31, 1999, maturity date May 26, 2002............. $168,000 $175,000
Notes payable to CMS Energy, interest at the three-month
LIBOR plus 2% per annum, 7.5% at December 31, 1999,
maturity date of April 15, 2009........................... 56,411 58,482
OPIC guaranteed loans at approximately three-month LIBOR
rates per annum, 5.5% at December 31, 1999................ 3,935 750
Capitalized leases and other................................ 2,038 2,185
-------- --------
Total long-term debt.............................. 230,384 236,417
Less current maturities of long-term debt................... 34,872 828
-------- --------
$195,512 $235,589
======== ========
</TABLE>
As of December 31, 1999, principal maturities of long-term debt over the
next five years were as follows:
<TABLE>
<CAPTION>
YEAR ENDING
DECEMBER 31,
------------
(IN THOUSANDS)
<S> <C>
2000................................................... $ 828
2001................................................... 82
2002................................................... 175,088
2003................................................... 46
2004................................................... --
Thereafter............................................. 60,373
--------
$236,417
========
</TABLE>
In May 1999, the Company negotiated the maturity and other terms of the
$225 million Credit Facility with a group of banks. Borrowings under the Credit
Facility are revolving credit loans for three years. The Credit Facility
provides various options to the Company relative to interest rates and also
requires a facility fee. The aggregate borrowing base under the Credit Facility
is limited to the estimated loan value of the Company's oil and natural gas
reserves subject to certain exclusions based upon forecast rates of production
and current commodity pricing as periodically predetermined by the banks which
are parties to the Credit Facility. The banks have broad discretion in
determining which of the Company's reserves to include in the borrowing base.
The total borrowing base at December 31, 1999 under the Credit Facility was
$210 million. Of the total amount available, $175 million in borrowings were
outstanding as of December 31, 1999.
Under the terms of the Credit Facility, the Company must maintain: (1) a
ratio of total indebtedness to total capitalization of no more than 0.60 to 1,
(2) a minimum tangible net worth, as defined, of $275 million plus 50% of the
positive net income commencing with quarter income ended June 30, 1999 plus 50%
of the net proceeds of any equity sale, as defined, (3) a ratio of EBITDA to
interest greater than 2.75 to 1, and (4) consolidated debt to adjusted cash
flow, of 4.25 to 1 for any fiscal quarter ending at any
F-11
<PAGE> 119
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
time on or after December 31, 1999 to and including September 30, 2000, or 3.75
to 1 for any fiscal quarter thereafter. Restrictive covenants under the Credit
Facility include certain limitations on indebtedness and contingent obligations,
as well as certain restrictions on liens, investments, affiliate transactions
and sales of assets. In addition, the banks have the right to require the
Company to repay all advances under the Credit Facility within 90 days after
notification to the banks that (1) CMS Energy no longer beneficially owns a
majority of the outstanding voting stock of the Company or (2) all or
substantially all of the assets of the Company are sold.
As of December 31, 1999, the Company's total indebtedness to total
capitalization was 0.40 to 1; its tangible net worth was $350.1 million; its
EBITDA to interest coverage ratio was 4.8 to 1; and its consolidated debt to
adjusted cash flow ratio was 2.4 to 1.
As of December 31, 1999, $0.8 million of project financing debt was
outstanding under agreements with Overseas Private Investment Corporation
("OPIC"). These OPIC guaranteed loans funded acquisition and development of the
Yombo Field in the Congo.
In August 1995, the Company issued a note in the principal amount of
approximately $61.3 million to the Parent which in turn assigned it to CMS
Energy in connection with the transfer by CMS Energy of the common stock of
Terra Energy, Ltd. to the Parent and then by the Parent to the Company, and in
May 1995, the Company issued another note in the principal amount of
approximately $6.5 million to CMS Energy in connection with borrowings made to
repay $6.5 million of indebtedness of Walter International, Inc. immediately
upon the closing of the Walter acquisition (the Terra note and the Walter note
together are referred to as the "CMS Notes"). During the second quarter of 1999
the Terra Note was amended to extend the maturity to April 15, 2009 and suspend
the interest payments until April 14, 2004. Interest will accrue and be added to
the outstanding debt balance. The outstanding balance of the CMS Notes at
December 31, 1999 was $58.5 million. The CMS Notes bear interest at the rate of
three-month London Interbank Offered Rate ("LIBOR") plus 2% per annum and have a
maturity date of November 1, 2003. Amounts outstanding under the CMS Notes are
expressly subordinate to the Credit Facility. Certain limitations are placed on
the Company's obligations to make payments on the CMS Notes in the event of
default under the terms of the Credit Facility.
4. INCOME TAXES
The Company and its consolidated subsidiaries join with CMS Energy in
filing a consolidated U.S. tax return. Taxable income or loss is determined for
the Company and its subsidiaries as if they were filing separate income tax
returns. Tax benefits for losses and nonconventional fuel tax credits ("Section
29 tax credits") are recognized by the Company to the extent utilized in the
consolidated return. Because the Company has been included in the consolidated
federal income tax return filed by CMS Energy, these Section 29 tax credits have
either been used currently to reduce the tax liability of the CMS Energy
consolidated group or have created an alternative minimum tax credit
carryforward for use in future years. CMS Energy reimburses the Company for the
Section 29 tax credits and other tax benefits used in its consolidated tax
return. The income tax benefit receivable from CMS Energy was $21.5 million and
$27.6 million as of December 31, 1998 and 1999, respectively. To the extent
required by local law, the Company and certain of its subsidiaries file income
and other tax returns in those foreign countries in which the Company does
business.
The Company does not record deferred U.S. taxes on the undistributed
earnings of its foreign subsidiaries as such earnings are intended to be
permanently reinvested. If distributed, those earnings would be subject to both
U.S. income taxes (subject to adjustment for foreign tax credits or deductions)
and withholding taxes payable to various foreign countries. As of September 30,
2000, the Company had approximately $91.0 million of undistributed earnings for
which no U.S. taxes have been provided. Should
F-12
<PAGE> 120
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
these funds be repatriated, then up to an additional $32.0 million in U.S. taxes
would be charged to income.
Significant components of income taxes were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------
1997 1998 1999
------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Current income tax provision (benefit)................ $(8,724) $(26,753) $(21,056)
Deferred income tax provision (benefit)............... 1,742 12,872 6,974
------- -------- --------
$(6,982) $(13,881) $(14,082)
======= ======== ========
</TABLE>
Total income taxes were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
U.S.:
Current............................................ $(11,084) $(25,036) $(23,402)
Deferred........................................... 1,597 6,614 17
Foreign
Current............................................ 2,360 (1,717) 2,346
Deferred........................................... 145 6,258 6,957
-------- -------- --------
Total...................................... $ (6,982) $(13,881) $(14,082)
======== ======== ========
</TABLE>
At December 31, 1999, the Company's wholly-owned subsidiaries have
approximately $129.2 million of net operating loss carryforwards generated in
foreign taxing jurisdictions. These foreign net operating loss carryforwards are
available to offset taxable income only in the jurisdiction in which the
corresponding losses occurred. The losses carry forward until utilized, until
they lapse under the respective taxation regime or the wholly-owned subsidiaries
which generated the losses withdraw from business activities within the
respective taxing jurisdiction. These foreign tax credits will begin expiring in
2001 and end in 2011.
F-13
<PAGE> 121
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal components of the Company's deferred tax assets (liabilities)
recognized in the Consolidated Balance Sheets are as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
--------------------
1998 1999
-------- ---------
(IN THOUSANDS)
<S> <C> <C>
Unsuccessful well and lease costs........................... $(35,500) $ (41,479)
Intangible drilling costs................................... (37,085) (37,125)
Acquisitions................................................ (9,466) (9,466)
Deferred foreign tax........................................ (1,338) (5,294)
Capitalized internal direct costs........................... (4,088) (4,380)
Delay rentals............................................... (1,919) (1,852)
Other....................................................... (2,491) (1,845)
-------- ---------
Deferred tax liabilities.................................... (91,887) (101,441)
-------- ---------
Accumulated depreciation, depletion and amortization........ 53,568 55,030
Alternative minimum tax credit carryforward................. 37,366 37,088
Gains/(losses).............................................. 4,605 4,710
OPEB........................................................ 875 656
Pensions.................................................... 1,180 1,302
Foreign write-offs.......................................... 16,989 15,086
Other....................................................... (800) 2,401
-------- ---------
Gross deferred tax assets................................... 113,783 116,273
-------- ---------
Net deferred tax asset (includes current)................... $ 21,896 $ 14,832
======== =========
</TABLE>
The actual income tax provision (benefit) differ from the amount computed
by applying the statutory U.S. federal tax rate to income before income taxes as
follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1997 1998 1999
-------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C>
Net Income (loss):
Domestic........................................... $ 1,565 $ 6,391 $(12,483)
Foreign............................................ 17,013 (957) 30,358
-------- -------- --------
Net Income........................................... 18,578 5,434 17,875
Income tax provision (benefit)....................... (6,982) (13,881) (14,082)
-------- -------- --------
11,596 (8,447) 3,793
Statutory U.S. income tax rate....................... 35% 35% 35%
-------- -------- --------
Statutory income taxes provision (benefit)........... 4,058 (2,956) 1,328
Increase (Decrease) in Taxes From:
Section 29 tax credits............................. (12,972) (12,820) (12,638)
Undistributed earnings............................. (4,195) (2,598) (11,208)
Intercompany interest income....................... 454 536 412
Foreign taxes, net of U.S. benefit................. 5,671 3,732 8,990
Permanent differences.............................. 237 -- --
Other, net......................................... (235) 225 (966)
-------- -------- --------
Actual income tax provision (benefit)................ $ (6,982) $(13,881) $(14,082)
======== ======== ========
</TABLE>
F-14
<PAGE> 122
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. RELATED PARTY TRANSACTIONS
The Company markets natural gas to affiliates at rates approximating the
average price of natural gas paid to other area producers. Total natural gas
marketed to an affiliate, Consumers Energy Company, was approximately $25.4
million in 1997, $24.2 million in 1998 and $17.8 million in 1999. Total natural
gas marketed to another affiliate, CMS Marketing, Services and Trading Company,
was approximately $30.8 million, $29.6 million, and $26.5 million in 1997, 1998
and 1998, respectively. Natural gas marketed to the Midland Cogeneration Venture
amounted to approximately $10.8 million, $7.6 million and $10.1 million in 1997,
1998 and 1999, respectively. Other intercompany transactions, principally
services, are billed at cost.
For the year ended December 31, 1999, the Company incurred a $0.4 million
service fee for crude oil marketing services by a partially owned affiliate of
CMS Marketing, Services and Trading Company. For each of the years ended
December 31, 1997 and 1998, the Company incurred a $0.2 million service fee for
marketing services by an affiliate, CMS Marketing, Services and Trading Company,
and for the year ended December 31, 1999, the Company incurred a $0.1 million
service fee for marketing services for natural gas.
6. HEALTH CARE AND LIFE INSURANCE BENEFITS
For measurement purposes, a 7.0% annual rate of increase was assumed in the
per capita cost of covered health care benefits for 1999. The rate was assumed
to gradually decrease to 6.0% per annum by the year 2005 and thereafter. The
health care cost trend rate assumption has an impact on the accumulated
postretirement benefit obligation and on future amounts accrued. For the years
ended December 31, 1998 and 1999, the weighted average discount rates were 7.75%
per annum, and the expected long term rate of return on plan assets was 7.0% for
both years. The health care cost trend rate assumption significantly affects the
amounts reported. A one-percentage point change in the assumed health care cost
trend assumption would have the following effects:
<TABLE>
<CAPTION>
ONE PERCENTAGE ONE PERCENTAGE
POINT INCREASE POINT DECREASE
-------------- --------------
(IN THOUSANDS)
<S> <C> <C>
Effect on total services and interest cost
components........................................... $ 86 $ (72)
Effect on postretirement benefit obligation............ $495 $(412)
</TABLE>
F-15
<PAGE> 123
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The funded status of the postretirement benefit plans is reconciled with
the liability recorded as follows:
<TABLE>
<CAPTION>
SERP HEALTH/LIFE
------------- -------------
1998 1999 1998 1999
----- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Benefit obligation January 1........................... $ 2.8 $ 3.5 $ 4.6 $ 4.0
Service cost........................................... 0.1 0.2 0.2 --
Interest cost.......................................... 0.2 0.2 0.3 --
Actuarial loss (gain), expected benefits paid, net..... 0.4 (0.1) (1.1) --
----- ----- ----- -----
Benefit obligation December 31......................... 3.5 3.8 4.0 4.0
----- ----- ----- -----
Plan assets at fair value at January 1................. -- -- 1.4 1.7
Actual return on plan assets........................... -- -- 0.1 --
Company contribution................................... 0.1 -- 0.2 0.3
Actual benefits paid................................... (0.1) -- -- --
----- ----- ----- -----
Plan assets at fair value at December 31............... -- -- 1.7 2.0
----- ----- ----- -----
Benefit obligation less than (in excess of) plan
assets............................................... (3.5) (3.8) (2.3) (2.0)
Unrecognized net (gain) loss from experience different
than assumed......................................... 0.9 0.9 0.2 --
Unrecognized prior service cost........................ 0.1 0.1 0.1 0.1
----- ----- ----- -----
Recorded liability..................................... $(2.5) $(2.8) $(2.0) $(1.9)
===== ===== ===== =====
</TABLE>
7. CAPITAL STOCK
The Company's capital stock consists of one class of common stock, with no
par value, and 5 million shares of preferred stock, with no par value. There are
55 million shares of common stock authorized and 20 million shares issued and
outstanding as of December 31, 1998 and 1999, respectively. The holders of the
common stock are entitled to one vote per share on all matters submitted to a
vote of shareholders. All outstanding shares are held by CMS Enterprises. The
Company has the authority to issue up to 5 million shares of preferred stock in
one or more series and to fix and determine the relative rights and preferences
of the preferred stock. There are no shares of preferred stock issued and
outstanding.
8. SIGNIFICANT CUSTOMERS
Revenues from sales to the Company's largest customers (greater than 10%)
as a percent of total Company revenues were:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-------------------------
1997 1998 1999
----- ----- -----
<S> <C> <C> <C>
ADDAX....................................................... -- -- 11%
BP Oil International, Ltd................................... 14% -- --
TOSCO....................................................... -- -- 14%
CMS Marketing, Services and Trading Company................. 12% 18% 16%
Consumers Energy Company.................................... 15% 19% 11%
Glencore.................................................... 13% 12% --
</TABLE>
9. COMMITMENTS AND CONTINGENCIES
The Company estimates its exploration and development expenditures for 2000
will be $152.6 million and certain commitments have been made in connection
therewith.
F-16
<PAGE> 124
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Dual Consolidated Losses
Under agreements relating to the Company's 1995 acquisition of Walter
International, Inc. and its Congo operations, CMS Energy and the Company could
become jointly and severally liable for the recapture of "dual consolidated
losses" under Section 1503(d) of the Internal Revenue Code if a "triggering
event" were to occur. Potential triggering events include certain asset or stock
dispositions to unrelated parties, certain tax deconsolidations, certain usage
of the losses on a foreign tax return and certain failures to comply with IRS
regulations. CMS Energy and the Company have no plans to effect any transaction
that would be a triggering event. The amount of the potential tax liability
could be up to $67 million plus interest. In connection with the same
acquisition, a subsidiary of the Company could also be jointly and severally
liable with an unrelated party for up to $48 million of tax plus interest. In
that event, the Company has certain indemnity rights against that unrelated
party. Additionally, the Company and its domestic subsidiaries have incurred
losses in certain foreign countries that could be recaptured if a triggering
event were to occur. The additional tax liability could be up to $10 million
plus interest.
Hedging Arrangements
The Company enters into oil and gas price hedging arrangements with an
affiliate to mitigate its exposure to price fluctuations on the sale of crude
oil and natural gas. The Company received $1.8 million in 1997 and made net
payments of $20.3 million in 1999 for settlements of its crude oil contracts.
There were no crude oil hedging contracts in 1998. The Company paid $7.4 million
in 1997, received $2.9 million in 1998 and paid $0.1 million in 1999 for
settlement of its natural gas contracts. As of December 31, 1999 the Company had
entered into 2000 hedging arrangements with an affiliate on 18.8 Bcf of natural
gas at an average price of $2.61 per Mcf and 5.7 million barrels of oil at an
average price of $15.62 per barrel.
The contracts are accounted for as hedges; accordingly, changes in market
value and gains or losses from settlements are deferred and recognized at such
time as the hedged transaction is completed. If there were a loss of correlation
between the changes in (1) the market value of the derivative contracts and (2)
the market price ultimately received for the hedged item, and the impact was
material, the open commodity price contracts would be marked to market and gains
and losses would be currently recognized in the statement of income currently.
The Company has also hedged certain of its natural gas supply obligations
to the Midland Cogeneration Venture in the years 2001 through 2006 by entering
into an agreement with Louis Dreyfus Natural Gas on May 1, 1989 to purchase the
economic equivalent of 10,000 MMBtu per day at a fixed price, escalating at 8%
per year thereafter, starting at $2.82 per MMBtu in 2001. The settlement periods
are each a one-year period ending December 31, 2001 through 2006 on 3.65 million
MMBtu. If the floating price, essentially the then-current Gulf Coast spot price
for a period, is higher than the fixed price, the seller pays the Company the
difference and vice versa.
The contract with Louis Dreyfus Natural Gas provides a calculation of
exposure for the purpose of requiring an exposed party to post a standby letter
of credit. Under this calculation, if a party's exposure at any time exceeds $5
million, that party is required to obtain a letter of credit in favor of the
other party for the excess over $5 million up to a maximum standby letter of
credit of $10 million. At December 31, 1999, a letter of credit was not required
by either party to the agreement. The letter of credit obligation does not
necessarily bear any relation to the market value of the contract. As of
December 31, 1999, the fair market value of the contract reflected a payment due
to Louis Dreyfus Natural Gas of $19.3 million. The Company believes the market
is thin for contracts with settlement periods comparable to the Company's
contract with Louis Dreyfus Natural Gas. In the second quarter of 2000, the
Company assigned this agreement to an affiliate. Although the affiliate has
assumed the Company's obligations under the agreement, the Company remains
liable for the obligations if the affiliate should fail to fulfill its
obligations.
F-17
<PAGE> 125
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company had entered into two-interest rate swap agreements, which
effectively fixed the interest rate on $30 million of floating rate debt. The
swap agreements included (1) a $15 million interest rate swap which matured
February 19, 1998 at 5.952 % and (2) a $15 million interest rate swap which
matured August 19, 1998 at 6.069 %. Both swaps required quarterly settlement
based on a three-month LIBOR rate.
Other
The Company is party to certain lawsuits and administrative proceedings
arising in the ordinary course of business before various courts and
governmental agencies involving, for example, claims for personal injury and
property damages, contractual matters, environmental issues, tax issues and
other matters. Management cannot predict the ultimate resolution of these
matters but it believes the resulting liabilities, if any, will not have a
material adverse effect upon the Company's financial position or results of
operations or cash flows.
In 1999 the Company's former subsidiary, Terra Energy Ltd., was sued by
Star Energy and White Pines Enterprises on grounds, among others, that Terra
violated oil and gas lease and other agreements by failing to drill wells it had
committed to drill. Among the defenses asserted by Terra were that the wells
were not required to be drilled and the claimant's sole remedy was termination
of the oil and gas lease. During trial the judge declared the lease terminated
in favor of White Pines. The jury then awarded Star and White Pines $7.6 million
in damages. Terra has filed an appeal. The Company believes Terra has
meritorious grounds for reversal of the judgment. The Company has an
indemnification obligation in favor of the purchaser of its Michigan properties
with respect to this litigation.
10. FINANCIAL INSTRUMENTS
The carrying amounts of cash, temporary cash investments and current
liabilities approximate their fair values due to their short-term nature. The
carrying amounts of long-term debt were $230.4 million and $236.4 million as of
December 31, 1998 and 1999, respectively. The fair value of such debt is
substantially equal to the carrying value due to the stated interest rates
approximating market rates at December 31, 1998 and 1999.
The fair values of the Company's off-balance sheet financial instruments
are based on the amounts estimated to terminate or settle the instruments. See
note 9 of the consolidated financial statements of the Company.
11. LEASES
The Company and its subsidiaries lease various assets, including vehicles,
office equipment and office space under leases expiring on various dates through
2008. Rental expense under these leases was $1.2 million, $1.2 million and $1.1
million for the years ended December 31, 1997, 1998 and 1999, respectively.
F-18
<PAGE> 126
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Minimum rental commitments under the Company's non-cancelable leases at
December 31, 1999, were as follows (capital leases are presented net of imputed
interest):
<TABLE>
<CAPTION>
CAPITAL OPERATING
------- ---------
(IN THOUSANDS)
<S> <C> <C>
2000........................................................ $ 78 $ 1,346
2001........................................................ 83 1,297
2002........................................................ 88 1,263
2003........................................................ 46 1,142
2004........................................................ -- 1,084
2005........................................................ -- 1,011
Thereafter.................................................. 1,890 3,034
------ -------
2,185 10,177
=======
Less: Current portion....................................... (78)
------
Non-current portion......................................... $2,107
======
</TABLE>
12. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment were as follows:
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
---------------------
1998 1999
--------- ---------
(IN THOUSANDS)
<S> <C> <C>
Oil and Gas Properties:
Proved.................................................... $ 611,847 $ 739,793
Unproved.................................................. 40,716 57,059
--------- ---------
652,563 796,852
Other properties............................................ 17,466 20,028
--------- ---------
670,029 816,880
Less accumulated depreciation, depletion and amortization... (245,059) (290,416)
--------- ---------
Net property, plant and equipment........................... $ 424,970 $ 526,464
========= =========
</TABLE>
Depreciation, depletion and amortization for oil and gas properties for the
years ended December 31, 1997, 1998 and 1999 were $47.1 million, $36.2 million
and $41.7 million, respectively.
13. OTHER OPERATING REVENUES
Other operating revenues were as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------
1997 1998 1999
------ ------ ------
(IN THOUSANDS)
<S> <C> <C> <C>
Natural gas liquids........................................ $5,095 $2,769 $3,715
Marketing, rentals & other................................. 3,377 1,626 1,823
------ ------ ------
$8,472 $4,395 $5,538
====== ====== ======
</TABLE>
F-19
<PAGE> 127
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
14. GEOGRAPHIC AREA INFORMATION
Pertinent information with respect to the Company's business is presented
in the following table:
<TABLE>
<CAPTION>
OIL AND GAS PRODUCING ACTIVITIES
---------------------------------------------------
AFRICA &
MIDDLE SOUTH UNITED OTHER
EAST* AMERICA STATES REGIONS SUBTOTAL OTHER TOTAL
-------- -------- -------- ------- -------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
1997:
Revenues.................. $ 38,663 44,165 $ 73,377 $ -- 156,205 $ -- $156,205
Pretax operating income
(loss)................. 3,717 1,834 32,766 34 38,351 (24,178) 14,173
Depreciation, depletion
and amortization....... 4,023 25,606 17,493 -- 47,122 1,007 48,129
Exploration and
development
expenditures........... 33,600 21,732 19,232 (8) 74,556 -- 74,556
Identifiable assets at
December 31............ 141,640 113,593 231,550 839 487,622 14,784 502,406
1998:
Revenues.................. $ 31,721 $ 33,030 $ 62,554 $ 14 $127,319 $ -- $127,319
Pretax operating income
(loss)................. 3,046 7,016 19,262 14 29,338 (22,949) 6,389
Depreciation, depletion
and amortization....... 5,364 13,457 17,382 -- 36,203 1,864 38,067
Exploration and
development
expenditures........... 57,930 22,015 61,871 380 142,196 -- 142,196
Identifiable assets at
December 31............ 200,673 110,684 277,874 354 589,585 17,853 607,438
1999:
Revenues.................. $ 61,122 $ 42,094 $ 39,546 $ -- $142,762 $ -- $142,762
Pretax operating income
(loss)................. 28,494 13,975 3,083 -- 45,552 (28,865) 16,687
Depreciation, depletion
and amortization....... 8,003 12,941 20,747 -- 41,691 2,095 43,786
Exploration and
development
expenditures........... 100,652 21,089 28,920 319 150,980 -- 150,980
Identifiable assets at
December 31............ 304,391 113,893 260,129 152 678,565 20,391 698,956
</TABLE>
---------------
* Includes exploration and development expenditures and identifiable assets
attributable to the Company's equity investment in Comeco; see Supplemental
Information following the Notes to the Consolidated Financial Statements.
15. SUBSEQUENT EVENTS (UNAUDITED)
The Company's indirect parent CMS Energy Corporation announced in January
2000 that it had signed a letter of intent to sell all of the Company's Michigan
oil and gas producing properties to Quicksilver Resources, Inc. for
approximately $162.9 million. The transaction closed on March 31, 2000 with an
after-tax gain of $5.2 million.
On June 30, 2000, the Company sold its 14% non-operated interest in Ecuador
for $95.8 million and recognized a $29.6 million after-tax gain.
F-20
<PAGE> 128
CMS OIL AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In September 2000, CMS Energy announced its intention to sell up to 50% of
its ownership in the Company through an initial public offering ("IPO"). In
connection with the proposed IPO, the Company plans to acquire an indirect 45%
interest in a methanol production plant from an affiliate for a non-interest
bearing note of $137.0 million, refinance its existing debt by issuing $200.0
million of senior subordinated notes, and distribute a $39.0 million
non-interest bearing note payable to the Parent.
In addition to the proposed transactions, the Company intends to adopt a
stock option plan for executive officers and other key employees, enter into
various service agreements with CMS Energy and other affiliates and enter into
oil and gas marketing and hedging agreements with affiliates. The Company has
entered into change of control severance agreements with its executive officers.
The Company currently is a member of the CMS Energy affiliate group of
corporations that files its U.S. tax returns on a consolidated basis. (See Note
4). Upon completion of the IPO, the Company will cease to be a member of the
affiliated group consolidated tax return and the Company will file a separate
income tax return.
F-21
<PAGE> 129
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
The following information was prepared in accordance with the Supplemental
Disclosure Requirements of SFAS No. 69, "Disclosures About Oil and Gas Producing
Activities." Refer to the Consolidated Statements of Income for the Company's
results of operations from exploration and production activities provided
elsewhere in the consolidated financial statements.
The following estimates of proved reserves and future net cash flows before
income taxes as of December 31, 1997, 1998 and 1999 have been prepared by Ryder
Scott Company L.P. and/or Lee Keeling and Associates, Inc. These estimates do
not purport to reflect realizable values or fair market values of the Company's
reserves. The Company emphasizes that reserve estimates are inherently imprecise
and that estimates of new discoveries are more imprecise than those of currently
producing oil and natural gas properties. Accordingly, these estimates are
expected to change as future information becomes available.
Proved reserves are estimated quantities of oil and natural gas which
geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and
operating conditions.
The government license in Venezuela is an oil service contract whereby the
Company is paid a fee per barrel for oil discovered, lifted and delivered to
Maraven S.A., a subsidiary of Petroleos de Venezuela S.A. Additionally, the
Company receives a fee for reimbursement of certain capital expenditures. The
volumes presented represent actual production with respect to which the Company
is paid a per barrel fee. Data related to the Company's equity investment in
Yemen through Comeco is shown separately.
1. ESTIMATED PROVED RESERVES OF OIL AND NATURAL GAS
<TABLE>
<CAPTION>
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S.
------------- ------------ ------- ------------
OIL GAS OIL GAS OIL OIL GAS
----- ----- ---- ----- ------- ---- -----
(OIL IN MMBBLS AND NATURAL GAS IN BCF)
<S> <C> <C> <C> <C> <C> <C> <C>
Estimated Proved Developed and Undeveloped
Reserves:
December 31, 1996............................. 76.4 323.2 35.0 49.5 39.6 1.8 273.7
Revisions and other changes................ 10.6 6.4 9.8 13.6 0.6 0.2 (7.2)
Extensions and discoveries................. 9.9 26.3 0.6 11.7 9.0 0.3 14.6
Acquisitions of reserves................... 8.3 -- -- -- 8.3 -- --
Sales of reserves.......................... -- (6.5) -- -- -- -- (6.5)
Production................................. (6.9) (27.2) (2.4) (.7) (3.8) (.7) (26.5)
----- ----- ---- ----- ----- ---- -----
December 31, 1997............................. 98.3 322.2 43.0 74.1 53.7 1.6 248.1
Revisions and other changes................ (8.2) (27.4) 2.0 1.4 (10.7) 0.5 (28.8)
Extensions and discoveries................. 3.3 278.3 3.2 270.9 0.1 -- 7.4
Acquisitions of reserves................... 2.9 17.4 2.9 17.4 -- -- --
Sales of reserves.......................... -- -- -- -- -- -- --
Production................................. (7.7) (26.5) (2.8) (1.9) (4.2) (0.7) (24.6)
----- ----- ---- ----- ----- ---- -----
December 31, 1998............................. 88.6 564.0 48.3 361.9 38.9 1.4 202.1
===== ===== ==== ===== ===== ==== =====
</TABLE>
F-22
<PAGE> 130
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
<TABLE>
<CAPTION>
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S.
------------- ------------ ------- ------------
OIL GAS OIL GAS OIL OIL GAS
----- ----- ---- ----- ------- ---- -----
(OIL IN MMBBLS AND NATURAL GAS IN BCF)
<S> <C> <C> <C> <C> <C> <C> <C>
December 31, 1998............................. 88.6 564.0 48.3 361.9 38.9 1.4 202.1
Revisions and other changes................ 15.2 135.2 15.3 131.1 (.6) 0.5 4.1
Extensions and discoveries................. 12.0 23.2 0.1 2.1 11.2 0.7 21.1
Acquisitions of reserves................... 8.8 92.1 8.8 92.1 -- -- --
Sales of reserves.......................... -- -- -- -- -- -- --
Production................................. (7.7) (26.4) (3.4) (3.3) (3.6) (0.7) (23.1)
----- ----- ---- ----- ----- ---- -----
December 31, 1999............................. 116.9 788.1 69.1 583.9 45.9 1.9 204.2
===== ===== ==== ===== ===== ==== =====
Estimated Proved Developed Reserves:
December 31, 1996............................. 39.2 270.0 22.1 -- 15.3 1.8 270.0
December 31, 1997............................. 45.3 267.8 25.1 29.6 18.5 1.7 238.2
December 31, 1998............................. 50.6 448.8 31.7 251.0 17.5 1.4 197.8
December 31, 1999............................. 74.5 652.7 50.9 460.9 21.8 1.8 191.8
Equity Interest in Estimated Proved Reserves of
Comeco (Company's holdings in Comeco sold on
December 5, 1997):
December 31, 1996............................. 3.2 -- 3.2 -- -- -- --
</TABLE>
2. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PROVED RESERVES
<TABLE>
<CAPTION>
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S.
---------- ----------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
December 31, 1997
Future Cash Flows:
Revenues(1)................................ $1,806,077 $ 770,305 $499,723 $536,049
Less:
Production costs(2)........................ 628,853 313,275 141,592 173,986
Development costs(2)....................... 114,248 36,224 65,119 12,905
---------- ---------- -------- --------
Future net cash flows before income taxes..... 1,062,976 420,806 293,012 349,158
Less discount to present value at 10% annual
rate....................................... 404,281 225,559 95,020 83,702
---------- ---------- -------- --------
Present value of future net cash flows before
income taxes............................... 658,695 195,247 197,992 265,456
Future income taxes discounted at 10% annual
rate(3).................................... 39,489 50,183 20,113 (30,807)
---------- ---------- -------- --------
Standardized measure of discounted future net
cash flows................................. $ 619,206 $ 145,064 $177,879 $296,263
========== ========== ======== ========
</TABLE>
F-23
<PAGE> 131
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
<TABLE>
<CAPTION>
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S.
---------- ----------- -------- --------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
December 31, 1998
Future Cash Flows:
Revenues(1)................................ $1,287,751 $ 645,155 $235,592 $407,004
Less:
Production costs(2)........................ 459,279 239,114 87,690 132,475
Development costs(2)....................... 108,386 55,222 44,813 8,351
---------- ---------- -------- --------
Future net cash flows before income taxes..... 720,086 350,819 103,089 266,178
Less discount to present value at 10% annual
rate....................................... 326,169 205,445 33,906 86,818
---------- ---------- -------- --------
Present value of future net cash flows before
income taxes............................... 393,917 145,374 69,183 179,360
Future income taxes discounted at 10% annual
rate(3).................................... (42,273) 17,551 (24,661) (35,163)
---------- ---------- -------- --------
Standardized measure of discounted future net
cash flows................................. $ 436,190 $ 127,823 $ 93,844 $214,523
========== ========== ======== ========
December 31, 1999
Future Cash Flows:
Revenues(1)................................ $2,971,270 $1,735,350 $747,616 $488,304
Less:
Production costs(2)........................ 668,231 366,314 145,924 155,993
Development costs(2)....................... 120,720 64,981 45,546 10,193
---------- ---------- -------- --------
Future net cash flows before income taxes..... 2,182,319 1,304,055 556,146 322,118
Less discount to present value at 10% annual
rate....................................... 946,822 653,429 179,800 113,593
---------- ---------- -------- --------
Present value of future net cash flows before
income taxes............................... 1,235,497 650,626 376,346 208,525
Future income taxes discounted at 10% annual
rate(3).................................... 229,077 154,291 92,696 (17,910)
---------- ---------- -------- --------
Standardized measure of discounted future net
cash flows................................. $1,006,420 $ 496,335 $283,650 $226,435
========== ========== ======== ========
</TABLE>
---------------
(1) Oil, natural gas and condensate revenues are based on year-end prices with
adjustments for changes reflected in existing contracts. There is no
consideration for future discoveries or risks associated with future
production of estimated proved reserves.
(2) Based on economic conditions at year-end. Does not include general,
administrative or financing costs. Does not consider future changes in
development or production costs.
(3) Based on current statutory rates applied to future cash inflows reduced by
future production and development costs, tax deductions and credits. Income
tax expense has been reduced by $60.6 million, $43.4 million and $32.8
million due to the nonconventional fuels tax credit for Antrim gas produced
at December 31, 1997, 1998 and 1999, respectively.
F-24
<PAGE> 132
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
3. RECONCILIATION OF THE CHANGE IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1997 1998 1999
--------- --------- ---------
(IN THOUSANDS)
<S> <C> <C> <C>
New discoveries................................... $ 66,484 $ 28,021 $ 131,451
Acquisitions of reserves in place................. 20,431 7,234 87,524
Sales of reserves in place........................ (7,963) -- --
Revisions to reserves............................. 33,437 (38,896) 161,765
Sales and transfers............................... (106,133) (71,077) (103,204)
Changes in prices................................. (334,855) (148,979) 455,217
Accretion of discount............................. 95,188 65,870 39,392
Net change in income taxes........................ 119,136 81,762 (271,350)
Changes in timing of production and other......... (59,770) (106,951) 69,435
--------- --------- ---------
Net change during year.................. $(174,045) $(183,016) $ 570,230
========= ========= =========
</TABLE>
4. NET INVESTMENT(1)
<TABLE>
<CAPTION>
AS OF DECEMBER 31,
-------------------
1998 1999
-------- --------
(IN THOUSANDS)
<S> <C> <C>
Proved developed properties................................. $611,847 $739,793
Proved undeveloped properties (not subject to depletion).... 40,716 57,059
-------- --------
652,563 796,852
Less accumulated depreciation, depletion and amortization... 240,082 284,209
-------- --------
$412,481 $512,643
======== ========
</TABLE>
---------------
(1) Excluded are approximately $17.4 million ($12.5 million net of accumulated
depreciation) in 1998 and $20.0 million ($13.8 million net of accumulated
depreciation) in 1999 for non-oil and gas producing properties. As of
December 31, 1999, the Company's non-U.S. investments in Colombia, Congo,
Ecuador, Equatorial Guinea, Tunisia and Venezuela are subject to depletion.
F-25
<PAGE> 133
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
5. EXPLORATION, DEVELOPMENT AND ACQUISITION EXPENDITURES
<TABLE>
<CAPTION>
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S. OTHER
-------- ----------- ------- ------- -----
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1997:(1)
Exploration................................ $ 40,593 $ 31,171 $ 7,032 $ 2,390 $ --
Development................................ 31,024 2,429 12,346 16,257 (8)
Property acquisitions...................... 2,939 -- 2,354 585 --
-------- -------- ------- ------- ----
$ 74,556 $ 33,600 $21,732 $19,232 $ (8)
======== ======== ======= ======= ====
Year Ended December 31, 1998:(1)
Exploration................................ $ 36,208 $ 21,234 $ 116 $14,478 $380
Development................................ 64,634 23,210 21,899 19,525 --
Property acquisitions...................... 41,354 13,485 -- 27,869 --
-------- -------- ------- ------- ----
$142,196 $ 57,929 $22,015 $61,872 $380
======== ======== ======= ======= ====
Year Ended December 31, 1999:
Exploration................................ $ 14,706 $ 2,864 $ 5,159 $ 6,410 $273
Development................................ 81,830 44,345 15,910 21,575 --
Property acquisitions...................... 54,444 53,444 20 980 --
-------- -------- ------- ------- ----
$150,980 $100,653 $21,089 $28,965 $273
======== ======== ======= ======= ====
</TABLE>
---------------
(1) Certain reclassifications have been reflected in the 1997 and 1998 amounts
to conform with the 1999 presentation.
F-26
<PAGE> 134
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
6. RESULTS OF OPERATIONS FROM OIL AND GAS PRODUCING ACTIVITIES
The following tables set forth the Company's results of operations from oil
and gas producing activities for the years ended December 31, 1997, 1998 and
1999. Income taxes are computed by applying the appropriate statutory rate to
the results of operations before income taxes. Applicable tax credits, permanent
differences and allowances related to oil and gas producing activities have been
taken into account in computing income taxes. The results of operations below do
not include general and administrative expenses, general taxes and net interest
expense.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S. OTHER
-------- ----------- ------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:(1)
Oil and condensate.......................... $ 91,364 $36,284 $44,165 $10,915 $ --
Natural gas................................. 56,369 177 -- 56,192 --
Other operating............................. 8,472 2,202 -- 6,270 --
-------- ------- ------- ------- -------
156,205 38,663 44,165 73,377 --
Operating Expenses:
Depreciation, depletion and amortization.... 47,122 4,023 25,606 17,493 --
Exploratory dry holes....................... 17,215 10,960 2,623 3,632 --
Operating and maintenance................... 44,169 15,119 13,162 13,215 2,673
Geological and geophysical expenses......... 9,628 4,844 510 1,579 2,695
Delay rentals and lease expenses............ 904 -- 43 887 (26)
Production taxes............................ 4,192 -- 387 3,805 --
-------- ------- ------- ------- -------
123,230 34,946 42,331 40,611 5,342
-------- ------- ------- ------- -------
32,975 3,717 1,834 32,766 (5,342)
Income Taxes(2)............................... (1,714) (1,230) 1,885 (499) (1,870)
-------- ------- ------- ------- -------
Results of Operations from Producing
Activities.................................. $ 34,689 $ 4,947 $ (51) $33,265 $(3,472)
======== ======= ======= ======= =======
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1998
----------------------------------------------------
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S. OTHER
-------- ----------- ------- ------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:(1)
Oil and condensate.......................... $ 66,822 $28,364 $32,217 $ 6,241 $ --
Natural gas................................. 56,103 1,489 -- 54,614 --
Other operating............................. 4,395 1,868 813 1,700 14
-------- ------- ------- ------- -------
127,320 31,721 33,030 62,555 14
Operating Expenses:
Depreciation, depletion and amortization.... 36,203 5,364 13,457 17,382 --
Exploratory dry holes....................... 13,717 3,973 (2) 9,746 --
Operating and maintenance................... 44,322 18,458 12,570 10,988 2,306
Geological and geophysical expenses......... 3,834 880 (11) 631 2,334
Delay rentals and lease expenses............ 1,425 -- -- 1,425 --
Production taxes & other.................... 3,120 -- -- 3,120 --
-------- ------- ------- ------- -------
102,621 28,675 26,014 43,292 4,640
-------- ------- ------- ------- -------
24,699 3,046 7,016 19,263 (4,626)
Income Taxes(2)............................... (2,687) 1,934 2,811 (5,808) (1,624)
-------- ------- ------- ------- -------
Results of Operations from Producing
Activities.................................. $ 27,386 $ 1,112 $ 4,205 $25,071 $(3,002)
======== ======= ======= ======= =======
</TABLE>
F-27
<PAGE> 135
CMS OIL AND GAS COMPANY
SUPPLEMENTAL INFORMATION OIL AND GAS PRODUCING ACTIVITIES -- (CONTINUED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999
-----------------------------------------------------
AFRICA & SOUTH
TOTAL MIDDLE EAST AMERICA U.S. OTHER
-------- ----------- ------- -------- -------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:(1)
Oil and condensate......................... $ 82,560 $52,418 $42,170 $(12,028) $ --
Natural gas................................ 54,664 4,680 -- 49,984 --
Other operating............................ 5,538 4,024 (76) 1,590
-------- ------- ------- -------- -------
142,762 61,122 42,094 39,546 --
Operating Expenses:
Depreciation, depletion and amortization... 41,691 8,003 12,941 20,747 --
Exploratory dry holes...................... 3 5 -- (2) --
Operating and maintenance.................. 51,985 21,404 14,591 10,087 5,903
Geological and geophysical expenses........ 4,874 1,149 497 270 2,958
Delay rentals and lease expenses........... 4,579 2,067 90 2,422 --
Production taxes........................... 2,939 -- -- 2,939 --
-------- ------- ------- -------- -------
106,071 32,628 28,119 36,463 8,861
-------- ------- ------- -------- -------
36,691 28,494 13,975 3,083 (8,861)
Income Taxes................................. (2,453) 6,172 5,298 (10,822) (3,101)
-------- ------- ------- -------- -------
Results of Operations from Producing
Activities................................. $ 39,144 $22,322 $ 8,677 $ 13,905 $(5,760)
======== ======= ======= ======== =======
</TABLE>
---------------
(1) The effects of hedging activities are included in oil and condensate
revenues or natural gas revenues depending on the nature of the hedge
instrument. See note 9 of the audited financial statements presented
elsewhere in this report.
(2) The computation of income taxes has been restated to conform to the 1999
presentation.
F-28
<PAGE> 136
APPENDIX A
[RYDER SCOTT LETTERHEAD]
November 10, 2000
CMS Oil and Gas Company
1021 Main Street, Suite 2800
Houston, TX 77002-6606
Gentlemen:
At your request, we have prepared an estimate of the reserves, future
production, and income attributable to certain leasehold and royalty interests
of CMS Oil and Gas Company (CMS) as of September 30, 2000. The income data were
estimated using Securities and Exchange Commission (SEC) future cost and price
parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. CMS provided us with September 2000 prices;
however, actual future prices may vary significantly from the September 2000
prices. Therefore, volumes of reserves actually recovered and amounts of income
actually received may differ significantly from the estimated quantities
presented in this report. A summary of the results of this study is shown below.
SEC PARAMETERS
ESTIMATED NET RESERVES AND INCOME DATA
CERTAIN LEASEHOLD AND ROYALTY INTERESTS OF
CMS OIL AND GAS COMPANY
AS OF SEPTEMBER 30, 2000
<TABLE>
<CAPTION>
PROVED
--------------------------------------------------------------
DEVELOPED
------------------------------
PRODUCING NON-PRODUCING UNDEVELOPED TOTAL PROVED
-------------- ------------- ------------ --------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
Oil/Condensate -- Barrels......... 61,107,596 4,746,763 13,322,001 79,176,360
Plant Products -- Barrels......... 12,216,744 0 0 12,216,744
Gas -- MMCF....................... 672,554 25,074 26,127 723,755
INCOME DATA
Future Gross Revenue.............. $2,445,316,991 $177,216,901 $465,892,570 $3,088,426,462
Deductions........................ 605,185,890 45,938,236 201,794,835 852,918,961
-------------- ------------ ------------ --------------
Future Net Income (FNI)........... $1,840,131,101 $131,278,665 $264,097,735 $2,235,507,501
Discounted FNI @ 10%.............. $ 939,135,185 $ 84,272,260 $141,318,884 $1,164,726,329
</TABLE>
Liquid hydrocarbons are expressed in standard 42 gallon barrels. All gas
volumes are sales gas expressed in millions of cubic feet (MMCF) at the official
temperature and pressure bases of the areas in which the gas reserves are
located.
The proved developed non-producing reserves included herein are comprised
of the shut-in and behind pipe categories. The various producing status
categories are defined under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
The future gross revenue is after the deduction of production taxes. The
deductions are comprised of the normal direct costs of operating the wells, ad
valorem taxes, recompletion costs, development costs, and transportation and
marketing charges. The future net income is before the deduction of state and
federal income taxes and general administrative overhead, and has not been
adjusted for outstanding loans that may exist nor does it include any adjustment
for cash on hand or undistributed income. No attempt
A-1
<PAGE> 137
CMS Oil and Gas Company
November 10, 2000
Page 2
was made to quantify or otherwise account for any accumulated gas production
imbalances that may exist. Liquid hydrocarbon reserves account for approximately
77 percent and gas reserves account for 23 percent of total future gross revenue
from proved reserves for those properties analyzed in this report.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly. Future net income was
discounted at four other discount rates which were also compounded monthly.
These results are shown on each estimated projection of future production and
income presented in a later section of this report and in summary form below.
<TABLE>
<CAPTION>
DISCOUNTED
FUTURE NET
INCOME AS OF
SEPTEMBER 30,
2000
DISCOUNT RATE -------------
PERCENT TOTAL PROVED
------------- -------------
<S> <C>
15.................................................... $928,067,749
20.................................................... $769,003,247
25.................................................... $654,963,992
30.................................................... $569,139,352
</TABLE>
The results shown above are presented for your information and should not be
construed as our estimate of fair market value.
RESERVES INCLUDED IN THIS REPORT
The proved reserves included herein conform to the definition as set forth
in the Securities and Exchange Commission's Regulation S-X Part 210.4-10 (a) as
clarified by subsequent Commission Staff Accounting Bulletin. Our definition of
proved reserves is included under the tab "Reserve Definitions and Pricing
Assumptions" in this report.
Because of the direct relationship between volumes of proved undeveloped
reserves and development plans, we include in the proved undeveloped category
only reserves assigned to undeveloped locations that we have been assured will
definitely be drilled, and reserves assigned to the undeveloped portions of
secondary or tertiary projects which we have been assured will definitely be
developed.
The various reserve status categories are defined under the tab "Reserve
Definitions" in this report.
ESTIMATES OF RESERVES
In general, the reserves included herein were estimated by performance
methods or the volumetric method; however, other methods were used in certain
cases where characteristics of the data indicated such other methods were more
appropriate in our opinion. The reserves estimated by the performance method
utilized extrapolations of various historical data in those cases where such
data were definitive in our opinion. Reserves were estimated by the volumetric
method in those cases where there were inadequate historical performance data to
establish a definitive trend or where the use of production performance data as
a basis for the reserve estimates was considered to be inappropriate.
The reserves included in this report are estimates only and should not be
construed as being exact quantities. They may or may not be actually recovered,
and if recovered, the revenues therefrom and the actual costs related thereto
could be more or less than the estimated amounts. Moreover, estimates of
reserves may increase or decrease as a result of future operations.
A-2
<PAGE> 138
CMS Oil and Gas Company
November 10, 2000
Page 3
FUTURE PRODUCTION RATES
Initial production rates are based on the current producing rates for those
wells now on production. Test data and other related information were used to
estimate the anticipated initial production rates for those wells or locations
which are not currently producing. If no production decline trend has been
established, future production rates were held constant, or adjusted for the
effects of curtailment where appropriate, until a decline in ability to produce
was anticipated. An estimated rate of decline was then applied to depletion of
the reserves. If a decline trend has been established, this trend was used as
the basis for estimating future production rates. For reserves not yet on
production, sales were estimated to commence at an anticipated date furnished by
CMS.
In general, we estimate that future gas production rates will continue to
be the same as the average rate for the latest available 12 months of actual
production until such time that the well or wells are incapable of producing at
this rate. The well or wells were then projected to decline at their decreasing
delivery capacity rate. Our general policy on estimates of future gas production
rates is adjusted when necessary to reflect actual gas market conditions in
specific cases.
The future production rates from wells now on production may be more or
less than estimated because of changes in market demand or allowables set by
regulatory bodies. Wells or locations which are not currently producing may
start producing earlier or later than anticipated in our estimates of their
future production rates.
HYDROCARBON PRICES
CMS furnished us with hydrocarbon prices in effect at September 30, 2000
and with its forecasts of future prices which take into account SEC and
Financial Accounting Standards Board (FASB) rules, current market prices,
contract prices, and fixed and determinable price escalations where applicable.
In accordance with FASB Statement No. 69, September 30, 2000 market prices
were determined using the daily oil price or daily gas sales price ("spot
price") adjusted for oilfield or gas gathering hub and wellhead price
differences (e.g. grade, transportation, gravity, sulfur and BS&W) as
appropriate. Also in accordance with SEC and FASB specifications, changes in
market prices subsequent to September 30, 2000 were not considered in this
report.
For hydrocarbon products sold under contract, the contract price including
fixed and determinable escalations, exclusive of inflation adjustments, was used
until expiration of the contract. Upon contract expiration, the price was
adjusted to the current market price for the area and held at this adjusted
price to depletion of the reserves.
The effects of derivative instruments designated as price hedges of oil and
gas quantities are generally not reflected in our individual property
evaluations.
COSTS
Operating costs for the projects, leases, and wells in this report are
based on the operating expense reports of CMS and include only those costs
directly applicable to the leases or wells. When applicable, the operating costs
include a portion of general and administrative costs allocated directly to the
leases and wells under terms of operating agreements. Operating costs include ad
valorem taxes where applicable. Development costs were furnished to us by CMS
and are based on authorizations for expenditure for the proposed work or actual
costs for similar projects. The current operating and development costs were
held constant throughout the life of the properties. The estimated net cost of
abandonment after salvage was included for properties where abandonment costs
net of salvage are significant. The estimates of the net abandonment costs
furnished by Nomeco were accepted without independent verification. No deduction
A-3
<PAGE> 139
CMS Oil and Gas Company
November 10, 2000
Page 4
was made for indirect costs such as general administration and overhead
expenses, loan repayments, interest expenses, and exploration and development
prepayments that are not charged directly to the leases or wells.
GENERAL
Table A presents a one line summary of proved reserve and income data for
each of the subject properties which are ranked according to their future net
income discounted at 10 percent per year. Table B presents a one line summary of
gross and net reserves and income data for each of the subject properties. Table
C presents a one line summary of initial basic data for each of the subject
properties. Tables 1 through 839 present our estimated projection of production
and income by years beginning September 30, 2000, by country, state, field, and
lease or well.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which CMS owns an interest; however, we have not made any
field examination of the properties. No consideration was given in this report
to potential environmental liabilities which may exist nor were any costs
included for potential liability to restore and clean up damages, if any, caused
by past operating practices. CMS has informed us that they have furnished us all
of the accounts, records, geological and engineering data, and reports and other
data required for this investigation. The ownership interests, prices, and other
factual data furnished by CMS were accepted without independent verification.
The estimates presented in this report are based on data available, in general,
through September 2000.
CMS has assured us of their intent and ability to proceed with the
development activities included in this report, and that they are not aware of
any legal, regulatory or political obstacles that would significantly alter
their plans.
Neither we nor any of our employees have any interest in the subject
properties and neither the employment to make this study nor the compensation is
contingent on our estimates of reserves and future income for the subject
properties.
This report was prepared for the exclusive use of CMS Oil and Gas Company.
The data, work papers, and maps used in this report are available for
examination by authorized parties in our offices. Please contact us if we can be
of further service.
Very truly yours,
RYDER SCOTT COMPANY, L.P.
/s/ John R. Warner, P.E.
John R. Warner, P.E.
Senior Vice President
JRW/sw
A-4
<PAGE> 140
HYDROCARBON PRICING PARAMETERS
SEC PARAMETERS
OIL AND CONDENSATE
CMS furnished us with oil and condensate prices in for September 2000 and
these prices were held constant to depletion of the properties.
PLANT PRODUCTS
CMS furnished us with plant product prices in effect for September 2000 and
these prices were held constant to depletion of the properties.
GAS
CMS furnished us with gas prices in effect for September 2000 and with its
forecasts of future gas prices which take into account SEC guidelines, current
spot market prices, contract prices, and fixed and determinable price
escalations where applicable. In accordance with SEC guidelines, the future gas
prices used in this report make no allowances for future gas price increases
which may occur as a result of inflation nor do they make any allowance for
seasonal variations in gas prices which may cause future yearly average gas
prices to be somewhat lower than December gas prices. For gas sold under
contract, the contract gas price including fixed and determinable escalations,
exclusive of inflation adjustments, was used until the contract expires and then
was adjusted to the current market price for the area and held at this adjusted
price to depletion of the reserves.
<PAGE> 141
PETROLEUM RESERVES DEFINITIONS
INTRODUCTION
Reserves are those quantities of petroleum which are anticipated to be
commercially recovered from known accumulations from a given date forward. All
reserve estimates involve some degree of uncertainty. The uncertainty depends
chiefly on the amount of reliable geologic and engineering data available at the
time of the estimate and the interpretation of these data. The relative degree
of uncertainty may be conveyed by placing reserves into one of two principal
classifications, either proved or unproved. Unproved reserves are less certain
to be recovered than proved reserves and may be further sub-classified as
probable and possible reserves to denote progressively increasing uncertainty in
their recoverability. It should be noted that Securities and Exchange Commission
Regulation S-K prohibits the disclosure of estimated quantities of probable or
possible reserves of oil and gas and any estimated value thereof in any
documents publicly filed with the Commission.
Reserves estimates will generally be revised as additional geologic or
engineering data become available or as economic conditions change. Reserves do
not include quantities of petroleum being held in inventory, and may be reduced
for usage or processing losses if required for financial reporting.
Reserves may be attributed to either natural energy or improved recovery
methods. Improved recovery methods include all methods for supplementing natural
energy or altering natural forces in the reservoir to increase ultimate
recovery. Examples of such methods are pressure maintenance, cycling,
waterflooding, thermal methods, chemical flooding, and the use of miscible and
immiscible displacement fluids. Other improved recovery methods may be developed
in the future as petroleum technology continues to evolve.
PROVED RESERVES (SEC DEFINITIONS)
Securities and Exchange Commission Regulation S-X Rule 4-10 paragraph (a)
defines proved reserves as follows:
Proved oil and gas reserves. Proved oil and gas reserves are the estimated
quantities of crude oil, natural gas, and natural gas liquids which geological
and engineering data demonstrate with reasonable certainty to be recoverable in
future years from known reservoirs under existing economic and operating
conditions, i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by contractual
arrangements, but not on escalations based upon future conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes:
(A) that portion delineated by drilling and defined by gas-oil
and/or oil-water contacts, if any; and
(B) the immediately adjoining portions not yet drilled, but which
can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of information
on fluid contacts, the lowest known structural occurrence of
hydrocarbons controls the lower proved limit of the reservoir.
(ii) Reserves which can be produced economically through application
of improved recovery techniques (such as fluid injection) are included in
the "proved" classification when successful testing by a pilot project, or
the operation of an installed program in the reservoir, provides support
for the engineering analysis on which the project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves";
<PAGE> 142
(B) crude oil, natural gas, and natural gas liquids, the recovery
of which is subject to reasonable doubt because of uncertainty as to
geology, reservoir characteristics, or economic factors;
(C) crude oil, natural gas, and natural gas liquids, that may occur
in undrilled prospects; and
(D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
Proved developed oil and gas reserves. Proved developed oil and gas
reserves are reserves that can be expected to be recovered through existing
wells with existing equipment and operating methods. Additional oil and gas
expected to be obtained through the application of fluid injection or other
improved recovery techniques for supplementing the natural forces and mechanisms
of primary recovery should be included as "proved developed reserves" only after
testing by a pilot project or after the operation of an installed program has
confirmed through production response that increased recovery will be achieved.
Proved undeveloped reserves. Proved undeveloped oil and gas reserves are
reserves that are expected to be recovered from new wells on undrilled acreage,
or from existing wells where a relatively major expenditure is required for
recompletion. Reserves on undrilled acreage shall be limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units can be claimed only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation. Under no circumstances should estimates for
proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
Certain Staff Accounting Bulletins published subsequent to the promulgation
of Regulation S-X have dealt with matters relating to the application of
financial accounting and disclosure rules for oil and gas producing activities.
In particular, the following interpretations extracted from Staff Accounting
Bulletins set forth the Commission staff's view on specific questions pertaining
to proved oil and gas reserves.
Economic producibility of estimated proved reserves can be supported to the
satisfaction of the Office of Engineering if geological and engineering data
demonstrate with reasonable certainty that those reserves can be recovered in
future years under existing economic and operating conditions. The relative
importance of the many pieces of geological and engineering data which should be
evaluated when classifying reserves cannot be identified in advance. In certain
instances, proved reserves may be assigned to reservoirs on the basis of a
combination of electrical and other type logs and core analyses which indicate
the reservoirs are analogous to similar reservoirs in the same field which are
producing or have demonstrated the ability to produce on a formation test.
(extracted from SAB-35)
In determining whether "proved undeveloped reserves" encompass acreage on
which fluid injection (or other improved recovery technique) is contemplated, is
it appropriate to distinguish between (i) fluid injection used for pressure
maintenance during the early life of a field and (ii) fluid injection used to
effect secondary recovery when a field is in the late stages of depletion? . . .
The Office of Engineering believes that the distinction identified in the above
question may be appropriate in a few limited circumstances, such as in the case
of certain fields in the North Sea. The staff will review estimates of proved
reserves attributable to fluid injection in the light of the strength of the
evidence presented by the registrant in support of a contention that enhanced
recovery will be achieved. (extracted from SAB-35)
Companies should report reserves of natural gas liquids which are net to
their leasehold interest, i.e., that portion recovered in a processing plant and
allocated to the leasehold interest. It may be appropriate in the case of
natural gas liquids not clearly attributable to leasehold interests ownership to
follow instruction (b) of Item 2(b)(3) of Regulation S-K and report such
reserves separately and describe the nature of the ownership. (extracted from
SAB-35)
<PAGE> 143
The staff believes that since coalbed methane gas can be recovered from
coal in its natural and original location, it should be included in proved
reserves, provided that it complies in all other respects with the definition of
proved oil and gas reserves as specified in Rule 4-10(a)(2) including the
requirement that methane production be economical at current prices, costs, (net
of the tax credit) and existing operating conditions. (extracted from SAB-85)
Statements in Staff Accounting Bulletins are not rules or interpretations
of the Commission nor are they published as bearing the Commission's official
approval; they represent interpretations and practices followed by the Division
of Corporation Finance and the Office of the Chief Accountant in administering
the disclosure requirements of the Federal securities laws.
SUB-CATEGORIZATION OF DEVELOPED RESERVES (SPE/WPC DEFINITIONS)
In accordance with guidelines adopted by the Society of Petroleum Engineers
(SPE) and the World Petroleum Congress (WPC), developed reserves may be
sub-categorized as producing or non-producing.
Producing. Reserves sub-categorized as producing are expected to be
recovered from completion intervals which are open and producing at the time of
the estimate. Improved recovery reserves are considered producing only after the
improved recovery project is in operation.
Non-Producing. Reserves sub-categorized as non-producing include shut-in
and behind pipe reserves. Shut-in reserves are expected to be recovered from (1)
completion intervals which are open at the time of the estimate but which have
not started producing, (2) wells which were shut-in awaiting pipeline
connections or as a result of a market interruption, or (3) wells not capable of
production for mechanical reasons. Behind pipe reserves are expected to be
recovered from zones in existing wells, which will require additional completion
work or future recompletion prior to the start of production.
<PAGE> 144
[CMS OIL AND GAS LOGO]
<PAGE> 145
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following is an itemized statement of the various expenses to be paid
by the Registrant and the selling shareholder in connection with this offering.
All amounts except the SEC registration fee, the NYSE listing fee and the NASD
filing fee are estimated. These expenses will be borne by the Registrant and the
selling shareholder based on the number of shares of common stock they are
selling in proportion to the aggregate number of shares being sold in this
offering.
<TABLE>
<S> <C>
SEC registration fee....................................... $79,200
NYSE listing fee........................................... *
NASD filing fee............................................ 30,500
Printing and engraving expenses............................ *
Petroleum engineering fees and expenses.................... *
Legal fees and expenses.................................... *
Accounting fees and expenses............................... *
Transfer agent and registrar fees and expenses............. *
Miscellaneous.............................................. *
-------
Total............................................ $ *
=======
</TABLE>
---------------
* To be completed by amendment.
ITEM 14. INDEMNIFICATION OF DIRECTORS AND OFFICERS.
Sections 561 through 571 of the Michigan Business Corporation Act (the
"MBCA") contain detailed provisions concerning the indemnification of directors
and officers against judgments, penalties, fines and amounts paid in settlement
of litigation.
Article VII of the Registrant's Restated Articles of Incorporation reads:
"A director shall not be personally liable to the corporation or its
shareholders for monetary damages for breach of duty as a director
except (i) for a breach of the director's duty of loyalty to the
corporation or its shareholders, (ii) for acts or omissions not in good
faith or that involve intentional misconduct or a knowing violation of
law, (iii) for a violation of Section 551(1) of the MBCA, and (iv) any
transaction from which the director derived an improper personal
benefit. If the MBCA is amended after approval by the shareholders of
this Article VII to authorize corporate action further eliminating or
limiting the personal liability of directors, then the liability of a
director shall be eliminated or limited to the fullest extent permitted
by the MBCA, as so amended. No amendment to or repeal of this Article
VII, and no modification to its provisions by law, shall apply to, or
have any effect upon, the liability or alleged liability of any director
of the corporation for or with respect to any acts or omissions of such
director occurring prior to such amendment, repeal or modification."
Article VIII of the Registrant's Restated Articles of Incorporation reads:
"Each director, officer, employee and agent of the corporation shall be
indemnified by the corporation to the fullest extent permitted by law
against expenses (including attorneys' fees), judgments, penalties,
fines and amounts paid in settlement actually and reasonably incurred by
him or her in connection with the defense of any proceeding in which he
or she was or is a party or is threatened to be made a party by reason
of being or having been a director, officer, employee and agent of the
corporation or by reason of the fact that he or she is or was serving at
the request of the corporation as a director, officer, employee or agent
of another corporation,
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<PAGE> 146
partnership, joint venture, trust or other enterprise. Such right of
indemnification is not exclusive of any other rights to which such
director, officer, employee and agent may be entitled under any now or
hereafter existing statute, any other provision of these Articles,
Bylaws, agreement, vote of shareholders or otherwise. If the MBCA is
amended after approval by the shareholders of this Article VIII to
authorize corporate action further eliminating or limiting the personal
liability of directors, then the liability of a director of the
corporation shall be eliminated or limited to the fullest extent
permitted by the MBCA, as so amended. Any repeal or modification of this
Article VIII by the shareholders of the corporation shall not adversely
affect any right or protection of a director of the corporation existing
at the time of such repeal or modification."
Officers and directors are covered within specified monetary limits by
insurance against certain losses arising from claims made by reason of their
being directors or officers of the Registrant or of the Registrant's
subsidiaries, and the Registrant's officers and directors are indemnified
against such losses by reason of their being or having been directors of
officers of another corporation, partnership, joint venture, trust or other
enterprise at the Registrant's request.
ITEM 15. RECENT SALES OF UNREGISTERED SECURITIES.
None.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
(a) Exhibits.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DOCUMENT DESCRIPTION
------- --------------------
<C> <S>
1.1* -- Form of Underwriting Agreement
3.1* -- Restated Articles of Incorporation of the Registrant, as
amended
3.2* -- Restated By-Laws of the Registrant
4.1* -- Specimen Common Stock Certificate
5.1* -- Opinion of William H. Stephens III
10.1 -- CMS Energy Performance Incentive Stock Plan, effective
February 3, 1988, as amended December 3, 1999,
incorporated herein by reference to Exhibit 10(d) to CMS
Energy's Form 10-K Report for the year ended December 31,
1999
10.2 -- Supplemental Executive Retirement Plan for Employees of
CMS Energy/ Consumers Energy Company, incorporated herein
by reference to Exhibit 10(o) to CMS Energy's Form 10-K
Report for the year ended December 31, 1993
10.3* -- Form of Executive Incentive Compensation Plan
10.4* -- Form of Stock Option Plan
10.5* -- Form of Change of Control Severance Agreement
10.6* -- Credit Agreement, dated as of May 26, 1999, among the
Registrant, the Banks, all as defined therein, Bank One,
N.A., as Agent, ABN AMRO Bank, N.V., as Syndication
Agent, and Societe Generale, Southwest Agency, as
Documentation Agent
10.7 -- Promissory Note, dated as of May 26, 1999, issued by the
Registrant to CMS Energy
10.8 -- Promissory Note, dated as of October 10, 2000, issued by
Western Australia Gas Transmission Company I to CMS Oil
and Gas (International) Ltd.
10.9* -- Promissory Note, dated as of , 2000 issued by
the Registrant to CMS Enterprises
</TABLE>
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<PAGE> 147
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DOCUMENT DESCRIPTION
------- --------------------
<C> <S>
10.10* -- Promissory Note, dated as of , issued by the
Registrant to CMS Gas Transmission Company
10.11 -- Amended and Restated Agreement for the Allocation of
Income Tax Liabilities and Benefits, dated as of January
1, 1994, among CMS Energy and its subsidiaries,
incorporated herein by reference to Exhibit 10.15 to the
Registrant's Registration Statement on Form S-1 (File No.
33-63693) filed on October 26, 1995
10.12 -- Tax Agreement, dated as of February 23, 1995, by and
between Amoco Production Company, Amoco Corporation,
Walter International, Inc., Walter Congo Holdings
Company, Nuevo Energy Company, The Congo Holding Company,
Walter International Congo, Inc., and the Nuevo Congo
Company, incorporated herein by reference to Exhibit
10.23 to the Registrant's Registration Statement on Form
S-1 (File No. 33-63693) filed on October 26, 1995
10.13 -- CMS Tax Agreement, dated as of February 24, 1995, between
the Registrant, Amoco Corporation, Amoco Production
Company, CMS Energy Corporation, CMS Enterprises, Inc.,
Walter International, Inc., Walter Holdings, Inc. and
Walter International Congo, Inc., incorporated herein by
reference to Exhibit 10.24 to the Registrant's
Registration Statement on Form S-1 (File No. 33-63693)
filed on October 26, 1995
10.14* -- Tax Separation Agreement, dated as of ,
between the Registrant and CMS Energy
10.15* -- Tax Indemnification Agreement, dated as of ,
between the Registrant and CMS Energy
10.16 -- Gas Purchase and Sales Agreement, dated as of February
11, 1999, between CMS NOMECO EG Ltd., Samedan of North
Africa, Inc., Walter & Westport International LLC, Globex
International, Inc. and Atlantic Methanol Production
Company LLC
10.17* -- South Midland Gas Gathering or Sales Agreement, dated as
of , between the Registrant and CMS Field
Services, Inc.
10.18* -- Master Field Services and Support Agreement, dated as of
, between the Registrant and CMS Field
Services, Inc.
10.19* -- Master Oil Marketing Agreement, dated as of ,
between the Registrant and CMS Marketing, Services and
Trading Company
10.20* -- Master Gas Purchase and Sale Agreement, dated as of
, between the Registrant and CMS Marketing,
Services and Trading Company
10.21* -- Hedging Administrative Support, Information and Advisory
Services Agreement, dated as of , 2000,
between the Registrant and CMS Marketing, Services and
Trading Company
10.22* -- Hedging Brokerage Services Agreement, dated as of
, between the Registrant and CMS Marketing,
Services and Trading Company
10.23 -- Assignment Agreement, dated as of April 1, 2000, between
the Registrant and CMS Marketing, Services and Trading
Company
10.24 -- Purchase and Sale Agreement, dated as of January 1, 2000,
between the Registrant and Quicksilver Resources Inc.
10.25 -- Stock Purchase Agreement, dated as of June 30, 2000,
among the Registrant, CMS Oil and Gas (International)
Ltd., Crestar Energy Holdings Ltd. and Crestar Energy
Inc.
</TABLE>
II-3
<PAGE> 148
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DOCUMENT DESCRIPTION
------- --------------------
<C> <S>
10.26* -- Manufacturing and Marketing Agreement, dated as of March
21, 1998, between Atlantic Methanol Production Company,
LLC and the Republic of Equatorial Guinea
10.27* -- Royalty Rights Purchase Agreement, dated as of March 1,
1996, between the Registrant and William H. Stephens III
10.28* -- Registration Rights Agreement, dated as of ,
between the Registrant and CMS Enterprises
10.29* -- Services Agreement, dated as of , among the
Registrant, CMS Enterprises and CMS Marketing, Services
and Trading Company
10.31* -- Services Agreement, dated as of , among the
Registrant, CMS Enterprises, CMS Energy and CMS
Marketing, Services and Trading Company
21.1 -- Subsidiaries of the Registrant
23.1 -- Consent of Arthur Andersen LLP
23.2* -- Consent of William H. Stephens III (included in Exhibit
5.1)
23.3 -- Consent of Ryder Scott Company, L.P.
23.4 -- Consent of Lee Keeling and Associates, Inc.
24.1 -- Powers of Attorney
27.1 -- Financial Data Schedule
</TABLE>
---------------
* To be filed by amendment.
(b) Financial Statement Schedule
All financial statement schedules are omitted because they are not
applicable or not required or because the required information is shown in the
financial statements or notes thereto.
ITEM 17. UNDERTAKINGS.
(a) The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act
of 1933, the information omitted from the form of prospectus filed as part
of this registration statement in reliance upon Rule 430A and contained in
a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or
(4) or 497(h) under the Securities Act shall be deemed to be part of this
registration statement as of the time it was declared effective.
(2) For the purpose of determining any liability under the Securities
Act of 1933, each post-effective amendment that contains a form of
prospectus shall be deemed to be a new registration statement relating to
the securities offered therein, and the offering of such securities at that
time shall be deemed to be the initial bona fide offering thereof.
(b) The undersigned Registrant hereby undertakes to provide to the
underwriters at the closing specified in the underwriting agreement,
certificates in such denominations and registered in such names as required by
the underwriters to permit prompt delivery to each purchaser.
(c) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the registrant pursuant to the foregoing provisions, or otherwise, the
Registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than
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<PAGE> 149
the payment by the registrant of expenses incurred or paid by a director,
officer or controlling person of the registrant in the successful defense of any
action, suit or proceeding) is asserted by such director, officer or controlling
person in connection with the securities being registered, the Registrant will,
unless in the opinion of its counsel the matter has been settled by controlling
precedent, submit to a court of appropriate jurisdiction the question whether
such indemnification by it is against public policy as expressed in the Act and
will be governed by the final adjudication of such issue.
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<PAGE> 150
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Registrant
has duly caused this Registration Statement to be signed on its behalf by the
undersigned, thereunto duly authorized, in the City of Houston, State of Texas,
on the 22nd day of November, 2000.
CMS OIL AND GAS COMPANY
By: /s/ WILLIAM H. STEPHENS III
----------------------------------
William H. Stephens III
Executive Vice President,
General Counsel and Secretary
Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities indicated on the 22nd day of November, 2000.
<TABLE>
<CAPTION>
NAME TITLE
---- -----
<C> <S>
/s/ BRADLEY W. FISCHER President, Chief Executive Officer and
----------------------------------------------------- Director (Principal Executive Officer)
Bradley W. Fischer
/s/ MARK E. STIRL Vice President and Controller (Principal
----------------------------------------------------- Financial and Accounting Officer)
Mark E. Stirl
* Director
-----------------------------------------------------
William T. McCormick, Jr.
* Director
-----------------------------------------------------
Victor J. Fryling
/s/ ALAN M. WRIGHT Director
-----------------------------------------------------
Alan M. Wright
*By: /s/ ALAN M. WRIGHT
------------------------------------------------
Alan M. Wright
Attorney-in-fact
</TABLE>
II-6
<PAGE> 151
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
1.1* -- Form of Underwriting Agreement
3.1* -- Restated Articles of Incorporation of the Registrant, as
amended
3.2* -- Restated By-Laws of the Registrant
4.1* -- Specimen Common Stock Certificate
5.1* -- Opinion of William H. Stephens III
10.1 -- CMS Energy Performance Incentive Stock Plan, effective
February 3, 1988, as amended December 3, 1999,
incorporated herein by reference to Exhibit 10(d) to CMS
Energy's Form 10-K Report for the year ended December 31,
1999
10.2 -- Supplemental Executive Retirement Plan for Employees of
CMS Energy/ Consumers Energy Company, incorporated herein
by reference to Exhibit 10(o) to CMS Energy's Form 10-K
Report for the year ended December 31, 1993
10.3* -- Form of Executive Incentive Compensation Plan
10.4* -- Form of Stock Option Plan
10.5* -- Form of Change of Control Severance Agreement
10.6* -- Credit Agreement, dated as of May 26, 1999, among the
Registrant, the Banks, all as defined therein, Bank One,
N.A., as Agent, ABN AMRO Bank, N.V., as Syndication
Agent, and Societe Generale, Southwest Agency, as
Documentation Agent
10.7 -- Promissory Note, dated as of May 26, 1999, issued by the
Registrant to CMS Energy
10.8 -- Promissory Note, dated as of October 10, 2000, issued by
Western Australia Gas Transmission Company I to CMS Oil
and Gas (International) Ltd.
10.9* -- Promissory Note, dated as of , 2000 issued by
the Registrant to CMS Enterprises
10.10* -- Promissory Note, dated as of , issued by the
Registrant to CMS Gas Transmission Company
10.11 -- Amended and Restated Agreement for the Allocation of
Income Tax Liabilities and Benefits, dated as of January
1, 1994, among CMS Energy and its subsidiaries,
incorporated herein by reference to Exhibit 10.15 to the
Registrant's Registration Statement on Form S-1 (File No.
33-63693) filed on October 26, 1995
10.12 -- Tax Agreement, dated as of February 23, 1995, by and
between Amoco Production Company, Amoco Corporation,
Walter International, Inc., Walter Congo Holdings
Company, Nuevo Energy Company, The Congo Holding Company,
Walter International Congo, Inc., and the Nuevo Congo
Company, incorporated herein by reference to Exhibit
10.23 to the Registrant's Registration Statement on Form
S-1 (File No. 33-63693) filed on October 26, 1995
10.13 -- CMS Tax Agreement, dated as of February 24, 1995, between
the Registrant, Amoco Corporation, Amoco Production
Company, CMS Energy Corporation, CMS Enterprises, Inc.,
Walter International, Inc., Walter Holdings, Inc. and
Walter International Congo, Inc., incorporated herein by
reference to Exhibit 10.24 to the Registrant's
Registration Statement on Form S-1 (File No. 33-63693)
filed on October 26, 1995
10.14* -- Tax Separation Agreement, dated as of ,
between the Registrant and CMS Energy
10.15* -- Tax Indemnification Agreement, dated as of ,
between the Registrant and CMS Energy
</TABLE>
<PAGE> 152
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
10.16 -- Gas Purchase and Sales Agreement, dated as of February
11, 1999, between CMS NOMECO EG Ltd., Samedan of North
Africa, Inc., Walter & Westport International LLC, Globex
International, Inc. and Atlantic Methanol Production
Company LLC
10.17* -- South Midland Gas Gathering or Sales Agreement, dated as
of , between the Registrant and CMS Field
Services, Inc.
10.18* -- Master Field Services and Support Agreement, dated as of
, between the Registrant and CMS Field
Services, Inc.
10.19* -- Master Oil Marketing Agreement, dated as of ,
between the Registrant and CMS Marketing, Services and
Trading Company
10.20* -- Master Gas Purchase and Sale Agreement, dated as of
, between the Registrant and CMS Marketing,
Services and Trading Company
10.21* -- Hedging Administrative Support, Information and Advisory
Services Agreement, dated as of , 2000,
between the Registrant and CMS Marketing, Services and
Trading Company
10.22* -- Hedging Brokerage Services Agreement, dated as of
, between the Registrant and CMS Marketing,
Services and Trading Company
10.23 -- Assignment Agreement, dated as of April 1, 2000, between
the Registrant and CMS Marketing, Services and Trading
Company
10.24 -- Purchase and Sale Agreement, dated as of January 1, 2000,
between the Registrant and Quicksilver Resources Inc.
10.25 -- Stock Purchase Agreement, dated as of June 30, 2000,
among the Registrant, CMS Oil and Gas (International)
Ltd., Crestar Energy Holdings Ltd. and Crestar Energy
Inc.
10.26* -- Manufacturing and Marketing Agreement, dated as of March
21, 1998, between Atlantic Methanol Production Company,
LLC and the Republic of Equatorial Guinea
10.27* -- Royalty Rights Purchase Agreement, dated as of March 1,
1996, between the Registrant and William H. Stephens III
10.28* -- Registration Rights Agreement, dated as of ,
between the Registrant and CMS Enterprises
10.29* -- Services Agreement, dated as of , among the
Registrant, CMS Enterprises and CMS Marketing, Services
and Trading Company
10.31* -- Services Agreement, dated as of , among the
Registrant, CMS Enterprises, CMS Energy and CMS
Marketing, Services and Trading Company
21.1 -- Subsidiaries of the Registrant
23.1 -- Consent of Arthur Andersen LLP
23.2* -- Consent of William H. Stephens III (included in Exhibit
5.1)
23.3 -- Consent of Ryder Scott Company, L.P.
23.4 -- Consent of Lee Keeling and Associates, Inc.
24.1 -- Powers of Attorney
27.1 -- Financial Data Schedule
</TABLE>
---------------
* To be filed by amendment.
