<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON FEBRUARY 7, 1996
REGISTRATION NO. 33-63693
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------------
AMENDMENT NO. 2 TO
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
------------------------------
CMS NOMECO OIL & GAS CO.
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C> <C>
MICHIGAN 1330 38-1859381
(State or other jurisdiction (Primary Standard Industrial (I.R.S. Employer
of incorporation or organization) Classification Code Number) Identification No.)
</TABLE>
ONE JACKSON SQUARE
P.O. BOX 1150
JACKSON, MICHIGAN 49204
(517) 787-9011
(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 AND GENERAL COUNSEL SENIOR VICE PRESIDENT AND CHIEF FINANCIAL
CMS NOMECO OIL & GAS CO. OFFICER
ONE JACKSON SQUARE CMS ENERGY CORPORATION
P.O. BOX 1150 FAIRLANE PLAZA SOUTH, SUITE 1100
JACKSON, MICHIGAN 49204 330 TOWN CENTER DRIVE
(517) 787-9011 DEARBORN, MICHIGAN 48126
(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>
DENISE M. STURDY, ESQ. ANDREW H. SHAW, ESQ. KERRY C. L. NORTH, ESQ.
Assistant General Counsel Sidley & Austin Baker & Botts, L.L.P.
CMS Energy Corporation One First National Plaza 2001 Ross Avenue
212 W. Michigan Avenue Chicago, Illinois 60603 Dallas, Texas 75201
Jackson, Michigan 49201 (312) 853-7000 (214) 953-6500
(517) 788-0179
</TABLE>
APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.
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 delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. / /
------------------------------
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.
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<PAGE> 2
CROSS-REFERENCE SHEET
PURSUANT TO ITEM 501(B) OF REGULATION S-K
BETWEEN REGISTRATION STATEMENT AND PROSPECTUS
<TABLE>
<CAPTION>
FORM S-1 ITEM NUMBER AND HEADING CAPTION OR LOCATION IN PROSPECTUS
<C> <S> <C>
1. Forepart of the Registration Statement and Outside
Front Cover Page of Prospectus..................... Facing Page; Cross-Reference Sheet;
Outside Front Cover Page
2. Inside Front and Outside Back Cover Pages
of Prospectus...................................... Inside Front Cover Page; Outside Back
Cover Page; Available Information
3. Summary Information, Risk Factors and Ratio of
Earnings to Fixed Charges.......................... Prospectus Summary; Risk Factors; The
Company
4. Use of Proceeds.................................... Use of Proceeds
5. Determination of Offering Price.................... Underwriting
6. Dilution........................................... Dilution
7. Selling Security Holders........................... *
8. Plan of Distribution............................... Outside Front Cover Page; Shares Eligible
for Future Sale; Underwriting
9. Description of Securities to be Registered......... Description of Capital Stock
10. Interests of Named Experts and Counsel............. *
11. Information with Respect to the Registrant......... Outside Front Cover Page; Inside Front
Cover Page; Prospectus Summary; Risk
Factors; The Company; Dividend Policy;
Capitalization; Selected Historical
Consolidated Financial Data; Pro Forma
Financial Information; Notes to Pro Forma
Financial Information; Management's
Discussion and Analysis of Financial
Condition and Results of Operations;
Business and Properties; Management;
Ownership of Capital Stock; Relationship
and Certain Transactions with CMS Energy;
Available Information; and Financial
Statements
12. Disclosure of Commission Position on
Indemnification for Securities Act Liabilities..... *
</TABLE>
- -------------------------
* Not applicable.
<PAGE> 3
INFORMATION CONTAINED HEREIN IS SUBJECT TO COMPLETION OR AMENDMENT. A
REGISTRATION STATEMENT RELATING TO THESE SECURITIES HAS BEEN FILED WITH THE
SECURITIES AND EXCHANGE COMMISSION. THESE SECURITIES MAY NOT BE SOLD NOR
MAY OFFERS TO BUY BE ACCEPTED PRIOR TO THE TIME THE REGISTRATION STATEMENT
BECOMES EFFECTIVE. THIS PROSPECTUS SHALL NOT CONSTITUTE AN OFFER TO SELL OR
THE SOLICITATION OF AN OFFER TO BUY NOR SHALL THERE BE ANY SALE OF THESE
SECURITIES IN ANY STATE IN WHICH SUCH OFFER, SOLICITATION OR SALE WOULD BE
UNLAWFUL PRIOR TO REGISTRATION OR QUALIFICATION UNDER THE SECURITIES LAWS
OF ANY SUCH STATE.
SUBJECT TO COMPLETION, DATED FEBRUARY 7, 1996
PROSPECTUS
February , 1996
[LOGO] 4,000,000 SHARES
CMS NOMECO OIL & GAS CO.
COMMON STOCK
All of the shares offered hereby are being sold by the Company. The Company
is currently an indirect subsidiary of CMS Energy Corporation. The capital stock
of CMS Energy Corporation is listed on the New York Stock Exchange. Upon
completion of this offering, CMS Energy Corporation will beneficially own 83.3%
of the outstanding shares of Common Stock (81.3% if the Underwriters' over-
allotment option is exercised in full).
Prior to this offering, there has been no public market for the Common
Stock of the Company. It is currently estimated that the initial public offering
price per share will be between $18.00 and $20.00. See "Underwriting" for
information relating to the factors to be considered in determining the initial
public offering price. The Company will apply to have the Common Stock approved
for quotation on the New York Stock Exchange under the symbol CNO.
FOR INFORMATION THAT SHOULD BE CONSIDERED BY PROSPECTIVE INVESTORS, SEE
"RISK FACTORS" BEGINNING ON PAGE 9.
THESE SECURITIES HAVE NOT BEEN APPROVED OR DISAPPROVED BY THE SECURITIES AND
EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION NOR HAS THE
SECURITIES AND EXCHANGE COMMISSION OR ANY STATE SECURITIES COMMISSION
PASSED UPON THE ACCURACY OR ADEQUACY OF THIS PROSPECTUS.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
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<TABLE>
PRICE UNDERWRITING PROCEEDS
TO THE DISCOUNTS AND TO THE
PUBLIC COMMISSIONS(1) COMPANY(2)
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<S> <C> <C> <C>
Per Share................................ $ $ $
Total(3)................................. $ $ $
</TABLE>
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(1) See "Underwriting" for indemnification arrangements with the several
Underwriters.
(2) Before deducting expenses payable by the Company estimated at $1,700,000.
(3) The Company has granted the Underwriters a 30-day option to purchase up to
600,000 additional shares at the Price to the Public, less Underwriting
Discounts and Commissions, solely to cover over-allotments, if any. If all
such shares are purchased, the total Price to the Public, Underwriting
Discounts and Commissions and Proceeds to the Company will be
$ , $ and $ , respectively. See
"Underwriting."
The shares of Common Stock are offered by the several Underwriters when, as
and if issued to and accepted by them, subject to various prior conditions,
including their right to reject orders in whole or in part. It is expected that
delivery of share certificates will be made in New York, New York on or about
February , 1996.
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
BEAR, STEARNS & CO. INC.
SALOMON BROTHERS INC
<PAGE> 4
[MAPS OF U.S. AND NON-U.S.
OIL AND GAS PROPERTIES]
IN CONNECTION WITH THIS OFFERING, THE UNDERWRITERS MAY OVER-ALLOT OR EFFECT
TRANSACTIONS WHICH STABILIZE OR MAINTAIN THE MARKET PRICE OF THE COMMON STOCK
OFFERED HEREBY AT A LEVEL ABOVE THAT WHICH MIGHT OTHERWISE PREVAIL IN THE OPEN
MARKET. SUCH TRANSACTIONS MAY BE EFFECTED ON THE NEW YORK STOCK EXCHANGE, IN THE
OVER-THE-COUNTER MARKET OR OTHERWISE. SUCH STABILIZING, IF COMMENCED, MAY BE
DISCONTINUED AT ANY TIME.
<PAGE> 5
[MAJOR NON-U.S. AREAS OF ACTIVITY]
<PAGE> 6
[MAJOR NON-U.S. AREAS OF ACTIVITY]
<PAGE> 7
PROSPECTUS SUMMARY
The following summary is qualified in its entirety by the more detailed
information and financial statements, including the notes thereto, appearing
elsewhere in this Prospectus. Unless otherwise indicated, the information in
this Prospectus assumes an initial offering price of $19.00 per share (the
mid-point of the filing range) and no exercise of the Underwriters'
over-allotment option. Except as otherwise noted, all information in this
Prospectus has been adjusted to reflect an approximate 1.644 for 1.0 stock split
of the Common Stock effected on October 25, 1995 and an approximate 0.833 for
1.0 reverse stock split of its Common Stock effected on January 19, 1996. The
June 30, 1995 estimated reserve data included throughout this Prospectus are
based on the report of Ryder Scott Company ("Ryder Scott"), independent
petroleum engineering consultants, and include the estimated reserves added as a
result of the Company's recent acquisition of Terra Energy Ltd. Unless otherwise
indicated, references to the Company include the Company and its direct and
indirect subsidiaries. Certain terms relating to the oil and gas industry are
defined in "Certain Definitions."
THE COMPANY
GENERAL
CMS NOMECO Oil & Gas Co. ("CMS NOMECO" or the "Company") is an independent
oil and natural gas company engaged in the exploration, development, acquisition
and production of oil and natural gas properties in the U.S. and seven other
countries. Formed in 1967 to explore and develop leaseholdings located solely in
Michigan, the Company has greatly expanded to become an international oil and
natural gas company. In large part as a result of acquisitions and development
activities, the Company has approximately doubled both its estimated proved
reserves and its production of oil and natural gas over the past four years. As
of June 30, 1995, the Company had estimated proved reserves of 118.6 MMBoe,
consisting of 68.9 MMBbls of oil (97.0% of which were located outside the U.S.)
and 298.1 Bcf of natural gas (94.5% of which were located in the U.S.).
Approximately 64.7% of the Company's estimated proved reserves on such date were
classified as proved developed. The Company's oil-producing assets are
concentrated in South America (Ecuador, Venezuela and Colombia) and offshore
West Africa (the Congo and Equatorial Guinea), and the Company's gas-producing
assets are concentrated in Michigan, the Gulf Coast region and the Gulf of
Mexico.
The following table summarizes by region the Company's estimated proved
reserves as of June 30, 1995 and estimated average daily production during the
month of September 1995:
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES ESTIMATED AVERAGE DAILY PRODUCTION
AS OF JUNE 30, 1995 DURING THE MONTH OF SEPTEMBER 1995
-------------------------------------------- -------------------------------------------
OIL AND NATURAL % OF OIL AND NATURAL % OF
CONDENSATE(1) GAS TOTAL TOTAL CONDENSATE GAS TOTAL TOTAL
(MMBBLS) (BCF) (MMBOE) RESERVES (MBBLS) (MMCF) (MBOE) PRODUCTION
<S> <C> <C> <C> <C> <C> <C> <C> <C>
U.S.:
Michigan.............. 1.2 238.5 40.9 34.5% 0.9 51.6 9.5 38.3%
Other U.S............. 0.9 43.1 8.1 6.8 0.7 25.4 4.9 19.8
---- ----- ----- ----- ---- ---- ---- ------
Total U.S........... 2.1 281.6 49.0 41.3 1.6 77.0 14.4 58.1
NON-U.S.:
South America:
Ecuador............. 16.7 -- 16.7 14.1 3.2 -- 3.2 12.9
Venezuela........... 11.3 -- 11.3 9.5 0.5 -- 0.5 2.0
Colombia............ 6.7 -- 6.7 5.7 1.1 -- 1.1 4.4
West Africa:
Congo............... 15.9 -- 15.9 13.4 3.4 -- 3.4 13.7
Equatorial Guinea... 11.5 10.7 13.3 11.2 1.9 -- 1.9 7.7
Other Non-U.S.(2)..... 4.7 5.8 5.7 4.8 0.2 0.3 0.3 1.2
---- ----- ----- ----- ---- ---- ---- ------
Total Non-U.S....... 66.8 16.5 69.6 58.7 10.3 0.3 10.4 41.9
---- ----- ----- ----- ---- ---- ---- ------
Total Company..... 68.9 298.1 118.6(3) 100.0% 11.9 77.3 24.8 100.0%
==== ===== ===== ===== ==== ==== ==== ======
</TABLE>
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(1) Oil and condensate includes 0.2 MMBbls and 3.0 MMBbls, respectively, of U.S.
and non-U.S. NGLs.
(2) Consists of Yemen, New Zealand and Papua New Guinea. The Company's
properties in New Zealand and Papua New Guinea were sold in December 1995.
(3) Based on current estimates, the Company expects proved reserves as of
December 31, 1995 to reflect decreases of 3.1 MMBoe due to the sale of the
Company's properties in New Zealand and Papua New Guinea and 4.3 MMBoe due
to production subsequent to June 30, 1995, partially offset by net
additions.
3
<PAGE> 8
The Company is an indirect subsidiary of CMS Energy Corporation ("CMS
Energy"). CMS Energy is a major international energy company with electric
utility operations, natural gas utility operations, gas transmission and
marketing, independent power production and, through the Company, oil and
natural gas exploration, development and production.
STRATEGY
The Company believes that its success has resulted from its ability to
capitalize on an extensive network of industry relationships, an efficient
evaluation and decision-making process and broad technical competence. The
Company believes that its future growth depends on maintaining an opportunistic
approach which builds on the Company's existing strengths. Accordingly, the
Company's business strategy is to focus on the following goals while maintaining
the flexibility to respond to new opportunities and changed circumstances.
BALANCE. The Company seeks to maintain a balance between its U.S. and
non-U.S. interests to diversify its political, geologic and economic risk. The
Company believes that projects outside the U.S. tend to have a higher potential
for significant reserve growth, but often have greater risks, including
political risks and the risks associated with infrastructure development
necessary to market production. The Company further believes that projects in
the U.S. do not have certain of these risks, but also generally do not offer as
large a potential for reserve growth as non-U.S. projects. The Company has
historically concentrated on natural gas in the U.S. and to date has focused its
non-U.S. activities on oil, providing the Company an additional balance between
natural gas and oil.
EXPLORATION AND DEVELOPMENT OF EXISTING NON-U.S. PROPERTIES. In recent
years, the Company has made a series of investments in properties outside the
U.S. that currently have both production from proved reserves and significant
potential for exploration and development. The Company is pursuing exploration
and development of such properties, which include Block 16 in Ecuador, the Colon
Unit in Venezuela, the Espinal Block in Colombia, the Yombo Field offshore the
Congo and the Bioko Block offshore Equatorial Guinea. Most of the Company's
exploration and development opportunities outside the U.S. are located in areas
which have significant production histories and adequate infrastructure and, in
the Company's view, have a reasonable possibility of yielding sizeable
additional reserves through the application of modern exploration and
development technologies.
SELECTIVE ACQUISITIONS. The Company intends to continue to pursue
attractive opportunities to acquire producing properties with significant
exploration and development potential. The Company's primary focus is in the
geographic regions where it has significant experience. The Company's recent
acquisitions of Walter International, Inc. and Terra Energy Ltd., discussed
below, are illustrative of the types of opportunities the Company seeks.
OPERATOR ROLE. The Company seeks to continue to expand its role as operator
of both U.S. and non-U.S. projects by pursuing acquisitions and investment
opportunities that allow it to do so. As operator, the Company believes that it
can better manage production performance and more effectively control expenses,
the allocation of capital and the timing of exploration and development of its
fields. In addition, the Company believes that its experience as operator will
provide it access to a broader range of additional investment opportunities. In
early 1995, the Company assumed the role of operator of significant offshore
producing properties in West Africa in conjunction with its acquisition of
Walter International, Inc., and more recently the Company materially increased
its role as operator of U.S. properties as a result of its acquisition of Terra
Energy Ltd. After giving effect to these acquisitions, the Company operates
properties representing approximately 37.5% of its estimated proved reserves,
including 43.9% of its U.S. proved reserves and 32.5% of its non-U.S. proved
reserves. With respect to projects not operated by the Company, the Company
actively monitors the performance of its operators with the same objectives it
seeks for Company-operated projects.
REGIONAL FOCUS. With respect to both its U.S. and non-U.S. activities, the
Company intends to focus on selected geographic regions, particularly those
where it is currently active. In the U.S., the Company expects to continue its
emphasis on development, production and, to a lesser extent, exploration of
natural gas in its core areas of Michigan, the Gulf of Mexico and the Gulf Coast
region. Outside the U.S., the Company intends to concentrate on exploration,
development and production of oil in South America and offshore West Africa
4
<PAGE> 9
while evaluating opportunities to acquire additional reserves in those areas and
in certain areas of Southeast Asia. By focusing activities in a relatively
limited number of U.S. and non-U.S. regions, the Company has acquired
significant experience in the operational, technical and legal aspects of
conducting business in these regions and can utilize its base of geologic,
engineering and production experience in such regions to better evaluate
drilling and acquisition prospects.
TECHNOLOGY. The Company expects to continue to utilize its growing
technology base, including increasing use of 3-D seismic surveys, horizontal
drilling, new fracturing techniques and reservoir modeling, on its existing
properties as well as newly acquired properties. The Company believes it must
utilize the latest available technology to continue to compete successfully as
the industry focuses on properties with increasing amounts of exploration,
development and production risk.
RECENT DEVELOPMENTS
ACQUISITION OF TERRA ENERGY LTD.
In August 1995, CMS Energy acquired Terra Energy Ltd. ("Terra"), a
significant producer of gas within the Devonian Antrim Shale ("Antrim")
formation underlying a large portion of the Michigan Basin in the northern
portion of Michigan's lower peninsula. The consideration relating to such
acquisition, after giving effect to certain anticipated post-closing
adjustments, is expected to aggregate approximately $63.6 million, payable in
common stock of CMS Energy. Immediately after consummation of such acquisition,
the stock of Terra was transferred to the Company (the "Terra Acquisition"). In
connection with the Terra Acquisition, the Company recorded a capital
contribution of $1.0 million and issued a promissory note which, after giving
effect to post-closing adjustments, is expected to be in the principal amount of
approximately $62.6 million. Such note is currently held by CMS Energy. As of
June 30, 1995, the acquired Terra properties included 1,225 gross (95.6 net)
producing Antrim gas wells and estimated net proved reserves of 91.9 Bcf of
Antrim gas. During the month of September 1995, estimated average daily net
production from these properties was approximately 9.5 MMcf of gas.
The Company has been a significant producer and operator of Antrim gas
wells for a number of years. Taking into account the Terra Acquisition, as of
December 31, 1995 the Company operated over 1,370 Antrim gas wells, or
approximately 30% of all producing gas wells in the Antrim formation, making the
Company the largest operator of gas wells in the Antrim formation. The Company
is currently serving as operator of several projects involving the planned
drilling of an additional 280 Antrim development wells by December 31, 1996.
Additionally, Terra has a sizeable inventory of unproved acreage in the Antrim
producing trend, and management believes that a number of its existing wells
have substantial potential for improved recovery. The Company believes that it
is particularly well suited to capitalize on the Terra Acquisition because of
its many years of experience in the natural gas industry in Michigan and its
ability as part of the CMS Energy consolidated group to utilize, to a
substantial extent, the nonconventional fuels (Section 29) tax credit associated
with certain Antrim gas production.
ACQUISITION OF WALTER INTERNATIONAL, INC.
In February 1995, CMS Energy acquired Walter International, Inc.
("Walter"), an international oil and gas company, for a purchase price of
approximately $28.4 million plus assumed indebtedness of $18.3 million.
Immediately after consummation of such acquisition, the stock of Walter was
contributed to the Company (the "Walter Acquisition" and, together with the
Terra Acquisition, the "Recent Acquisitions"). In connection with the Walter
Acquisition, the Company issued a promissory note in the principal amount of
$6.5 million to CMS Energy to fund repayment of certain of the above-referenced
assumed indebtedness of Walter. Walter owns interests in and operates fields
offshore the Congo and offshore Equatorial Guinea in West Africa and in Tunisia
in North Africa. As of June 30, 1995, the acquired Walter properties included 22
gross (6.6 net) producing oil and condensate wells and estimated net proved
reserves of 21.0 MMBbls of oil and condensate. During the month of September
1995, estimated average daily net production from these properties was
approximately 4,829 Bbls of oil and condensate.
5
<PAGE> 10
The Company became familiar with Walter in part because of the Company's
participation in the Alba Field operated by Walter offshore Equatorial Guinea.
The acquisition of Walter is consistent with the Company's strategy of acquiring
producing properties with exploration and development potential. The Walter
Acquisition also expands the Company's role as operator of offshore and non-U.S.
projects.
OTHER RECENT ACQUISITIONS AND DISCOVERIES
The Company experienced significant growth in reserves in 1994 primarily as
a result of certain acquisitions of producing properties and one significant
discovery.
In December 1994, a consortium in which the Company has a 29.17% working
interest agreed to assume operation of the Colon Unit in Venezuela from an
affiliate of the state-owned oil company pursuant to an operating services
agreement. As of June 30, 1995, the Company's estimated proved oil reserves
attributable to this transaction were 11.3 MMBbls, and the Company has committed
to spend approximately $47.0 million ($38.0 million for capital expenditures and
$9.0 million for operating expenditures) over the next three years on rework and
other development and, to a lesser extent, exploration activities at the Colon
Unit. In June 1994, the Company acquired Sun Colombia, whose sole asset is a
working interest in the Espinal Block in Colombia, for approximately $25.0
million. As of June 30, 1995, the Company's estimated proved oil reserves
attributable to the Sun Colombia acquisition were 5.5 MMBbls. In the third
quarter of 1994, the Company completed two Antrim gas property acquisitions for
a total of approximately $8.5 million. The Company's estimated proved natural
gas reserves attributable to these acquisitions were approximately 10.3 Bcf as
of June 30, 1995.
In early 1994, the Company participated in a significant discovery in the
Freshwater Bayou Field in southern Louisiana. Since this discovery, four
successful development wells in this field have been drilled and with their
reserve additions, the Company's estimated proved natural gas reserves in the
field as of June 30, 1995 were 29.4 Bcf.
THE OFFERING
<TABLE>
<S> <C>
Common Stock offered by the Company................. 4,000,000 shares
Common Stock to be outstanding after the
Offering*......................................... 24,000,000 shares
Use of Proceeds..................................... To repay a portion of the indebtedness
of the Company, including indebtedness
to CMS Energy, and for general
corporate purposes. See "Use of
Proceeds."
Proposed New York Stock Exchange Symbol............. CNO
</TABLE>
- -------------------------
* After completion of the offering made hereby (the "Offering"), approximately
83.3% (81.3% if the Underwriters exercise their over-allotment option in full)
of the outstanding Common Stock of the Company will be beneficially owned by
CMS Energy by virtue of its ownership of all of the common stock of CMS
Enterprises Company ("CMS Enterprises"). Excludes options to purchase 89,000
shares of Common Stock expected to be issued in connection with the Offering.
RISK FACTORS
Prospective investors should carefully consider the factors discussed in
detail elsewhere in this Prospectus under the caption "Risk Factors."
6
<PAGE> 11
SUMMARY OIL AND NATURAL GAS RESERVE DATA
The following table summarizes certain historical and pro forma estimates
of the Company's net proved oil and natural gas reserves as of the dates
indicated and estimated future net cash flows and standardized measure data
attributable to these reserves at such dates. The reserve estimates and
estimated future net cash flows as of June 30, 1995 have been prepared by Ryder
Scott. The reserve estimates, estimated future net cash flows and standardized
measure data as of January 1, 1993, 1994 and 1995 have been prepared by the
Company's internal engineers. The June 30, 1995 standardized measure data were
prepared by the Company's internal engineers based on the June 30, 1995 reserve
estimates prepared by Ryder Scott. For additional information relating to the
Company's oil and natural gas reserves, see "Risk Factors -- Uncertainty of
Reserve Estimates," "Business and Properties -- Reserves," Supplemental
Information -- Oil and Gas Producing Activities in the Notes to Consolidated
Financial Statements of the Company and the supplemental oil and gas information
in the Notes to the Consolidated Financial Statements relating to the Recent
Acquisitions included elsewhere in this Prospectus. Attached hereto as Appendix
A is a letter from Ryder Scott relating to their reserve report.
<TABLE>
<CAPTION>
AS OF JANUARY 1,
-------------------------- AS OF JUNE 30,
1993 1994 1995 1995(1)
<S> <C> <C> <C> <C>
ESTIMATED PROVED RESERVES:
Oil and condensate (MMBbls)(2).................................. 36.1 36.2 54.8 68.9
Natural gas (Bcf)............................................... 208.5 201.8 231.2 298.1
Net equivalent barrels of oil (MMBoe)........................... 70.9 69.8 93.3 118.6(3)
Discounted estimated future net cash flows (millions)(2)(4)..... $347.0 $364.7 $528.5 $629.0
Standardized measure of discounted estimated future net cash
flows after net income taxes (millions)(2)(5) $317.3 $318.4 $413.2 $526.0
</TABLE>
- -------------------------
(1) Gives effect to the Terra Acquisition.
(2) Includes natural gas liquids and the equity interest in estimated proved
reserves in the East Shabwa Block in the Republic of Yemen.
(3) Based on current estimates, the Company expects proved reserves as of
December 31, 1995 to reflect decreases of 3.1 MMBoe due to the sale of the
Company's properties in New Zealand and Papua New Guinea and 4.3 MMBoe due
to production subsequent to June 30, 1995, partially offset by net
additions.
(4) The discounted estimated future net cash flows attributable to the Company's
reserves were prepared using constant prices as of the calculation date,
discounted at 10% per annum before income taxes. Such discounted estimated
future net cash flows include the estimated value of nonconventional fuels
(Section 29) tax credits.
(5) The standardized measure of discounted estimated future net cash flows
represents discounted estimated future net cash flows attributable to the
Company's reserves after income tax, calculated in accordance with the
provisions of Statement of Financial Accounting Standards No. 69.
SUMMARY OPERATING DATA
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------------------ --------------------
PRO FORMA PRO FORMA
1992 1993 1994 1994(1) 1995 1995(1)
<S> <C> <C> <C> <C> <C> <C>
OPERATING DATA:
Production:
Oil and condensate (MBbls)............. 1,417 1,716 2,025 3,806 3,219 3,437
Natural gas (MMcf)..................... 17,578 18,487 20,546 22,925 18,989 20,883
Natural gas liquids (MBbls)............ 291 186 193 193 172 172
Average sales price(2):
Oil and condensate (per Bbl)........... $ 18.85 $ 15.52 $ 13.30 $ 13.12 $ 14.04 $ 14.02
Natural gas (per Mcf).................. 1.89 2.17 2.05 2.02 1.88 1.82
Natural gas liquids (per Bbl).......... 16.55 15.24 14.90 14.90 14.57 14.57
OPERATING EXPENSES (PER BOE):
Depreciation, depletion and
amortization........................... $ 7.02 $ 7.15 $ 6.19 $ 5.12 $ 5.20 $ 4.96
Operating and maintenance................ 2.91 3.01 3.42 3.48 3.54 3.40
General and administrative............... 0.97 1.12 1.12 1.26 0.86 0.83
</TABLE>
- -------------------------
(1) Gives effect to the Recent Acquisitions as if such transactions had been
consummated as of January 1 of the period presented.
(2) Adjusted to reflect amounts received or paid under futures contracts entered
into to hedge the price of production.
7
<PAGE> 12
SUMMARY HISTORICAL AND PRO FORMA FINANCIAL DATA
The following table presents certain historical consolidated and pro forma
financial data of the Company as of the dates and for the periods indicated. The
historical consolidated financial data as of and for each of the three years in
the period ended December 31, 1994 are derived from the consolidated financial
statements of the Company which have been audited by Arthur Andersen LLP,
independent certified public accountants. The historical consolidated financial
data as of and for the nine months ended September 30, 1994 and 1995 are derived
from unaudited consolidated financial statements of the Company which, in the
opinion of management, contain all adjustments (consisting of normal recurring
adjustments) necessary for a fair presentation thereof. The following data
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations," "Pro Forma Consolidated
Financial Information" and the Consolidated Financial Statements of the Company
and those relating to the Recent Acquisitions, including the Notes thereto,
included elsewhere in this Prospectus. The pro forma financial data are not
necessarily indicative of the results that would have been achieved if the pro
forma transactions had occurred on the dates indicated or the results that will
be achieved in the future. The consolidated results for the nine months ended
September 30, 1995 are not necessarily indicative of the results that may be
achieved for the full year ending December 31, 1995.
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
YEAR ENDED DECEMBER 31, ----------------------------------
------------------------------------------- PRO FORMA
1992 1993 1994 PRO FORMA 1994 1995 1995(2)
1994(2)
(UNAUDITED)
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA(1):
Operating Revenues:
Oil and condensate.................... $ 26,553 $ 26,635 $ 26,831 $ 49,847 $ 18,479 $ 45,423 $ 48,388
Natural gas........................... 34,391 40,995 39,904 43,946 30,550 32,927 35,163
Other operating....................... 8,408 6,275 12,333 17,424 10,107 17,738 21,163
------- ------- -------- --------- ------- -------- --------
69,352 73,905 79,068 111,217 59,136 96,088 104,714
Operating Expenses:
Depreciation, depletion and
amortization........................ 32,566 35,605 34,919 40,026 25,358 34,072 35,168
Cost center write-offs................ 5,744 9,648 5,612 5,612 452 2,184 2,184
Operating and maintenance............. 13,476 15,005 19,323 27,182 14,050 23,204 24,116
General and administrative............ 4,489 5,599 6,345 9,870 4,346 5,609 5,884
Production and other taxes............ 3,997 4,221 3,838 4,117 3,010 3,463 3,735
Cost of products sold and other....... 1,427 1,127 973 1,019 682 773 773
------- ------- -------- --------- ------- -------- --------
61,699 71,205 71,010 87,826 47,898 69,305 71,860
Pretax operating income................. 7,653 2,700 8,058 23,391 11,238 26,783 32,854
Other income (expense).................. 163 382 239 (680) 152 522 1,068
Interest expense, net................... 4,954 3,844 4,023 4,297 2,624 6,455 5,993
------- ------- -------- --------- ------- -------- --------
Income (loss) before income taxes....... 2,862 (762) 4,274 18,414 8,766 20,850 27,929
Income tax provision (benefit).......... (2,100) (5,900) (5,523) (4,088) (2,148) 386 1,570
Extraordinary item, early retirement of
debt.................................. -- -- -- -- -- (987) (987 )
Cumulative effect of accounting
change................................ (1,124) -- -- -- -- -- --
------- ------- -------- --------- ------- -------- --------
Net income.............................. $ 3,838 $ 5,138 $ 9,797 $ 22,502 $ 10,914 $ 19,477 $ 25,372
======= ======= ======== ========= ======= ======== ========
Net income per common share............. $ 0.19 $ 0.26 $ 0.49 $ 0.94 $ 0.55 $ 0.97 $ 1.06
======= ======= ======== ========= ======= ======== ========
Average common shares
outstanding(000)...................... 20,000 20,000 20,000 24,000 20,000 20,000 24,000
OTHER DATA:
EBITDA(3)............................... $ 46,126 $ 48,335 $ 48,828 $ 68,349 $ 37,200 $ 63,561 $ 71,274
Cash Flow:
From Operating Activities............. 44,731 45,971 46,921 66,082 33,626 53,207 48,933
From Financing Activities............. 22,582 31,839 66,421 53,693 63,873 (4,100) (1,473 )
From Investing Activities............. (68,059) (77,750) (108,188) (105,620) (93,854) (46,125) (48,236 )
Capital expenditures.................... 68,059 77,750 108,188 105,620 93,854 152,958(4) 155,069 (4)
<CAPTION>
AS OF SEPTEMBER 30,
AS OF DECEMBER 31, PRO FORMA
1992 1993 1994 1994 1995 1995(5)
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
BALANCE SHEET DATA:
Working capital(6)...................... $ 8,989 $ 9,847 $ 15,189 $ 13,671 $ 31,648 $ 31,648
Investments and other assets............ 4,218 7,088 12,539 10,814 23,121 23,121
Property, plant and equipment, net...... 346,188 375,990 438,057 440,194 547,943 547,943
Total assets............................ 370,274 402,361 472,700 476,082 662,406 662,406
Long-term debt, including current
portion............................... 96,382 118,720 129,041 130,593 199,048 130,048
Stockholders' equity.................... 208,351 222,989 288,886 285,903 341,089 410,089
</TABLE>
- -------------------------
(1) Certain reclassifications have been reflected in amounts prior to 1995 to
conform with 1995 presentation.
(2) Gives effect to the Recent Acquisitions and the application of the estimated
net proceeds of $69.0 million from the Offering as if such transactions had
been consummated as of January 1 of the period presented. See "Use of
Proceeds."
(3) EBITDA is earnings before interest, income taxes, depreciation, depletion
and amortization, extraordinary item, cumulative effect of accounting change
and cost center write-offs of oil and gas assets. EBITDA is presented to
provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA 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. See the Consolidated Statements of Cash Flows of the
Company included elsewhere in this Prospectus for disclosure of operating,
investing and financing cash flows.
(4) Includes non-cash capital expenditures of $106.9 million relating to the
Recent Acquisitions.
(5) Gives effect to the application of the estimated net proceeds of $69.0
million from the Offering as if such net proceeds had been applied as of
September 30, 1995. See "Use of Proceeds."
(6) Excluding current maturities of long-term debt.
8
<PAGE> 13
RISK FACTORS
In addition to the other information in this Prospectus, the following risk
factors should be considered carefully in evaluating the Company and its
business before purchasing shares of the Common Stock offered hereby.
Volatility of Oil and Natural Gas Prices. Revenues generated from the
Company's operations are highly dependent upon the price of, and demand for, oil
and natural gas. Historically, the markets for oil and natural gas have been
volatile and are likely to continue to be volatile in the future. The prices for
oil and natural gas are subject to wide fluctuation 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 the control of
the Company. 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, political conditions in the Middle East
and other petroleum producing areas, the 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 would not only reduce revenue but could
reduce the amount of the Company's oil and natural gas that can be produced
economically and could therefore have a material adverse effect on the Company's
financial condition and results of operations. In order to reduce its exposure
to price risks in the sale of its oil and natural gas, the Company enters into
hedging arrangements from time to time. The Company's hedging arrangements apply
to only a portion of its production and provide only limited price protection
against fluctuations in the oil and natural gas markets. To the extent that the
Company engages in such activities, it may be prevented from realizing the
benefits of price increases above the levels of the hedges. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and
"Business and Properties."
Ceiling Test Write-Offs. The Company uses the full cost method of
accounting for its investment in oil and natural gas properties. Under the full
cost method of accounting, all costs of acquisition, exploration and development
of oil and natural gas reserves are capitalized into a "full cost pool" as
incurred, and properties in the pool, including estimated future development
costs, are depleted and charged to operations using the unit-of-production
method based on the ratio of current production to total proved oil and natural
gas reserves. To the extent that such capitalized costs (net of accumulated
depreciation, depletion and amortization) less deferred taxes exceed the sum of
discounted estimated future net cash flows from proved oil and natural gas
reserves (using unescalated prices and costs and a 10% per annum discount rate)
and the lower of cost or market value of unproved properties after income tax
effects (the "ceiling"), such excess costs are charged against earnings. The
test is applied at the end of each fiscal quarter on a country-by-country basis
and requires a write-down of oil and natural gas properties if the ceiling is
exceeded, even if prices decline for only a short period. Once incurred, such a
write-down of oil and natural gas properties is not reversible at a later date
even if oil or natural gas prices increase. As of September 30, 1995, the
Company recorded a $2.0 million write-down to the ceiling in the U.S. cost
center due to low oil and natural gas prices. Significant downward revisions of
the estimates of proved reserves or declines in oil and natural gas prices from
those in effect on September 30, 1995 which are not offset by other factors
could result in a write-down for impairment of oil and natural gas properties.
Uncertainty of Reserve Estimates. The reserve data of the Company and Ryder
Scott 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 factors and assumptions, such
as the assumed effects of regulations 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, all of
which may in fact vary considerably from actual experience. Reserves located
outside the U.S. are often held pursuant to complex contractual arrangements
with respective foreign governments, thus further complicating reserve estimates
and creating the risk of conflicting contractual interpretations. For these
reasons, estimates of economically recoverable quantities of oil and natural gas
attributable to any particular group of properties, classifications of such
reserves based on risk of recovery, and estimates of the future net cash flows
expected therefrom prepared by different engineers or by the same engineers at
different times may vary substantially and such reserve estimates may be subject
to downward or upward adjustment based upon
9
<PAGE> 14
such factors. Actual production, revenues and expenditures with respect to the
Company's reserves will likely vary from estimates, and such variances may be
material.
The discounted estimated future net cash flows referred to in this
Prospectus should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to the Company's properties. In
accordance with applicable requirements of the Securities and Exchange
Commission (the "Commission"), the discounted estimated future net cash flows
from proved reserves are generally based on prices and costs as of the date of
the estimate, whereas actual future prices and costs may be materially higher or
lower. 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
and changes in governmental regulations or taxation. The timing of actual future
net cash flows from proved reserves, and actual discounted cash flow, will be
affected by the timing of both the production and the incurrence of expenses in
connection with development and production of oil and natural gas properties. In
addition, the calculation of the discounted estimated future net cash flows
using a 10% discount per annum as required by the Commission is not necessarily
the most appropriate discount factor based on interest rates in effect from time
to time and risks associated with the Company's reserves or the oil and natural
gas industry in general. See "Business and Properties -- Reserves."
Replacement of 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. Except to the extent the
Company acquires properties containing proved reserves or conducts successful
exploration and development activities, or both, the estimated proved reserves
of the Company will decline as reserves are produced. The Company's future oil
and natural gas production, and therefore cash flow and income, are highly
dependent upon the Company's level of success in finding or acquiring additional
reserves. The business of exploring for, developing and acquiring reserves is
capital intensive. To the extent cash flow from operations is reduced and
external sources of capital become limited or unavailable, the Company's ability
to make the necessary capital investment to maintain or expand its asset base of
oil and natural gas reserves would be impaired. See "Business and Properties --
Reserves."
Economic Risks of Oil and Natural Gas Operations. The Company's 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, the Company may drill unsuccessful wells and
experience losses. There is no assurance that any discovered oil or natural gas
can be economically produced or satisfactorily marketed. Moreover, the presence
of unanticipated pressure or irregularities in formations or accidents may cause
some or all of the Company's exploration, development and production activities
to be unsuccessful, and could result in a total loss of the Company's investment
in such activities. The Company's operations may be materially curtailed as a
result of a number of factors, including lack of infrastructure, bad weather,
title problems or shortages. In addition, certain of the Company's producing
properties are subject to production limitations imposed by governmental or
regulatory authorities or under contracts. Consequently, the Company's actual
future production may be substantially affected by factors beyond the Company's
control, any of which could have a material adverse effect on the Company's
financial condition or results of operations. See "Business and Properties."
Oil and Natural Gas Transportation; Ecuador Pipeline Curtailment. A
substantial portion of the Company's oil and most of its natural gas are
transported through gathering systems and pipelines which are not owned by the
Company. Transportation space on such gathering systems and pipelines is
occasionally limited and at times unavailable due to repairs or improvements
being made to such facilities or due to such space being utilized by other oil
or natural gas shippers that may or may not have priority transportation
agreements. Production in Block 16 and related fields in Ecuador in which the
Company has an interest is currently curtailed due to a limitation in the
capacity of the Trans-Andean pipeline to 345,000 Bopd, of which Block 16's share
as of September 30, 1995 was 33,000 Bopd. See "Business and Properties --
Description of Non-U.S. Operations -- South America -- Republic of Ecuador."
With the exception of such pipeline curtailment, the Company has not experienced
any material inability to market its proved reserves of oil or natural gas as a
result of limited access to transportation space. If transportation space is
materially restricted
10
<PAGE> 15
or is unavailable in the future, the Company's ability to market its 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 the Company's
financial condition or results of operations. See "Business and Properties --
Marketing."
Limitations on Availability of Nonconventional Fuels Tax Credits. In the
years 1992, 1993 and 1994, the Company generated $4.4 million, $5.6 million and
$8.5 million, respectively, in tax credits under Section 29 of the Internal
Revenue Code of 1986, as amended ("IRC"), for the production of natural gas from
nonconventional sources ("Section 29 Credit"). Such tax credits were associated
principally with its production of certain Antrim gas. Because the Company has
been (and is expected to continue to be) included in the consolidated federal
income tax return filed by CMS Energy, these Section 29 Credits have either been
used currently to reduce the tax liability of the CMS Energy consolidated group
or have created a minimum tax credit carryforward for use in future years. For
1995, it is estimated that the Company generated approximately $12 million of
Section 29 Credits; for 1996 through 2002, it is expected that the Company will
generate Section 29 Credits averaging approximately $14 million annually. Under
the Tax Sharing Agreement that has been entered into by CMS Energy and its
subsidiaries (see "Relationship and Certain Transactions with CMS Energy -- Tax
Sharing Agreement"), the Company will be paid for those Section 29 Credits which
it generates as such credits are utilized (either as current year Section 29
Credits or minimum tax credits) by the CMS Energy consolidated group to reduce
such group's consolidated regular tax liability. Forecasts of the CMS Energy
consolidated tax position for 1995 indicate that the CMS Energy consolidated
group is expected to generate sufficient regular tax liabilities so that the
Company will be paid for all or substantially all of its approximately $12
million of Section 29 Credits for the 1995 taxable year after CMS Energy's
consolidated tax return is filed for 1995. Such forecasts also indicate that the
CMS Energy consolidated group is expected to generate sufficient regular tax
liabilities for subsequent years so that the Company will be paid for its
Section 29 Credits for the 1996 - 2002 tax years in the same year the returns
for such years are filed. Also, such forecasts indicate that the Company is
expected to be paid over the next five years for the approximately $27.2 million
of accumulated minimum tax credit carryforward allocated to the Company through
December 31, 1994. However, because CMS Energy's consolidated tax position is
subject to many uncertainties, some of which are not within the control of the
Company or the other members of the CMS Energy consolidated group, there can be
no assurance that this will be the case. If the taxable income of the CMS Energy
consolidated group were to be less than projected, the payments for the Section
29 Credits would be deferred or eliminated. Moreover, if the Company were
deconsolidated from the CMS Energy consolidated group, the Company's ability to
realize any benefit from past or future Section 29 Credits would be materially
restricted. Further, a limitation on the ability of the Company to realize
Section 29 Credits, as a result of deconsolidation or otherwise, could
substantially reduce the Company's discounted estimated future net cash flows
from proved reserves, thereby increasing the likelihood of the Company being
required to record a non-cash charge to earnings. The Company has no plans, and
has been advised by CMS Energy that CMS Energy has no plans, to effect any
transaction in the foreseeable future that would cause a deconsolidation of the
Company from the CMS Energy consolidated group. See "Business and Properties --
Tax Matters" and "Business and Properties -- Reserves."
Potential Dual Consolidated Loss Recapture. As a result of the Walter
Acquisition and related transactions, CMS NOMECO acquired certain assets located
in the Congo which, prior to such transactions, were owned by affiliates of
Amoco Corporation ("Amoco"). As a result of certain agreements entered into in
connection with the Walter Acquisition, CMS Energy and CMS NOMECO could become
jointly and severally liable to Amoco or to the Internal Revenue Service for the
recapture of "dual consolidated losses" utilized by Amoco in prior years if a
"triggering event" were to occur with respect to such assets or with respect to
the stock of Walter or certain of its subsidiaries. The amount of such potential
liability could be up to $78.2 million, plus an interest factor thereon.
However, CMS Energy has agreed to indemnify CMS NOMECO for such liability if the
triggering event results from acts or omissions (i) of CMS Energy or any of its
subsidiaries (other than CMS NOMECO) which occur after the initial sale of the
Common Stock offered hereby; (ii) of CMS NOMECO or any of its subsidiaries if
such acts or omissions are approved by the Board of Directors of CMS NOMECO,
which approval includes the affirmative vote of a majority of the employees of
CMS Energy or any of its subsidiaries (other than CMS NOMECO) who serve on CMS
NOMECO's Board of Directors; or (iii) of any person if such acts or omissions
occur prior to the initial sale of the
11
<PAGE> 16
Common Stock offered hereby. In return, CMS NOMECO has agreed to indemnify CMS
Energy for any such dual consolidated loss tax liability if the triggering event
results from acts or omissions of CMS NOMECO on or after the date of the initial
sale of the Common Stock offered hereby which have not been approved by the
Board of Directors of CMS NOMECO in the manner described in the preceding
sentence. CMS NOMECO's subsidiary, Walter (now named CMS NOMECO International,
Inc.), could also be secondarily liable to Amoco for up to $59.0 million in
potential recapture tax, plus an interest factor thereon, if Nuevo Energy
Company ("Nuevo"), an unaffiliated company, were to fail to satisfy its
potential liability to Amoco with respect to the recapture of dual consolidated
losses relating to certain other assets located in the Congo acquired by Nuevo's
affiliate from an affiliate of Amoco simultaneously with Walter's acquisition of
its Congolese assets. Because the net assets of Nuevo currently appear to be
adequate to satisfy any obligation which Nuevo may have with respect to such
other assets, CMS NOMECO believes that it is unlikely that Walter would have to
make a payment to satisfy its secondary liability, although there can be no
assurance that this will be the case. However, if Walter were required to make
such a payment, it would have a claim against Nuevo, but would not be able to
recover such payment from CMS Energy under the above-described indemnity. See
"Business and Properties -- Tax Matters -- Dual Consolidated Losses."
In addition, as a result of another acquisition, CMS NOMECO has agreed to
become jointly and severally liable for potential tax liability in a lesser
amount as the result of the recapture of other dual consolidated losses if
triggering events were to occur after such acquisition. Such liability is not
subject to the above-described CMS Energy indemnity. See "Business and
Properties -- Tax Matters -- Dual Consolidated Losses."
Risks of Non-U.S. Operations. The Company's non-U.S. oil and natural gas
exploration, development and production activities are subject to political and
economic uncertainties (including but not limited to changes, sometimes frequent
or marked, in energy policies or the personnel administering them),
expropriation of property, cancellation or modification of contract rights,
foreign exchange restrictions, currency fluctuations, royalty and tax increases
and other risks arising out of foreign governmental sovereignty over the areas
in which the Company's operations are conducted, as well as risks of loss due to
civil strife, acts of war, guerrilla activities and insurrection. These risks
may be higher in the developing countries in which the Company conducts such
activities. Consequently, the Company's non-U.S. exploration, development and
production activities may be substantially affected by factors beyond the
Company's control, any of which could have a material adverse effect on the
Company's financial condition or results of operations. Furthermore, in the
event of a dispute arising from non-U.S. operations, the Company 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 dispute. See "Business
and Properties -- Governmental Regulation."
Risk of Ecuador Contract Renegotiation. Production from Block 16 and
related fields in the Oriente Basin of the Ecuadorian Amazon region has steadily
increased since start-up in mid-1994, with new wells and fields continuing to be
brought on stream. As of June 30, 1995, these fields represented approximately
14.1% of the Company's estimated total proved reserves of oil and natural gas on
a Boe basis. With lower worldwide oil prices and increases in total project
costs reducing the overall economic benefit of these fields to the Ecuadorian
government, in September 1994 the Ministry of Energy and Mines in Ecuador
notified the members of the consortium with interests in such fields that they
should investigate alternatives for improving project economics to the
Ecuadorian government, including the renegotiation of the service contract
governing the Company's interest in these fields. The Ecuadorian government has
significant leverage to force changes due to its broad governmental and
regulatory powers. Authorizations have been and may in the future be withheld
and/or delayed to the economic detriment of the consortium unless the
discussions are productive. Discussions with the Ecuadorian government
concerning various alternatives began in September 1995 and will likely continue
for at least the next several months. The Company cannot currently predict what
impact, if any, these discussions will have on the project's economics, and
there can be no assurance that these discussions or their outcome will not have
a material adverse effect on the Company's estimated reserves, financial
condition or results of operations. See "Business and Properties -- Description
of Non-U.S. Operations -- South America -- Republic of Ecuador."
12
<PAGE> 17
Operational Risks and Insurance. The oil and natural gas business involves
certain operating hazards such as 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, any of which could result in substantial losses to the
Company. The Company's offshore operations also are subject to the additional
hazards of marine operations, such as severe weather, capsizing and collision.
In addition, the Company may be legally responsible for environmental damages
caused by previous owners of property purchased or leased by the Company. As a
result, substantial liabilities to third parties or governmental entities may be
incurred. In accordance with customary industry practices, the Company maintains
insurance against some, but not all, of such risks and losses. The occurrence of
such an event not fully covered by insurance could have a material adverse
effect on the Company's financial condition or results of operations. See
"Business and Properties -- Operational Risks and Insurance" and "Business and
Properties -- Environmental Matters."
Governmental Regulation. The Company's 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 the Company conducts
business, including regulation relating to such matters 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 such regulations could result in substantial liabilities to third
parties or governmental entities, the payment of which could have a material
adverse effect on the Company's financial condition or results of operations.
Moreover, there is no assurance that laws or regulations enacted in the future
or the modification of existing laws or regulations will not adversely affect
the Company's exploration for or development, production or marketing of oil or
natural gas. See "Business and Properties -- Governmental Regulation."
Environmental Matters. Extensive federal, state and local laws and
regulations relating to health and environmental quality in the United States as
well as environmental laws and regulations of other countries in which the
Company operates affect nearly all of the operations of the Company. These laws
and regulations set various standards regulating certain aspects of health and
environmental quality, provide for penalties and other liabilities for the
violation of such standards and establish in certain circumstances obligations
to remediate current and former facilities and off-site locations. In addition,
special provisions may be appropriate or required in environmentally sensitive
non-U.S. areas of operation, such as the rain forests in Ecuador where the
Company has substantial interests.
Significant liability could be imposed on the Company for damages, clean-up
costs and/or penalties in the event of certain discharges into the environment,
environmental damage caused by previous owners of property purchased by the
Company or non-compliance with environmental laws or regulations. Such liability
could have a material adverse effect on the Company's financial condition or
results of operations. Moreover, the Company 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 the
regulatory agencies, could in the future require material expenditures by the
Company for the installation and operation of systems and equipment for remedial
measures, all of which could have a material adverse effect on the Company's
financial condition or results of operations. See "Business and Properties --
Environmental Matters."
Competition. The oil and natural gas industry is highly competitive. The
Company faces competition in all aspects of its business, including acquiring
reserves, leases, licenses and concessions, obtaining the equipment and labor
needed to conduct its operations and marketing its oil and natural gas. The
Company's 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 the Company and, accordingly, may
be better positioned to acquire and exploit prospects, hire personnel and market
production. In addition, many of the Company's 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 the
Company's oil
13
<PAGE> 18
and natural gas production and which are beyond the control of the Company.
Moreover, many competitors have established strategic long-term positions and
maintain strong governmental relationships in countries in which the Company may
seek new entry. The Company expects this high degree of competition to continue.
See "Business and Properties -- Competition."
Legal Proceedings. On December 18, 1987, Tribal Drilling Company and
certain other plaintiffs, including J. Stuart Hunt, an affiliate of Tribal and a
director of the Company, filed a lawsuit in Dallas County, Texas (the "Dallas
County Lawsuit"), seeking, among other things, (i) a declaratory judgment
against Heritage Resources, Inc. ("Heritage") to the effect that Heritage was
not qualified to serve as the operator of Sections 21, 22 and 23 of the
Crittendon Field in Winkler County, Texas, that Heritage had been properly
removed as operator pursuant to a vote of non-operator working interest owners
and that Tribal was the duly elected replacement operator and (ii) damages
against Heritage and certain related parties in connection with Heritage's
alleged failure to carry out its obligations as operator of Sections 21, 22 and
23. The Company owns non-operating working interests in Sections 21 and 23 of
the Crittendon Field, but has no interest in Section 22 of such field. The
Company was not originally a plaintiff in the Dallas County Lawsuit, but
pursuant to a court order to join all indispensable parties, on April 20, 1988,
plaintiffs filed an amended petition which included the Company as one of the
plaintiffs. Heritage and certain related parties subsequently filed
counterclaims against all of the approximately 20 plaintiffs in the Dallas
County Lawsuit, including the Company, alleging various causes of action,
including without limitation claims for breach of contract, slander of title,
tortious interference with contract, tortious interference with business
relations, fraud, conspiracy and intentional infliction of emotional distress.
In the Dallas County Lawsuit, Heritage seeks approximately $100 million in
actual damages, exemplary damages not to exceed $1 billion, attorneys' fees and
declaratory relief. Trial of the Dallas County Lawsuit, including counterclaims,
is currently scheduled for May 1996.
On December 18, 1987, Heritage and certain related parties filed two
separate lawsuits, since consolidated, in Winkler County, Texas (the "Winkler
County Lawsuit"), against certain but not all non-operator working interest
owners of Sections 21 and 22 of the Crittendon Field. The Company was not a
party to the Winkler County Lawsuit. In the Winkler County Lawsuit, the
plaintiffs in many respects alleged the same course of conduct that is the
subject of the Dallas County Lawsuit, including Heritage's counterclaims. In
October 1992, a jury in the Winkler County Lawsuit returned a special verdict in
favor of plaintiffs and against the defendants in that litigation in an
aggregate amount in excess of $80 million plus attorneys' fees in excess of $20
million. Certain defendants subsequently entered into a settlement with the
plaintiffs and the non-settling plaintiffs have appealed the judgments in the
Winkler County Lawsuit to the Texas Court of Appeals in El Paso, Texas. The
Court of Appeals has indicated that it may rule on the appeal by early 1996.
The Company believes that it has meritorious defenses to the counterclaims
in the Dallas County Lawsuit and intends to defend itself vigorously in such
lawsuit. Nonetheless, the outcome of a jury trial is difficult to predict, and
there can be no assurance that the resolution of Heritage's counterclaims
against the Company will not have a material adverse effect on the Company's
financial condition or results of operations. See "Business and Properties --
Legal Proceedings."
Acquisition Risks. The Company's rapid growth in recent years has been
attributable in significant part to acquisitions of producing properties. After
the Offering, the Company expects to continue to evaluate and, where
appropriate, pursue acquisition opportunities on terms management considers
favorable to the Company. The successful acquisition of producing properties
requires an assessment of recoverable reserves, exploration potential, future
oil and natural gas prices, operating costs, potential environmental and other
liabilities and other factors beyond the Company's control. In connection with
such an assessment, the Company performs a review of the subject properties that
it believes to be generally consistent with industry practices. Nonetheless, the
resulting assessments are necessarily inexact and their accuracy inherently
uncertain, and such a review 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.
14
<PAGE> 19
The Recent Acquisitions have been made initially by CMS Energy using common
stock of CMS Energy, with the acquired companies subsequently transferred by CMS
Energy, through CMS Enterprises, to the Company. Such acquisitions have
generally been structured to be tax-free to the sellers. This method may not be
replicated in the future, and acquisitions structured in this manner, if any,
would likely require the issuance of additional Common Stock to CMS Energy or to
CMS Enterprises at the then prevailing market price which would result in a
dilution of the ownership interest of the public holders of Common Stock. The
issuance by the Company of a significant amount of its Common Stock as
consideration to a seller could result in certain adverse consequences, such as
the Company being deconsolidated from the CMS Energy consolidated group for
federal income tax purposes. See "Business and Properties -- Tax Matters -- Dual
Consolidated Losses" and "Business and Properties -- Tax Matters -- Section 29
Credits." Accordingly, it is unlikely that the Company would issue shares of its
Common Stock to the sellers in an amount sufficient to cause a deconsolidation
in order to make an acquisition. If the seller were to require a tax-free
transaction requiring Common Stock of the Company, it may be possible for the
Company to use cash on hand and/or cash available under its credit facilities or
other sources to acquire shares of its Common Stock in the open market to effect
such a transaction. If a transaction could not be structured to be tax-free, a
seller may be unwilling to consummate a sale or may require greater
consideration than if the transaction were tax free. No assurance can be given
that the Company will have sufficient cash resources to consummate large
acquisitions in the future.
Principal Stockholder Will Effectively Control the Company. After the
Offering, CMS Enterprises will own approximately 83.3% of the issued and
outstanding Common Stock of the Company (81.3% if the Underwriters exercise
their over-allotment option in full). As a result, CMS Enterprises, and its
parent company, CMS Energy, will be able to elect all members of the Board of
Directors of the Company and to control all matters submitted to a vote of the
Board of Directors or stockholders, including without limitation the Company's
exploration, development, capital, operating and acquisition expenditure plans.
The Board of Directors is currently comprised of ten members, six of whom are
directors or current or former officers of CMS Energy, CMS Enterprises or the
Company. Such concentration of ownership of Common Stock may have an adverse
effect on the market price of the Common Stock. See "Ownership of Capital Stock"
and "Relationship and Certain Transactions with CMS Energy."
Potential Conflicts Involving CMS Energy and its Affiliates. The Company
and CMS Energy and certain of its other subsidiaries have entered into certain
agreements, including a tax sharing agreement, services agreements and a
registration rights agreement, to provide for certain transactions and
relationships between the parties. The Company and CMS Energy and its other
affiliates may enter into other material transactions and agreements from time
to time in the future.
The relationship between the Company and CMS Energy and its other
affiliates may give rise to conflicts of interest with respect to, among other
things, transactions and agreements among the Company 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 the Company. When
the interests of CMS Energy and its other subsidiaries diverge from those of the
Company, CMS Energy may exercise its influence in favor of its own interests or
the interests of another of its subsidiaries over the interests of the Company.
See "Relationship and Certain Transactions with CMS Energy."
Benefits of the Offering to CMS Energy and Its Affiliates. Upon completion
of the Offering, CMS Energy will beneficially own approximately 83.3% of the
issued and outstanding Common Stock of the Company (81.3% if the Underwriters
exercise their over-allotment option in full). CMS Energy and certain of its
affiliates other than the Company may realize certain benefits as a result of
the Offering including the creation of a public market for the Company's Common
Stock which will provide a market indication of the value of the Company. See
"Shares Eligible for Future Sale." In addition, most of the net proceeds to the
Company from the Offering will be used to repay notes payable to affiliates of
the Company. See "Use of Proceeds."
Dividends. The Company has not paid cash dividends on its Common Stock
since 1989 and has no current plans to pay cash dividends on its Common Stock in
the proximal future. The Company currently intends to retain its cash for the
continued expansion of its business, including exploration, development and
15
<PAGE> 20
acquisition activities. See "Dividend Policy." The Company's revolving credit
agreement contains customary financial and other covenants that could have the
effect of limiting the Company's ability to pay dividends. See "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Liquidity and Capital Resources -- Financing Activities -- The Credit Facility."
No Prior Market and Determination of Public Offering Price. Prior to the
Offering, there has been no public market for shares of the Common Stock, and
there can be no assurance that an active public market for such shares will
develop or be sustained. The initial offering price for the Common Stock has
been determined by negotiation among the Company and the representatives of the
Underwriters and may not be indicative of the price at which the Common Stock
will trade following completion of the Offering. See "Underwriting" for a
discussion of the factors to be considered in determining the initial public
offering price. The market price of the Common Stock could also be subject to
significant fluctuation in response to variations in results of operations and
other factors.
Shares Eligible for Future Sale. Sales of substantial amounts of Common
Stock in the public market, whether issued in connection with acquisitions or
otherwise, following the Offering could adversely affect the market price of the
Common Stock. The Company, CMS Enterprises and CMS Energy have agreed that
during the period beginning from the date of this Prospectus and continuing to
and including the date 180 days after the date of this Prospectus, none of them
will offer, sell, contract to sell or otherwise dispose of any securities of the
Company (other than pursuant to employee stock incentive plans existing or
contemplated on the date of this Prospectus and for certain other purposes)
which are substantially similar to the shares of Common Stock or which are
convertible or exchangeable into securities which are substantially similar to
the shares of Common Stock, without the prior written consent of Donaldson,
Lufkin & Jenrette Securities Corporation. Upon expiration of this period, all
20,000,000 shares of 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 (the
"Securities Act"). The sale of shares upon the expiration of such period, or the
perception of the availability of shares for sale, could adversely affect the
prevailing market price of Common Stock. See "Shares Eligible for Future Sale."
THE COMPANY
The Company is an independent oil and natural gas company engaged in the
exploration, development, acquisition and production of oil and natural gas
properties in the U.S. and seven other countries. Formed in 1967 to explore and
develop leaseholdings located solely in Michigan, the Company has greatly
expanded to become an international oil and natural gas company. In large part
as a result of acquisitions and development activities, the Company has
approximately doubled both its estimated proved reserves and its production of
oil and natural gas over the last four years. As of June 30, 1995, the Company
had estimated proved reserves of 118.6 MMBoe, consisting of 68.9 MMBbls of oil
(97.0% of which were located outside the U.S.) and 298.1 Bcf of natural gas
(94.5% of which were located in the U.S.). Approximately 64.7% of the Company's
estimated proved reserves on such date were classified as proved developed. The
Company's oil-producing assets are concentrated in South America (Ecuador,
Venezuela and Colombia) and offshore West Africa (the Congo and Equatorial
Guinea), and the Company's gas-producing assets are concentrated in Michigan,
the Gulf Coast region and the Gulf of Mexico.
The Company is an indirect subsidiary of CMS Energy. CMS Enterprises owns
all of the outstanding stock of the Company and CMS Energy owns all of the
outstanding common stock of CMS Enterprises. CMS Energy is a major international
energy company with electric utility operations, natural gas utility operations,
gas transmission and marketing, independent power production and, through the
Company, oil and natural gas exploration, development and production.
The Company's principal offices are located at One Jackson Square, Jackson,
Michigan 49201. The Company's telephone number is (517) 787-9011.
16
<PAGE> 21
USE OF PROCEEDS
The net proceeds from the Offering are estimated to be $69.0 million after
deducting underwriting discounts and commissions and estimated expenses ($79.3
million if the over-allotment option is exercised in full). The Company intends
to use the estimated net proceeds (i) to repay the indebtedness of the Company
under a promissory note which, after giving effect to certain anticipated
post-closing adjustments, is expected to be in the principal amount of
approximately $62.6 million issued in connection with the Terra Acquisition and
currently held by CMS Energy (the "Terra Note") and a promissory note in the
principal amount of approximately $6.5 million ($3.6 million of which was
outstanding as of December 31, 1995) issued to CMS Energy in connection with the
Walter Acquisition (the "Walter Note" and, together with the Terra Note, the
"CMS Notes"); and (ii) for general corporate purposes, which may include
repayment of a portion of the Company's indebtedness ($113.3 million as of
September 30, 1995) under its three year unsecured bank credit facility
established under the Amended and Restated Credit Agreement dated as of November
1, 1993, as amended, among the Company, NBD Bank, as Agent, and the Banks named
therein (the "Credit Agreement"). The Company issued the Terra Note to CMS
Enterprises, which in turn assigned it to CMS Energy, in connection with the
transfer by CMS Energy of the common stock of Terra to CMS Enterprises and then
by CMS Enterprises to the Company, and the Company issued the Walter Note to CMS
Energy in connection with the repayment of $6.5 million of indebtedness of
Walter immediately after the consummation of the Walter Acquisition. The CMS
Notes bear interest at the rate of LIBOR plus 2% and have a maturity date of
November 1, 1999. See "Business and Properties -- Terra Acquisition," "Business
and Properties -- Walter Acquisition" and "Relationship and Certain Transactions
with CMS Energy." Advances under the Credit Agreement during the past year were
used primarily for capital expenditures, property acquisitions and working
capital. The average rate of interest on indebtedness under the Credit Agreement
was 7.2% per annum as of September 30, 1995 and such indebtedness is due on
November 1, 1996. See "Capitalization" and "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
Pending use of the net proceeds for the above purposes, the Company intends
to invest such funds in short-term, interest bearing obligations of investment
grade.
DIVIDEND POLICY
The Company has not paid cash dividends on its Common Stock since 1989 and
has no current plans to pay cash dividends on its Common Stock in the proximal
future. The Company currently intends to retain its cash for the continued
expansion of its business, including exploration, development and acquisition
activities. The Credit Agreement contains customary financial and other
covenants, including covenants that could have the effect of limiting the
Company's ability to pay dividends. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital Resources
- -- Financial Activities -- The Credit Facility." The amount of future cash
dividends, if any, will depend upon future earnings, results of operations,
capital requirements, covenants contained in various financing agreements of the
Company, the financial condition of the Company and certain other factors as the
Board of Directors deems relevant.
17
<PAGE> 22
DILUTION
The net tangible book value of the Company at September 30, 1995 was $341.1
million, or $17.05 per share. Net tangible book value per share of Common Stock
represents the amount of the Company's tangible net worth (tangible assets less
liabilities) divided by the total number of shares of Common Stock outstanding.
After giving effect to the sale by the Company of 4,000,000 shares of Common
Stock offered hereby at an assumed offering price of $19.00 per share and the
application of the estimated net proceeds therefrom, the adjusted net tangible
book value of the Company at September 30, 1995 would have been $410.1 million,
or $17.09 per share. This represents an immediate dilution in net tangible book
value of $1.91 per share to purchasers of Common Stock in the Offering, as
illustrated by the following table:
<TABLE>
<S> <C> <C>
Assumed initial public offering price per share.............. $19.00
------
Net tangible book value per share at September 30, 1995.... $17.05
------
Increase per share attributable to new investors........... 0.04
------
Net tangible book value per share after the Offering......... 17.09
------
Dilution per share to new investors.......................... $ 1.91
======
</TABLE>
Dilution is determined by subtracting the net tangible book value per share
after giving effect to the Offering from the initial public offering price per
share paid by a purchaser of Common Stock in the Offering.
The following table sets forth, as of September 30, 1995, the number of
shares of Common Stock purchased from the Company, the total consideration paid
therefor and the average price per share paid by the Company's sole existing
stockholder, CMS Enterprises, and by new investors:
<TABLE>
<CAPTION>
SHARES PURCHASED TOTAL CONTRIBUTION
------------------------- ------------------------- AVERAGE PRICE
NUMBER PERCENT AMOUNT PERCENT PER SHARE
(IN THOUSANDS) (IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
CMS Enterprises........................ 20,000 83.3% $341,089 81.8% $ 17.05
New Investors.......................... 4,000 16.7 76,000* 18.2 19.00
------- ----- -------- ----- ------
Total............................. 24,000 100.0% $417,089 100.0% $ 17.38
======= ===== ======== ===== ======
</TABLE>
- -------------------------
* Before deducting underwriting discounts and commissions and estimated expenses
relating to the Offering.
The foregoing information assumes no exercise of options to purchase 89,000
shares of Common Stock expected to be issued in connection with the Offering.
See "Management -- Long-Term Performance Incentive Plan."
18
<PAGE> 23
CAPITALIZATION
The following table sets forth the capitalization of the Company as of
September 30, 1995 and as adjusted to reflect the sale of the shares of Common
Stock offered hereby and the application of the estimated net proceeds
therefrom. This table should be read in conjunction with "Use of Proceeds,"
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," "Pro Forma Consolidated Financial Information" and the Consolidated
Financial Statements of the Company and the related Notes thereto included
elsewhere in this Prospectus.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1995
----------------------------
HISTORICAL AS ADJUSTED(1)
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Long-Term Debt:
CMS Energy......................................................... $ 67,840 $ --
Credit Agreement................................................... 113,300 112,140
Other(2)........................................................... 17,908 17,908
-------- --------
Total......................................................... 199,048 130,048
Stockholders' Equity:
Common Stock, no par value, 55,000,000 shares authorized;
20,000,000 shares issued and outstanding; 24,000,000 shares
issued and outstanding as adjusted(3)........................... 169,726 238,726
Preferred stock, issuable in series, 5,000,000 shares authorized,
no shares issued and outstanding................................ -- --
Retained earnings.................................................. 171,363 171,363
-------- --------
Total stockholders' equity.................................... 341,089 410,089
-------- --------
Total capitalization.......................................... $ 540,137 $540,137
======== ========
</TABLE>
- -------------------------
(1) Adjusted to reflect the application of the estimated net proceeds of $69.0
million from the Offering.
(2) "Other" debt consists of (i) OPIC guaranteed loans relating to project
financing in Equatorial Guinea and the Congo in the amount of $14.2 million
and (ii) $3.7 million of debt assumed in the Terra Acquisition. See
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Financing Activities."
(3) Reflects an approximate 1.644 for 1.0 stock split of the Common Stock of the
Company effected October 25, 1995 and an approximate 0.833 for 1.0 reverse
stock split of the Common Stock of the Company effected January 19, 1996.
Excludes 89,000 shares of Common Stock expected to be reserved for issuance
pursuant to options expected to be issued in connection with the Offering.
19
<PAGE> 24
PRO FORMA CONSOLIDATED FINANCIAL INFORMATION
In August 1995, CMS Energy acquired Terra for aggregate consideration of
approximately $63.6 million, payable in common stock of CMS Energy. Immediately
after consummation of such acquisition, the stock of Terra was transferred to
the Company. In connection with the Terra Acquisition, the Company issued the
Terra Note currently held by CMS Energy and recorded a $1.0 million capital
contribution. The Company used the purchase method to account for this
transaction. See "Business and Properties -- Recent Developments -- Terra
Acquisition."
In February 1995, CMS Energy acquired Walter for a purchase price of
approximately $28.4 million plus assumed indebtedness of $18.3 million.
Immediately after consummation of such acquisition, the stock of Walter was
contributed to the Company, and the Company issued the Walter Note to fund
repayment of $6.5 million of the assumed indebtedness of Walter. Shortly prior
to the acquisition of Walter by CMS Energy, Walter had acquired Amoco Congo
Exploration Company ("ACEC"), and an unaffiliated company had acquired Amoco
Congo Petroleum Company ("ACPC" and together with ACEC, the "Amoco Congo
Companies"), from Amoco Production Company ("APC"), a subsidiary of Amoco. The
Company used the purchase method to account for this transaction. See "Business
and Properties -- Recent Developments -- Walter Acquisition."
The unaudited Pro Forma Consolidated Statement of Income for the year ended
December 31, 1994 gives effect to the Terra Acquisition and the Walter
Acquisition and to the application of the assumed net proceeds from the Offering
as if all such transactions had been consummated as of January 1, 1994. The
unaudited Pro Forma Consolidated Statement of Income for the nine months ended
September 30, 1995 gives effect to the Terra Acquisition and the Walter
Acquisition and to the application of the assumed net proceeds from the Offering
as if all such transactions had been consummated as of January 1, 1995. The
unaudited Pro Forma Consolidated Balance Sheet as of September 30, 1995 gives
effect to the application of the assumed net proceeds from the Offering as if
such transaction had been consummated as of September 30, 1995. See "Use of
Proceeds."
The Pro Forma Consolidated Financial Statements of the Company do not
purport to be indicative of the results of operations of the Company had such
transactions occurred on the dates assumed, nor are the Pro Forma Consolidated
Financial Statements necessarily indicative of the future results of operations
of the Company. The Pro Forma Consolidated Financial Statements should be read
together with the Consolidated Financial Statements of the Company and those
relating to the Recent Acquisitions, including the Notes thereto, included
elsewhere in this Prospectus.
20
<PAGE> 25
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors,
CMS NOMECO Oil & Gas Co.:
We have examined the pro forma adjustments reflecting the transactions
described in the Notes to Pro Forma Consolidated Statement of Income for the
year ended December 31, 1994 (the "December 31, 1994 Notes") and the application
of those adjustments to the historical amounts in the accompanying Pro Forma
Consolidated Statement of Income of CMS NOMECO Oil & Gas Co. (the "Company") for
the year ended December 31, 1994. The historical amounts are derived from the
historical consolidated financial statements of the Company, CMS NOMECO
International Inc. (formerly Walter International, Inc., "CMS NOMECO
International") and Terra Energy Ltd. ("Terra"), which were audited by us, and
of Amoco Congo Exploration and Petroleum Companies (the "Amoco Congo
Companies"), which were audited by other accountants, all appearing elsewhere
herein. Such pro forma adjustments are based upon management's assumptions
described in the December 31, 1994 Notes. Our examination was made in accordance
with standards established by the American Institute of Certified Public
Accountants and accordingly, included such procedures as we considered necessary
in the circumstances.
We have reviewed the pro forma adjustments reflecting the transactions
described in the Notes to Pro Forma Consolidated Statement of Income for the
Nine Months Ended September 30, 1995, and the Notes to Pro Forma Consolidated
Balance Sheet as of September 30, 1995 (collectively, the "September 30, 1995
Notes") and the application of those adjustments to the historical amounts in
the accompanying Pro Forma Consolidated Statement of Income for the nine months
ended September 30, 1995, and the Pro Forma Consolidated Balance Sheet as of
September 30, 1995. The historical amounts are derived from the historical
unaudited consolidated financial statements of the Company, which were reviewed
by us, of the Amoco Congo Companies, which were reviewed by other accountants,
and of Terra and CMS NOMECO International all appearing elsewhere herein. Such
pro forma adjustments are based on management's assumptions as described in the
September 30, 1995 Notes. Our review was conducted in accordance with standards
established by the American Institute of Certified Public Accountants and
accordingly, included such procedures as we considered necessary in the
circumstances.
The objective of the Pro Forma Consolidated Financial Statements referred
to above is to show what the significant effects on the historical financial
information might have been had the transactions occurred at an earlier date.
However, the Pro Forma Consolidated Financial Statements are not necessarily
indicative of the results of operations, or related effects on financial
position, that would have been attained had the above-mentioned transactions
actually occurred earlier.
In our opinion, management's assumptions provide a reasonable basis for
presenting the significant effects directly attributable to the above-mentioned
transactions described in the December 31, 1994 Notes, the related pro forma
adjustments give appropriate effect to those assumptions, and the pro forma
combined column reflects the proper application of those adjustments to the
historical amounts in the Pro Forma Consolidated Statement of Income for the
year ended December 31, 1994.
A review is substantially less in scope than an examination, the objective
of which is the expression of an opinion on management's assumptions, the pro
forma adjustments and the application of those adjustments to historical
financial information. Accordingly, we do not express such an opinion on the pro
forma adjustments or the application of such adjustments to the Pro Forma
Consolidated Statement of Income for the nine months ended September 30, 1995,
and the Pro Forma Consolidated Balance Sheet as of September 30, 1995. Based on
our review, however, nothing came to our attention that caused us to believe
that management's assumptions do not provide a reasonable basis for presenting
the significant effects directly attributable to the above-mentioned
transactions described in the September 30, 1995 Notes, that the related pro
forma adjustments do not give appropriate effect to those assumptions, or that
the pro forma combined column does not reflect the proper application of those
adjustments to the historical financial statement amounts in the Pro Forma
Consolidated Statement of Income for the nine months ended September 30, 1995,
and the Pro Forma Consolidated Balance Sheet as of September 30, 1995.
Arthur Andersen LLP
Detroit, Michigan,
February 1, 1996.
21
<PAGE> 26
PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1994
<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS
COMPANY TERRA WALTER ------------------------- PRO FORMA
HISTORICAL HISTORICAL(1) PRO FORMA(2) ACQUISITIONS OFFERING COMBINED
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate.................. $ 26,831 $ 433 $ 22,583 $49,847
Natural gas......................... 39,904 4,042 -- 43,946
Gain on sales of assets............. -- 2,900 -- 2,900
Other operating..................... 12,333 2,043 148 14,524
-------- ------- -------- -------- ------ -------
79,068 9,418 22,731 111,217
Operating Expenses:
Depreciation, depletion and
amortization...................... 34,919 955 4,944 $ (792)(3) 40,026
Cost center write-offs.............. 5,612 -- -- 5,612
Operating and maintenance........... 19,323 1,005 6,854 27,182
General and administrative.......... 6,345 3,744 3,881 (4,600)(4) $ 500(5) 9,870
Production and other taxes.......... 3,838 279 -- 4,117
Costs of products sold.............. 973 -- -- 973
Other............................... -- 46 -- 46
-------- ------- -------- -------- ------ -------
71,010 6,029 15,679 (5,392) 500 87,826
Pretax operating income............... 8,058 3,389 7,052 5,392 (500) 23,391
Write-down of notes receivable...... -- (1,451) -- (1,451)
Other income........................ 239 696 53 988
Interest expense, net............... 4,023 64 210 4,297
-------- ------- -------- -------- ------ -------
Income before income taxes and
minority interest................... 4,274 2,570 6,895 5,392 (500) 18,631
Minority interest in subsidiary..... -- 217 -- 217
Income tax provision (benefit)...... (5,523) 518 14 1,078(6) (175)(6) (4,088)
-------- ------- -------- -------- ------ -------
Net income............................ $ 9,797 $ 1,835 $ 6,881 $ 4,314 $ (325) $22,502
======== ======= ======== ======== ====== =======
Net income per common share........... $ 0.49 $ 0.94
======== =======
Average common shares outstanding
(000)............................... 20,000 4,000(7) 24,000
======== ====== =======
</TABLE>
- -------------------------
Notes to Pro Forma Consolidated Statement of Income for the Year Ended December
31, 1994:
(1) The Company acquired Terra in August 1995. This column reflects the
historical consolidated results of operations of Terra for the twelve months
ended December 31, 1994. See the Consolidated Financial Statements of Terra
included elsewhere in this Prospectus.
(2) The Company acquired Walter in February 1995. Walter and an unrelated
company acquired the respective Amoco Congo Companies on the business day
prior to the Company's acquisition of Walter. This column reflects the pro
forma consolidated results of operations of Walter after giving effect to
Walter's effective interest in the assets of the Amoco Congo Companies for
the twelve months ended December 31, 1994. See the Pro Forma Consolidated
Financial Statements of Walter and the Amoco Congo Companies included
elsewhere in this Prospectus.
(3) Adjustment to reflect the "unit-of-production" depreciation, depletion and
amortization of oil and gas properties of the Company and Terra based on the
aggregate consideration for the Terra Acquisition of $63.6 million.
(4) Historical general and administrative expenses for the twelve months ended
December 31, 1994 have been adjusted by estimated expense reductions of $0.5
million associated with the combination of the operations of the Company and
Terra. Such expenses have also been adjusted, based on changes in
compensation resulting from consummation of the Terra Acquisition, to
reflect the elimination of $4.1 million of pre-acquisition employee bonuses
recorded on the books of Terra as of December 31, 1994. Such bonuses were
paid to the two controlling shareholders of Terra at such time and had the
effect of reducing the net income of Terra. In connection with the Terra
Acquisition, these two individuals resigned their employment with Terra and,
through a limited liability company owned by them, entered into a consulting
agreement with Terra pursuant to which they agreed to continue to devote
time to Terra matters, with their indirect compensation for such time to be
roughly commensurate with the respective amounts they had been receiving as
salary (excluding bonus) while they were employed by Terra. Further, the
responsibilities of such individuals will not be diminished to the point
that other costs will be incurred that offset the pro forma adjustment to
compensation expense. Although an officer of the Company has been designated
as the new chief executive officer of Terra, Terra is not expected to bear
any additional expenses in connection therewith. Nor is Terra expected to
pay bonuses in the future to the above-referenced former controlling
shareholders of Terra or to Terra's new chief executive officer.
Accordingly, the adjustment relating to such bonuses is directly
attributable to the Terra Acquisition and is non-recurring.
(5) Historical general and administrative expenses for the twelve months ended
December 31, 1994 have been adjusted by estimated incremental general and
administrative expenses expected to be associated with the Company becoming
a publicly traded entity.
(6) Adjustment of income tax expense to reflect the combined results of
operations.
(7) Adjustment to reflect the issuance of 4,000,000 shares of Common Stock in
the Offering.
22
<PAGE> 27
PRO FORMA CONSOLIDATED STATEMENT OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1995
<TABLE>
<CAPTION>
PRO FORMA ADJUSTMENTS
COMPANY TERRA WALTER ------------------------- PRO FORMA
HISTORICAL(1) HISTORICAL(2) PRO FORMA(3) ACQUISITIONS OFFERING COMBINED
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate............ $45,423 $ 373 $2,592 $ 48,388
Natural gas................... 32,927 2,236 -- 35,163
Gain on sales of assets....... -- 994 -- 994
Other operating............... 17,738 2,431 -- 20,169
------- ------- ------ -------- ------ --------
96,088 6,034 2,592 104,714
Operating Expenses:
Depreciation, depletion and
amortization................ 34,072 464 432 $ 200(4) 35,168
Cost center write-offs........ 2,184 -- -- 2,184
Operating and maintenance..... 23,204 378 534 24,116
General and administrative.... 5,609 3,518 306 (3,924)(5) $ 375(6) 5,884
Production and other taxes.... 3,463 267 5 3,735
Costs of products sold........ 773 -- -- 773
------- ------- ------ -------- ------ --------
69,305 4,627 1,277 (3,724) 375 71,860
Pretax operating income......... 26,783 1,407 1,315 3,724 (375) 32,854
Other income.................. 522 541 5 1,068
Interest expense, net......... 6,455 36 27 (525)(7) 5,993
------- ------- ------ -------- ------ --------
Income before income taxes...... 20,850 1,912 1,293 3,724 150 27,929
Income tax provision.......... 386 387 -- 744(8) 53(8) 1,570
------- ------- ------ -------- ------ --------
Income before extraordinary
item.......................... 20,464 1,525 1,293 2,980 97 26,359
Extraordinary item, early
retirement of debt, net....... (987) -- -- -- -- (987)
------- ------- ------ -------- ------ --------
Net income...................... $19,477 $ 1,525 $1,293 $ 2,980 $ 97 $ 25,372
======= ======= ====== ======== ====== ========
Net income per common share..... $ 0.97 $ 1.06
======= ========
Average common shares
outstanding (000)............. 20,000 4,000(9) 24,000
====== ========
</TABLE>
- -------------------------
Notes to Pro Forma Consolidated Statement of Income for the Nine Months Ended
September 30, 1995:
(1) This column reflects the historical results of operations of the Company,
including Walter for the eight months ended September 30, 1995 and Terra for
the two months ended September 30, 1995. See Consolidated Financial
Statements of the Company included elsewhere in this Prospectus.
(2) The Company acquired Terra in August 1995. This column reflects the
historical consolidated results of operations of Terra for the seven months
ended July 31, 1995. See the Consolidated Financial Statements of Terra
included elsewhere in this Prospectus.
(3) The Company acquired Walter in February 1995. Walter and an unrelated
company acquired the respective Amoco Congo Companies on the business day
prior to the Company's acquisition of Walter. This column reflects the pro
forma consolidated results of operations of Walter after giving effect to
Walter's effective interest in the assets of the Amoco Congo Companies for
the month ended January 31, 1995. See the Pro Forma Consolidated Financial
Statements of Walter included elsewhere in this Prospectus.
(4) Adjustment to reflect the "unit-of-production" depreciation, depletion and
amortization of oil and gas properties of the Company and Terra based on the
aggregate consideration for the Terra Acquisition of $63.6 million.
(5) Historical general and administrative expenses for the seven months ended
July 31, 1995 have been adjusted by estimated expense reductions of $375,000
associated with the combination of the operations of the Company and Terra.
The expenses have also been adjusted to reflect the elimination of
pre-acquisition employee bonuses of $3.6 million recorded on the books of
Terra as of July 31, 1995.
(6) Historical general and administrative expenses for the nine months ended
September 30, 1995 have been adjusted by estimated incremental general and
administrative expenses expected to be associated with the Company becoming
a publicly traded entity.
(7) Adjustment to reflect the application of the estimated net proceeds of $69.0
million from the Offering to repay an aggregate of $69.0 million of debt
(and the corresponding reduction of interest expense), including debt
incurred in connection with the Recent Acquisitions.
(8) Adjustment of income tax expense to reflect the combined results of
operations.
(9) Adjustment to reflect the issuance of 4,000,000 shares of Common Stock in
the Offering.
23
<PAGE> 28
PRO FORMA CONSOLIDATED BALANCE SHEET
AS OF SEPTEMBER 30, 1995
<TABLE>
<CAPTION>
COMPANY PRO FORMA PRO FORMA
HISTORICAL(1) ADJUSTMENTS COMBINED
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash............................................... $ 5,255 $ $ 5,255
Temporary cash investments......................... 3,813 3,813
Accounts receivable................................ 69,074 69,074
Other.............................................. 13,200 13,200
--------- -------- ---------
91,342 91,342
Investments and other assets......................... 23,121 23,121
Property, plant and equipment, at cost............... 1,073,981 1,073,981
Less accumulated depreciation, depletion
and amortization................................ (526,038) (526,038)
--------- -------- ---------
547,943 547,943
--------- -------- ---------
Total assets......................................... $ 662,406 $ $ 662,406
========= ======== =========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current maturities of long-term debt............... $ 6,677 $ $ 6,677
Accounts payable................................... 49,308 49,308
Accrued interest................................... 1,171 1,171
Accrued taxes and other............................ 9,215 9,215
--------- -------- ---------
66,371 66,371
Long-term debt....................................... 192,371 (69,000)(2) 123,371
Deferred Credits:
Deferred income taxes.............................. 54,590 54,590
Other.............................................. 7,985 7,985
--------- -------- ---------
62,575 62,575
Stockholders' Equity:
Common stock....................................... 169,726 69,000(2) 238,726
Retained earnings.................................. 171,363 171,363
--------- -------- ---------
341,089 69,000 410,089
--------- -------- ---------
Total liabilities and stockholders' equity........... $ 662,406 $ -- $ 662,406
========= ======== =========
</TABLE>
- -------------------------
Notes to Pro Forma Consolidated Balance Sheet as of September 30, 1995:
(1) The Company's historical consolidated balance sheet includes the balances of
Terra and Walter as of September 30, 1995. See the Consolidated Financial
Statements of the Company included elsewhere in this Prospectus.
(2) Adjustment to reflect the application of the estimated net proceeds of $69.0
million from the Offering to repay an aggregate of $69.0 million in debt,
including debt incurred in connection with the Recent Acquisitions, and to
reflect the issuance of 4,000,000 shares of Common Stock for the Offering.
24
<PAGE> 29
SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA
The following table presents selected historical consolidated financial
data of the Company 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, 1994 are derived from the consolidated financial
statements of the Company which have been audited by Arthur Andersen LLP,
independent certified public accountants. The historical consolidated financial
data as of and for the nine months ended September 30, 1994 and 1995 are derived
from unaudited consolidated financial statements of the Company which, in the
opinion of management, contain all adjustments (consisting of normal recurring
adjustments) necessary for a fair presentation thereof. The following data
should be read in conjunction with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and the Consolidated Financial
Statements of the Company and those relating to the Recent Acquisitions,
including the Notes thereto, included elsewhere in this Prospectus. The results
for the nine months ended September 30, 1995 are not necessarily indicative of
the results that may be achieved for the full year ending December 31, 1995.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------------------------------------- --------------------
1990 1991 1992 1993 1994 1994 1995
<S> <C> <C> <C> <C> <C> <C> <C>
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE DATA)
INCOME STATEMENT DATA(1):
Operating Revenues:
Oil and condensate.................... $ 30,316 $ 24,381 $ 26,553 $ 26,635 $ 26,831 $ 18,479 $ 45,423
Natural gas........................... 34,866 36,577 34,391 40,995 39,904 30,550 32,927
Other operating....................... 6,244 7,546 8,408 6,275 12,333 10,107 17,738
-------- -------- -------- -------- --------- -------- --------
71,426 68,504 69,352 73,905 79,068 59,136 96,088
Operating Expenses:
Depreciation, depletion and
amortization.......................... 25,890 27,302 32,566 35,605 34,919 25,358 34,072
Cost center write-offs.................. 8,176 5,339 5,744 9,648 5,612 452 2,184
Operating and maintenance............... 9,326 11,618 13,476 15,005 19,323 14,050 23,204
General and administrative.............. 4,510 4,525 4,489 5,599 6,345 4,346 5,609
Production and other taxes.............. 4,528 4,134 3,997 4,221 3,838 3,010 3,463
Cost of products sold and other......... 2,440 1,256 1,427 1,127 973 682 773
-------- -------- -------- -------- --------- -------- --------
54,870 54,174 61,699 71,205 71,010 47,898 69,305
Pretax operating income................... 16,556 14,330 7,653 2,700 8,058 11,238 26,783
Other income.............................. 331 363 163 382 239 152 522
Interest expense, net..................... 5,007 4,314 4,954 3,844 4,023 2,624 6,455
-------- -------- -------- -------- --------- -------- --------
Income (loss) before income taxes......... 11,880 10,379 2,862 (762) 4,274 8,766 20,850
Income tax provision (benefit)............ 3,720 250 (2,100) (5,900) (5,523) (2,148) 386
Income before accounting change and
extraordinary item...................... 8,160 10,129 4,962 5,138 9,797 10,914 20,464
-------- -------- -------- -------- --------- -------- --------
Extraordinary item, early retirement of
debt, net............................... -- -- -- -- -- -- (987)
Cumulative effect of accounting change,
net of income taxes..................... -- -- (1,124) -- -- -- --
-------- -------- -------- -------- --------- -------- --------
Net income................................ $ 8,160 $ 10,129 $ 3,838 $ 5,138 $ 9,797 $ 10,914 $ 19,477
======== ======== ======== ======== ========= ======== ========
Net income per common share............... $ 0.41 $ 0.51 $ 0.19 $ 0.26 $ 0.49 $ 0.55 $ 0.97
======== ======== ======== ======== ========= ======== ========
Average common shares outstanding (000)... 20,000 20,000 20,000 20,000 20,000 20,000 20,000
OTHER DATA:
EBITDA(2)............................... $ 50,953 $ 47,334 $ 46,126 $ 48,335 $ 48,828 $ 37,200 $ 63,561
Cash Flow:
From Operating Activities............. 39,776 47,540 44,731 45,971 46,921 33,626 53,207
From Financing Activities............. 42,200 24,600 22,582 31,839 66,421 63,873 (4,100)
From Investing Activities............. (81,834) (71,431) (68,059) (77,750) (108,188) (93,854) (46,125)
Capital expenditures.................... 81,834 71,431 68,059 77,750 108,188 93,854 152,958(3)
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital(4)...................... $ 4,451 $ 10,501 $ 8,989 $ 9,847 $ 15,189 $ 13,671 $ 31,648
Investments and other assets............ 4,650 4,635 4,218 7,088 12,539 10,814 23,121
Property, plant and equipment, net...... 276,793 315,555 346,188 375,990 438,057 440,194 547,943
Total assets............................ 301,946 345,936 370,274 402,361 472,700 476,082 662,406
Long-term debt, including current
portion............................... 84,500 79,600 96,382 118,720 129,041 130,593 199,048
Stockholder's equity.................... 159,084 198,713 208,351 222,989 288,886 285,903 341,089
</TABLE>
- -------------------------
(1) Certain reclassifications have been reflected in amounts prior to 1995 to
conform with 1995 presentation.
(2) EBITDA is earnings before interest, income taxes, depreciation, depletion
and amortization, cumulative effect of accounting change, extraordinary item
and cost center write-offs of oil and gas assets. EBITDA is presented to
provide additional information about the Company's ability to meet its
future requirements for debt service, capital expenditures and working
capital. EBITDA 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. See the Consolidated Statements of Cash Flows of the
Company included elsewhere in this Prospectus for disclosure of operating,
investing and financing cash flows.
(3) Includes non-cash capital expenditures of $106.9 million relating to the
Recent Acquisitions.
(4) Excluding current maturities of long-term debt.
25
<PAGE> 30
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion is intended to assist in an understanding of the
Company's historical financial position and results of operations for each of
the three years in the period ended December 31, 1994 and the unaudited
historical financial data as of and for the nine months ended September 30, 1994
and 1995. The Company's 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 appearing in this Prospectus includes (i) unaudited Pro
Forma Consolidated Financial Statements and Notes thereto reflecting the Recent
Acquisitions; (ii) historical Consolidated Financial Statements and Notes
thereto for CMS NOMECO International, Inc. and Subsidiaries (formerly Walter
International, Inc. and Subsidiaries) as of and for the year ended December 31,
1994; (iii) historical Consolidated Financial Statements and Notes thereto for
the Amoco Congo Companies as of December 31, 1993 and 1994 and for the years
ended December 31, 1992, 1993 and 1994, respectively, and (iv) historical
Consolidated Financial Statements and Notes thereto for Terra Energy Ltd. and
Subsidiaries as of and for the year ended December 31, 1994.
GENERAL
The Company, an indirect subsidiary of CMS Energy, is an independent oil
and natural gas company engaged in the exploration, development, acquisition and
production of oil and natural gas properties in the U.S. and seven other
countries. The Company's oil-producing assets are concentrated in South America
(Ecuador, Venezuela and Colombia) and offshore West Africa (the Congo and
Equatorial Guinea), and the Company's gas-producing assets are concentrated in
Michigan, the Gulf Coast region and the Gulf of Mexico.
The following events have recently had, and will continue to have, a
significant impact on the Company's results of operations and financial
condition: (i) the Terra Acquisition in August 1995; (ii) the Walter Acquisition
in February 1995; (iii) the assumption by a consortium in which the Company has
a 29.17% working interest of operations of the Colon Unit in Venezuela in May
1995; (iv) the June 1994 acquisition by the Company of Sun Colombia whose sole
asset is a working interest in the Espinal Block in Colombia; (v) the completion
by the Company in the third quarter of 1994 of two Antrim gas property
acquisitions; (vi) the commencement of Ecuador production in mid-1994 and the
subsequent commencement of production from additional fields; and (vii) the
commencement of production from the Freshwater Bayou Field in late 1994 and the
subsequent completion of four successful development wells. See "Business and
Properties -- Recent Developments."
The Company uses the full cost method of accounting for its investment in
oil and natural gas properties. Under the full cost method of accounting, all
costs of acquisition, exploration and development of oil and natural gas
reserves are capitalized into a "full cost pool" as incurred, and properties in
the pool, including estimated future development costs, are depleted and charged
to operations using the unit-of-production method based on the ratio of current
production to total proved oil and natural gas reserves. To the extent that such
capitalized costs (net of accumulated depreciation, depletion and amortization)
less deferred taxes exceed the sum of discounted estimated future net cash flows
from proved oil and natural gas reserves (using unescalated prices and costs and
a 10% per annum discount rate) and the lower of cost or market value of unproved
properties after income tax effects, such excess costs are charged against
earnings. The test is applied at the end of each fiscal quarter on a
country-by-country basis and requires a write-down of oil and natural gas
properties if the ceiling is exceeded, even if prices decline for only a short
period. Once incurred, such a write-down is not reversible at a later date even
if oil or natural gas prices increase. Significant downward revisions of the
estimates of proved reserves or declines in oil and natural gas prices from
those in effect on September 30, 1995 which are not offset by other factors
could result in a write-down for impairment of oil and natural gas properties.
The Company periodically utilizes hedging arrangements such as collar
contracts and swap agreements with respect to portions of its oil and gas
production to achieve more predictable cash flows and to reduce its exposure to
fluctuations in oil and gas prices. The Company may employ these hedging
arrangements with respect to some or all of that portion of its annual oil and
gas production which is sold at variable or market
26
<PAGE> 31
sensitive pricing when the Company views market prices as favorable compared to
its projected prices. For the nine months ended September 30, 1995, after giving
effect to the Recent Acquisitions, the portion of the Company's oil and gas
production sold at variable or market sensitive pricing was approximately 3.4
MMBbls, or 100%, of its oil production, and 12.5 Bcf, or 60%, of its gas
production. The Company has also hedged certain of its gas supply obligations in
the years 2001 to 2006. For a description of recent hedging arrangements entered
into by the Company, see "Business and Properties -- Marketing -- Hedging
Arrangements." To the extent utilized, these hedging arrangements tend to have
the effects of increasing predictability of the Company's cash flows and
reducing (but not eliminating) the Company's exposure to fluctuations, both up
and down, in oil and gas prices.
The Company has generated significant amounts of Section 29 Credits as a
result of the sale of natural gas produced from Antrim shale and, to a lesser
extent, tight sands wells. For 1995, it is estimated that the Company generated
approximately $12.0 million of Section 29 Credits; for 1996 through 2002, it is
estimated that the Company will generate Section 29 Credits averaging $14.0
million annually. No Section 29 Credit will be allowed for fuels sold after
December 31, 2002. Forecasts of the CMS Energy consolidated group's tax position
indicate that such group will be able to use and, therefore, that the Company
will be paid for all or substantially all of its approximately $12.0 million of
Section 29 Credits for the 1995 taxable year after CMS Energy's tax return is
filed for 1995. Such forecasts also indicate that the CMS Energy consolidated
group is expected to generate sufficient regular tax liabilities for subsequent
years so that the Company will be paid for its Section 29 Credits for the 1996 -
2002 tax years in the same year the returns for such years are filed. Also, such
forecasts indicate that the Company is expected to be paid over the next five
years for the approximately $27.2 million of accumulated minimum tax credit
carryforward allocated to the Company through December 31, 1994. However,
because CMS Energy's consolidated tax position is subject to many uncertainties,
some of which are not within the control of the Company or the other members of
the CMS Energy consolidated group, there can be no assurance that this will be
the case. See "Business and Properties -- Tax Matters." If the taxable income
for the CMS Energy consolidated group were to be less than projected, the
payments for the Section 29 Credits would be deferred or eliminated.
As of June 30, 1995, Block 16 and related fields in the Oriente Basin of
the Ecuadorian Amazon region represented approximately 14.1% of the Company's
estimated total proved reserves of oil and natural gas on a Boe basis. The
Ministry of Energy and Mines in Ecuador has notified the members of the
consortium with interests in such fields that they should investigate
alternatives for improving project economics to the Ecuadorian government,
including the renegotiation of the service contract governing the Company's
interest in these fields. Discussions with the Ecuadorian government concerning
various alternatives began in late September 1995 and will likely continue for
at least the next several months. The Company cannot currently predict what
impact, if any, these discussions will have on the project's economics, and
there can be no assurance that these discussions or their outcome will not have
a material adverse effect on the Company's estimated reserves, financial
condition or results of operations. See "Business and Properties -- Description
of Non-U.S. Operations -- South America -- Republic of Ecuador."
Outlook
Based on estimated capital expenditures for the fourth quarter of 1995 and
on current estimates of proved reserves as of December 31, 1995, which reflect
downward revisions in estimated reserves as of June 30, 1995 as reported by
Ryder Scott which were not offset by projected additions, it appears that U.S.
depletion expense for the year ended December 31, 1995 will be recorded based on
an annual U.S. depletion rate of $1.12 per MMBtu as compared with the depletion
rate of $0.99 per MMBtu used for calculating U.S. depletion expense for the nine
months ended September 30, 1995. This adjustment is expected to increase U.S.
depletion expense and to decrease pretax income of the Company by $4.0 million
for the fourth quarter of 1995. Based on preliminary unaudited financial
information, the Company currently expects its consolidated pretax operating
income and net income for the year ended December 31, 1995 to be approximately
$30.2 million and $23.9 million, respectively.
See "Risk Factors" for more information to assist in an understanding of
the Company's results of operations and financial position.
27
<PAGE> 32
RESULTS OF OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30, 1994 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1995
PRETAX OPERATING INCOME AND EARNINGS
The Company's pretax operating income for the nine months ended September
30, 1995 increased $15.6 million (139.3%) to $26.8 million, from $11.2 million
in the nine months ended September 30, 1994. The increase is primarily
attributable to an increase in gains from the disposition of gas sales contracts
($9.9 million in 1995 and $4.8 million in 1994), as well as higher sales volumes
and higher average market prices for oil, partially offset by lower average
market prices for natural gas and a $2.0 million U.S. cost center write-down.
The volume increase includes eight months' production from the Walter properties
acquired in February 1995 and two months' production from the Terra properties
acquired in August 1995. Net income increased $8.6 million (78.9%) to $19.5
million in the nine months ended September 30, 1995 from $10.9 million in the
comparable 1994 period, reflecting the higher operating income and a $3.0
million increase in Section 29 Credits, partially offset by an increase in
interest expense, net, and an extraordinary item, early retirement of debt, net
of income taxes. The following table sets forth selected oil and gas operating
statistics of the Company for the nine-month periods ended September 30, 1994
and 1995:
SELECTED OIL AND GAS OPERATING STATISTICS
<TABLE>
<CAPTION>
NINE MONTHS
ENDED SEPTEMBER
30,
---------------- INCREASE
1994 1995 (DECREASE)
<S> <C> <C> <C>
Oil volumes (MBbl):
U.S............................................................. 518 463 (10.6)%
Non-U.S......................................................... 874 2,756 215.3
Total........................................................... 1,392 3,219 131.3
Average oil price (per Bbl):
U.S............................................................. $15.64 $16.62 6.3
Non-U.S......................................................... 11.87 13.69 15.3
Overall*........................................................ 13.32 14.04 5.4
Gas volumes (MMcf)................................................ 15,008 18,989 26.5
Average gas price (per Mcf)*...................................... $ 2.11 $ 1.88 (10.9)
NGL volumes (MBbl)................................................ 123 172 39.8
Average NGL price (per Bbl)....................................... $14.84 $14.57 (1.8)
Operating expenses (per Boe):
Depreciation, depletion and amortization........................ $ 6.31 $ 5.20 (17.6)
Production costs................................................ 3.50 3.54 1.1
General and administrative...................................... 1.08 0.86 (20.4)
</TABLE>
- -------------------------
* Adjusted to reflect amounts received or paid under futures contracts entered
into to hedge the price of a portion of production, including $1,113,000 and
$2,826,000 received for settlement of gas hedging contracts in the nine months
ended September 30, 1994 and 1995, respectively, and payment of $224,000 for
settlement of oil hedging contracts in the nine months ended September 30,
1995. Without giving effect to such price hedging, overall average oil price
(per Bbl) would have been $13.32 and $14.11, and average gas price (per Mcf)
would have been $2.04 and $1.73, for the nine months ended September 30, 1994
and 1995, respectively. See Note 12 to the Consolidated Financial Statements
of the Company included elsewhere in this Prospectus.
28
<PAGE> 33
REVENUES
Oil and Condensate. Oil and condensate revenues increased $26.9 million
(145.4%) to $45.4 million in the first nine months of 1995 over the comparable
period of 1994 as a result of a 1,827,000 Bbl (131.3%) increase in production
and a $0.72 per Bbl (5.4%) increase in the overall average market price of oil
sales (adjusted for hedging). The production increase reflected increases due
to: (i) 851,000 Bbls of Ecuador production that commenced in mid-year 1994, (ii)
approximately 1.1 million Bbls from the Walter properties acquired in February
1995, and (iii) 245,000 Bbls from the Espinal Block properties in Colombia
acquired in mid-1994, partially offset by decreased production in New Zealand
due to well performance declines.
Natural Gas. Natural gas revenues increased $2.4 million (7.9%) in the
first nine months of 1995 to $32.9 million as compared with $30.5 million in the
comparable 1994 period. A 4.0 Bcf (26.5%) increase in gas production in the
first nine months of 1995 was offset by $0.23 per Mcf (10.9%) lower average gas
prices (adjusted for hedging). The volume increase included higher production in
Michigan Antrim (2.7 Bcf) and the Freshwater Bayou properties in Louisiana (2.5
Bcf) which properties commenced production in late 1994. These increases more
than offset lower production in other U.S. areas and in New Zealand. Other U.S.
gas production declined due to lower Gulf of Mexico production and the sale of
producing properties in 1994.
Other Operating. Other operating revenues for the first nine months of 1995
include a $9.9 million gain from the disposition of a gas sales contract and a
$1.5 million increase in hedging settlements while the comparable 1994 period
included a $4.8 million gain from the disposition of a gas sales contract. The
gas sales contract disposed of in 1995 had provided for sales prices of $3.25
per MMBtu in 1995, escalating 4.0% each year through December 31, 2006, and
covered 5,000 MMBtu per day or 1.8 Bcf annually of the Company's gas sales. The
gas sales contract disposed of in 1994 had provided for sales prices of $2.53
per MMBtu in 1994, escalating 4.0% each year through December 31, 2006, and
covered 10,000 MMBtu per day or 3.6 Bcf annually of the Company's gas sales. In
the future, the Company expects to sell these gas volumes on the spot market or
under term contracts providing for current market price.
COSTS AND EXPENSES
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $8.7 million (34.3%) to $34.1 million in the nine
months ended September 30, 1995 over the comparable period of 1994 primarily due
to the addition of production from the Ecuador, Walter, Terra and Espinal
properties. Additionally, depletion on increased gas production more than offset
the effects of lower U.S. oil production and a lower U.S. depletion rate, $0.99
per MMBtu in the first nine months of 1995 as compared with $1.13 per MMBtu for
the comparable period in 1994. The rate decrease resulted from significant
additions of gas reserves in the last half of 1994 in Louisiana and Michigan,
coupled with the effects of the acquisition of Terra reserves in Michigan.
Cost Center Write-offs. Cost center write-offs include a $2.0 million U.S.
write-down in the third quarter of 1995 due to low oil and gas prices.
Operating and Maintenance. Operating and maintenance expenses of $23.2
million increased $9.2 million (65.7%) in the first nine months of 1995 over the
comparable period of 1994 primarily because of $10.2 million of expense due to
the addition of production from the Ecuador, Walter and Espinal properties and a
$1.4 million increase attributable to higher Antrim gas production, including
Terra properties. The increases attributable to these items were partially
offset by the elimination of 1994 expense on properties sold (producing
properties and the Kalkaska Gas Processing Plant interest) and large workover
expense early in 1994.
General and Administrative. General and administrative expenses increased
$1.3 million (30.2%) to $5.6 million in the first nine months of 1995 over the
comparable period of 1994 primarily due to additional salaries and benefits.
This increase primarily reflects costs associated with the addition of personnel
in 1995 resulting from the Recent Acquisitions and development activities in the
Colon Block in Venezuela and the Espinal Block in Colombia.
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<PAGE> 34
Production and Other Taxes. Production and other taxes increased $0.5
million (16.7%) to $3.5 million in the first nine months of 1995 over the
comparable period of 1994 due to taxes on production from the Espinal Block in
Colombia acquired in mid-1994.
Interest Expense, Net. Interest expense, net increased $3.9 million
(150.0%) to $6.5 million in the first nine months of 1995 over the comparable
period of 1994 due to higher expense and lower capitalized interest. The
interest expense increase resulted from higher interest rates and higher debt
levels attributable to borrowings in the last half of 1994 and in 1995 primarily
associated with acquired properties (Terra, Walter and Espinal). Interest rates
averaged 7.9% per annum in the first nine months of 1995 as compared with 6.6%
per annum in the comparable period of 1994. Average outstanding debt balances
were $147.8 million in the first nine months of 1995 and $124.8 million in the
comparable period of 1994. Interest capitalized decreased $1.9 million due to
lower Ecuador development-stage assets as a result of commencement of production
in 1994.
Extraordinary Item. On August 10, 1995, the Company repaid in full senior
serial notes in the principal amount of $27.9 million and incurred a $1.5
million ($987,000 after income tax effects) prepayment penalty for the early
extinguishment of debt.
Income Tax Expense. Income tax expense of $0.4 million in the first nine
months of 1995 is $2.5 million higher than the $2.1 million tax benefit
(resulting from Section 29 Credits) in the first nine months of 1994. The
expense associated with higher income in the first nine months of 1995 was
partially offset by an increase in Section 29 Credits, which amounted to $9.0
million in the first nine months of 1995 as compared with $6.0 million in the
comparable period of 1994.
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<PAGE> 35
YEAR ENDED DECEMBER 31, 1993 COMPARED TO YEAR ENDED DECEMBER 31, 1994
PRETAX OPERATING INCOME AND EARNINGS
The Company's 1994 pretax operating income of $8.1 million increased $5.4
million (200.0%) from 1993. A gain of $4.8 million from the disposition of a gas
sales contract and a decrease of $4.0 million in cost center write-offs more
than offset the effects of lower average oil and gas prices. The increase in
pretax operating income also reflects lower U.S. depletion rates reduced by
higher expenses that were not directly related to increased production, and
lower plant products revenues. Net income increased $4.7 million (92.2%) from
1993 to $9.8 million in 1994. Income taxes were slightly higher by $0.4 million,
due to an increase in income, offset by an increase in Section 29 Credits. The
following table sets forth selected oil and gas operating statistics of the
Company for the years ended December 31, 1993 and 1994:
SELECTED OIL AND GAS OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------------ INCREASE
1993 1994 (DECREASE)
<S> <C> <C> <C>
Oil volumes (MBbl):
U.S........................................................... 870 690 (20.7)%
Non-U.S....................................................... 846 1,335 57.8
Total......................................................... 1,716 2,025 18.0
Average oil price (per Bbl):
U.S........................................................... $ 16.58 $ 15.22 (8.2)
Non-U.S....................................................... 14.43 12.23 (15.2)
Overall*...................................................... 15.52 13.30 (14.3)
Gas volumes (MMcf).............................................. 18,487 20,546 11.1
Average gas price (per Mcf)*.................................... $ 2.17 $ 2.05 (5.5)
NGL volumes (MBbl).............................................. 186 193 3.8
Average NGL price (per Bbl)..................................... $ 15.24 $ 14.90 (2.2)
Operating expenses (per Boe):
Depreciation, depletion and amortization...................... $ 7.15 $ 6.19 (13.4)
Production costs.............................................. 3.01 3.42 13.6
General and administrative.................................... 1.12 1.12 --
</TABLE>
- -------------------------
* Adjusted to reflect amounts received or paid under futures contracts entered
into to hedge the price of a portion of production, including payment of
$889,000 for settlement of gas hedging contracts in the year ended December
31, 1993 and $2,285,000 and $95,000 received for settlement of gas and oil
hedging contracts, respectively, for the year ended December 31, 1994. Without
giving effect to such price hedging, overall average oil price (per Bbl) would
have been $15.52 and $13.25, and average gas price (per Mcf) would have been
$2.22 and $1.94, for the years ended December 31, 1993 and 1994, respectively.
See Note 12 to the Consolidated Financial Statements of the Company included
elsewhere in this Prospectus.
REVENUES
Oil and Condensate. Oil and condensate revenues increased $0.2 million
(0.8%) in 1994 over 1993 as a result of a 309,000 Bbl (18.0%) increase in oil
sales volumes, partially offset by a $2.22 per Bbl (14.3%) decrease in the
average sales price. The increased volumes resulted from a 489,000 Bbl increase
in non-U.S. production primarily due to a 159,000 Bbl increase in production in
Colombia in 1994 as compared with 1993 and 369,000 Bbls of Ecuador production
which commenced in mid-year 1994. U.S. oil sales decreased 180,000 Bbls (20.7%)
in 1994 due to natural declines, sales of producing properties and well
performance problems in the Gulf of Mexico.
Natural Gas. Natural gas revenues decreased $1.1 million (2.7%) in 1994 to
$39.9 million compared with $41.0 million in 1993. In 1994, an increase of 2.1
Bcf (11.1%) in gas sales volumes increased natural gas revenues by $0.9 million
but the increase was fully offset by a $0.12 per Mcf (5.5%) decrease in the
average gas price (adjusted for hedging). Contributing to the sales volume
increase in 1994 were Antrim gas sales,
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<PAGE> 36
which reached 8.8 Bcf in 1994 compared with 6.0 Bcf in 1993. The increase in
Antrim gas sales volumes is attributable to production from properties acquired
in 1994, the completion of several projects which were not producing in 1993 and
the utilization of improved production technology. A 0.9 Bcf increase in other
Michigan gas sales volumes in 1994 partially offset decreases in other U.S.
areas.
Other Operating. Revenues received by the Company from the sale of
processing plant liquids decreased $1.2 million (30.8%) in 1994 from 1993, due
to lower revenues resulting from (i) the sale of the Company's interest in the
Kalkaska Gas Processing Plant in Michigan in the fourth quarter of 1994 and (ii)
a lower Btu content of the Company's Michigan gas production. Processing plant
sales amounted to $2.7 million in 1994 and $3.9 million in 1993. A gain of $4.8
million attributable to the disposition of a gas sales contract is included in
other revenues in 1994, while 1993 included $0.6 million of prior period items.
The gas sales contract had provided for sales prices of $2.53 per MMBtu in 1994,
escalating 4.0% per year to December 31, 2006 on 10,000 MMBtu per day, or 3.7
Bcf annually, of gas sales. Other revenues also included hedging settlements
which resulted in receipt of $2.4 million in 1994 compared with a payment of
$0.9 million in 1993.
COSTS AND EXPENSES
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense decreased $0.7 million (2.0%) in 1994 compared with 1993
due to a $0.15 per MMBtu decrease in the U.S. depletion rate to $1.11 per MMBtu,
partially offset by depletion attributable to increased non-U.S. oil production.
The rate decrease resulted from significant 1994 estimated proved reserve
additions in Louisiana and Michigan. The production increase resulted from
commencement of Ecuador production in mid-year 1994 and the acquisition of
Colombian properties in June 1994.
Cost Center Write-offs. Cost center write-offs decreased $4.0 million
(41.7%) to $5.6 million in 1994 compared with $9.6 million in 1993. These
write-offs primarily included dry hole costs associated with unsuccessful
exploration in Thailand ($4.2 million in 1994 and $3.9 million in 1993) and
China ($3.3 million in 1993). Also included are ceiling test write-downs of $0.7
million in 1994 for Papua New Guinea and $1.9 million in 1993 for Colombian
assets.
Operating and Maintenance. Operating and maintenance expenses of $19.3
million increased $4.3 million (28.7%) in 1994 from 1993. This increase reflects
$3.4 million in higher operating expenses in Michigan, Colombia and Ecuador
where production increased, combined with workover and maintenance costs
offshore Equatorial Guinea and in the Gulf of Mexico.
Production and Other Taxes. Production and other taxes decreased $0.4
million (9.5%) in 1994 compared with 1993 as a result of a $3.9 million decrease
in U.S. oil revenues, partially offset by increased severance tax on Antrim gas
production and taxes on higher Colombian oil production attributable to the
Espinal properties acquired in June 1994.
Interest Expense, Net. Net interest expense for 1994 remained about the
same as for 1993, $4.0 million compared with $3.8 million. The impact of higher
debt levels and interest rates was offset by increased capitalized interest on
the Company's investment in its Ecuador project. The Company had capitalized
interest associated with Ecuador development amounting to $4.4 million in 1994
and $2.5 million in 1993. Average outstanding debt balances were $125.4 million
in 1994 and $108.7 million in 1993.
Income Taxes. Income taxes increased slightly in 1994 from 1993. Section 29
Credits amounted to $8.5 million in 1994 and $5.6 million in 1993. However, the
$2.9 million increase in Section 29 Credits was more than offset by taxes on
higher income and the tax effects of non-U.S. income and investments. Income tax
expense for 1993 included $1.9 million to increase prior years' deferred taxes
for the 1.0% per annum federal income tax rate increase effective January 1,
1993.
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<PAGE> 37
YEAR ENDED DECEMBER 31, 1992 COMPARED TO YEAR ENDED DECEMBER 31, 1993
PRETAX OPERATING INCOME AND EARNINGS
The Company's 1993 pretax operating income decreased $5.0 million (64.9%)
to $2.7 million compared with $7.7 million in 1992. This decrease is
attributable to lower average oil prices, cost center write-offs, lower plant
revenues and higher depletion, partially offset by higher average gas prices and
increased oil and gas production volumes. Net income increased $1.3 million
(34.2%) in 1993 to $5.1 million due to the effects of lower income taxes and a
1992 accounting change. The following table sets forth selected oil and gas
operating statistics of the Company for the years ended December 31, 1992 and
1993:
SELECTED OIL AND GAS OPERATING STATISTICS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------------ INCREASE
1992 1993 (DECREASE)
<S> <C> <C> <C>
Oil volumes (MBbl):
U.S........................................................... 994 870 (12.5)%
Non-U.S....................................................... 423 846 100.0
Total......................................................... 1,417 1,716 21.1
Average oil price (per Bbl):
U.S........................................................... $ 19.25 $ 16.58 (13.9)
Non-U.S....................................................... 17.53 14.43 (17.7)
Overall....................................................... 18.85 15.52 (17.7)
Gas volumes (MMcf).............................................. 17,578 18,487 5.2
Average gas price (per Mcf)*.................................... $ 1.89 $ 2.17 14.8
NGL volumes (MBbl).............................................. 291 186 (36.1)
Average NGL price (per Bbl)..................................... $ 16.55 $ 15.24 (7.9)
Operating expenses (per Boe):
Depreciation, depletion and amortization...................... $ 7.02 $ 7.15 1.9
Production costs.............................................. 2.91 3.01 3.4
General and administrative.................................... 0.97 1.12 15.5
</TABLE>
- -------------------------
* Adjusted to reflect amounts paid under futures contracts entered into to hedge
the price of a portion of production, including $963,000 and $889,000 for the
years ended December 31, 1992 and 1993, respectively. Without giving effect to
such price hedging, average gas price (per Mcf) would have been $1.96 and
$2.22 for the years ended December 31, 1992 and 1993, respectively. See Note
12 to the Consolidated Financial Statements of the Company included elsewhere
in this Prospectus.
REVENUES
Oil and Condensate. Oil and condensate revenues were flat in 1993, $26.6
million in both 1993 and 1992 as a result of a 299,000 Bbl (21.1%) increase in
oil sales volumes, offset by a $3.33 per Bbl (17.7%) decrease in the average oil
sales price and a $1.6 million (39.3%) increase in transportation costs
attributable to higher Antrim gas production in Michigan and oil production in
Colombia. The increased volumes resulted from a 423,000 Bbl (100.0%) increase in
non-U.S. production due largely to increased production of 141,000 Bbls offshore
Equatorial Guinea and 192,000 Bbls of Colombian production which commenced in
1993. U.S. oil sales decreased 124,000 Bbls (12.5%) due to natural declines
without significant additions.
Natural Gas. Natural gas revenues increased $6.6 million (19.2%) to $41.0
million in 1993 over 1992 as a result of a $0.28 per Mcf (14.8%) increase in the
average gas sales price and 0.9 Bcf (5.1%) increase in gas sales volumes. A 1.3
Bcf increase in Antrim gas sales was partially offset by declines in other
areas.
Other Operating. Other operating revenues received by the Company from the
sale of processing plant liquids decreased $1.6 million (29.1%) to $3.9 million
in 1993 from $5.5 million in 1992. A nonrecurring gain relating to a $1.2
million settlement with Amoco Production Company was included in 1992 while 1993
33
<PAGE> 38
included $0.6 million of prior period items. Other revenues also included
hedging settlement payments of $0.9 million in 1993 and $1.0 million in 1992.
COSTS AND EXPENSES
Depreciation, Depletion and Amortization. Depreciation, depletion and
amortization expense increased $3.0 million (9.2%) to $35.6 million in 1993 from
$32.6 million in 1992 due to higher non-U.S. production volumes and an increase
in the U.S. depletion rate from $1.23 per MMBtu in 1992 to $1.26 per MMBtu in
1993. The rate increase is attributable to unsuccessful U.S. exploration results
in 1993 outside Michigan.
Cost Center Write-offs. Cost center write-offs increased $3.9 million
(68.4%) to $9.6 million in 1993 compared with $5.7 million in 1992. These
write-offs included unsuccessful exploration in Thailand ($3.9 million) and
China ($3.3 million) in 1993 and the Congo ($1.3 million) in 1992. Also included
are ceiling test write-downs of $1.9 million and $3.1 million in 1993 and 1992,
respectively, for Colombian assets.
Operating and Maintenance. Operating and maintenance expenses increased
$1.5 million (11.1%) to $15.0 million in 1993 from $13.5 million in 1992. The
increase corresponds with higher Antrim gas production in Michigan and the
start-up of production in Colombia which commenced in early 1993, partially
offset by reductions in other Michigan oil and gas production.
General and Administrative. General and administrative expenses increased
$1.1 million (24.4%) to $5.6 million in 1993 compared with $4.5 million in 1992.
The 1993 increase included $0.6 million higher salaries and benefits, primarily
due to $0.3 million of post-retirement benefits costs in 1993 general and
administrative expenses while the corresponding 1992 expense was included in the
cumulative effect of an accounting change. Also included in 1993 was $0.1
million of currency losses, while 1992 had $0.2 million of currency gains.
Production and Other Taxes. Production and other taxes increased $0.2
million (5.0%) to $4.2 million in 1993 from $4.0 million in 1992 primarily due
to Colombian taxes relating to the commencement of production in 1993.
Interest Expense, Net. In 1993, net interest expense decreased $1.2 million
(24.0%) to $3.8 million from $5.0 million in 1992, primarily due to increased
capitalized interest in connection with the Company's Ecuador project. The
Company had capitalized interest associated with Ecuador development amounting
to $2.5 million in 1993 and $1.0 million in 1992. The expense associated with
higher levels of debt was partially offset by lower interest rates. Average
outstanding debt balances were $108.7 million in 1993 and $94.5 million in 1992.
Income Taxes. Income taxes decreased $3.8 million to a $5.9 million benefit
in 1993 compared with a $2.1 million benefit in 1992 due to lower pretax income,
higher Section 29 Credits and the tax effects of non-U.S. income and
investments. These decreases more than offset the $1.9 million effect of a 1.0%
federal income tax rate increase effective January 1, 1993. Section 29 Credits
amounted to $5.6 million in 1993 and $4.4 million in 1992.
LIQUIDITY AND CAPITAL RESOURCES
GENERAL
The Company's primary needs for capital, in addition to the funding of
ongoing operations, are for the exploration, development and acquisition of oil
and natural gas properties and the repayment of principal and interest on debt.
The Company's primary sources of liquidity have been net cash provided by
operating activities, proceeds from borrowings and equity contributions from CMS
Energy (effected through CMS Enterprises). Contributions from CMS Energy may not
be available in the future, and acquisitions funded by such contributions, if
any, would likely require the issuance of additional Common Stock to CMS Energy
or to CMS Enterprises at the then prevailing market price, which would result in
a dilution of the ownership interest of the public holders of Common Stock. In
addition, the issuance by the Company of a significant amount of its Common
Stock as consideration to a seller of acquired properties could result in
certain adverse consequences, such as the Company being deconsolidated from the
CMS Energy consolidated group for
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<PAGE> 39
federal income tax purposes. Accordingly, it is unlikely that the Company would
issue shares of its Common Stock to the sellers in an amount sufficient to cause
a deconsolidation in order to make an acquisition. If the Company decides not
to, or does not have the ability to, issue its Common Stock or to obtain equity
contributions from CMS Energy to finance acquisitions, the Company would likely
need to use cash on hand and/or cash available under its credit facilities or
other sources to acquire shares of its Common Stock in the open market to
consummate any proposed tax-free acquisitions. See "Risk Factors -- Acquisition
Risks." The Company budgets its capital expenditures based upon projected cash
flows and, subject to contractual commitments, routinely adjusts its capital
expenditures in response to changes in oil and natural gas prices and
corresponding changes in cash flow.
The Company's accounts receivable and accounts payable have increased, and
are expected to remain at a higher level, as a result of the Recent
Acquisitions. For instance, Terra has substantial amounts of accounts receivable
and accounts payable as a result of Terra serving as promoter and operator of a
number of gas drilling projects, including its Antrim drilling program. Terra
typically initially bears all drilling and operating costs relating to such
projects, which can be substantial, even though its working interest therein is
generally far below 100%. Terra then invoices non-operator working interest
owners for their proportionate share of such costs, resulting in Terra's
receivables and payables being significantly higher per unit of revenue than
those of the Company on an historical basis.
The Company believes that cash generated from operations, together with the
estimated net proceeds of the Offering and borrowing capacity under its existing
and future financing arrangements, will be sufficient to meet its liquidity and
capital requirements for the foreseeable future.
OPERATING ACTIVITIES
Net cash provided by operating activities for the nine months ended
September 30, 1995 was $53.2 million, an increase of $19.6 million (58.3%) from
$33.6 million for the comparable 1994 period. The increase reflects income from
the Ecuador, Terra, Walter and Espinal properties as well as the income from the
disposition of a gas sales contract in March 1995 ($9.9 million) which succeeded
a similar disposition of another gas sales contract in July 1994 ($4.8 million).
Net cash provided by operating activities during the year ended December 31,
1994 was $46.9 million, up $0.9 million (2.0%) from $46.0 million in the
comparable 1993 period.
FINANCING ACTIVITIES
The Company received equity contributions totaling $32.7 million ($9.0
million in cash and $23.7 million in property) from CMS Energy through CMS
Enterprises in the first nine months of 1995, primarily relating to the Walter
Acquisition, which represents a decrease of $19.3 million (37.1%) from the $52.0
million received as equity contributions from CMS Energy in the first nine
months of 1994. These 1994 equity contributions included $25.0 million for the
Sun Colombia acquisition. The amount of net additional borrowings was $70.0
million in the first nine months of 1995 as compared with $11.9 million in the
comparable 1994 period. This increase in borrowings is primarily attributable to
$67.8 million of CMS Notes incurred in connection with the Recent Acquisitions
and $15.3 million of debt assumed with these acquisitions, offset by the $27.9
million early retirement of the senior serial notes. Total debt outstanding at
September 30, 1995 was $199.0 million, an increase of $70.0 million from $129.0
million at December 31, 1994. Borrowings increased $10.3 million (8.7%) in the
year ended December 31, 1994 to $129.0 million at December 31, 1994. The Company
also received $56.1 million in equity contributions from CMS Energy during the
year ended December 31, 1994. Financing for 1993 capital expenditures was
provided in part by $46.0 million of net cash provided by operating activities
and in part by $9.5 million of equity contributions from CMS Energy. Long-term
debt at December 31, 1993 was $118.7 million, reflecting an increase of $22.3
million (23.1%) compared with December 31, 1992.
In December 1994, CMS Energy arranged for the issuance of a standby letter
of credit, currently in the amount of $45.0 million, to secure the Company's
performance under the operating services agreement with respect to the Colon
Unit in Venezuela. The Company has agreed to reimburse CMS Energy on demand for
35
<PAGE> 40
any draw made under the letter of credit and to pay to CMS Energy a fee of
2.125% per annum of the face amount of the letter of credit. See "Relationship
and Certain Transactions with CMS Energy."
THE CREDIT FACILITY
The Company's Credit Agreement provides a maximum lending commitment of
$130.0 million (the "Credit Facility"). The Credit Facility is subject to an
aggregate borrowing base limitation equal to the estimated loan value of the
Company's oil and gas reserves, subject to certain exclusions, based upon
forecast rates of production and current commodity pricing assessments, as
periodically redetermined by the Banks which are parties to the Credit
Agreement. The Banks have broad discretion in determining which of the Company's
reserves to include in the borrowing base. As of September 30, 1995, the
borrowing base was $135.3 million, and accordingly, the total amount available
for borrowing from the Credit Facility at September 30, 1995 was $130.0 million.
Of this availability, $113.3 million in borrowings was outstanding at September
30, 1995. In November 1995, the Credit Agreement was amended to increase the
maximum lending commitment to $140 million. The borrowing base was increased to
$145.3 million.
Under the terms of the Credit Agreement, the Company must (i) maintain a
ratio of current assets to current liabilities at least equal to 0.75 to 1.0,
(ii) maintain a ratio of total liabilities to tangible net worth of no more than
0.75 to 1.0, (iii) maintain a minimum tangible net worth of $150.0 million, and
(iv) maintain a ratio of cash flow after dividends to fixed charges for the most
recent four quarters of 2.0 to 1.0. Restrictive covenants under the Credit
Agreement 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 Agreement within 90
days after notification to the banks that (i) CMS Energy no longer beneficially
owns a majority of the outstanding voting stock of the Company or (ii) all or
substantially all of the assets of the Company are sold. See "Capitalization."
As of September 30, 1995, the Company's current ratio was 1.60 to 1.0, its
total liabilities to tangible net worth ratio was 0.72 to 1.0, its tangible net
worth was $302.0 million and its ratio of cash flow after dividends to fixed
charges was 4.9 to 1.0.
The Company has executed a term sheet to obtain a replacement credit
facility which will, among other things, increase the commitment level to $225
million and expand the borrowing base. Under the proposed terms, the Company
will be required, among other things (i) to maintain total debt to total
capitalization at no more than 55%, (ii) to maintain tangible net worth of not
less than $275 million, to be increased by 50% of net proceeds of new common
stock and 50% of additional net income, and (iii) to maintain a ratio of
earnings before interest, taxes, and depletion to interest expense of not less
than 3.5 to 1. There can be no assurance that a replacement credit facility will
be executed in accordance with the term sheet.
CMS NOTES
In August 1995, the Company issued the Terra Note to CMS Enterprises, which
in turn assigned it to CMS Energy, in connection with the transfer by CMS Energy
of the common stock of Terra to CMS Enterprises and then by CMS Enterprises to
the Company. In July 1995, the Company issued the Walter Note to CMS Energy to
evidence indebtedness originally incurred in February 1995 to fund repayment of
$6.5 million of indebtedness of Walter immediately after the consummation of the
Walter Acquisition. The CMS Notes are subordinated to the Company's obligations
under the Credit Agreement, bear interest at the rate of LIBOR plus 2.0% per
annum and have a maturity date of November 1, 1999. See "Use of Proceeds" and
"Relationship and Certain Transactions with CMS Energy."
OTHER DEBT
As of September 30, 1995, $14.2 million of project financing debt is
outstanding under agreements with the Overseas Private Investment Corporation
("OPIC"). These OPIC guaranteed loans funded development
36
<PAGE> 41
drilling for the Alba Field in Equatorial Guinea ($5.4 million) and acquisition
financing for the Yombo Field in the Congo ($8.8 million).
In connection with the Terra Acquisition, the Company assumed $3.7 million
of long-term debt comprised of $1.9 million of capitalized leases and $1.8
million outstanding under a term loan for financing of a processing plant under
construction.
INVESTING ACTIVITIES
The Company's recent capital investments have focused primarily on the
acquisition and development of properties with proved reserves. Capital
expenditures of $153.0 million ($46.1 million in cash) for the first nine months
of 1995 represented an increase of $59.1 million (62.9%) from the comparable
1994 period. Non-cash expenditures for the first nine months of 1995 include
$65.1 million for the Terra Acquisition and $41.8 million for the Walter
Acquisition. Expenditures for the first nine months of 1994 included $25.0
million for the Sun Colombia acquisition. The Company's capital expenditures of
$108.2 million for the year ended December 31, 1994 were $30.4 million (39.1%)
higher than capital expenditures of $77.8 million for the comparable 1993
period. The increase reflects a $32.6 million increase in purchases of proved
reserves ($33.5 million in 1994 compared with $0.9 million in 1993) and an
increase of $2.7 million for non-U.S. expenditures, offset by decreases in U.S.
spending. The purchases in 1994 consisted of the Sun Colombia acquisition for
$25.0 million and two acquisitions of Antrim gas properties for $8.5 million.
The Company's capital expenditures for the year ended December 31, 1993 of $77.8
million were $9.7 million (14.2%) higher than the capital expenditures for the
comparable 1992 period. The increase reflects a $30.8 million increase in
non-U.S. expenditures, including substantial expenditures for development in
Ecuador, offset by decreases of $8.1 million in U.S. spending and $13.0 million
for U.S. acquisitions.
In December 1994, a consortium in which the Company is a 29.17% participant
entered into an agreement with Maraven, S.A. ("Maraven"), a unit of the
Venezuelan state oil company, to develop the Colon Block in the Maracaibo Basin
of southwest Venezuela. The agreement commits the consortium to spend at least
$160 million over three years in a development program involving reworking,
re-equipping and re-entering existing wells and drilling new wells to optimize
production from existing proved reserves.
The Company estimates that its capital expenditures for 1995 totalled
approximately $180.0 million, including approximately $66.7 million for the
Terra Acquisition, $41.3 million for the Walter Acquisition and additional
Ecuador, Venezuela and Colombia development expenditures of over $34.0 million.
As of September 30, 1995, $153.0 million of such capital expenditure budget had
been spent. The Company estimates that its capital expenditures for 1996 will be
approximately $120.0 million.
INFLATION AND CHANGE IN PRICES
The Company's revenues and the value of its oil and gas properties have
been and will be affected by changes in oil and natural gas prices. The
Company's 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 that are beyond the Company's ability to control
or predict. Although certain of the Company's costs and expenses are affected by
the level of inflation, inflation has not had a significant effect on the
Company's results of operations during the first nine months of 1995 or during
each of the three years in the period ended December 31, 1994.
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<PAGE> 42
BUSINESS AND PROPERTIES
OVERVIEW
The Company is an independent oil and natural gas company engaged in the
exploration, development, acquisition and production of oil and natural gas
properties in the U.S. and seven other countries. Formed in 1967 to explore and
develop leaseholdings located solely in Michigan, the Company has greatly
expanded to become an international oil and natural gas company. In large part
as a result of acquisitions and development activities, the Company has
approximately doubled both its estimated proved reserves and its production of
oil and natural gas over the last four years. As of June 30, 1995, the Company
had estimated proved reserves of 118.6 MMBoe, consisting of 68.9 MMBbls of oil
(97.0% of which were located outside the U.S.) and 298.1 Bcf of natural gas
(94.5% of which were located in the U.S.). Approximately 64.7% of the Company's
estimated proved reserves on such date were classified as proved developed. The
Company's oil-producing assets are concentrated in South America (Ecuador,
Venezuela and Colombia) and offshore West Africa (the Congo and Equatorial
Guinea), and the Company's gas-producing assets are concentrated in Michigan,
the Gulf Coast region and the Gulf of Mexico.
The following table sets forth by region the Company's estimated proved
reserves as of June 30, 1995, and estimated average daily production during the
month of September 1995:
<TABLE>
<CAPTION>
ESTIMATED PROVED RESERVES ESTIMATED AVERAGE DAILY PRODUCTION
AS OF JUNE, 30, 1995 DURING THE MONTH OF SEPTEMBER 1995
--------------------------------------------- ----------------------------------------------
OIL AND NATURAL % OF OIL AND NATURAL % OF
CONDENSATE(1) GAS TOTAL TOTAL CONDENSATE GAS TOTAL TOTAL
(MMBBLS) (BCF) (MMBOE) RESERVES (MBBLS) (MMCF) (MBOE) PRODUCTION
<S> <C> <C> <C> <C> <C> <C> <C> <C>
U.S.:
Michigan Antrim....... -- 218.0 36.3 30.6% -- 42.8 7.1 28.6%
Michigan Other........ 1.2 20.5 4.6 3.9 0.9 8.8 2.4 9.7
Freshwater Bayou...... 0.2 29.4 5.1 4.3 0.1 11.0 1.9 7.7
Gulf of Mexico........ 0.2 3.8 0.8 0.7 0.3 8.7 1.8 7.3
Other U.S. ........... 0.5 9.9 2.2 1.8 0.3 5.7 1.2 4.8
----- ----- ----- ----- ---- ---- ---- -----
Total U.S. ....... 2.1 281.6 49.0 41.3 1.6 77.0 14.4 58.1
NON-U.S.:
South America:
Ecuador............. 16.7 -- 16.7 14.1 3.2 -- 3.2 12.9
Venezuela........... 11.3 -- 11.3 9.5 0.5 -- 0.5 2.0
Colombia............ 6.7 -- 6.7 5.7 1.1 -- 1.1 4.4
Africa/Middle East:
Congo............... 15.9 -- 15.9 13.4 3.4 -- 3.4 13.7
Equatorial Guinea... 11.5 10.7 13.3 11.2 1.9 -- 1.9 7.7
Yemen............... 2.6 -- 2.6 2.2 -- -- -- --
Other Non-U.S.(2)..... 2.1 5.8 3.1 2.6 0.2 0.3 0.3 1.2
----- ----- ----- ----- ---- ---- ---- -----
Total Non-U.S. ..... 66.8 16.5 69.6 58.7 10.3 0.3 10.4 41.9
----- ----- ----- ----- ---- ---- ---- -----
Total Company..... 68.9 298.1 118.6(3) 100.0% 11.9 77.3 24.8 100.0%
===== ===== ===== ===== ==== ==== ==== =====
</TABLE>
- -------------------------
(1) Oil and condensate includes 0.2 MMBbls and 3.0 MMBbls, respectively, of U.S.
and non-U.S. NGLs.
(2) Consists of New Zealand and Papua New Guinea. The Company's properties in
each of these countries were sold in December 1995.
(3) Based on current estimates, the Company expects proved reserves as of
December 31, 1995 to reflect decreases of 3.1 MMBoe due to the sale of the
Company's properties in New Zealand and Papua New Guinea and 4.3 MMBoe due
to production subsequent to June 30, 1995, partially offset by net
additions.
For a discussion of the amounts of revenue, operating profit and
identifiable assets attributable to each region in which the Company is active,
see Note 11 to the Consolidated Financial Statements of the Company included
elsewhere in this Prospectus.
STRATEGY
The Company believes that its success has resulted from its ability to
capitalize on an extensive network of industry relationships, an efficient
evaluation and decision-making process and broad technical competence. The
Company believes that its future growth depends on maintaining an opportunistic
approach which builds
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<PAGE> 43
on the Company's existing strengths. Accordingly, the Company's business
strategy is to focus on the following goals while maintaining the flexibility to
respond to new opportunities and changed circumstances.
BALANCE
The Company seeks to maintain a balance between its U.S. and non-U.S.
interests to diversify its political, geologic and economic risk. The Company
believes that projects outside the U.S. tend to have a higher potential for
significant reserve growth but often have greater risks, including political
risks and the risks associated with infrastructure development necessary to
market production. The Company further believes that projects in the U.S. do not
have certain of these risks, but also generally do not offer as large a
potential for reserve growth as non-U.S. projects. The Company has historically
concentrated on natural gas in the U.S. and to date has focused its non-U.S.
activities on oil, providing the Company an additional balance between natural
gas and oil.
EXPLORATION AND DEVELOPMENT OF EXISTING NON-U.S. PROPERTIES
In recent years, the Company has made a series of investments in properties
outside the U.S. that currently have both production from proved reserves and
significant potential for exploration and development. The Company is pursuing
exploration and development of such properties, which include Block 16 in
Ecuador, the Colon Unit in Venezuela, the Espinal Block in Colombia, the Yombo
Field offshore the Congo and the Bioko Block offshore Equatorial Guinea. Most of
the Company's exploration and development opportunities outside the U.S. are
located in areas which have significant production histories and adequate
infrastructure and, in the Company's view, have a reasonable possibility of
yielding sizeable additional reserves through the application of modern
exploration and development technologies.
SELECTIVE ACQUISITIONS
The Company intends to continue to pursue attractive opportunities to
acquire producing properties with significant exploration and development
potential. The Company's primary focus is in the geographic regions where it has
significant experience. The Company's recent acquisitions of Walter and Terra
are illustrative of the types of opportunities the Company seeks.
OPERATOR ROLE
The Company seeks to continue to expand its role as operator of both U.S.
and non-U.S. projects by pursuing acquisitions and investment opportunities that
allow it to do so. As operator, the Company believes that it can better manage
production performance and more effectively control expenses, the allocation of
capital and the timing of exploration and development of its fields. In
addition, the Company believes that its experience as operator will provide it
access to a broader range of additional investment opportunities. In early 1995,
the Company assumed the role of operator of significant offshore producing
properties in West Africa in conjunction with the Walter Acquisition, and more
recently the Company materially increased its role as operator of U.S.
properties as a result of the Terra Acquisition. After giving effect to these
Recent Acquisitions, the Company operates properties representing approximately
37.5% of its estimated proved reserves, including 43.9% of its U.S. proved
reserves and 32.5% of its non-U.S. proved reserves. With respect to projects not
operated by the Company, the Company actively monitors the performance of its
operators with the same objectives it seeks for Company-operated projects.
REGIONAL FOCUS
With respect to both its U.S. and non-U.S. activities, the Company intends
to focus on selected geographic regions, particularly those where it is
currently active. In the U.S., the Company expects to continue its emphasis on
development, production and, to a lesser extent, exploration of natural gas in
its core areas of Michigan, the Gulf of Mexico and the Gulf Coast region.
Outside the U.S., the Company intends to concentrate on exploration, development
and production of oil in South America and offshore West Africa while evaluating
opportunities to acquire additional reserves in those areas and in certain areas
of Southeast
39
<PAGE> 44
Asia. By focusing activities in a relatively limited number of U.S. and non-U.S.
regions, the Company has acquired significant experience in the operational,
technical and legal aspects of conducting business in these regions and can
utilize its base of geologic, engineering and production experience in such
regions to better evaluate drilling and acquisition prospects.
TECHNOLOGY
The Company expects to continue to utilize its growing technology base,
including increasing use of 3-D seismic surveys, horizontal drilling, new
fracturing techniques and reservoir modeling, on its existing properties as well
as newly acquired properties. The Company believes it must utilize the latest
available technology to continue to compete successfully as the industry focuses
on properties with increasing amounts of exploration, development and production
risk.
RECENT DEVELOPMENTS
TERRA ACQUISITION
In August 1995, CMS Energy acquired Terra, a significant producer of gas
within the Antrim formation underlying a large portion of the Michigan Basin in
the northern portion of Michigan's lower peninsula. The consideration relating
to such acquisition, after giving effect to certain anticipated post-closing
adjustments, is expected to aggregate approximately $63.6 million, payable in
common stock of CMS Energy. Immediately after consummation of such acquisition,
the stock of Terra was transferred by CMS Energy, through CMS Enterprises, to
the Company. In connection with the Terra Acquisition, the Company recorded a
capital contribution of $1.0 million and issued the Terra Note which, after
giving effect to post-closing adjustments, is expected to be in the principal
amount of approximately $62.6 million. The Terra Note is currently held by CMS
Energy. A portion of the net proceeds from the Offering will be used to repay
indebtedness under the Terra Note. The Terra Acquisition was accounted for as a
purchase.
As of June 30, 1995, the acquired Terra properties included 1,225 gross
(95.6 net) producing Antrim gas wells and estimated net proved reserves of 91.9
Bcf of Antrim gas. Approximately 80.8% of the reserves attributable to the
acquired Terra properties at June 30, 1995 were proved developed reserves.
During the month of September 1995, estimated average daily net production from
these properties was approximately 9.5 MMcf of gas.
The Company has been a significant producer and operator of Antrim gas
wells for a number of years. Taking into account the Terra Acquisition, as of
December 31, 1995 the Company operated over 1,370 Antrim gas wells, or
approximately 30% of all gas wells producing from the Antrim formation, making
the Company the largest operator of Antrim gas wells. The Company is currently
serving as operator of several projects involving the planned drilling of an
additional 280 Antrim development wells by December 31, 1996. Additionally,
Terra has a sizeable inventory of unproved acreage in the Antrim producing
trend, and management believes that a number of its existing wells have
substantial potential for improved recovery. The Company believes that it is
particularly well suited to capitalize on the Terra Acquisition because of its
many years of experience in the natural gas industry in Michigan and its ability
as part of the CMS Energy consolidated group to utilize, to a substantial
extent, the Section 29 Credits associated with certain Antrim gas production.
Consolidated Financial Statements for Terra, and the related Notes thereto,
are included elsewhere in this Prospectus. See also "Pro Forma Consolidated
Financial Information."
WALTER ACQUISITION
In February 1995, CMS Energy acquired Walter, an international oil and gas
company, for a purchase price of approximately $28.4 million (of which
approximately $25.0 million was payable by delivery of CMS Energy common stock
and $3.4 million was paid in cash) plus assumed indebtedness of $18.3 million.
Immediately after consummation of such acquisition, the stock of Walter was
contributed by CMS Energy, through CMS Enterprises, to the Company. The Company
recorded a capital contribution of $28.4 million as a result of the Walter
Acquisition. The Walter Acquisition was accounted for as a purchase.
40
<PAGE> 45
Of the above-referenced assumed indebtedness of Walter, $6.5 million was
immediately repaid with funds which the Company borrowed from CMS Energy
pursuant to the Walter Note. A portion of the net proceeds from the Offering
will be used to repay the indebtedness under the Walter Note.
Walter owns interests in and operates fields offshore the Congo and
offshore Equatorial Guinea in West Africa and in Tunisia in North Africa. As of
June 30, 1995, the acquired Walter properties included 22 gross (6.6 net)
producing oil and condensate wells and estimated net proved reserves of 21.0
MMBbls of oil and condensate. Approximately 73.3% of the reserves attributable
to Walter's oil and natural gas properties at June 30, 1995, on a Boe basis,
were proved developed reserves. During the month of September 1995, estimated
average daily net production from these properties was approximately 4,829 Bbls
of oil and condensate. Walter is the operator of its fields in the Congo and
Equatorial Guinea, which account for virtually all of Walter's production.
The Company became familiar with Walter in part because of the Company's
participation in the Alba Field operated by Walter offshore Equatorial Guinea.
The acquisition of Walter is consistent with the Company's strategy of acquiring
producing properties with exploration and development potential. The Walter
Acquisition also expands the Company's role as operator of offshore and non-U.S.
projects.
Shortly prior to the acquisition of Walter by CMS Energy, Walter had
acquired ACEC from APC, a subsidiary of Amoco. At the same time, an affiliate of
Nuevo acquired ACPC, another subsidiary of APC which, together with ACEC, own
significant interests in the Yombo Field offshore the Congo. As a result of
these acquisitions and a related agreement between Walter and Nuevo, each of
Walter and Nuevo owns beneficially a 21.875% working interest in the Yombo
Field.
Consolidated Financial Statements for Walter (now named CMS NOMECO
International, Inc.), together with Combined Financial Statements for ACEC and
ACPC and unaudited pro forma consolidated financial information with respect to
Walter and its effective interest in the combined assets of ACEC and ACPC, and
the related Notes thereto, are included elsewhere in this Prospectus. See also
"Pro Forma Consolidated Financial Information."
OTHER RECENT ACQUISITIONS AND DISCOVERIES
The Company experienced significant growth in reserves in 1994 primarily as
a result of certain acquisitions of producing properties and one significant
discovery.
In December 1994, a consortium in which the Company has a 29.17% working
interest agreed to assume operation of the Colon Unit in Venezuela from an
affiliate of the state-owned oil company pursuant to an operating services
agreement. As of June 30, 1995, the Company's estimated proved oil reserves
attributable to this transaction were 11.3 MMBbls, and the Company has committed
to spend approximately $47.0 million ($38.0 million for capital expenditures and
$9.0 million for operating expenditures) over the next three years on rework and
other development and, to a lesser extent, exploration activities at the Colon
Unit. In June 1994, the Company acquired Sun Colombia, whose sole asset is a
working interest in the Espinal Block in Colombia, for approximately $25.0
million. As of June 30, 1995, the Company's estimated proved oil reserves
attributable to the Sun Colombia acquisition were 5.5 MMBbls. In the third
quarter of 1994, the Company completed two Antrim gas property acquisitions for
a total of approximately $8.5 million. The Company's estimated proved natural
gas reserves attributable to these acquisitions were approximately 10.3 Bcf as
of June 30, 1995.
In early 1994, the Company participated in a significant discovery in the
Freshwater Bayou Field in southern Louisiana. Since this discovery, four
successful development wells in this field have been drilled and with their
reserve additions, the Company's estimated proved natural gas reserves in the
field as of June 30, 1995 were 29.4 Bcf.
41
<PAGE> 46
DESCRIPTION OF U.S. OPERATIONS
MICHIGAN ANTRIM SHALE
The Company has become increasingly involved in the development of Antrim
natural gas projects in northern Michigan since its initial investment in such
projects in 1988. The Antrim formation is a Devonian age, brittle, carbonaceous,
shale which, when naturally or hydraulically fractured, yields natural gas at
modest flow rates.
The Antrim formation is attractive to the Company for several reasons.
Antrim gas wells are inexpensive to drill and complete, can have producing lives
of 30 years or more and show unusually high drilling success rates. The
characteristics of Antrim projects make them relatively low in drilling risk,
but economically sensitive to changes in production rates, expenses and market
prices. The Company believes that it is an industry leader among Antrim
producers in technical and operating capabilities, including the development and
utilization of production optimization technologies. For instance, the Company
has successfully employed several techniques in the Antrim formation, such as
down-hole progressive cavity pumps, plunger lift and stainless steel gas lift
technology, reduced density spacing, cased and multiple completions and new
fracturing strategies, in order to increase production of its recoverable
reserves and to minimize expenses and well workovers. Antrim shale has been
determined to be a non-conventional fuel source qualifying for the Section 29
Credit under the IRC, and the Company, as part of the CMS Energy consolidated
group, expects to be able to utilize such credits to a substantial extent. See
"-- Tax Matters -- Section 29 Credits."
Taking into account the Terra Acquisition, as of December 31, 1995 the
Company operated over 1,370 Antrim gas wells, or approximately 30% of all
producing gas wells in the Antrim formation, making the Company the largest
operator of gas wells in the Antrim formation. The Company is currently serving
as operator of projects involving the planned drilling of an additional 280
Antrim development wells by December 31, 1996. As of June 30, 1995, after giving
effect to the Terra Acquisition, estimated net proved reserves in the Company's
Antrim projects totaled 218.0 Bcf of natural gas (36.3 MMBoe). Estimated gross
gas production for the month of September 1995 from over 2,500 producing Antrim
gas wells in which the Company has an interest averaged 215.0 MMcf of natural
gas per day, of which the Company's net share was 42.8 MMcf per day. The Company
also has a sizeable inventory of unproved acreage in the Antrim producing trend
and management believes that a number of its wells, including certain of those
acquired in the Terra Acquisition, have substantial potential for improved
recovery. The Company estimates that capital expenditures for 1995 relating to
its Antrim interests totalled approximately $15.3 million for its share of the
costs of drilling 328 development wells, including non-operated wells, and
construction of flowlines and production facilities. The Company expects to make
capital expenditures totaling $16.2 million in 1996 for its share of the costs
of drilling approximately 300 Antrim development wells and constructing
flowlines and facilities to serve the new wells.
OTHER MICHIGAN
The Company discovered the Kalkaska 21 Field in 1971 and commenced
production from the first of 14 wells in 1972. The Company owns a 100% working
interest in and operates this field. As of June 30, 1995, net proved reserves in
the field totaled 6.3 Bcf of natural gas (1.1 MMBoe) and 0.5 MMBbls of oil.
Estimated gross production for the month of September 1995 from nine producing
wells averaged 372 Bopd and 170.0 Mcf of natural gas per day, of which the
Company's net share was 324 Bopd and 149.0 Mcf of natural gas per day.
Horizontal wells and secondary recovery methods are being employed in the
project. The Company also operates two natural gas processing plants at the
field. No significant capital expenditures with respect to this field were made
in 1995. The Company expects to make capital expenditures totalling $600,000 to
drill two development wells in this field in 1996.
As of June 30, 1995, other Michigan properties contained net proved
reserves of 14.2 Bcf of natural gas (2.4 MMBoe) and 0.7 MMBbls of oil. Estimated
net production for the month of September 1995 from other Michigan producing
wells was 8.6 MMcf of natural gas per day and 600 Bopd.
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<PAGE> 47
GULF COAST REGION
One of the Company's most significant natural gas discoveries in recent
years occurred in early 1994 with the successful drilling to a depth of 19,260
feet and completion of the UNOCAL Louisiana Furs C 16 exploratory well in the
Freshwater Bayou Field in Vermilion Parish, Louisiana. The discovery flowed
natural gas at a rate of 30.6 MMcf per day and 192 Bcpd. The Company has a 10%
working interest in the project, in which the other participants are Unocal
Corporation, as operator, The Louisiana Land and Exploration Company and the
Vincent Joseph Duncan Trust. In addition to the exploratory well, four
successful development wells have been drilled in 1994 and 1995. As of June 30,
1995, estimated gross proved natural gas reserves in the field totaled 355.2 Bcf
of natural gas, with net reserves to the Company of 29.4 Bcf of natural gas (4.9
MMBoe), and 3.0 MMBbls of condensate, with net reserves to the Company of 0.2
MMBbls of condensate. Estimated gross production for the month of September 1995
from three of the five wells averaged 133.0 MMcf per day, of which the Company's
net share was 11.0 MMcf per day. Production from the remaining two wells
commenced in October 1995. The Company estimates that capital expenditures for
1995 totalled approximately $4.1 million for its share of the costs of drilling,
completing and equipping development wells and expansion of natural gas
processing and production facilities. One exploratory well may be drilled in
1996 to complete evaluation of the acreage block. The Company expects that its
share of capital expenditures for such well, if drilled, and for other
operations in the field, will be $0.9 million in 1996.
The Company estimates that capital expenditures relating to other
activities in the Gulf Coast region for 1995 totalled approximately $6.2
million. The Company expects that capital expenditures for other operations in
the region will be $3.4 million in 1996.
GULF OF MEXICO
The Company has been active in the Gulf of Mexico since 1970 and currently
holds working interests varying from 10.0% to 37.5% in six producing blocks and
17 undeveloped blocks in the Gulf, including those referred to in the following
paragraph. The Company does not operate in the Gulf of Mexico. Operators of the
Company's blocks include The Louisiana Land and Exploration Company, Oryx Energy
Company, Pogo Producing Company, Vastar Resources, Inc. and Apache Corporation.
As of June 30, 1995, estimated gross proved reserves in the Company's producing
blocks totaled 18.4 Bcf of natural gas and 1.5 MMBbls of oil, with respective
net reserves to the Company of 3.8 Bcf (0.6 MMBoe) and 0.2 MMBbls. Estimated
gross production for the month of September 1995 from the six producing blocks
averaged 36.8 MMcf gas per day and 2,195 Bopd, of which the Company's net share
was 8.7 MMcf per day and 335 Bopd.
The Company's interests in the Gulf of Mexico include a recently completed
successful development well on Galveston Block 313, which as of early September
1995 was flowing 15.3 MMcf of gas per day and 313 Bcpd. The Company's working
interest in Galveston 313 is 37.5%. The Company participated in both the March
1994, the March 1995 and the September 1995 outer continental shelf federal
offshore sales covering the central Gulf of Mexico, offshore Louisiana.
Successful bids were filed on Vermilion Block 335 and Vermilion Block 346 with
Pogo Producing Company as operator (with the Company's working interest being
25% and 33.33%, respectively), Ship Shoal Block 367 with Vastar Resources, Inc.,
as operator (with the Company's working interest being 10%) and West Cameron
Block 567 and Galveston Block 331 with Apache Corporation as operator (with the
Company's working interest being 25% and 33.3%, respectively). Ship Shoal Block
367 is located southwest of the Ship Shoal Block 349 subsalt discovery recently
made by Phillips Petroleum Corporation. The Company will participate with its
partners in acquiring and interpreting 3-D seismic data in anticipation of
drilling a subsalt well on the block in 1996 or 1997. The Company has an
interest in three other blocks in the Ship Shoal area surrounding the subsalt
discovery. Plans are underway to evaluate the subsalt potential of each of these
blocks. The Company estimates that capital expenditures for 1995 totalled
approximately $5.3 million principally for its share of the costs of lease and
seismic acquisition programs and the drilling of three wells in the Gulf of
Mexico. The Company expects to make capital expenditures of up to $8.2 million
in 1996 for its share of the costs of drilling at least three exploratory wells
and one development well in the Gulf.
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<PAGE> 48
OTHER
The Company is a member of two consortia which have acquired an aggregate
of 38,200 acres in the Lodgepole play, an oil project, in the Williston Basin in
North Dakota, of which the Company's net share is an aggregate of 7,800 acres.
One of the consortia has acquired one 3-D seismic survey of 30 square miles
relating to this acreage, and a second 3-D seismic survey is planned.
The Company also has interests in producing, undeveloped and unproved
properties in several other areas in the U.S.
DESCRIPTION OF NON-U.S. OPERATIONS
SOUTH AMERICA
Republic of Ecuador ("Ecuador"). A consortium in which the Company has a
14% working interest was awarded the Oriente Block 16 concession in 1986. The
consortium later acquired, pursuant to special service contracts, development
rights for the Tivacuno Field located north of Block 16 and for the Capiron
Field which has been unitized with the Bogi Field located in Block 16. The other
members of the consortium include Maxus Ecuador, Inc., Overseas Petroleum
Investment Corp. (the Taiwanese state oil company), Murphy Oil Company, Ltd.,
and Canam Offshore Limited. The project is operated by Maxus Energy Corporation,
a recently acquired subsidiary of YPF Sociedad Anonima.
By the end of 1989, the consortium had acquired, processed and interpreted
over 2,500 kilometers of seismic data, leading to the drilling of eight
exploratory wells. Of these eight wells, seven were commercial discoveries. The
consortium prepared a development plan, approved by the Ecuadorian Minister of
Energy and Mines in 1991, covering five fields. Implementation of the plan
commenced in 1992 and development thereunder continues to proceed. Production
commenced in the Tivacuno Field in May 1994, in the Bogi-Capiron Field in June
1994 and in the Amo Field in December 1994. Production facilities, an oil
pipeline and roads have been completed, resulting in oil being delivered through
blending facilities at Shushufindi for transport via the Trans-Andean pipeline
to the Pacific Ocean for export.
As of June 30, 1995, estimated gross proved reserves in Block 16 and the
Tivacuno and Capiron Fields totaled 152.6 MMBbls of oil, with net reserves to
the Company of 16.7 MMBbls. Estimated gross production for the month of
September 1995 from 16 producing wells averaged 31,201 Bopd, of which the
Company's net share was 3,187 Bopd. The Company estimates that capital
expenditures for 1995 totalled approximately $15.6 million for its share of the
costs of drilling 12 development wells and constructing roads, flowlines and
certain production facilities. The Company expects to make capital expenditures
totaling $12.7 million in 1996 for its share of the costs relating to the
planned drilling of 10 development wells and the construction of additional
facilities and flowlines to serve the new wells.
The Block 16 project is located in a tropical rain forest environment.
Extensive environmental impact assessments have been completed and the
development plan has been designed to minimize impacts to the forest. The plan
provides for controlled access to the development area, provides for strict
levels of compliance and is designed to produce minimal disruption within the
project area.
Production in Block 16 and related fields is currently curtailed due to a
limitation in the capacity of the Trans-Andean pipeline to 345,000 Bopd, of
which Block 16's share as of September 30, 1995 was 33,000 Bopd. The Ecuadorian
government has solicited bids for expansion of pipeline capacity to 460,000 Bopd
but has not to date awarded a contract for such expansion. Such expansion, if
undertaken, is expected to be completed no earlier than 1998. The reserves in
the fields in the southern end of the block, including the Iro, Diami and Ginta
Fields, have not yet been officially declared part of the national petroleum
reserve by the Ecuadorian Oil Ministry. Receipt of such declaration would give
the Block 16 consortium a larger pro-rated share of Trans-Andean pipeline
capacity. However, the Company can give no assurance that pipeline curtailment
will not limit production in Block 16 for the foreseeable future.
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<PAGE> 49
With lower worldwide oil prices and increases in total project costs
reducing the overall economic benefit of Block 16 and related fields to the
Ecuadorian government, the Ministry of Energy and Mines in Ecuador has notified
the members of the consortium with interests in these fields that they should
investigate alternatives for improving project economics to the Ecuadorian
government, including the renegotiation of the service contract governing the
Company's interest in these fields. The Ecuadorian government has significant
leverage to force changes due to its broad governmental and regulatory powers.
Discussions with the Ecuadorian government concerning various alternatives began
in September 1995 and will likely continue for at least the next several months.
See "Risk Factors -- Risk of Ecuador Contract Renegotiation."
Republic of Venezuela ("Venezuela"). A consortium in which the Company is a
member was awarded the Colon Unit in Venezuela's Marginal Fields Reactivation
Program in 1994. The Company has a 29.17% working interest in the project, in
which the other participants are Tecpetrol International, Inc., as operator,
Wascana de Venezuela C.A. and Corexland B.V. On May 1, 1995, the consortium
assumed responsibility for the unit. As of June 30, 1995, estimated gross proved
reserves in the unit totaled 86.7 MMBbls of oil, with net reserves to the
Company of 11.3 MMBbls. Estimated gross production during the month of September
1995 from 50 producing wells averaged 3,748 Bopd, of which the Company's net
share was 479 Bopd.
The operating services agreement among the consortium and Maraven commits
the consortium to make capital and operating expenditures of $160.0 million over
three years commencing in May 1995. The Company's share of costs relating to the
project over this period is estimated to be approximately $47.0 million ($38.0
million for capital expenditures and $9.0 million for operating expenditures).
The Company estimates that capital expenditures for 1995 totalled approximately
$12.4 million for its share of the costs of production refitting, reworks and
drilling 11 development wells. The Company expects to make capital expenditures
totaling $18.7 million in 1996 for its share of the costs of drilling nine
development wells and three exploratory wells, workovers and repair of existing
wells and facilities and both conventional and 3-D seismic surveys.
Republic of Colombia ("Colombia"). In June 1994, the Company acquired from
Sun Company, Inc. all the capital stock of Sun Colombia, whose sole asset is a
33.33% working interest in the Espinal Block located in Colombia's Upper
Magdalena Valley. LASMO Oil (Colombia) Limited ("LASMO") is the operator of and
has the remaining working interest in this project. At the time of the Company's
acquisition of Sun Colombia, production from the block was 4,000 Bopd (gross)
from two wells in the Purificacion field. Subsequently, a third Purificacion
development well was drilled and placed on line to replace one of the two
producing wells. Estimated gross production for the month of September 1995
averaged 5,815 Bopd of which the Company's share was 675 Bopd. In addition to
these two producing wells, the block contains three undeveloped discoveries.
Development plans call for bringing two of the undeveloped fields on the block,
Venganza and Revancha, into production by the second quarter of 1996. The last
undeveloped field, Chenche, is scheduled to be developed in 1997 or sometime
thereafter.
As of June 30, 1995, estimated gross proved reserves in the block totaled
44.7 MMBbls of oil, with net reserves to the Company of 5.6 MMBbls. The Company
estimates that capital expenditures for 1995 totalled approximately $3.9 million
for its share of the costs of drilling one development well in the Revancha
Field and constructing a pipeline, flowlines and production facilities. The
Company believes that the Espinal Block holds significant exploration potential.
LASMO and the Company have obtained a detailed seismic survey of the block which
the Company expects will lead to the drilling of three exploratory wells in
1996. Costs to the Company for 1996 capital expenditures relating to the block
are expected to total $9.1 million.
The association contract among LASMO, Sun Colombia and Empressa Colombiana
de Petroleos ("Ecopetrol"), the state oil company, provides for an option for
Ecopetrol to assume a 50% working interest in the development and production of
reserves on a field-by-field basis. Ecopetrol has exercised this option with
respect to the Purificacion Field, and accordingly the Company's working
interest in such field is expected to be 16.7% over the remaining life of the
contract.
The Company has been involved in Colombia since 1981 when it initiated
exploration efforts leading to discoveries in 1988 and 1989 on the Cano de la
Hermosa Block. As of June 30, 1995, estimated gross proved
45
<PAGE> 50
reserves in the block totalled 1.4 MMBbls of oil, with net reserves to the
Company of 1.1 MMBbls. Estimated gross production during the month of September
1995 from two wells on the block averaged 500 Bopd, of which the Company's net
share was 378 Bopd. The Company estimates capital expenditures of $0.3 million
in 1995 and $1.8 million in 1996 in connection with drilling one development
well.
AFRICA
Republic of the Congo (the "Congo"). As a result of the Walter Acquisition,
the Company acquired a 43.75% working interest in and became operator of the
Marine I Exploration Permit offshore the Congo in West Africa which includes the
Yombo Field. Other participants in the project are Nuevo Congo Company, Kuwait
Foreign Petroleum Exploration Co. K.S.C. and Hydro-Congo, the Congolese state
oil company, whose interest is being carried by the other participants. The
field has been producing since 1991. As of June 30, 1995, estimated gross proved
reserves totaled 50.0 MMBbls of oil, with net reserves to the Company of 15.9
MMBbls. Estimated gross production during the month of September 1995 from 20
producing wells averaged 10,860 Bopd, of which the Company's net share was 3,400
Bopd. Oil is produced into a self-contained floating production, storage and
off-loading vessel anchored on site. The vessel's storage capacity is over one
MMBbls of oil. The Company estimates that capital expenditures for 1995 totalled
approximately $7.1 million for its share of the costs of drilling two
development wells. The Company expects to make capital expenditures totaling
$11.6 million in 1996 for its share of costs relating to the planned drilling of
one exploratory well and nine development wells. Deeper objectives within the
Yombo Field and undrilled structures on additional acreage within the Marine I
Exploration Permit remain to be explored.
Republic of Equatorial Guinea ("Equatorial Guinea"). In 1991, the Company
joined in the development of the Alba Field, located within offshore Blocks
A-12, A-13, B-12 and B-13, Equatorial Guinea. The Company's initial working
interest in these blocks of 16.67% increased to 40.125% upon consummation of the
Walter Acquisition in February 1995. By virtue of the Walter Acquisition, the
Company became the operator of the project, the other participants in which
include Samedan of North America, Globex International, Axem Resources, Inc. and
Walter Oil & Gas Corporation. Production of condensate from the field commenced
in December 1991. As of June 30, 1995, estimated gross proved reserves in the
field totaled 25.2 MMBbls of condensate, with net reserves to the Company of 8.5
MMBbls, 9.4 MMBls (gross) of plant products, 3.0 MMBls net to the Company, and
31.3 Bcf of natural gas, 10.7 Bcf net to the Company. Estimated gross production
for the month of September 1995 from two producing wells averaged 6,226 Bcpd, of
which the Company's net share was 1,844 Bcpd.
The condensate is being recovered, processed and sold for export. The
residue gas is not currently being utilized due to the lack of a proximate
market. The participants in the block recently joined with the government of
Equatorial Guinea for the development of an LPG extraction plant which is
scheduled for completion in late 1996. The cost of the plant is projected to be
approximately $20 million, of which the Company's share is $8 million.
Production is expected to be approximately 2,500 Bbls per day of LPG and an
additional 400 Bcpd.
The Company, as operator, has acquired a 3-D seismic survey of both the
Alba Field and prospective acreage on the northern portion of the blocks. The
seismic program is designed to identify a suitable location for a committed
exploratory well and to study the Alba Field to determine the location of future
development wells. Recent activity by other operators on nearby blocks has
indicated exploration potential for the area.
The Company estimates that capital expenditures for 1995 totalled
approximately $5.9 million for its share of the costs of conducting the 3-D
seismic survey and construction of the LPG extraction plant. The Company expects
to make capital expenditures totaling $9.0 million in 1996 for its share of
costs relating to the planned drilling of two exploratory wells and completion
of the construction of the LPG extraction plant.
Republic of Tunisia ("Tunisia"). As a result of the Walter Acquisition, the
Company acquired a 100% working interest in and became the operator of the El
Franig concession. A shut-in gas discovery is located within the concession.
Testing of this well began in October 1995. No reserves have been attributed to
this
46
<PAGE> 51
project pending the outcome of testing. If such testing proves successful, CMS
Generation Co., or another CMS Energy affiliate, may become involved in the
project by providing gas transmission and electric generation facilities. The
Company estimates that capital expenditures for 1995 totalled approximately $1.5
million. If warranted by test results, the Company expects to make capital
expenditures totaling $3.0 million in 1996 for further development of the
discovery.
MIDDLE EAST
Republic of Yemen ("Yemen"). The Company, through its 50% ownership of
Comeco Petroleum, Inc., holds a 14.28% working interest in the East Shabwa Block
in Yemen. Complex Resources N.L. has an option exercisable by March 31, 1996 to
buy 17.5% of Comeco Petroleum, Inc.'s issued capital in the form of nonvoting
shares at a price currently estimated to be $4.5 million. Other participants in
the East Shabwa Block are Total Yemen, as operator, Unocal Yemen Limited, Kuwait
Foreign Petroleum Exploration Co. K.S.C. and Command Petroleum Holdings N.L. The
block contains three discoveries and a number of prospects and leads. A seismic
program was completed in 1994 with a view to moving forward with development. As
of June 30, 1995, estimated gross proved reserves in the block totaled 28.1
MMBbls of oil, with net reserves to the Company of 2.6 MMBbls.
The three discoveries in the East Shabwa Block are the Kharir, Atuf N.W.
and Wadi Taribah Fields. The discovery well of the Kharir Field, drilled in
1992, tested oil at a combined rate of 3,400 Bopd. Two appraisal wells have been
drilled on the Kharir structure and tested at rates up to 12,250 Bopd. The
discovery well of the Atuf N.W. #1 Field encountered high quality oil pays on a
separate structure and was cased for testing at a later date. The discovery well
of the Wadi Taribah Field, drilled in August 1995 tested oil at the rate of
1,459 Bopd. The East Shabwa Block's production is anticipated to commence in
mid-1997. Construction of production facilities, flowlines and pipelines is
scheduled to begin during the second half of 1996. The Company estimates that
capital expenditures for 1995 totalled approximately $3.5 million for its share
of the costs of drilling two exploratory wells and one development well and
constructing pipelines and production facilities. The Company expects to make
capital expenditures totaling $9.3 million in 1996 for its share of the costs
relating to the planned drilling of one exploratory well and one development
well and continuing with pipeline and facilities construction.
OTHER NON-U.S.
In May 1995, the Company sold its 10% working interest in the Black Stump,
Bodalla South and Kenmore producing licenses in Australia for approximately $2.2
million. The Company's interests in properties in New Zealand and Papua New
Guinea were sold in December 1995 for approximately $10.2 million and $4.3
million, respectively, in net proceeds (including adjustments). The Company had
working interests of less than 10% in each of the properties.
RESERVES
As of September 30, 1995 the Company had interests in producing wells
located in ten states and offshore the Gulf of Mexico in the U.S. and in six
foreign countries, with most of its estimated proved reserves of natural gas
located in three natural gas producing areas of the United States (northern
Michigan, the Gulf Coast region and the Gulf of Mexico) and most of its
estimated proved reserves of oil located in South America (Ecuador, Venezuela
and Colombia) and West Africa (the Congo and Equatorial Guinea). At June 30,
1995, the Company had estimated proved reserves of 68.9 MMBbls of oil and 298.1
Bcf of natural gas, or a total of 118.6 MMBoe.
47
<PAGE> 52
The following table sets forth the Company's net interest in estimated
quantities of developed and undeveloped proved oil and natural gas reserves at
June 30, 1995, after giving effect to the Terra Acquisition, as prepared by
Ryder Scott, independent petroleum reserve engineers for the Company.
<TABLE>
<CAPTION>
OIL AND CONDENSATE (MMBBLS)(1) NATURAL GAS (BCF) TOTAL (MMBOE)
------------------------------- ------------------------------- ------------------------------- PERCENT
DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED UNDEVELOPED TOTAL DEVELOPED
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
U.S............. 2.0 0.1 2.1 248.7 32.9 281.6 43.4 5.6 49.0 88.6%
South America... 13.9 20.8 34.7 -- -- -- 13.9 20.8 34.7 40.1
Africa/Middle
East.......... 18.0 12.0 30.0 -- 10.7 10.7 18.0 13.8 31.8 56.6
Other(2)........ 0.4 1.7 2.1 5.8 -- 5.8 1.4 1.7 3.1 45.2
---- ---- ---- ----- ---- ----- ---- ---- ----- ----
Total....... 34.3 34.6 68.9 254.5 43.6 298.1 76.7 41.9 118.6(3) 64.7%
==== ==== ==== ===== ==== ===== ==== ==== ===== ====
</TABLE>
- -------------------------
(1) Oil and condensate includes 0.2 MMBbls and 3.0 MMBbls, respectively, of U.S.
and non-U.S. NGLs.
(2) Consists of the Company's properties in New Zealand and Papua New Guinea
which were sold in December 1995.
(3) Based on current estimates, the Company expects proved reserves as of
December 31, 1995 to reflect decreases of 3.1 MMBoe due to the sale of the
Company's properties in New Zealand and Papua New Guinea and 4.3 MMBoe due
to production subsequent to June 30, 1995, partially offset by net
additions.
The Company retained Ryder Scott to prepare the above reserve estimates at
June 30, 1995. A letter from Ryder Scott relating to their reserve report, dated
October 2, 1995, is included as Appendix A hereto.
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 the
Company, may vary. In addition, results of drilling, testing and production
subsequent to the date of an estimate may justify revision of such estimates,
and such 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, the Company has
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 herein. The 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, 1995, the standardized
measure of discounted future net cash flows (in thousands) attributable to the
Company's estimated proved reserves at such date as prepared by the Company's
internal engineers.
<TABLE>
<CAPTION>
SOUTH AFRICA & TOTAL
U.S. AMERICA MIDDLE EAST(1) OTHER(2) WORLDWIDE
<S> <C> <C> <C> <C> <C>
Future cash flows............................ $577,369 $472,746 $414,517 $39,939 $1,504,571
Future production costs...................... 218,438 111,842 185,913 8,497 524,690
Future development costs..................... 10,496 59,794 25,564 6,451 102,305
-------- -------- -------- ------- ----------
Total costs............................ 228,934 171,636 211,477 14,948 626,995
Future net cash flows before taxes........... 348,435 301,110 203,040 24,991 877,576
Income tax expenses (benefit)................ (15,271) 56,230 86,304 5,145 132,408
-------- -------- -------- ------- ----------
Future net cash flows........................ 363,706 244,880 116,736 19,846 745,168
Discount to present value at 10% per
annum...................................... 110,328 74,849 41,197 9,817 236,191
-------- -------- -------- ------- ----------
Standardized measure of discounted future net
cash flows................................. $253,378 $170,031 $ 75,539 $10,029 $ 508,977
======== ======== ======== ======= ==========
</TABLE>
- -------------------------
(1) Includes the Company's equity interests in the East Shabwa Block in the
Republic of Yemen.
(2) Consists of the Company's properties in New Zealand and Papua New Guinea
which were sold in December 1995.
48
<PAGE> 53
The standardized measure of discounted future net cash flows from estimated
production of the Company's proved oil and gas reserves after income taxes 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, assumptions and estimates have been utilized, and
no assurance can be given that such assumptions and estimates will be indicative
of future economic conditions. The Company cautions against interpreting this
information as a forecast of future economic conditions or revenues. Future net
cash flows are determined by using estimated quantities of proved reserves and
the periods in which they are expected to be developed and produced based on
September 30, 1995 economic conditions. Estimated future production is priced at
September 30, 1995, except where fixed and determinable price escalations are
provided by contract. The resulting estimated future net cash flows are reduced
by estimated future costs to develop and produce the proved reserves based on
September 30, 1995 cost levels, but not for debt service and general and
administrative expenses.
The discounted estimated future net cash flows referred to in this
Prospectus should not be construed as the current market value of the estimated
oil and natural gas reserves attributable to the Company's properties. In
accordance with applicable requirements of the Commission, the discounted
estimated future net cash flows from proved reserves are generally based on
prices and costs as of the date of the estimate, whereas actual future prices
and costs may be materially higher or lower. 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 and changes in governmental
regulations or taxation. The timing of actual future net cash flows from proved
reserves, and actual discounted cash flow, will be affected by the timing of
both the production and the incurrence of expenses in connection with
development and production of oil and natural gas properties. In addition, the
calculation of the discounted estimated future net cash flows using a 10%
discount per annum as required by the Commission is not necessarily the most
appropriate discount factor based on interest rates in effect from time to time
and risks associated with the Company's reserves or the oil and natural gas
industry in general.
For additional information concerning reserves, the future net cash flows
and the standardized measure of discounted future net cash flows to be derived
from the Company's reserves calculated in accordance with the provisions of SFAS
No. 69, see "Risk Factors -- Uncertainty of Reserve Estimates" and Supplemental
Information -- Oil and Gas Producing Activities in the Consolidated Financial
Statements included elsewhere herein.
49
<PAGE> 54
WELLHEAD VOLUMES, PRICES AND PRODUCTION COSTS
The following table sets forth certain information regarding the Company's
net wellhead production volumes of 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, 1992,
1993 and 1994 and the nine-month periods ended September 30, 1994 and 1995 and
pro forma for the year ended December 31, 1994 and the nine months ended
September 30, 1995, giving effect to the Recent Acquisitions as if such
acquisitions had occurred on the first day of each such period.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
----------------------------- ---------------------------------------
PRO FORMA PRO FORMA
1994 1995 1995 1992 1993 1994 1994
<S> <C> <C> <C> <C> <C> <C> <C>
SALES VOLUME:
Oil and Condensate (MBbls):
U.S........................ 518 463 485 994 870 690 717
South America.............. 409 1,269 1,269 -- 192 720 720
Africa/Middle East......... 181 1,404 1,600 149 290 283 2,037
Other(1)................... 284 83 83 274 364 332 332
------ ------ ------- ------ ------ ------ -------
Total.................... 1,392 3,219 3,437 1,417 1,716 2,025 3,806
====== ====== ======= ====== ====== ====== =======
Natural Gas (MMcf):
U.S........................ 14,793 18,903 20,797 17,384 18,197 20,300 22,679
Other(1)................... 215 86 86 194 290 246 246
------ ------ ------- ------ ------ ------ -------
Total.................... 15,008 18,989 20,883 17,578 18,487 20,546 22,925
====== ====== ======= ====== ====== ====== =======
Natural Gas Liquids (MBbls):
U.S........................ 123 172 172 291 186 193 193
====== ====== ======= ====== ====== ====== =======
AVERAGE SALES PRICES:
Oil and Condensate (per Bbl):
U.S........................ $15.64 $16.63 $ 16.66 $19.25 $16.58 $15.22 $ 15.25
South America.............. 10.20 13.22 13.22 -- 9.46 10.72 10.72
Africa/Middle East......... 15.29 14.09 13.99 19.32 17.14 15.97 13.31
Other(1)................... 12.10 13.94 13.94 16.55 14.89 12.32 12.32
Composite(2)............. 13.32 14.04 14.02 18.85 15.52 13.30 13.12
Natural Gas (per Mcf):
U.S........................ $ 2.05 $ 1.73 $ 1.68 $ 1.97 $ 2.24 $ 1.95 $ 1.93
Other(1)................... 1.00 1.33 1.33 0.51 0.82 1.04 1.04
Composite(2)............. 2.11 1.88 1.82 1.89 2.17 2.05 2.02
Natural Gas Liquids (per Bbl):
U.S........................ $14.84 $14.57 $ 14.57 $16.55 $15.24 $14.90 $ 14.90
AVERAGE PRODUCTION COSTS (PER BOE):
U.S........................... $ 3.40 $ 2.58 $ 2.46 $ 2.83 $ 3.07 $ 3.29 $ 3.21
South America................. 3.85 4.97 4.97 -- 3.23 3.94 3.94
Africa/Middle East............ 7.51 4.73 4.49 6.66 4.00 6.03 4.20
Other(1)...................... 1.70 5.03 5.03 2.00 1.64 2.02 2.02
Composite................ 3.50 3.54 3.50 2.91 3.01 3.42 3.48
</TABLE>
- -------------------------
(1) Consists of the Company's properties in New Zealand which were sold in
December 1995.
(2) Adjusted to reflect amounts received or paid under futures contracts entered
into to hedge the price of production. See Note 12 to the Consolidated
Financial Statements of the Company included elsewhere in this Prospectus.
50
<PAGE> 55
ACREAGE
The following table sets forth the developed and undeveloped acreage in
which the Company holds a leasehold, mineral or other interest at September 30,
1995. Excluded is acreage in which the Company's 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>
U.S.:
Alabama....................... 320 2 1,065 133 1,385 135
Indiana....................... -- -- 38,444 3,844 38,444 3,844
Louisiana..................... 14,326 1,476 1,647 1,358 15,973 2,834
Michigan...................... 199,214 71,348 549,160 191,714 748,374 263,062
Mississippi................... 5,765 622 1,185 296 6,950 918
Montana....................... 680 138 -- -- 680 138
New Mexico.................... 597 14 280 240 877 254
North Dakota.................. 640 27 45,872 13,079 46,512 13,106
Offshore Gulf of Mexico....... 34,046 8,305 97,034 24,627 131,080 32,932
Ohio.......................... -- -- 17,864 4,685 17,864 4,685
Oklahoma...................... 22,983 4,239 1,283 1,120 24,266 5,359
Texas......................... 24,456 2,627 19,337 5,033 43,793 7,660
Wyoming....................... 1,025 11 -- -- 1,025 11
------- ------- --------- --------- --------- ---------
Total U.S................ 304,052 88,809 773,171 246,129 1,077,223 334,938
NON-U.S.:
Colombia...................... 3,396 3,396 255,908 85,217 259,304 88,613
Congo......................... 2,000 917 41,196 17,981 43,196 18,898
Ecuador....................... 19,500 2,730 474,500 66,430 494,000 69,160
Equatorial Guinea............. 26,651 10,694 283,981 113,947 310,632 124,641
New Zealand*.................. 17,139 1,390 7,413 602 24,552 1,992
Papua New Guinea*............. -- -- 903,138 63,220 903,138 63,220
Tunisia....................... -- -- 135,782 67,891 135,782 67,891
Venezuela..................... 13,120 3,827 789,171 230,175 802,291 234,002
Yemen......................... -- -- 2,813,279 401,897 2,813,279 401,897
------- ------- --------- --------- --------- ---------
Total Non-U.S.............. 81,806 22,954 5,704,368 1,047,360 5,786,172 1,070,314
Total.................... 385,858 111,763 6,477,539 1,293,489 6,863,395 1,405,252
======= ======= ========= ========= ========= =========
</TABLE>
- -------------------------
* The Company's properties in these countries were sold in December 1995.
51
<PAGE> 56
PRODUCING WELL SUMMARY
The following table sets forth the number of producing oil and natural gas
wells in which the Company has ownership interests at September 30, 1995 in
gross and net producing oil and natural gas wells:
<TABLE>
<CAPTION>
OIL GAS TOTAL
------------- -------------- --------------
GROSS NET GROSS NET GROSS NET
<S> <C> <C> <C> <C> <C> <C>
U.S.:
Michigan Antrim................................... -- -- 2,092 412.8 2,092 412.8
Michigan Other.................................... 91 36.3 26 7.9 117 44.2
Freshwater Bayou.................................. -- -- 5 0.5 5 0.5
Offshore Gulf of Mexico........................... 23 2.9 38 5.3 61 8.2
All Other U.S..................................... 68 7.0 96 14.3 164 21.3
NON-U.S.:
South America
Ecuador........................................ 35 3.6 -- -- 35 3.6
Venezuela(1)................................... 73 9.7 -- -- 73 9.7
Colombia....................................... 6 2.7 -- -- 6 2.7
Africa/Middle East
Congo.......................................... 20 6.3 -- -- 20 6.3
Equatorial Guinea.............................. 2 0.6 -- -- 2 0.6
Tunisia........................................ -- -- -- -- -- --
Yemen.......................................... 5 0.4 -- -- 5 0.4
Other
New Zealand(2)................................. 9 0.7 2 0.1 11 0.8
Papua New Guinea(2)............................ 5 0.1 -- -- 5 0.1
--- ---- ----- ----- ----- -----
Total.......................................... 337 70.3 2,259 440.9 2,596 511.2
=== ==== ===== ===== ===== =====
</TABLE>
- -------------------------
(1) The group in which the Company participates assumed control of operations in
May 1995.
(2) Properties in these countries were sold in December 1995.
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. Wells that are
completed in more than one producing horizon are counted as one well. Of the
gross wells reported above, two had multiple completions.
52
<PAGE> 57
DRILLING ACTIVITIES
During the years ended December 31, 1992, 1993 and 1994, and the nine
months ended September 30, 1995, the Company spent approximately $43.2 million,
$55.5 million, $54.0 million and $39.4 million, respectively, for exploratory
and development drilling. The Company drilled or participated in the drilling of
gross and net wells as set out in the table below for the periods indicated
(with the Company's participation in Antrim gas drilling shown separately):
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, NINE MONTHS
------------------------------------------------------ ENDED
SEPTEMBER 30,
1992 1993 1994 1995
--------------- --------------- -------------- --------------
GROSS NET GROSS NET GROSS NET GROSS NET
<S> <C> <C> <C> <C> <C> <C> <C> <C>
U.S.:
Development Wells Completed:
Gas........................ 10.0 2.12 3.0 0.67 5.0 0.84 6.0 1.21
Oil........................ 13.0 0.74 1.0 0.20 1.0 0.29 -- --
Dry........................ 4.0 0.72 1.0 0.12 -- -- 1.0 0.28
Exploratory Wells Completed:
Gas........................ 2.0 1.56 -- -- 5.0 1.86 2.0 1.17
Oil........................ 1.0 0.25 -- -- 2.0 0.56 -- --
Dry........................ 3.0 0.84 4.0 1.11 6.0 2.30 2.0 1.21
SOUTH AMERICA:
Development Wells Completed:
Oil........................ -- -- 6.0 0.84 10.0 1.42 7.0 0.98
AFRICA/MIDDLE EAST:
Development Wells Completed:
Gas........................ 1.0 0.16 -- -- -- -- -- --
Exploratory Wells Completed:
Gas........................ -- -- -- -- -- -- -- --
Oil........................ -- -- -- -- -- -- 1.0 0.14
Dry........................ 3.0 0.31 -- -- -- -- -- --
OTHER(1):
Development Wells Completed:
Gas........................ -- -- -- -- -- -- 1.0 0.08
Oil........................ 3.0 0.27 2.0 0.16 3.0 0.28 1.0 0.08
Dry........................ 1.0 0.10 -- -- 2.0 0.16 -- --
Exploratory Wells Completed:
Dry........................ -- -- 3.0 0.73 2.0 0.32 -- --
----- ----- ---- ----- ---- ---- ---- ----
Total................. 41.0 7.07 20.0 3.83 36.0 8.03 25.0 5.71
===== ===== ==== ===== ==== ==== ==== ====
MICHIGAN ANTRIM GAS WELLS(2):... 109.0 80.36 27.0 17.02 12.0 9.54 63.0 9.00
===== ===== ==== ===== ==== ==== ==== ====
</TABLE>
- -------------------------
(1) Includes the Company's properties in New Zealand and Papua New Guinea which
were sold in December 1995.
(2) Includes drilling of 59.0 gross (6.5 net) wells by Terra from August 1
through September 30, 1995.
Due to the success rates typically associated with drilling Antrim gas
wells, the table above sets forth separately the Company's participation in such
drilling activities. The success rate for these wells for each of the periods
represented in the table above was 100%. The Company also participated in other
wells through farmouts, acreage contributions and other nonpaying interests.
With the exception of Antrim gas wells, all of the Company's drilling
activities are conducted on a contract basis with independent drilling
contractors. Three drilling rigs were acquired by the Company in connection with
the Terra Acquisition and are used in drilling certain Antrim gas wells. The
Company owns no other material drilling equipment.
53
<PAGE> 58
Excluding the drilling of Antrim gas wells, at September 30, 1995, the
Company was participating in the drilling or completion of one gross (0.1 net)
well in the U.S., which was subsequently determined to be dry, two gross (0.47
net) wells in South America which will become productive when completed and one
gross (0.14 net) well in Yemen which was subsequently determined to be dry.
MARKETING
NATURAL GAS
Approximately 60.0% of the Company's natural gas production is sold to
various marketing companies on either the spot market or under short-term
contracts (one year or less) providing for variable or market sensitive pricing.
The balance of the Company's natural gas production is sold under long-term
contracts at fixed prices with periodic adjustments based on contract formulas,
principally to Consumers Power Company ("Consumers"), a local distribution
company which is an affiliate of the Company. During the first nine months of
1995, sales to Consumers accounted for approximately 14.7% of the Company's
consolidated revenues. See "Relationship and Certain Transactions with CMS
Energy -- Gas Sales Agreements." The Company does not believe the loss of any
purchaser would have a material adverse effect on its financial condition or
results of operations due to the likely availability of other purchasers for the
Company's production at comparable prices.
OIL
The Company markets its oil and condensate production from its Congo and
Equatorial Guinea properties under short-term contracts at market prices on a
cargo lot basis. The Company's oil production from its Ecuadorian and Colombian
properties is sold by the respective operators of such properties under
short-term contracts at market prices. The Company's oil production from its
Venezuelan project is marketed by Maraven. With the exception of pipeline
curtailment relating to Block 16 in Ecuador, see "Business and Properties --
Description of Non-U.S. Operations -- South America -- Republic of Ecuador," the
Company has not experienced any material inability to market its oil as a result
of limited access to transportation space.
HEDGING ARRANGEMENTS
The Company periodically enters into oil and natural gas price hedge
arrangements to mitigate its exposure to price fluctuations on the sale of oil
and natural gas. As of September 30, 1995, the Company had entered into gas
price collar contracts on 1.22 Bcf of gas for delivery through December 1995 at
prices ranging from $2.05 to $2.35 per MMBtu, an oil collar contract for
delivery through December 1995 of 1,000 Bopd with a floor of $18.00 per Bbl and
a ceiling of $19.95 per Bbl. In December 1995, the Company entered into gas and
oil swap contracts on a total of 7.4 Bcf of gas for delivery in the months of
January through May 1996 at prices ranging from $1.89 to $2.18 per MMBtu and on
21.7 MBbls of oil for delivery in each of the months of January, February and
March 1996 at a fixed price of $18.75 per Bbl. These contracts are accounted for
as hedges; accordingly, any changes in market value and gains or losses from
settlements are deferred and recognized at such time as the hedged transaction
is completed.
The Company has also hedged certain of its gas supply obligations to the
Midland Cogeneration Venture ("MCV") in the years 2001 through 2006 by entering
into an agreement with Louis Dreyfus Exchanges Ltd. on May 1, 1989 to purchase
the economic equivalent of 10,000 MMBtu per day at fixed, escalating prices
starting at $2.82 per MMBtu in 2001. The settlement periods are each one year
period ending December 31, 2001 through 2006 on 3.65 Bcf of natural gas. If the
"floating price," generally the then current Gulf Coast spot price, for a period
is higher than the "fixed price," the seller pays the Company the difference,
and if the fixed price for a period is higher than the floating price, the
Company pays the seller the difference. If a party's exposure at any time
exceeds $2.0 million, that party is required to obtain a letter of credit in
favor of the other
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party for the excess over $2.0 million, to a maximum of $10.0 million. At
September 30, 1995, neither party was required to obtain a letter of credit.
TITLE TO PROPERTIES
As is customary in the oil and natural gas industry, the Company makes only
a limited review of title to farmout acreage and to undeveloped U.S. oil and
natural gas leases upon execution of the contracts and leases. Prior to the
commencement of drilling operations, a thorough title examination is conducted
and curative work is performed with respect to significant defects. To the
extent title opinions or other investigations reflect title defects, the Company
or other operator of the project, rather than the seller of the undeveloped
property, is typically responsible to cure any such title defects at its
expense. If the Company or 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, the Company could suffer a loss of a portion of, or
its entire investment in, the property. The Company has obtained title opinions
on substantially all of its domestic producing properties and believes that it
has satisfactory title to such properties in accordance with standards generally
accepted in the oil and natural gas industry. The Company's oil and natural gas
properties are subject to customary royalty interests, liens for current taxes
and other burdens which the Company believes do not materially interfere with
the use of or affect the value of such properties. In the case of the Company's
non-U.S. interests, the host government generally owns the minerals. The Company
contracts with the government to explore, develop and produce oil and natural
gas, and title opinions are not considered necessary.
COMPETITION
The oil and natural gas industry is highly competitive. The Company faces
competition in all aspects of its business, including acquiring reserves,
leases, licenses and concessions, obtaining the equipment and labor needed to
conduct its operations and marketing its oil and natural gas. The Company's
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. The Company believes that its competitive position
is also affected by its geological and geophysical capabilities, the
qualification of certain of its U.S. natural gas interests for tax credits and
ready access to markets for production. Many competitors have financial and
other resources substantially greater than those available to the Company and,
accordingly, may be better positioned to acquire and exploit prospects, hire
personnel and market production. In addition, many of the Company's 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 the Company's oil and natural gas production and which
are beyond the control of the Company. Moreover, many competitors have
established strategic long-term positions and maintain strong governmental
relationships in countries in which the Company may seek entry. The Company
expects this high degree of competition to continue.
GOVERNMENTAL REGULATION
The Company's 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 the Company conducts business, including regulation
relating to such matters 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 such regulations could
result in substantial liabilities to third parties or governmental entities, the
payment of which could have a material adverse effect on the Company's financial
condition or results of operations. The Company believes that it is in
substantial compliance with such laws and regulations. However, there is no
assurance that laws or regulations enacted in the future or the modification of
existing laws or regulations will not adversely affect the Company's exploration
for or development, production or marketing of oil or natural gas. In addition,
non-U.S. 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 and other
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foreign laws or policies 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 non-U.S. operations, the Company 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. The Company may also
be hindered or prevented from enforcing its rights with respect to a
governmental instrumentality because of the doctrine of sovereign immunity.
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 such laws and
regulations are frequently expanded, amended or reinterpreted, the Company is
unable to predict the future cost or impact of complying with such regulations.
Exploration and Production. Exploration and production operations of the
Company are subject to various types of regulation at the federal, state and
local levels. Such regulation includes requiring permits for the drilling of
wells, maintaining bonding requirements in order to drill or operate wells, and
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. The Company's 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 the Company can produce from its wells, and to
limit the number of wells or the locations at which the Company can drill.
A portion of the Company's oil and natural gas leases are granted by the
federal government and administered by the Bureau of Land Management (the "BLM")
and the Minerals Management Service (the "MMS"), both of which are federal
agencies. Such 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). For
offshore operations, lessees must obtain MMS approval for exploration plans and
development and production plans prior to the commencement of such operations.
In addition to permits required from other agencies (such as the Coast Guard,
Army Corps of Engineers and Environmental Protection Agency), lessees must
obtain a permit from the BLM or the MMS prior to the commencement of drilling.
The Mineral Lands Leasing Act of 1920 (the "MLLA") places limitations on
the number of acres under federal leases that the Company may own in any one
state. While subject to this law, the Company does not have a substantial
federal lease acreage position in any state or in the aggregate.
Natural Gas Marketing and Transportation. Federal legislation and
regulatory controls in the U.S. have historically affected the price of the
natural gas produced by the Company and the manner in which such production is
marketed. The Federal Energy Regulatory Commission (the "FERC") regulates the
interstate transportation and sale for resale of natural gas by interstate and
intrastate pipelines. The FERC previously regulated the maximum selling prices
of certain categories of gas sold in "first sales" in interstate and intrastate
commerce under the Natural Gas Policy Act. Effective January 1, 1993, however,
the Natural Gas Wellhead Decontrol Act (the "Decontrol Act") deregulated natural
gas prices for all "first sales" of natural gas, which includes all sales by the
Company of its own production. As a result, all sales of the Company's
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domestically produced natural gas may be sold at market prices, unless otherwise
committed by contract. The FERC's jurisdiction over natural gas transportation
and gas sales other than first sales was unaffected by the Decontrol Act.
The Company's natural gas sales are affected by the regulation of
intrastate and interstate gas transportation. 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 Nos. 636, 636-A and 636-B ("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 obtain transportation of such
gas on a non-discriminatory basis. The effect of Order No. 636 has been to
enable the Company to market its natural gas production to a wider variety of
potential purchasers. The Company believes that these changes generally have
improved the Company's access to transportation and have enhanced the
marketability of its natural gas production. To date, Order No. 636 has not had
any material adverse effect on the Company's ability to market and transport its
natural gas production. However, the Company cannot predict what new regulations
may be adopted by the FERC and other regulatory authorities, or what effect
subsequent regulations may have on the Company's activities. Further, even
though the implementation of Order No. 636 on individual interstate pipelines is
essentially complete, many of the individual pipeline restructuring proceedings,
as well as Order No. 636 itself and the regulations promulgated thereunder, are
subject to pending appellate review and could possibly be changed as a result of
future court orders.
In recent years the FERC also has pursued a number of other important
policy initiatives which could significantly affect the marketing of natural
gas. Some of the more notable of these regulatory initiatives include (i) a
series of orders in individual pipeline proceedings articulating a policy of
generally approving the voluntary divestiture of interstate natural gas
pipeline-owned gathering facilities to pipeline affiliates, (ii) the completion
of a rulemaking involving the regulation of interstate natural gas pipelines
with marketing affiliates under Order No. 497, (iii) FERC's on-going efforts to
promulgate standards for pipeline electronic bulletin boards and electronic data
exchange, (iv) a generic inquiry into the pricing of interstate pipeline
capacity, (v) efforts to refine FERC's regulations controlling the operation of
the secondary market for released interstate natural gas pipeline capacity, and
(vi) a policy statement regarding market-based rates and other non-cost-based
rates for interstate pipeline transmission and storage capacity. Several of
these initiatives are intended to enhance competition in natural gas markets.
While any resulting FERC action would affect the Company only indirectly, the
ongoing, or, in some instances, preliminary evolving nature of these regulatory
initiatives makes it impossible at this time to predict their ultimate impact
upon the Company's activities.
In Michigan, the pricing provisions of natural gas purchase contracts with
utilities are subject to modification by regulatory authorities. A Michigan
Court of Appeals opinion recently affirmed that the Michigan Public Service
Commission ("MPSC") has the statutory authority under certain circumstances to
approve and change the pricing provisions in gas purchase contracts between
common purchasers, principally natural gas utilities such as Consumers, and
Michigan natural gas producers such as the Company upon the petition of the
common purchaser. The court found that producers in Michigan are charged with
the knowledge that the MPSC has the power to inspect and interpret the price
aspect of natural gas purchase contracts entered into by common purchasers and
to determine the reasonableness of such prices.
NON-U.S. REGULATION
The Company's non-U.S. exploration, development and production of oil and
natural gas are also subject to various types of governmental regulation. In
addition, non-U.S. projects in which the Company has an interest generally
involve complex contractual relationships with the host government which often
contain extensive provisions governing the operation of such projects. The
matters addressed by these regulations and
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contractual provisions 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 the Company operates affect nearly all
of the operations of the Company. These laws and regulations set various
standards regulating certain aspects of health and environmental quality,
provide for penalties and other liabilities for the violation of such standards
and establish, in certain circumstances, obligations to remediate current and
former facilities and off-site locations.
The Company believes that its 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 its business. However,
significant liability could be imposed on the Company for damages, clean-up
costs and/or penalties in the event of certain discharges into the environment,
environmental damage caused by previous owners of property purchased by the
Company or non-compliance with environmental laws or regulations. Such liability
could have a material adverse effect on the Company's financial condition or
results of operations. Moreover, the Company 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 the
regulatory agencies, could in the future require material expenditures by the
Company for the installation and operation of systems and equipment for remedial
measures, all of which could have a material adverse effect on the Company's
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 such legislation were to be enacted, it could have a significant impact on
the operating costs of the Company, 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 certain states, and these various
initiatives could have a similar impact on the Company. Finally, environmental
regulations are becoming increasingly stringent and more vigorously enforced in
other countries where the Company operates, raising similar concerns.
The United States Oil Pollution Act of 1990 (the "OPA") and regulations
promulgated thereunder 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, the
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. The OPA 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. On August 25, 1993, the MMS published an advance notice of
its intention to prepare a rule under the OPA that would 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 the Company owns or
operates many oil and natural gas facilities that could affect "waters of the
United States," the Company could become subject to the financial responsibility
rule if it is proposed as described. Under the 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. The Company cannot predict the final form of the financial
responsibility rule that may be proposed by the MMS under the OPA or whether
pending legislation may affect it, but if such a rule
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were adopted and were to apply to the Company, no assurance can be given as to
the Company's ability to comply with such rule or the costs of such compliance.
In addition, 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. The Company believes that it has adequate procedures that
address containment of potential discharges and spill contingency planning. The
U.S. Environmental Protection Agency 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.
The Comprehensive Environmental Response, Compensation and Liability Act,
as amended ("CERCLA"), 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
CERCLA, such 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. The Company is engaged in a number of site
remediation activities in Michigan. The Company believes that neither the costs
nor any liabilities incurred in such activities would have a material adverse
effect on its financial condition or results of operations.
The Company's non-U.S. 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., are viewed
by the Company as generally establishing standards comparable to those in the
U.S. In addition, in environmentally sensitive non-U.S. areas of operation, such
as the rain forest in Ecuador where the Company has substantial interests,
especially stringent measures and special provisions may be appropriate or
required. Most of the Company's non-U.S. projects involve complex contractual
relationships with the host government, and the sources of environmental
regulation applicable to the Company's non-U.S. 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.
Management believes that the Company is in substantial compliance with
applicable environmental laws and regulations and that continued compliance with
existing requirements will not have a material adverse effect on the Company.
OPERATIONAL RISKS AND INSURANCE
The oil and natural gas business involves certain operating hazards such as
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, any of which could
result in substantial losses to the Company. The Company's 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 operations. The
availability of a ready market for the Company's 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, the Company may be legally responsible for
environmental damages caused by previous owners of property purchased or leased
by
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the Company. As a result, the Company 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 the Company's properties.
In accordance with customary industry practices, the Company maintains
insurance against some, but not all, of such risks and losses. The Company
currently maintains coverage with respect to general liability, commercial
property, workers' compensation, automotive liability and electronic equipment
and, with respect to certain properties, political risk from OPIC. The Company
also maintains an umbrella liability policy and operator's extra expense
policies. All such insurance is subject to normal deductible levels.
Among other things, coverage is not obtainable for certain 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 the
Company's financial condition or results of operation. Moreover, there can be no
assurance that the Company's insurance will be adequate to cover any losses or
exposure to liability or that the Company will be able to maintain adequate
insurance in the future at rates it considers reasonable.
TAX MATTERS
DUAL CONSOLIDATED LOSSES
As a result of the Walter Acquisition and related transactions in February
1995, Walter became a wholly-owned subsidiary of CMS NOMECO. Among Walter's
consolidated assets at such time were certain assets located in the Congo
acquired from an affiliate of Amoco shortly prior to the Walter Acquisition. As
a result of certain agreements entered into by Walter in connection with the
acquisition of the Congolese assets, Walter agreed to become liable for tax
liabilities incurred as a result of the recapture of "dual consolidated losses"
utilized by Amoco for tax purposes in prior years, if a "triggering event" were
to occur with respect to such assets or with respect to the stock of Walter or
certain of its subsidiaries. As part of the Walter Acquisition, CMS Energy and
CMS NOMECO became jointly and severally liable for Walter's obligation to Amoco
and agreed to obtain the approval of Amoco prior to entering into transactions
which could constitute triggering events. It is currently estimated that the
additional tax liability that could be recaptured upon a triggering event would
be approximately $78.2 million, plus an interest factor thereon. CMS Energy has
subsequently agreed to indemnify CMS NOMECO (the "CMS Energy Indemnity") for any
liability relating to recapture of such dual consolidated losses if the
triggering event results from acts or omissions (i) of CMS Energy or any of its
subsidiaries (other than CMS NOMECO) which occur after the initial sale of the
Common Stock offered hereby; (ii) of CMS NOMECO if such acts or omissions are
approved by the Board of Directors of CMS NOMECO, which approval includes the
affirmative vote of a majority of the employees of CMS Energy or any of its
subsidiaries (other than CMS NOMECO) who serve on CMS NOMECO's Board of
Directors; or (iii) of any person if such acts or omissions occur prior to the
initial sale of the Common Stock offered hereby. Pursuant to the CMS Energy
Indemnity, CMS NOMECO has also agreed to indemnify CMS Energy for any such dual
consolidated loss tax liability if the triggering event results from acts or
omissions of CMS NOMECO on or after the initial sale of the Common Stock offered
hereby which have not been approved by the Board of Directors of CMS NOMECO in
the manner described in the preceding sentence.
Among the triggering events that could result in a recapture of these dual
consolidated losses would be a sale of the assets in question under certain
circumstances to an unrelated party. Another triggering event could be the
inability to continue to include Walter in the CMS Energy consolidated group for
federal income tax purposes. Such tax deconsolidation could occur if, for
instance, CMS NOMECO issued sufficient shares of its Common Stock to unrelated
parties so that CMS Energy and its affiliates no longer owned at least 80% of
CMS NOMECO's Common Stock. A tax deconsolidation could also occur if CMS Energy
reduced its holdings in CMS Enterprises, CMS Enterprises reduced its equity
interest in CMS NOMECO to an extent that CMS Enterprises no longer owned at
least 80% of the stock of CMS NOMECO, or another U.S. corporation acquired 80%
or more of CMS Energy's stock. CMS NOMECO has no plans, and has been advised
that CMS Energy has no plans, to effect any transaction in the foreseeable
future that would cause such a deconsolidation.
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In addition, at the time the Walter group acquired Congolese assets
formerly owned by Amoco's affiliate, the Nuevo group acquired from an affiliate
of Amoco certain other Congolese assets. As in the case of the transaction
involving Walter described above, subsequent triggering events with respect to
the assets acquired by the Nuevo group (or transactions with respect to the
stock of Nuevo or its affiliates) could result in recapture of dual consolidated
losses with respect to such assets. Under the arrangements negotiated among
Amoco, Walter and Nuevo prior to the Walter Acquisition, Walter and Nuevo would
be jointly and severally liable for up to $59.0 million in potential recapture
tax, plus an interest factor thereon, to Amoco if Amoco were required to
recapture its dual consolidated losses as a result of triggering events
occurring after the acquisitions described above. Although Walter and Nuevo have
agreed to indemnify each other for payments that are required to be made to
Amoco as a result of the other party's acts or omissions, if a triggering event
were to occur with respect to the assets acquired by the Nuevo group, Walter
could be required to make a payment to Amoco to indemnify Amoco for the
resulting tax recapture and would then have to recover such payment from Nuevo.
Because the net assets of Nuevo currently appear to be adequate to satisfy any
obligation which Nuevo may have with respect to a triggering event related to
assets acquired from Amoco's affiliate, CMS NOMECO believes that it is unlikely
that Walter would have to make a payment to satisfy its secondary liability,
although there can be no assurance that this will be the case. However, if
Walter were required to make such a payment, it would have a claim against
Nuevo, but would not be able to recover such payment from CMS Energy under the
CMS Energy Indemnity.
As a result of CMS NOMECO's November 1993 acquisition (the "Yemen
Acquisition") of its ownership interest in Pecten Yemen Company ("PYC"), a
predecessor of Comeco Petroleum, Inc., from a member of the Shell Petroleum Inc.
consolidated group (the "SPI Group"), CMS NOMECO agreed to become jointly and
severally liable for tax liabilities incurred by the SPI Group as a result of
the recapture of dual consolidated losses generated by PYC and utilized by the
SPI Group for tax purposes in prior years, if a "triggering event" were to occur
with respect to the stock or assets of PYC after such acquisition. It is
estimated that CMS NOMECO's potential joint and several liability for dual
consolidated loss recapture tax liability incurred by the SPI Group would be
approximately $15.8 million plus an interest factor thereon. CMS Energy has not
agreed to indemnify CMS NOMECO for this potential tax claim. However, if CMS
NOMECO were required to make a payment in satisfaction of such liability due to
a triggering event that it did not solely cause, it would have a claim against
the other stockholder of Comeco for at least the amount by which such payment
exceeded $7.9 million (plus an interest factor thereon).
SECTION 29 CREDITS
IRC Section 29 provides a "nonconventional fuels" tax credit for the
domestic production of oil, natural gas and synthetic fuels derived from
specified nonconventional sources and sold to unrelated persons from wells
drilled after December 31, 1979 and before January 1, 1993. In general, Section
29 Credits are not allowed for fuels sold after December 31, 2002. The amount of
Section 29 Credits is phased out as the average wellhead price of uncontrolled
domestic oil increases. The phaseout begins when this price, known as the
reference price, reaches $23.50 per Bbl (adjusted for inflation). Due to this
inflation adjustment, the phaseout for 1992, 1993 and 1994 began at $43.31,
$44.46 and $45.14, respectively. Since the reference price for those years was
$15.98, $14.24 and $13.19, respectively, no phaseout of the Credit occurred in
those years. The estimates of the Company's Section 29 Credits for the years
1995 through 2002 assume that the reference price will not exceed the point at
which the phaseout of such Credits begins.
The Section 29 Credits allowed for any taxable year may not exceed the
excess of the regular tax (reduced by certain credits, primarily the foreign tax
credit) over the tentative alternative minimum tax. To the extent that the
Section 29 Credits are limited by the tentative alternative minimum tax
limitation, they can be carried forward as a "minimum tax credit," which can be
used to reduce regular tax in subsequent years (but not below the tentative
alternative minimum tax for such subsequent year). Any Credits not used in the
taxable year (or allowed as a minimum tax credit in a future year) are
permanently lost.
In the years 1992, 1993 and 1994, the Company generated $4.4 million, $5.6
million and $8.5 million, respectively, in Section 29 Credits as a result of the
sale of natural gas produced from Antrim and, to a lesser extent, tight sands
wells. Because of the limitations described in the preceding paragraph,
approximately
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$27.2 million of Section 29 Credits have been carried forward as a minimum tax
credit carryover. For the year 1995, it is estimated that the Company and its
subsidiaries generated approximately $12.0 million of Section 29 Credits; for
the years 1996 through 2002, it is estimated that the Company and its
subsidiaries will generate Section 29 Credits averaging $14 million annually.
During the period of time it has produced natural gas qualifying for the
Section 29 Credit, the Company's income has been insufficient to use those
credits on a separate return basis. However, the limitations on Section 29
Credits are determined on the basis of a consolidated group's consolidated
regular tax and alternative minimum tax. Because the Company has been included
in the consolidated federal income tax return filed by CMS Energy, these credits
have either been used currently to reduce the tax liability of the CMS Energy
consolidated group or, as described above, have created a minimum tax credit
carryforward for use in future years. Under the Tax Sharing Agreement among CMS
Energy and its subsidiaries, the Company will be paid for those Section 29
Credits generated by the Company which are ultimately utilized (either as
current year Section 29 Credits or as alternative minimum tax credits) by the
CMS Energy consolidated group to reduce its consolidated regular tax liability.
These payments are made after the filing of the CMS Energy consolidated group
tax return in which such Section 29 Credit (or minimum tax credit carryforward)
is utilized.
Because the Company is expected for the foreseeable future to continue to
be included in the CMS Energy consolidated group, and because forecasts of the
CMS Energy consolidated group's tax position indicate that it is expected to
generate significant regular tax liabilities, it is expected that the Company
will be paid for all or substantially all of its approximately $12.0 million of
Section 29 Credits for the 1995 taxable year after its tax return is filed for
1995. Such forecasts also indicate that the CMS Energy consolidated group is
expected to generate sufficient regular tax liabilities for subsequent years so
that the Company will be paid for its Section 29 Credits for the 1996-2002 tax
years in the same year the returns for such years are filed. Also, such
forecasts indicate that the Company is expected to be paid over the next five
years for the approximately $27.2 million of accumulated minimum tax credit
carryforward allocated to the Company through December 31, 1994. Because CMS
Energy's consolidated tax position is subject to many uncertainties, some of
which are not within the control of the Company or the other members of the CMS
Energy consolidated group, there can be no assurance that this will be the case.
If the taxable income for the CMS Energy consolidated group were to be less than
projected, the payments for the Section 29 Credits would be deferred or
eliminated. The issuance of additional Common Stock of the Company, the sale of
shares of the Company's Common Stock by CMS Enterprises or the sale or
distribution of the shares of CMS Enterprises by CMS Energy in the future could
result in the Company being deconsolidated from CMS Energy for tax purposes,
which would eliminate the payments from the CMS consolidated group and restrict
the ability of the Company to realize the benefit of past Section 29 Credits and
those Section 29 Credits expected to be generated in the future. The Company has
no plans, and has been advised by CMS Energy that CMS Energy has no plans, to
effect any transaction in the foreseeable future that would cause such a
deconsolidation. See "Risk Factors -- Limitations on Availability of
Nonconventional Fuels Tax Credits."
NON-U.S. OPERATIONS
The Company operates its non-U.S. oil and natural gas business primarily
through 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.
Through December 31, 1994, the operations of these subsidiaries have resulted in
foreign source losses for U.S. income tax purposes of approximately $90.0
million. Through the date hereof, these losses have reduced the tax liability of
the CMS Energy consolidated group, without causing any related decrease in the
tax benefits to the other members of the consolidated group which would require
an adjustment of the amount otherwise payable to the Company under the Tax
Sharing Agreement. However, if previously generated or future foreign source
losses of the Company or its subsidiaries result in the loss of tax benefits to
which another member of the CMS Energy consolidated group would otherwise be
entitled, such as foreign tax credits, the amount of such lost tax benefits
would reduce the payments to the Company under the Tax Sharing Agreement or
require a payment by the Company for the benefit of such other member.
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The Company's operations that operate outside the U.S. may be subject to
foreign income taxes as well. Although 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, the
provisions of that credit as they apply to the Company's income operate in a
manner which may subject the Company's foreign income to tax at a combined
foreign and U.S. income tax rate significantly higher than the rate applicable
to corporations which conduct only U.S. operations.
In addition, the Company conducts certain of its operations outside the
U.S. through non-U.S. entities. The Company believes that the income from these
entities will not be subject to U.S. income taxes until repatriated to the U.S.
through dividends. Because the Company intends to cause its non-U.S. entities to
reinvest their profits in oil and natural gas operations outside the U.S., it
believes that the existing structure will postpone the payment of U.S. tax on
the income from these non-U.S. affiliates. However, because of the operation of
the foreign tax credit referred to above, the combined foreign and U.S. income
tax rate on the income generated by the foreign affiliates may exceed the
generally applicable tax rate on corporations which conduct only U.S.
operations. In addition, any losses that these entities (or the other foreign
entities owned by the Company) realize will not be currently deductible for U.S.
income tax purposes.
LEGAL PROCEEDINGS
On December 18, 1987, Tribal Drilling Company and certain other plaintiffs,
including J. Stuart Hunt, an affiliate of Tribal and a director of the Company,
filed a lawsuit in the 162nd Judicial District Court of Dallas County, Texas
(Tribal Drilling Company, et al. v. Heritage Resources, Inc., et al.) (the
"Dallas County Lawsuit"), seeking (i) a declaratory judgment against Heritage
Resources, Inc. ("Heritage") to the effect that Heritage was not qualified to
serve as the operator of Sections 21, 22 and 23 of the Crittendon Field in
Winkler County, Texas under the applicable Joint Operating Agreements, that
Heritage was removed as operator of such sections pursuant to a vote of
non-operator working interest owners and that Tribal was the duly elected
replacement operator and (ii) seeking damages against Heritage and certain
related parties in connection with Heritage's alleged failure to carry out its
obligations as operator of Sections 21, 22 and 23. The Company owns
non-operating working interests in Sections 21 and 23 of the Crittendon Field,
but has no interest in Section 22 of such field. The Company was not originally
a plaintiff in the Dallas County Lawsuit, but pursuant to a court order to join
all indispensable parties, on April 20, 1988, plaintiffs filed a Second Amended
Original Petition for Declaratory Relief which included the Company as one of
the plaintiffs.
On June 28, 1988, Heritage filed counterclaims against all of the
approximately 20 plaintiffs in the Dallas County Lawsuit, including the Company,
alleging intentional interference with business relations and deliberate and
malicious acts of interference with Heritage's actual and prospective business
relationships. Following several amendments to the counterclaims, on or about
August 25, 1995, Heritage, together with Wise Oil Ventures, Crittendon
Acquisition Company, Chase Avenue Corporation and Michael B. Wisenbaker,
individually, filed a Fifth Amended Counterclaim and Third Party Claim against
all plaintiffs, including the Company, which alleges various causes of action,
including without limitation claims for breach of contract, slander of title,
tortious interference with contract, tortious interference with business
relations, fraud, conspiracy and intentional infliction of emotional distress.
The Fifth Amended Counterclaim seeks relief of approximately $100 million in
actual damages, exemplary damages not to exceed $1 billion, attorneys' fees and
declaratory relief. Discovery in the Dallas County Lawsuit has commenced, and
all pleadings must be filed by March 29, 1996. Trial of the Dallas County
Lawsuit, including counterclaims, is currently scheduled for May 1996.
On December 18, 1987, Heritage and certain related parties filed two
separate lawsuits, since consolidated, styled Heritage Resources, Inc., et al.
v. Margaret Hunt Hill, et al., in the 109th Judicial District Court of Winkler
County, Texas (the "Winkler County Lawsuit"), against certain but not all
non-operator working interest owners of Sections 21 and 22 of the Crittendon
Field. In the Winkler County Lawsuit, the plaintiffs alleged in many respects
the same course of conduct that is the subject of the Dallas County Lawsuit,
including Heritage's counterclaims. The Company was not a party to the Winkler
County Lawsuit. On October 23, 1992, a jury in the Winkler County Lawsuit
returned a special verdict in favor of plaintiffs which found, among other
things, that the defendants (i) defrauded Heritage with respect to the
non-payment of
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costs of drilling the No. 3 well located in Section 22 (in which the Company has
no interest), (ii) tortiously interfered with Heritage's alleged agreements to
sell non-consent interests in such No. 3 well, (iii) tortiously interfered with
Heritage's alleged agreements to sell its interest in the Crittendon Field and
in the gas therefrom, and (iv) slandered Heritage's title to Sections 21 and 22.
The jury's verdict in the Winkler County Lawsuit was in an aggregate amount in
excess of $80 million plus attorneys' fees in excess of $20 million. The jury
also found that Heritage owned an interest in Sections 21 and 22 that was
sufficient for Heritage to serve as operator of those sections under the Joint
Operating Agreements attendant to those sections, and that Heritage had not
breached its duties under those Joint Operating Agreements. The jury found
against the defendants on their counterclaims. The defendants have appealed the
judgment in the Winkler County Lawsuit to the Texas Court of Appeals in El Paso,
Texas. However, certain defendants have dismissed their appeal pursuant to a
settlement with the plaintiffs that was arrived at pending the appeal. The
non-settling defendants continue to prosecute their appeal of the judgment in
the Winkler County Lawsuit. The Court of Appeals has indicated that it may rule
on the appeal by early 1996.
Although the Company was not a party to the Winkler County Lawsuit and did
not participate in that litigation, Heritage moved in the Dallas County Lawsuit
for judgment in its favor on all of the claims asserted against Heritage by
Tribal and other plaintiffs on grounds of res judicata and collateral estoppel,
i.e., that the judgment in the Winkler County Lawsuit bars the litigation of
plaintiffs' claims in the Dallas County Lawsuit. The Company opposed the
Heritage motion on the ground that the Company was not a party to the Winkler
County Lawsuit and should not be subject to any res judicata or collateral
estoppel effect from that lawsuit. Heritage's motion was denied in September
1995. The Company believes that the verdict rendered in the Winkler County
Lawsuit was based at least in part on several acts allegedly constituting
misconduct by the non-operator working interest owner defendants named therein
in asserting their alleged contractual rights relating to Section 22 (in which
the Company has no interest) and only to a lesser extent Section 21, in which
acts the Company did not actively participate (other than to vote for Heritage's
removal as operator of Section 21). Although Heritage alleges in the Dallas
County Lawsuit that the Company conspired with such non-operator working
interest owners and that such interest owners were acting as the Company's agent
with respect to all allegedly actionable conduct of all defendants, the Company
contests these allegations. The Company also believes that under the applicable
contracts it had the right to vote for the removal of Heritage as operator.
The Company believes that it has meritorious defenses to the counterclaims
in the Dallas County Lawsuit and intends to defend itself vigorously in such
lawsuit. Management believes it is unlikely that the ultimate outcome of this
matter will have a material adverse effect on the Company's financial condition
or results of operations. However, the outcome of a jury trial is difficult to
predict, and there can be no assurance that the resolution of Heritage's
counterclaims against the Company will not have such material adverse effect.
The Company is a named defendant in various other unrelated lawsuits and is
a party in governmental proceedings from time to time arising in the ordinary
course of business. While the outcome of such lawsuits and other proceedings
against the Company cannot be predicted with certainty, management does not
believe that these matters will have a material adverse effect on the financial
condition or results of operations of the Company.
OFFICES
The Company's principal executive offices are located at One Jackson
Square, Jackson, Michigan 49201 in approximately 29,000 square feet of leased
space. The Company also maintains owned or leased district offices in Traverse
City, Michigan; Houston, Texas; and Tulsa, Oklahoma; and non-U.S. offices in
Bogota, Colombia; Malabo, Equatorial Guinea; and Pointe Noire, the Congo. All
offices are managed by professional geologists or petroleum engineers.
Replacement of any of the Company's offices would not result in material
expenditures by the Company and alternative locations to its leased space are
anticipated to be readily available.
EMPLOYEES
As of September 30, 1995, the Company employed approximately 192 full-time
employees (including approximately 50 foreign nationals) and two part-time
employees.
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MANAGEMENT
EXECUTIVE OFFICERS AND DIRECTORS
The table below sets forth the names, ages (as of October 1, 1995) and
positions of the executive officers and directors of the Company. The Company's
directors are elected annually at the annual meeting of the stockholders and
hold office from the date of their election until the next succeeding annual
meeting or until their successors are elected and qualified, and until their
resignation or removal.
<TABLE>
<CAPTION>
NAME AGE POSITION(S)
<S> <C> <C>
Gordon L. Wright................... 53 President, Chief Executive Officer
and Director
William H. Stephens, III........... 46 Executive Vice President and
General Counsel
Robert A. Dunn..................... 48 Vice President Exploration
T. Rodney Dykes.................... 39 Vice President Operations -- Africa
and the Middle East
Paul E. Geiger..................... 53 Vice President, Secretary and
Treasurer
Richard L. Redmond, Jr. ........... 39 Vice President Operations --
Western Hemisphere/Southeast Asia
Victor J. Fryling.................. 47 Chairman of the Board
Richard J. Burgess................. 64 Vice Chairman of the Board
Frank M. Burke, Jr. ............... 55 Director
J. Stuart Hunt..................... 74 Director
Thomas K. Matthews, II............. 69 Director
William T. McCormick, Jr. ......... 51 Director
S. Kinnie Smith, Jr. .............. 64 Director
P. W. J. Wood...................... 70 Director
Alan M. Wright..................... 50 Director
</TABLE>
Set forth below is a brief description of the business experience of the
executive officers and directors of the Company.
Gordon L. Wright is President and Chief Executive Officer of the Company
and has been a director of the Company since December 1994. He received a B.S.
degree in Petroleum Engineering from West Virginia University in 1965. He is a
member of the Society of Petroleum Engineers and serves on the Board of
Directors and as Chairman of the Michigan Oil and Gas Association. Mr. Wright
has over 25 years of industry experience. From 1968 to 1970, he was employed as
a petroleum engineer by Gulf Oil Corporation. From 1970 to 1976, he held various
engineering positions with Consumers. From 1976 to 1978, he was employed as
Division Manager of Reef Petroleum Corporation. He became Manager of Operations
for the Company in March 1978 and became Vice President of Operations in July
1981. In October 1993, Mr. Wright was named Executive Vice President and Chief
Operating Officer and assumed his current position February 1, 1995.
William H. Stephens, III, is Executive Vice President and General Counsel
of the Company. 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 mid-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 General Attorney for the Company, 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 is Chairman of the Industry Economics and Taxation
Committee and a member of the Legal and Legislative Committee of the Michigan
Oil and Gas Association. He is former Chairman of the Oil and Gas Committee of
the Michigan Bar Association and a member of the Section of Natural Resources
Law of the American Bar Association.
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Robert A. Dunn is Vice President Exploration of the Company. He received
his B.A. degree in Geology from Western Michigan University in 1968 and his MBA
in Finance in 1995. In 1968 he joined the Geological Survey Division, Michigan
Department of Natural Resources, holding the position of Petroleum Geologist and
subsequently District Geologist. He joined Consumers in 1974 as an exploration
geologist, and in 1981 he was promoted by the Company to District Geologist for
Michigan. He became District Exploration Manager for the Company in 1982 and
assumed his current position effective October 1, 1984. He is a member of the
Michigan Oil and Gas Association, the Michigan Basin Geological Society and The
Geological Society of London, and is a Certified Petroleum Geologist with the
American Association of Petroleum Geologists.
T. Rodney Dykes is Vice President Operations -- Africa and Middle East of
the Company. He received a B.S. in Petroleum Engineering from Louisiana State
University in 1978. He was employed as a Petroleum Engineer with Kerr-McGee
Corporation from 1978 to 1980. From 1980 until 1994, when he joined the Company,
Mr. Dykes held a variety of positions with Maxus Energy Corporation (formerly
Diamond Shamrock Corporation), including resident Project Manager for Block 16
in Ecuador and Manager of Engineering and Development and International Drilling
Manager for a number of projects operated by Maxus in South America. He became
Manager of Operations -- Africa and Middle East when he joined the Company in
1994 and assumed his current position in October 1995. Mr. Dykes is a member of
the Society of Petroleum Engineers.
Paul E. Geiger is Vice President, Secretary and Treasurer of the Company.
He received a Bachelor of Science Degree with an Accounting major from Michigan
State University in 1964. His first 13 years of employment were with Consumers
where he worked in the Accounting, Internal Audit and Utility Rates Departments.
His last position with Consumers was Director of Corporate Accounting. Mr.
Geiger assumed his current position in March 1978. From 1971 to 1978, he served
on the Budget Committee of the American Gas Association and during the operating
year 1976 to 1977 served as Chairman of the Committee.
Richard L. Redmond, Jr., is Vice President Operations-Western Hemisphere
and Southeast Asia of the Company. He received a B.S. in Petroleum Engineering
from Marietta College in 1979. Prior to joining the Company he was employed by
Amoco Production Company from 1979 to 1989 where he held a variety of positions
including New Ventures Engineer for the Central South America-Far East Region,
Production Engineer for Galeota Point, Trinidad and Operations/Reservoir
Engineer for Europe/Latin America-Far East Region. From June 1989 through July
1991, he held various engineering positions with the Company. In January 1993,
he assumed the position of Manager of International Engineering & Production. He
became Manager of Operations-South America and Southeast Asia in August 1994 and
assumed his current position December 1, 1994. Mr. Redmond is a member of the
Society of Petroleum Engineers.
Victor J. Fryling is the Chairman of the Board of Directors of the Company
and has been a Director of the Company since 1987. Mr. Fryling has been Chief
Operating Officer of CMS Energy since January 1996 and President of CMS Energy
and Vice Chairman of Consumers since January 1992. 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.
Richard J. Burgess is Vice Chairman of the Board of Directors and has been
a director of the Company since 1968. From July 1981 to January 1995, he was
President and Chief Executive Officer of the Company.
Frank M. Burke, Jr., has been a director of the Company since 1992. Mr.
Burke has been Chief Executive Officer and Managing General Partner of Burke,
Mayborn Company, Ltd. since May 1984. He serves on the boards of directors of
several private companies.
J. Stuart Hunt has been a director of the Company since 1985. Mr. Hunt is
currently an investor, an oil and gas producer, a real estate owner, and a
director of Pogo Producing Company, an oil and gas exploration, development and
production company.
Thomas K. Matthews, II, has been a director of the Company since 1988. Mr.
Matthews is the retired Vice Chairman of the Board of First City National Bank
of Houston. He is a director of Holly Corporation, an oil refining company.
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William T. McCormick, Jr., has been a director of the Company since 1985.
From December 1985 to February 1992 he served as Chairman of the Board of
Directors of the Company. Mr. McCormick has been the Chairman of the Board of
Directors and Chief Executive Officer of CMS Energy since December 1987, and the
Chairman of the Board of Directors of Consumers since November 1985. He has been
Chairman of the Board of Directors of CMS Enterprises since May 1995. In
addition, Mr. McCormick serves on the boards of directors of First Chicago NBD
Corporation, Rockwell International Corporation and Schlumberger Ltd. He is also
a director of the American Gas Association, the Edison Electric Institute and
the National Petroleum Council.
S. Kinnie Smith, Jr., has been a director of the Company since 1987. Mr.
Smith has been the Vice Chairman of the Board of Directors of CMS Energy since
November 1992, Vice Chairman of the Board of Directors of Consumers since March
1987 and Vice Chairman of the Board of Directors of CMS Enterprises since
January 1989. Mr. Smith was also General Counsel of CMS Energy from November
1992 through December 1995. Mr. Smith serves on the boards of directors of
Clarcor Corporation, a filtration and consumer packaging products company, and
Michigan National Corporation.
P. W. J. Wood has been a director of the Company since 1987. Mr. Wood is
the President of Energy Exploration Management Company. He retired from Exxon
Co. U.S.A. on August 1, 1987, as Vice President of Exploration.
Alan M. Wright has been a director of the Company since 1993. Mr. Wright
has been Senior Vice President and Chief Financial Officer of CMS Energy since
January 1992, and in July 1994 was also elected Treasurer. He has been Senior
Vice President and Chief Financial Officer of Consumers since January 1992. In
addition, Mr. Wright has been Senior Vice President, Chief Financial Officer and
Treasurer of CMS Enterprises since October 1994.
COMMITTEES
The Board of Directors of the Company has an Audit Committee, an Executive
and Remuneration Committee and a Nominating Committee. The Audit Committee, of
which Messrs. Burke and Matthews constitute the present members, recommends the
employment of the Company's independent auditors and reviews with management and
the independent auditors the Company's financial statements, basic accounting
and financial policies and practices, audit scope and competency of control
personnel. The Executive and Remuneration Committee, which consists of Messrs.
Burgess, Fryling, McCormick and Wood, reviews and recommends to the Board of
Directors the executive organization of the Company, the compensation and
promotion of officers of the Company, the terms of any proposed employee benefit
arrangements and the making of awards under such arrangements. The Nominating
Committee, which consists of Messrs. McCormick, Fryling, Smith and Hunt, reviews
and recommends to the Board of Directors modifications to Director tenure policy
and Board size, compensation and composition, and aids in seeking out and
attracting qualified Board candidates.
COMPENSATION OF DIRECTORS
The annual retainer for outside directors of the Company is $20,000. In
addition, a fee of $1,500 per meeting is paid to Directors who are not officers
or employees of the Company or CMS Energy for attendance of board and committee
meetings.
CONSULTING AND NON-COMPETE AGREEMENT
The Company is a party to a consulting and non-compete agreement with
Richard J. Burgess, the Company's Vice Chairman of the Board and former
President and Chief Executive Officer, with an initial term ending in April 1996
and continuing month-to-month thereafter unless terminated by either party.
Under the agreement, Mr. Burgess has agreed to advise the Company on issues
pertaining to the Company's business and render other services as the Company
may from time to time require. The agreement also provides that Mr. Burgess will
not, directly or indirectly, engage in the business of the Company in any market
in which the Company currently competes. Mr. Burgess is entitled to a monthly
fee of $7,500 under the agreement and an
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additional $1,500 for each day in excess of five days devoted in any month to
services under the agreement. The monthly and daily fees shall be increased on
the same basis as any increase in the meeting fees paid to directors who are not
officers or employees of the Company.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
Mr. Burgess, a member of the Executive and Remuneration Committee of the
Company's Board of Directors, was the President and Chief Executive Officer of
the Company until March 1, 1995 and is currently Vice Chairman of the Board of
Directors of the Company. Mr. Burgess has a consulting and non-compete agreement
with the Company. See "-- Consulting and Non-Compete Agreement." Mr. Fryling,
also a member of the Executive and Remuneration Committee, is Chairman of the
Board of Directors of the Company.
EXECUTIVE COMPENSATION
Effective with the adoption of the Executive Incentive Compensation Plan
and the Long-Term Performance Incentive Plan, described below, compensation for
the executive officers will consist of a base salary (as shown in the Summary
Compensation Table below) which is intended to be competitive with amounts paid
to senior 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 the Company's success in
achieving stock appreciation and other performance goals. Annual incentive
(bonus) compensation payments are based on the Company's success in meeting
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 and profit sharing awards
under the Company's Performance Long-Term Incentive Plan as described below.
SUMMARY COMPENSATION TABLE
The following table sets forth a summary of compensation for services
rendered in all capacities to the Company for the chief executive officer and
the six other most highly compensated executive officers of the Company for the
years ended December 31, 1994 and 1995.
<TABLE>
<CAPTION>
ANNUAL COMPENSATION
------------------------ ALL OTHER
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($)(1) COMPENSATION($)(2)
<S> <C> <C> <C> <C>
Gordon L. Wright,................................ 1995 189,000 116,392
President and Chief Executive Officer(3) 1994 167,000 0 157,714
William H. Stephens, III,........................ 1995 152,400 93,837
Executive Vice President and General Counsel(4) 1994 141,400 0 134,347
Robert A. Dunn,.................................. 1995 135,000 81,971
Vice President, Exploration 1994 127,135 0 120,134
T. Rodney Dykes,................................. 1995 122,250 62,191
Vice President, Operations 1994 50,000 16,515 42,148
Africa and the Middle East(5)
Paul E. Geiger,.................................. 1995 134,400 81,795
Vice President, Secretary and Treasurer 1994 128,900 0 121,995
Richard L. Redmond, Jr........................... 1995 115,000 71,144
Vice President, Operations 1994 90,335 0 66,197
W. Hemisphere and Southeast Asia
Richard J. Burgess,.............................. 1995 37,170 95,339
Vice Chairman(6) 1994 223,020 0 221,002
</TABLE>
- -------------------------
(1) Amounts of bonus, if any, payable with respect to 1995 have not yet been
determined.
(2) Consists of Company-matched defined contribution plan contributions for the
years ended December 31, 1994 and 1995 (Mr. Wright, $7,256 and $7,566,
respectively; Mr. Stephens, $6,619 and $6,641, respectively; Mr. Dunn,
$6,166 and $5,726,
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respectively; Mr. Geiger, $6,238 and $5,734, respectively; Mr. Dykes,
$1,200 and $4,343, respectively; Mr. Redmond, $4,420 and $4,976,
respectively, and Mr. Burgess, $11,058 and $0, respectively); cash payments
under Plan A under the Employee Well Participation Program for the years
ended December 31, 1994 and 1995 (Mr. Wright, $7,823 and $8,143,
respectively; Mr. Stephens, $6,782 and $6,506, respectively; Mr. Dunn,
$6,141 and $5,680, respectively; Mr. Dykes, $0 and $0, respectively; Mr.
Geiger, $6,238 and $5,670, respectively; Mr. Redmond, $4,066 and $8,142,
respectively; and Mr. Burgess, $11,376 and $2,803, respectively); and the
value of overriding royalty interests received under Plan B under the
Employee Well Participation Program for the years ended December 31, 1994
and 1995 (Mr. Wright $142,635 and $100,683, respectively; Mr. Stephens,
$120,946 and $80,690, respectively; Mr. Dunn, $107,827 and $70,565,
respectively; Mr. Dykes, $40,948 and $57,848, respectively; Mr. Geiger,
$109,519 and $70,391, respectively; Mr. Redmond, $57,711 and $58,026,
respectively; and Mr. Burgess, $198,568 and $92,537, respectively). The
Employee Well Participation Program, which was recently terminated as to
any future wells drilled or acquired, was in effect from April 1, 1980 to
October 4, 1995. The Program consisted of Plan A and Plan B. Plan A covered
all executive, administrative and professional employees who were not then
covered by Plan B. Under Plan A, participating employees received monthly
cash incentive payments from the proceeds of a simulated 1.0% overriding
royalty in properties acquired or spudded after 1980, a simulated 0.5%
overriding royalty in properties acquired or spudded after 1985 and a
simulated 0.25% overriding royalty in properties acquired or spudded after
1990. Plan B covered key employees designated by the President of the
Company, from time to time. Certain current and former employees of the
Company continue to own interests acquired when they participated in the
plan as active employees. Plan B called for participating employees to
receive actual property assignments that divide a 1.75% overriding royalty
interest. The property assignments were allocated among the participants
based on their annualized salaries plus up to 50% of the maximum year-end
bonus the participants were qualified to receive. The Company reserves a
right of first refusal on participants' sales of their interests. Further,
participants have the option to require the Company to purchase their
interests. Because they receive actual property assignments, participants
are vested in the income stream for the life of the property, which may
last 20 years or more. The Company and each of Messrs. Wright, Stephens,
Dunn, Dykes and Redmond are expected to enter into royalty rights purchase
agreements providing that the Company will, effective on or about March 1,
1996, purchase all of the overriding royalty interests previously received
by such persons under Plan B. See "Relationship and Certain Transactions
with CMS Energy -- Certain Transactions -- Repurchase of Interests under
Employee Well Participation Program."
(3) Mr. Wright was Executive Vice President and Chief Operating Officer until
March 1, 1995.
(4) Mr. Stephens was Senior Vice President and General Counsel until March 1,
1995.
(5) Mr. Dykes has been employed by the Company since August 1, 1994 and became
Vice President, Operations, Africa and the Middle East, on October 1, 1995.
(6) Mr. Burgess was President and Chief Executive Officer prior to his
retirement on March 1, 1995.
EXECUTIVE INCENTIVE COMPENSATION PLAN
CMS NOMECO intends to establish the Executive Incentive Compensation Plan
which provides cash bonus payments for participants based on CMS NOMECO's
achievement of annual performance objectives established by the Executive and
Remuneration Committee of the Board with the following weighting: no less than
65% based on CMS NOMECO's earnings and finding costs and no more than 35% based
on CMS Energy's earnings. Because officers of other affiliates of CMS Energy
have similar incentives based at least in part on the earnings of CMS Energy,
such officers have incentives to identify opportunities for CMS NOMECO. The
participants in the Plan include the executive officers and other executives
designated by the President. The Plan has a threshold payout at 80% of goal and
a maximum payout at 120% of goal. The President is eligible for a standard
annual award of 55% of the median for his/her salary grade adjusted to reflect
his/her individual performance for the year. Dependent on their salary grade,
other participants are eligible for awards ranging from 15% to 45% of the median
for their particular salary grade.
LONG-TERM PERFORMANCE INCENTIVE PLAN
In connection with the Offering, the Company expects to adopt the Company's
Long-Term Performance Incentive Plan.
The objective of the Plan is to link the financial interests of the
Company's executive officers and other executive employees directly with those
of stockholders. The Plan consists of a stock option program for officers
(currently six individuals) and a profit sharing plan for other key employees
(currently approximately 20 individuals). Stock appreciation rights (SARs) may
also be granted in conjunction with options. Restricted stock awards may also be
made, but will be based on Company performance. Shares included in the Plan may
not be more than 1% of the outstanding shares of the Company's Common Stock.
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<PAGE> 74
The six executive officers of the Company are expected to be granted,
subject to the completion of the Offering, options to purchase shares of Common
Stock as follows:
<TABLE>
<CAPTION>
NAME OPTIONS
<S> <C>
Gordon L. Wright..................................... 25,000
William H. Stephens, III............................. 20,000
Robert A. Dunn....................................... 15,000
T. Rodney Dykes...................................... 12,000
Paul E. Geiger....................................... 5,000
Richard L. Redmond, Jr............................... 12,000
</TABLE>
Each of the options is expected to have an exercise price equal to the
initial public offering price of the Common Stock offered hereby and to have a
ten year term.
For other executive participants, the Committee may make cash awards
aggregating no more than 2% of the average of the most recent three years of the
net income of the Company. Such awards may be paid to the eligible participants
in equal installments over not more than three years. If a participant's
employment is terminated before a payment date other than by retirement on or
after age 62, or death, all rights to future payments may be forfeited.
PENSION PLAN & SERP TABLE
The Company is a participating employer in the Pension Plan for Employees
of Consumers ("Pension Plan"), which is a noncontributory defined benefit
pension plan intended to qualify under Section 401(a) of the IRC. The Company is
also a participating employer in the Supplemental Executive Retirement Plan for
Employees of Consumers ("SERP"). The SERP is a non-qualified plan under the IRC
providing supplemental retirement income for officers and selected executives of
the Company, based on their years of service and final pay, as defined in the
SERP. The following table shows the aggregate annual pension benefits at normal
retirement presented on a straight life annuity basis under the Pension Plan and
SERP (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>
$ 90,000.................................... $ 28,400 $ 37,800 $ 44,100 $ 50,400 $ 56,700
190,000.................................... 59,900 79,800 93,100 106,400 119,700
290,000.................................... 91,400 121,800 142,100 162,400 182,700
390,000.................................... 122,900 163,800 191,100 218,400 245,700
</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 bonus incentive plans as shown
in the Summary Compensation Table during the five years of highest earnings are
used in computing benefits under the SERP. As of December 31, 1995 the estimated
years of service for each of Messrs. Wright, Stephens, Dunn, Dykes, Geiger,
Redmond and Burgess are respectively 35.00 years, 25.50 years, 31.92 years, 1.58
years, 35.00 years, 7.50 years and 35.00 years.
OWNERSHIP OF CAPITAL STOCK
CMS Enterprises owns all of the outstanding Common Stock of the Company,
which constitutes all of the outstanding capital stock of the Company. CMS
Energy owns all of the outstanding common stock of CMS Enterprises (the "CMS
Enterprises Common Stock") and Consumers owns all of the outstanding preferred
stock of CMS Enterprises (the "CMS Enterprises Preferred Stock"), which together
constitute all of the outstanding capital stock of CMS Enterprises. CMS Energy
owns all of the outstanding common stock of Consumers.
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<PAGE> 75
The following table sets forth certain information regarding the beneficial
ownership by CMS Enterprises of the Common Stock of the Company (i) immediately
prior to the Offering and (ii) as adjusted to reflect the sale of Common Stock
in the Offering. CMS Enterprises has sole voting and investment power with
respect to all shares beneficially owned by it.
<TABLE>
<CAPTION>
SHARES OWNED SHARES OWNED
PRIOR TO OFFERING AFTER OFFERING
---------------------- ----------------------
NAME AND ADDRESS NUMBER PERCENT NUMBER PERCENT
<S> <C> <C> <C> <C>
CMS Enterprises................................... 20,000,000 100% 20,000,000 83.3%
330 Town Center Drive
Suite 1100
Dearborn, MI 48126
</TABLE>
The CMS Enterprises Preferred Stock may be issued in series, the terms of
which may be determined by the CMS Enterprises Board of Directors without
further action by stockholders, which terms may include, among others, dividend
rights, voting rights, redemption and sinking fund provisions, liquidation
preferences and conversion rights.
The shares of CMS Enterprises Preferred Stock currently outstanding and
owned by Consumers are 10 shares of Series A Preferred Stock (the "Series A
Preferred Stock"). The holders of the Series A Preferred Stock are entitled to
receive dividends payable, when and as declared, at the rate of $1,425,000 per
share per annum, cumulative from the date of original issuance. Upon
liquidation, the holders of the Series A Preferred Stock are entitled to receive
$25 million per share, plus accrued dividends.
On August 1, 1997 and on each August 1 thereafter, CMS Enterprises must
redeem two shares of the outstanding Series A Preferred Stock at a sinking fund
redemption price equal to $25 million per share, plus accrued dividends, and may
opt to redeem up to two additional shares under the same terms. Further, on each
such August 1, CMS Enterprises must redeem whole or fractional shares of the
Series A Preferred Stock equal to 100% of the amount of cash dividends received
from the Company during the preceding twelve-month period at a redemption price
of $25 million per share plus accrued dividends.
In addition to voting rights as otherwise provided by law, holders of
Series A Preferred Stock are entitled to one noncumulative vote per share on
each matter to be voted upon by the common stockholders. Holders of CMS
Enterprises Preferred Stock also have the exclusive right, voting as a separate
class, to elect a certain number of directors of CMS Enterprises whenever there
exist triggering defaults in quarterly dividends or any mandatory sinking fund
redemption.
The following table sets forth certain information regarding the beneficial
ownership by CMS Energy and Consumers of the CMS Enterprises Common Stock and
the CMS Enterprises Preferred Stock immediately prior to the Offering. Each of
CMS Energy and Consumers has sole voting and investment power with respect to
their respective shares.
<TABLE>
<CAPTION>
SHARES PERCENT
NAME AND ADDRESS TITLE OF CLASS BENEFICIALLY OWNED OF CLASS
<S> <C> <C> <C>
CMS Energy Corporation.............. CMS Enterprises Common Stock 100 100%
330 Town Center Drive
Suite 1100 CMS Enterprises Preferred 10* 100%
Dearborn, Michigan 48126 Stock
</TABLE>
- -------------------------
* Represents 10 shares of Series A Preferred Stock held of record by Consumers,
a subsidiary of CMS Energy of which CMS Energy owns all of the outstanding
common stock.
As of December 31, 1995, there were 91,583,501 shares of CMS Energy common
stock outstanding (the "CMS Energy Common Stock"), no shares of CMS Energy
preferred stock outstanding, and 7,618,602 shares of CMS Energy Class G common
stock outstanding (the "Class G Common Stock"). The CMS Energy Common Stock and
Class G Common Stock are together referred to hereinafter in this and the
following two
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<PAGE> 76
paragraphs as "common stock of CMS Energy." Both classes of common stock of CMS
Energy are listed on the New York Stock Exchange.
Class G Common Stock reflects the separate performance of the gas
distribution, storage and transportation businesses conducted by Consumers and
Michigan Gas Storage Company, a subsidiary of Consumers (such businesses,
collectively, the "Consumers Gas Group"). CMS Energy Common Stock reflects the
performance of all of the businesses of CMS Energy and its subsidiaries, except
for the interest in the Consumers Gas Group attributable to the outstanding
shares of Class G Common Stock.
The holders of both classes of common stock of CMS Energy vote as a single
class, except on matters which are required by law or the Articles of
Incorporation of CMS Energy to be voted on by class. Each holder of common stock
of CMS Energy is entitled to one noncumulative vote per share of common stock of
CMS Energy held by such holder on each matter voted upon by the stockholders.
The following table sets forth, as of December 31, 1995, the number and
percentage of outstanding shares of capital stock of CMS Energy that are
beneficially owned by (i) each director of the Company, (ii) each executive
officer of the Company named in "Management -- Summary Compensation Table,"
(iii) all directors and officers of the Company as a group and (iv) each person
known by the Company to own beneficially more than 5% of the Common Stock of the
Company by virtue of such person's ownership of any class of CMS Energy's voting
securities before giving effect to the Offering. Except as otherwise indicated
below, to the Company's knowledge, each individual or entity named has sole
investment and voting power with respect to its respective securities, except to
the extent authority is shared by spouses under applicable law.
<TABLE>
<CAPTION>
SHARES BENEFICIALLY OWNED
---------------------------- PERCENT OF
CMS ENERGY CLASS G COMMON STOCK
NAME COMMON STOCK COMMON STOCK OF CMS ENERGY
<S> <C> <C> <C>
Gordon L. Wright.................................... 3,935 100 *
William H. Stephens, III............................ 3,796 0 *
Robert A. Dunn...................................... 3,286 0 *
T. Rodney Dykes..................................... 221 0 *
Paul E. Geiger...................................... 6,001 0 *
Richard L. Redmond, Jr. ............................ 908 0 *
Victor J. Fryling................................... 68,530 1,500 *
Richard J. Burgess.................................. 0 0 *
Frank M. Burke, Jr. ................................ 0 0 *
J. Stuart Hunt...................................... 0 0 *
Thomas K. Matthews, II.............................. 0 0 *
William T. McCormick, Jr. .......................... 143,908 3,000 *
S. Kinnie Smith, Jr. ............................... 59,308 2,000 *
P. W. J. Wood....................................... 0 0 *
Alan M. Wright...................................... 22,105 300 *
--------- ----- ---
All Directors and Executive Officers
as a group (15 persons)........................... 311,998 6,900 *
Brinson Partners, Inc. ............................. 5,080,000 0 5.5%
</TABLE>
- -------------------------
* Less than 1%.
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<PAGE> 77
RELATIONSHIP AND CERTAIN TRANSACTIONS
WITH CMS ENERGY
VOTING CONTROL
After the Offering, CMS Enterprises will own approximately 83.3% (81.3% if
the Underwriters exercise their over-allotment option in full) of the issued and
outstanding Common Stock of the Company. As a result, CMS Enterprises, and
indirectly CMS Energy, by virtue of its control of CMS Enterprises, will be able
to direct the election of the entire Board of Directors of the Company and to
control the affairs and policies of the Company, including without limitation
the Company's exploration, development, capital, operating and acquisition
expenditure plans. The Company's Board of Directors is currently composed of ten
members, six of whom are directors or current or former officers of CMS Energy,
CMS Enterprises or the Company.
CONTRACTUAL ARRANGEMENTS
The Company and CMS Energy and certain of its other subsidiaries have
entered into a number of agreements described below for the purpose of defining
their ongoing relationship. These agreements are not the result of arm's-length
negotiation between independent parties, but are believed by the Company to be
at least as favorable to the Company as could be obtained from unaffiliated
third parties.
SERVICES AGREEMENTS
The Company has entered into respective Services Agreements (the "Services
Agreements") with each of CMS Energy, CMS Enterprises and Consumers which
provide, among other things, that CMS Energy, CMS Enterprises and Consumers will
make or cause to be made available to the Company from time to time management
and consulting services such as financial services, including such
administrative, clerical, managerial, professional and/or technical services as
the parties may from time to time agree.
REGISTRATION RIGHTS AGREEMENT
Under a Registration Rights Agreement (the "Registration Rights
Agreement"), the Company has agreed, upon the request of CMS Enterprises, to
file one or more registration statements under the Securities Act of 1933, as
amended (the "Securities Act") or take other appropriate action under the laws
of foreign jurisdictions in order to permit CMS Enterprises to offer and sell,
domestically or abroad, securities of the Company that CMS Enterprises may hold
at any time. CMS Enterprises will pay all costs relating thereto and any
underwriting discounts and commissions relating to any such offering, except
that the Company will pay the fees and expenses of its accountants, and any
trustees, transfer agents or other agents appointed in connection therewith.
There is no limitation on the number or frequency of the occasions on which
CMS Enterprises may exercise its registration rights, except that the Company
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 such class then
outstanding, or, in the case of a class of debt securities, the principal amount
of debt securities covered by the request is at least $5 million.
The Company has also granted to CMS Enterprises the right to include
Company securities owned by it in certain registrations under the Securities Act
covering offerings of securities by the Company and the Company will pay all
costs of such offerings other than incremental costs attributable to the
inclusion of securities of the Company owned by CMS Enterprises in such
registrations, and CMS Enterprises will pay the fees and expenses of its counsel
and all underwriting discounts and commissions for the sale of securities
offered by it.
The Company will indemnify CMS Enterprises, its officers and directors and
each underwriter, if any, and controlling persons of CMS Enterprises or any such
underwriter against certain liabilities arising under the laws of any country in
respect of any registration or other offering covered by the Registration Rights
Agreement. The Company has the right to require CMS Enterprises to delay any
exercise by CMS
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<PAGE> 78
Enterprises of its rights to require registration and other actions for a period
of up to 90 days if, in the judgment of the Company, any underwritten offering
by the Company of securities for its account then being conducted or about to be
conducted would be materially adversely affected. CMS Enterprises has further
agreed that it will not include any securities of the Company in any
registration by the Company under the Securities Act which, in the judgment of
the managing underwriters, would materially adversely affect any offering of
securities by the Company. The rights of CMS Enterprises under the Registration
Rights Agreement are transferable to non-affiliates of CMS Enterprises.
TAX SHARING AGREEMENT
The Company and its subsidiaries will continue to join in filing
consolidated federal income tax returns with the CMS Energy affiliated group. In
order to allocate the aggregate tax liability of the CMS Energy affiliated group
among its members and provide for certain other matters relating to the payment
of federal income taxes, CMS Energy has entered into the Amended and Restated
Agreement for the Allocation of Income Tax Liabilities and Benefits with the
Company and other members of the CMS Energy affiliated group (the "Tax Sharing
Agreement") pursuant to which, in general, CMS Energy will pay each member for
the reduction (and each member will pay CMS Energy for the increase) in the
aggregate federal income taxes payable by the CMS Energy affiliated group
resulting from the inclusion of such member in that group.
CONFLICTS OF INTEREST
The relationship between the Company and CMS Energy and its other
affiliates may give rise to conflicts of interest with respect to, among other
things, transactions and agreements between the Company 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 the Company. When
the interests of CMS Energy and its other subsidiaries diverge from those of the
Company, CMS Energy may exercise its influence in favor of its own interests or
the interests of another of its subsidiaries over the interests of the Company.
CMS Energy has advised the Company that it does not intend to engage in the
exploration for natural gas and oil except through its ownership of Common Stock
of the Company. However, circumstances may arise that would result in CMS
Energy, by itself or through one of its affiliated entities, in connection with
projects unrelated to those of the Company, engaging in the exploration for or
development or production of natural gas and oil.
The Company and CMS Energy and its other subsidiaries from time to time
have entered into significant intercompany transactions and agreements incident
to their respective businesses and may enter into similar transactions and
agreements in the future. In the past, such transactions and agreements have
related to, among other things, the purchase and sale of natural gas and
indemnification arrangements in connection with acquisitions. See "-- Certain
Transactions." The Company intends that the terms of any future agreements
between the Company and CMS Energy or its other affiliates will be at least as
favorable to the Company as could be obtained from unaffiliated third parties.
CERTAIN TRANSACTIONS
GAS SALES AGREEMENTS
The Company sells natural gas to affiliates at rates approximating the
average price of gas paid to other area producers. A five-year gas sales
contract dated as of January 1, 1995 between the Company and Consumers provides
for sales prices of $2.50 per MMBtu in 1995, $2.60 per MMBtu in 1996, and at
negotiated rates from 1997 through 1999, on 20,000 MMBtu per day. Total sales to
Consumers under certain other gas sales contracts between such parties were
approximately $3.4 million in 1992, $2.6 million in 1993 and $0.7 million in
1994. Gas sales to MCV under three gas sales contracts amounted to approximately
$6.4 million in 1992, $12.2 million in 1993 and $9.2 million in 1994. In 1994,
the Company recognized a gain of $4.8 million attributable to the disposition of
an MCV gas sales contract. The gas sales contract had provided for sales prices
of $2.53 per MMBtu in 1994, escalating 4% per year to December 31, 2006 on
10,000 MMBtu per day
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<PAGE> 79
or 3.7 Bcf annually of gas sales. In March 1995, the Company recognized a gain
of $9.9 million attributable to the disposition of another MCV gas sales
contract. This gas sales contract had provided for sales prices of $3.25 per
MMBtu in 1995, escalating 4% each year through December 31, 2006, and covered
3,750 MMBtu per day or 1.37 Bcf annually of the Company's gas sales. The Company
expects to sell these volumes on the spot market or under term contracts
providing for current market price.
TERRA ACQUISITION
In August 1995, CMS Energy acquired all of the outstanding capital stock of
Terra, a significant producer of Antrim gas, for consideration which, after
giving effect to certain anticipated post-closing adjustments, is expected to
aggregate approximately $63.6 million, payable in common stock of CMS Energy.
Immediately after consummation of such acquisition, and pursuant to a transfer
agreement among CMS Energy, CMS Enterprises and the Company, the stock of Terra
was transferred by CMS Energy, through CMS Enterprises, to the Company. In
connection with the Terra Acquisition, the Company recorded a capital
contribution of $1.0 million and issued the Terra Note to CMS Enterprises which,
after giving effect to post-closing adjustments, is expected to be in the
principal amount of $62.6 million. The Terra Note is currently held by CMS
Energy. See "-- CMS Notes." A portion of the net proceeds from the Offering will
be used to repay the Terra Note.
WALTER ACQUISITION AND RELATED INDEMNIFICATION AGREEMENT
In February 1995, CMS Energy acquired all of the outstanding capital stock
of Walter, an international oil and gas company, for a purchase price of
approximately $28.4 million (of which approximately $25.0 million was payable by
delivery of CMS Energy common stock and $3.4 million was paid in cash) plus
assumed indebtedness of $18.3 million. Immediately upon consummation of such
acquisition, the stock of Walter was contributed by CMS Energy, through CMS
Enterprises, to the Company. The Company recorded a capital contribution of
$28.4 million as a result of the Walter Acquisition. Of the assumed indebtedness
of Walter, $6.5 million was immediately repaid with funds which the Company
borrowed from CMS Energy as evidenced by the Walter Note. See "-- CMS Notes." A
portion of the net proceeds from the Offering will be used to repay the Walter
Note.
Included among the assets and liabilities of Walter and its subsidiaries at
the time of the Walter Acquisition were certain Congolese assets that had been
acquired by a Walter subsidiary from affiliates of Amoco and a tax indemnity
obligation that had been incurred by Walter in connection with such acquisition.
In connection with the Walter Acquisition, CMS Energy, the Company and Walter
agreed to be jointly and severally liable for Walter's obligation to indemnify
Amoco for tax liabilities attributable to the recapture of "dual consolidated
losses" utilized by 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 such assets or with respect
to the stock of such entities or certain of their subsidiaries. CMS Energy has
agreed to indemnify the Company under the CMS Energy Indemnity for such
liability if the triggering event results from acts or omissions (i) of CMS
Energy or any of its subsidiaries (other than the Company or any of its
subsidiaries) which occur after the initial sale of the Common Stock offered
hereby; (ii) of the Company or any of its subsidiaries if such acts or omissions
are approved by the Board of Directors of the Company, which approval includes
the affirmative vote of a majority of the employees of CMS Energy or any of its
subsidiaries (other than the Company or any of its subsidiaries) who serve on
the Company's Board of Directors; or (iii) of any person if such acts or
omissions occur prior to the initial sale of the Common Stock offered hereby.
Conversely, the Company has agreed to indemnify CMS Energy (and/or CMS
Enterprises) if, in fact, the triggering event results from acts or omissions of
the Company or its subsidiaries which occur after the initial sale of the Common
Stock offered hereby and such acts or omissions are not approved by the Board of
Directors of the Company, which approval includes the affirmative vote of a
majority of the employees of CMS Energy or any of its subsidiaries (other than
the Company) who serve on the Company's Board of Directors. See "Business and
Properties -- Tax Matters -- Dual Consolidated Losses."
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<PAGE> 80
CMS NOTES
In August 1995, the Company issued the Terra Note to CMS Enterprises, which
in turn assigned it to CMS Energy, in connection with the transfer of the common
stock of Terra by CMS Energy to CMS Enterprises and then by CMS Enterprises to
the Company. In July 1995, the Company issued the Walter Note to CMS Energy to
evidence indebtedness originally incurred in February 1995 to fund repayment of
$6.5 million of indebtedness of Walter immediately after the consummation of the
Walter Acquisition. The CMS Notes bear interest at the rate of LIBOR plus 2.0%
per annum and have a maturity date of November 1, 1999. Amounts outstanding
under the CMS Notes are expressly subordinate to borrowings under the Company's
Credit Agreement. Certain limitations are placed on the Company's obligation to
make payments on the indebtedness evidenced by the CMS Notes in the event of
default under the terms of the Credit Agreement. The Company intends to use a
portion of the net proceeds from the Offering to repay the CMS Notes.
LETTER OF CREDIT REIMBURSEMENT AGREEMENT
In December 1994, CMS Energy arranged for the issuance of a standby letter
of credit, currently in the amount of $45.0 million, to secure the Company's
performance under the operating services agreement relating to the Colon Unit in
Venezuela. The Company has agreed to reimburse CMS Energy on demand for any draw
made under the letter of credit and to pay to CMS Energy a fee of 2.125% per
annum of the face amount of the letter of credit.
CONTRIBUTIONS TO CAPITAL
During the years 1992, 1993, 1994 and the nine months ended September 30,
1995, the Company received equity contributions from CMS Enterprises amounting
to $5.8 million, $9.5 million, $56.1 million and $4.5 million, respectively.
Additionally, during the nine months ended September 30, 1995, the Company
received from CMS Enterprises equity contributions of $27.2 million ($3.5
million in cash and $23.7 million in stock) with respect to the Walter
Acquisition and $1.0 million with respect to the Terra Acquisition.
ADDITIONAL TRANSACTIONS
In 1993, the Company received $2.6 million for its share of proceeds from
the sale of certain northern Michigan pipelines to an affiliate of the Company,
CMS Gas Transmission and Storage Company. These pipelines were constructed by
the Company shortly prior to their sale for a cost of $2.2 million.
REPURCHASE OF INTERESTS UNDER EMPLOYEE WELL PARTICIPATION PROGRAM
The Company and each of Gordon L. Wright, William H. Stephens, III, Robert
A. Dunn, T. Rodney Dykes and Richard L. Redmond, Jr., each of which is an
officer and one of which is a director of the Company, are expected to enter
into royalty rights purchase agreements providing that the Company will,
effective on or about March 1, 1996, purchase all of the overriding royalty
interests previously received by such persons under Plan B of the Employee Well
Participation Program. See "Management -- Summary Compensation Table." These
agreements are expected to provide that such persons will receive as
consideration for such Plan B interests a combination of cash and phantom stock
units relating to CMS Energy Common Stock half of the value of which will,
effective upon the completion of the Offering, be converted into phantom stock
units relating to the Common Stock of the Company. The aggregate amount of cash
and the initial value of the phantom stock units in such respective transactions
are as follows: Mr. Wright $975,207; Mr. Stephens $699,048; Mr. Dunn $953,256;
Mr. Dykes $180,577; and Mr. Redmond $296,149.
On March 1 in each of the years 1997 through 2001, the Company will pay to
each person named above a stipulated percentage of the then value of his phantom
stock units (including appreciation, if any, on the securities underlying such
units). The Company will also pay such persons an amount equal to any dividends
paid on the securities underlying the units at the time such dividends are paid.
If any of the above-named persons terminates his employment with the Company
voluntarily, except in certain circumstances such as upon a serious health
problem, an adverse change in officer-level responsibilities or other terms or
conditions of employment, certain employment relocations or a change in control
(as defined in the purchase
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<PAGE> 81
agreements) of the Company or CMS Energy, any remaining installment payments
relating to the phantom stock units of such person shall be forfeited. If the
employment of any of such persons with the Company is voluntarily terminated for
the foregoing reasons or involuntarily terminated for any other reason, any
remaining payments relating to the phantom stock units of such person shall
immediately become due and the Company will also pay such person a stipulated
cash payment, which shall be in the following amounts if such a termination
occurs on or prior to June 1, 1996, which amounts shall gradually decrease to
zero by March 1, 2001: Mr. Wright $447,706; Mr. Stephens $270,928; Mr. Dunn
$151,631; Mr. Dykes $107,810; and Mr. Redmond $162,898.
In connection with these transactions, the Company has agreed to indemnify
each such person with respect to certain tax matters relating to such
transactions.
DESCRIPTION OF CAPITAL STOCK
Certain statements under this caption are summaries of the respective
Restated Articles of Incorporation and Restated Bylaws of the Company, copies of
which are filed as exhibits to the Registration Statement of which this
Prospectus is a part. Summaries herein of certain provisions of such documents
do not purport to be complete and are subject and qualified in their entirety by
reference to all provisions of such documents.
The authorized capital stock of the Company 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, there are 20,000,000
shares of Common Stock outstanding, all of which are owned by CMS Enterprises,
and no shares of Preferred Stock outstanding. Upon completion of the Offering,
there will be 24,000,000 shares of Common Stock outstanding, 20,000,000 shares
of which will be owned by CMS Enterprises, assuming no exercise of options.
COMMON STOCK OF THE COMPANY
The holders of Common Stock are entitled to one vote per share on all
matters submitted to a vote of stockholders. Holders of Common Stock do not have
cumulative voting rights with respect to the election of directors. Therefore,
the holders of more than 50% of the issued and outstanding shares of Common
Stock may elect all of the Company's directors. After the Offering, CMS
Enterprises will hold approximately 83.3% of the issued and outstanding Common
Stock (81.3% if the over-allotment option is exercised in full) and therefore
will hold the voting power to determine all matters upon which stockholders of
the Company vote, including the election of directors. See "Relationship and
Certain Transactions with CMS Enterprises and CMS Energy."
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.
In the event of a liquidation, dissolution or winding up of the Company,
holders of Common Stock are entitled to share ratably in all net assets
available for distribution to common stockholders. Holders of Common Stock have
no preemptive, subscription, redemption or conversion rights. All outstanding
shares of Common Stock are, and the shares of Common Stock to be sold by the
Company in this Offering when issued will be, fully paid and nonassessable.
Application will be made to list the shares of Common Stock to be issued in
the Offering on the New York Stock Exchange upon official notice of issuance.
PREFERRED STOCK OF THE COMPANY
The authorized capital stock of the Company includes 5,000,000 shares of
Preferred Stock. Such Preferred Stock may be issued in series, the terms of
which may be determined by the Company's Board of Directors without further
action by stockholders, which terms may include, among others, dividend rights,
voting rights, redemption and sinking fund provisions, liquidation preferences
and conversion rights.
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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 Common Stock and could have the
effect of delaying, deferring or preventing a change in control of the Company.
CERTAIN PROVISIONS OF MICHIGAN CORPORATE LAW
Chapter 7A of the Michigan Business Corporation Act (the "MBCA"), M.C.L.
sec.450.1775 et seq., is applicable to corporations organized under the laws of
Michigan which have at least 100 beneficial owners of their stock. Subject to
certain exceptions set forth therein, Chapter 7A provides that a corporation
shall not engage in any business combination with any "interested stockholder"
unless an advisory statement is given by the Board of Directors and the
combination is approved by a vote of at least 90% of the votes of each class of
stock entitled to vote, and at least two-thirds of the votes of each class of
stock entitled to vote other than the voting shares owned by the interested
stockholder. However, these statutory requirements do not apply if, prior to the
date that an interested stockholder first becomes an interested stockholder, the
Board of Directors by resolution approves or exempts such business combinations
generally or a particular combination from the requirements of the MBCA.
Furthermore, the voting requirement does not apply to a business combination if:
(a) specified fair price criteria are met, as described below; (b) the
consideration to be given to the stockholders is in cash or in the form the
interested stockholder paid for shares of the same class or series; and (c)
between the time the interested stockholder becomes an interested stockholder
and before the consummation of a business combination the following conditions
are met: (1) any preferred stock dividends are declared and paid on their
regular date; (2) the annual dividend rate of stock other than preferred stock
is not reduced and is raised if necessary to reflect any transaction which
reduces the number of outstanding shares; (3) the interested stockholder does
not receive any financial assistance or tax advantage from the corporation other
than proportionally as a stockholder; (4) the interested stockholder does not
become the beneficial owner of any additional shares of the corporation; and (5)
at least five years elapse. Except as specified therein, an "interested
stockholder" is defined to mean any person that: (a) is the owner of 10% or more
of the outstanding voting stock of the corporation, or (b) is an affiliate of
the corporation and was the owner of 10% or more of the outstanding voting stock
of the corporation at any time within two years immediately prior to the
relevant date. Under certain circumstances, Chapter 7A makes it more difficult
for an "interested stockholder" to effect various business combinations with a
corporation for a five-year period, although the stockholders may elect not to
be governed by this section, upon approval of 90% of the outstanding voting
shares and two thirds of the shares not owned by the interested stockholder. The
Company's stockholders have not excluded the Company from the restrictions
imposed under Chapter 7A of the MBCA. It is anticipated that the provisions of
Chapter 7A may encourage companies interested in acquiring the Company to
negotiate in advance with the Board of Directors.
Fair price criteria include the following: (a) the aggregate amount of the
cash and market value of noncash consideration to be received by the holders of
common stock is at least as much as the highest of (1) the highest price the
interested stockholder paid for stock of the same class or series within the
two-year period immediately prior to the announcement date of the combination
proposal, and (2) the market value of stock of the same class or series on the
announcement date or on the determination date; and (b) the aggregate amount of
the cash and market value of noncash consideration to be received by holders of
stock other than common stock is at least as much as the highest of (1) the
highest price the interested stockholder paid for stock of the same class or
series within the two-year period immediately prior to the announcement date of
the combination proposal, (2) the highest preferential amount per share to which
the holders of such stock are entitled in the event of any liquidation,
dissolution, or winding up of the corporation, and (3) the market value of stock
of the same class or series on the announcement date or on the determination
date.
Chapter 7B of the MBCA, M.C.L. sec.450.1790 et seq., is applicable to
corporations organized under the laws of Michigan which have (a) at least 100
beneficial owners of their stock; (b) their principal place of business,
principal office or substantial assets in Michigan; and (c) at least one of the
following: (1) more than 10% of their stockholders reside in Michigan, (2) more
than 10% of their shares are owned by Michigan residents, or (3) at least 10,000
stockholders reside in Michigan. Subject to certain exceptions set forth
therein, Chapter 7B provides that once a person proposes to make or makes a
"control share acquisition" and delivers an acquiring person statement to the
corporation, the stockholders must vote on whether the control
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shares may exercise voting rights. Such rights are granted only by resolution
approved by both (a) a majority of the votes cast by holders entitled to vote
and a majority of any class entitled to vote, and (b) a majority of the votes
cast and a majority of any class entitled to vote excluding the interested
shares. Further, a corporation's articles of incorporation or bylaws may
authorize, under certain circumstances, redemption at fair value of the control
shares acquired in a control share acquisition if no acquiring person statement
is filed with the corporation. "Control shares" means shares which, if voted,
would have voting power when added together with all other shares a person
either owns or directs their exercise, within the following ranges: (a) at least
20% but less than 33 1/3% of all voting power; (b) at least 33 1/3% but less
than a majority of all voting power; or (c) a majority of all voting power. An
acquisition of shares is not considered a control share acquisition under
certain circumstances, including where the acquisition is part of a merger or
share exchange if the corporation is a party to the agreement of merger or share
exchange. Under certain circumstances, Chapter 7B makes it more difficult for an
"acquiring person" to exercise control over a corporation due to the limitations
placed on that person's ability to vote the control shares, although the
corporation may, before any such control share acquisition, elect not to be
governed by this chapter by adopting an amendment to the corporation's articles
of incorporation or bylaws. The Company's Restated Articles of Incorporation and
Restated By-laws do not exclude the Company from the restrictions imposed under
Chapter 7B of the MBCA. It is anticipated that the provisions of Chapter 7B may
encourage acquiring persons interested in obtaining control over the Company to
negotiate in advance with the Board of Directors.
Section 450.1368 of the MBCA is applicable to corporations organized under
the laws of Michigan. This section prohibits a corporation from purchasing,
either directly or indirectly, any of its shares that are listed on a national
securities exchange from any person who holds at least 3% of its shares unless
one of the following conditions is met: (a) the corporation makes an equivalent
offer to all other holders of the same shares; (b) the purchase is authorized in
advance by the stockholders entitled to vote thereon; (c) the purchase meets the
requirements of the articles of incorporation for such a purchase; (d) the
shares are beneficially owned by the person for at least two years prior to the
purchase date; (e) the purchase is made on the open market; (f) the purchase
price is not more than the average market price of the shares during the 30
business days prior to the purchase date; or (g) the purchase is otherwise
authorized by the MBCA. Under certain circumstances, sec.450.1368 prevents a
stockholder from selling his shares back to the corporation at a premium within
two years of that stockholder's purchase of the shares unless one of the other
conditions is met. However, the stockholders may approve such a purchase by the
corporation or the corporation may include in its articles of incorporation
lesser requirements for such a transaction. The Company's Restated Articles of
Incorporation do not contain any provisions regarding the purchase of the
Company's shares from any stockholder who beneficially owns at least 3% of its
stock. It is anticipated that the provisions of sec.450.1368 may discourage
persons from obtaining quantities of the Company's stock for the sole purpose of
eliciting a premium from the Company in a resale of those shares.
LIMITATION ON PERSONAL LIABILITY OF DIRECTORS; INDEMNIFICATION PROVISIONS
The Company's Restated Articles of Incorporation contains a provision,
authorized by the MBCA, designed to eliminate the personal liability of
directors for monetary damages to the Company or its stockholders 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 the Company or its
stockholders, 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
the rights of the Company or any stockholder to seek an injunction or any other
nonmonetary 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.
The Company's Restated Articles of Incorporation and Restated Bylaws
provide that the Company shall indemnify all directors and officers of the
Company to the full extent permitted by the MBCA. Under the provisions of the
MBCA, 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
the Board determines such director or officer acted in
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good faith and in a manner he reasonably believed to be in or not opposed to the
best interests of the Company or its stockholders.
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 Company or of the Company's subsidiaries and
the Company'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
Company's request.
TRANSFER AGENT AND REGISTRAR
The transfer agent and registrar for the Common Stock is the Company.
SHARES ELIGIBLE FOR FUTURE SALE
Upon completion of the Offering, the Company will have 24,000,000 shares of
Common Stock outstanding, assuming no exercise of options. All of the 4,000,000
shares sold in the Offering will be freely tradeable by persons other than
"affiliates" of the Company, as such term is defined under Rule 144 under the
Securities Act (each, an "Affiliate"), without restriction under the Securities
Act. The remaining 20,000,000 shares of Common Stock that will continue to be
beneficially owned by CMS Energy after the Offering constitute "restricted
securities" within the meaning of Rule 144. Pursuant to the Registration Rights
Agreement, CMS Enterprises may cause the Company at any time to register under
the Securities Act all or a portion of the Common Stock owned by it, in which
event CMS Enterprises would be able to sell such shares upon the effectiveness
of any such registration without regard to the provisions of Rule 144.
In general, under Rule 144 as currently in effect, beginning 90 days after
the effective date of this Prospectus, any person, including an Affiliate, who
has beneficially owned shares for at least two years, will be entitled to sell
in "brokers' transactions" or to market makers, within any three-month period, a
number of shares that does not exceed the greater of (i) 1% of the then
outstanding shares of Common Stock (approximately 240,000 shares immediately
after the completion of the Offering) or (ii) the average weekly trading volume
in the Common Stock during the four calendar weeks immediately preceding the
date on which notice of the sale is filed with the Securities and Exchange
Commission (the "Commission"). Sales under Rule 144 are also subject to certain
manner of sale provisions, notice requirements and the availability of current
public information about the Company. Further, a person who is not an Affiliate,
and has not been an Affiliate at any time during the three months immediately
preceding the sale, and who has beneficially owned the shares proposed to be
sold for at least three years, is entitled to sell such shares under Rule 144(k)
without regard to the limitations described above. The Commission has proposed
amendments to Rule 144 that, if adopted, would reduce the two-year and
three-year holding periods described above to one-year and two-year holding
periods, respectively. No assurances can be given as to when or if these
proposed amendments will be adopted or that the proposed amendments will not be
significantly revised prior to their adoption.
The Company intends to file promptly after the completion of the Offering a
Registration Statement on Form S-8 relating to the Company's Long-Term
Performance Incentive Plan and the shares of the Common Stock issuable
thereunder, thus permitting the resale of such shares by nonaffiliates in the
public market without restriction and by affiliates subject to compliance with
certain restrictions under the Securities Act. An estimated 89,000 shares are
expected to be issuable upon exercise of options expected to be granted by the
Company under the Plan, subject to the completion of the Offering. Such options
will vest six months after the Offering.
The Company, CMS Enterprises and CMS Energy have agreed that during the
period beginning from the date of this Prospectus and continuing to and
including the date 180 days after the date of this Prospectus, not to offer,
sell, contract to sell or otherwise dispose of any securities of the Company
(other than pursuant to employee stock incentive plans existing or contemplated
on the date of this Prospectus and for certain other purposes) which are
substantially similar to the shares of Common Stock or which are convertible or
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exchangeable into securities which are substantially similar to the shares of
Common Stock, without the prior written consent of Donaldson, Lufkin & Jenrette
Securities Corporation. Upon expiration of this period, all 20,000,000 shares of
Common Stock held by CMS Enterprises will have been held for more than two years
and will be available for sale in the public market subject to compliance with
the volume and other limitations of Rule 144 described above.
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 such purchasers without regard to
volume or any other restrictions.
Prior to the Offering, there has been no market for the Common Stock of the
Company and no predictions can be made as to the effect, if any, that market
sales of shares of Common Stock, or the availability of such shares for sale,
will have on the market price prevailing from time to time. Nevertheless, sales
of substantial amounts of Common Stock of the Company in the public market, or
the perception that such sales could occur, could adversely affect prevailing
market prices and could impair the Company's future ability to raise capital
through the sale of its equity securities.
UNDERWRITING
Subject to the terms and conditions of the Underwriting Agreement, the
Company has agreed to sell to each of the Underwriters named below, and each of
such Underwriters, for whom Donaldson, Lufkin & Jenrette Securities Corporation,
Bear, Stearns & Co., Inc. and Salomon Brothers Inc and are acting as
representatives, has severally agreed to purchase from the Company, the
respective number of shares of Common Stock set forth opposite its name below:
<TABLE>
<CAPTION>
NUMBER OF
SHARES OF
COMMON
UNDERWRITER STOCK
<S> <C>
Donaldson, Lufkin & Jenrette Securities Corporation................
Bear, Stearns & Co., Inc...........................................
Salomon Brothers Inc...............................................
---------
Total......................................................... 4,000,000
=========
</TABLE>
Under the terms and conditions of the Underwriting Agreement, the
Underwriters are committed to take and pay for all of the shares offered hereby,
if any are taken.
The Underwriters propose to offer the shares of Common Stock in part
directly to the public at the initial public offering price set forth on the
cover page of this Prospectus, and in part to certain securities dealers at such
price less a concession of $ per share. The Underwriters may allow, and such
dealers may reallow, a concession not in excess of $ per share to certain
brokers and dealers. After the shares of Common Stock are released for sale to
the public, the offering price and other selling terms may from time to time be
varied by the representatives.
The Company has granted the Underwriters an option exercisable for 30 days
after the date of this Prospectus to purchase up to an aggregate of 600,000
additional shares of Common Stock solely to cover
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over-allotments, if any. If the Underwriters exercise their over-allotment
option, the Underwriters have severally agreed, subject to certain conditions,
to purchase approximately the same percentage thereof that the number of shares
to be purchased by each of them, as shown in the foregoing table, bears to the
4,000,000 shares of Common Stock offered.
Up to 50,000 shares of Common Stock may be reserved for sale to the
Company's employees, the Company's Board of Directors and the employees of CMS
Energy and its subsidiaries. Sales of shares to such persons will be at the
initial public offering price. None of such persons has yet advised the Company
or the Representatives whether they desire to purchase any such shares. The
number of shares available for sale to the general public may be reduced to the
extent such persons purchase such 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 offered hereby.
The Company, CMS Enterprises and CMS Energy have agreed that during the
period beginning from the date of this Prospectus and continuing to and
including the date 180 days after the date of this Prospectus, not to offer,
sell, contract to sell or otherwise dispose of any securities of the Company
(other than pursuant to employee stock incentive plans existing or contemplated
on the date of this Prospectus and for certain other purposes) which are
substantially similar to the shares of Common Stock or which are convertible or
exchangeable into securities which are substantially similar to the shares of
Common Stock, without the prior written consent of Donaldson, Lufkin & Jenrette
Securities Corporation.
The representatives of the Underwriters have informed the Company that they
do not expect sales to accounts over which the Underwriters exercise
discretionary authority to exceed five percent of the total number of shares of
Common Stock offered by them.
Prior to the Offering, there has been no public market for the Shares. The
initial public offering price will be negotiated among the Company and the
representatives. Among the factors to be considered in determining the initial
public offering price of the Common Stock, 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 the Company's oil and natural gas
properties, the history of and prospects for the industry in which the Company
operates, the earnings multiples of publicly traded common stocks of comparable
companies, the cash flow and earnings of the Company and comparable companies in
recent periods and the Company's business potential and cash flow and earnings
prospects.
Application will be made to list the Common Stock on the New York Stock
Exchange. In order to meet one of the requirements for listing the Common Stock
on the New York Stock Exchange, the Underwriters will undertake to sell lots of
100 or more shares to a minimum of 2,000 beneficial holders.
The Company has agreed to indemnify the several Underwriters against
certain liabilities, including liabilities under the Securities Act of 1933.
Each of the named Representatives has 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. Such services include serving as underwriter or
private placement agent in connection with various securities offerings. Such
firms have also performed various investment banking services for CMS Energy for
which they received customary fees and reimbursement of their out-of-pocket
expenses.
LEGAL MATTERS
The validity of the shares of Common Stock offered hereby is being passed
upon for the Company by William H. Stephens, III, Executive Vice President and
General Counsel of the Company, and certain other legal matters in connection
with the Offering are being passed upon for the Company by Sidley & Austin and
William H. Stephens, III. Certain legal matters in connection with the Offering
will be passed upon for the Underwriters by Baker & Botts, L.L.P. As to all
matters of Michigan law, Sidley & Austin and Baker & Botts, L.L.P. will rely on
the opinion of William H. Stephens, III.
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EXPERTS
The Consolidated Financial Statements of the Company as of December 31,
1993 and 1994 and for each of the three years in the period ended December 31,
1994, the Consolidated Financial Statements of CMS NOMECO International, Inc.
(formerly Walter) as of and for the year ended December 31, 1994, and the
Consolidated Financial Statements of Terra as of and for the year ended December
31, 1994, all included in this Prospectus have been audited and the Pro Forma
Consolidated Statement of Income, of the Company for the year ended December 31,
1994, included in this Prospectus, has been examined by Arthur Andersen LLP
(formerly Arthur Andersen & Co.), independent public accountants, as indicated
in their reports with respect thereto, and are included herein in reliance upon
the authority of such firm as experts in accounting and auditing in giving said
reports. Reference is made to said report on the audited Consolidated Financial
Statements of the Company, which includes an explanatory paragraph with respect
to the change in the method of accounting for postretirement benefits other than
pensions in 1992 as discussed in Note 1.i to the Consolidated Financial
Statements of the Company.
With respect to the unaudited interim consolidated financial information
relating to the Company as of and for the nine month period ended September 30,
1995, Arthur Andersen LLP has applied limited procedures in accordance with
professional standards for a review of such information. However, their separate
report included herein states that they did not audit and they did not express
an opinion on that interim consolidated financial information. Accordingly, the
degree of reliance on their report on that information should be restricted in
light of the limited nature of the review procedures applied. In addition, the
accountants are not subject to the liability provisions of Section 11 of the
Securities Act for their report on the unaudited interim consolidated financial
information because that report is not a "report" or "part" of the Registration
Statement prepared or certified by the accountants within the meaning of
Sections 7 and 11 of the Securities Act.
The Consolidated Financial Statements of Walter as of December 31, 1992 and
1993 and for each of the two years in the period ended December 31, 1993
included in this Prospectus have been audited by Deloitte & Touche LLP,
independent auditors, as set forth in their report thereon (which report
expresses an unqualified opinion and includes an explanatory paragraph referring
to substantial doubt about Walter's ability to continue as a going concern),
appearing elsewhere herein and in the Registration Statement, and are included
herein in reliance upon the authority of said firm as experts in auditing and
accounting.
The Combined Balance Sheets of the Amoco Congo Companies as of December 31,
1993 and 1994, and the related Combined Statements of Operations, Stockholder's
Equity, and Cash Flows for each of the three years in the period ended December
31, 1994 have been included herein and in the Registration Statement in reliance
upon the report of KPMG Peat Marwick LLP, independent certified public
accountants, appearing elsewhere herein, and upon the authority of said firm as
experts in accounting and auditing.
With respect to the unaudited combined interim financial information of the
Amoco Congo Companies as of and for the one-month period ended January 31, 1995,
included herein the independent certified public accountants have reported that
they applied limited procedures in accordance with professional standards for a
review of such information. However, their separate report included herein,
states that they did not audit and they do not express an opinion on that
interim financial information. Accordingly, the degree of reliance on their
report on such information should be restricted in light of the limited nature
of the review procedures applied. The accountants are not subject to the
liability provisions of Section 11 of the Securities Act for their report on the
unaudited combined interim financial information because that report is not a
"report" or a "part" of the Registration Statement prepared or certified by the
accountants within the meaning of Sections 7 and 11 of the Securities Act.
Information relating to the estimated proved reserves of oil and natural
gas at June 30, 1995 included herein have been prepared by Ryder Scott,
independent petroleum engineer consultants, as stated in their reserve report
dated October 2, 1995, and is included herein in reliance upon the authority of
such firm as an expert in such matters. Information relating to the estimated
proved reserves of oil and natural gas and the related estimates of future net
cash flows and standardized measure data as of January 1, 1993, 1994 and 1995
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included herein were based upon engineering studies prepared by the Company's
internal engineers. Set forth as Appendix A is a letter of Ryder Scott relating
to their reserve report.
AVAILABLE INFORMATION
The Company has not previously been subject to the reporting requirements
of the Securities Exchange Act of 1934, as amended. The Company has filed with
the Commission a Registration Statement on Form S-1 (the "Registration
Statement", which term shall include all amendments, exhibits and schedules
thereto) under the Securities Act with respect to the offer and sale of Common
Stock pursuant to this Prospectus. This Prospectus, filed as a part of the
Registration Statement, does not contain all of the information set forth in the
Registration Statement or the exhibits and schedules thereto and reference is
hereby made to such omitted information. Although the material terms of the
Company's material contracts, agreements and other documents are summarized in
this Prospectus, statements made in this Prospectus concerning the contents of
any contract, agreement or other document filed as an exhibit to the
Registration Statement are summaries of the terms of such contracts, agreements
or documents and are not necessarily complete. Reference is made to each such
exhibit for a more complete description of the matters involved. The
Registration Statement and the exhibits and schedules thereto filed with the
Commission may be inspected, without charge, and copies may be obtained at
prescribed rates, at the public reference facility maintained by the Commission
at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C. 20549 and at the
regional offices of the Commission located at 7 World Trade Center, Suite 1300,
New York, New York 10048 and 500 West Madison Street, Suite 1400, Chicago,
Illinois 60621.
The Company intends to furnish its stockholders with annual reports
containing audited financial statements and the report of independent auditors
and quarterly reports for the first three quarters of each fiscal year
containing unaudited financial statements.
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CERTAIN DEFINITIONS
The terms defined below are used throughout this Prospectus.
Acreage held by production. Acreage covered by an oil and gas lease which
has a producing well on it, or which is pooled or unitized with a lease or
leases having one or more producing wells on them, so the lease is maintained in
effect for the duration of such production.
API. American Petroleum Institute.
Bbl. One stock tank Bbl, 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.
Bopd. Barrels of oil per day.
Bcpd. Barrels of condensate per day.
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.
Discounted estimated future net cash flows. Estimated future net cash flows
discounted at a rate of ten percent per annum.
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.
Farmin or Farmout. 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 "farmin" while the interest
transferred by the assignor is a "farmout."
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 the Company has an interest, without regard to the size
of that 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. Liquified petroleum gas.
MBbl. One thousand barrels of oil or other liquid hydrocarbons.
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MBoe. One thousand Boe.
Mcf. One thousand cubic feet.
MMBbl. One million barrels of oil or other liquid hydrocarbons.
MMBoe. One million Boe.
MMBtu. One million Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Natural gas liquids (NGL) 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 the Company's working interest in those wells or acres.
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.
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, net of estimated production and future development costs, using prices
and costs in effect 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%.
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.
86
<PAGE> 91
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.
3-D Seismic Survey. 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.
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.
87
<PAGE> 92
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
<S> <C>
CONSOLIDATED FINANCIAL STATEMENTS OF CMS NOMECO OIL & GAS CO.:
Report of Independent Public Accountants.............................................. F-3
Consolidated Balance Sheets as of December 31, 1993 and 1994 and September 30, 1995
(unaudited)......................................................................... F-4
Consolidated Statements of Income for the years ended December 31, 1992, 1993 and 1994
and for the nine months ended September 30, 1994 (unaudited) and 1995 (unaudited)... F-5
Consolidated Statements of Stockholder's Equity for the years ended December 31, 1992,
1993 and 1994 and for the nine months ended September 30, 1995 (unaudited).......... F-6
Consolidated Statements of Cash Flows for the years ended December 31, 1992, 1993 and
1994 and for the nine months ended September 30, 1994 (unaudited) and 1995
(unaudited)......................................................................... F-7
Notes to Consolidated Financial Statements............................................ F-8
Supplemental Information -- Oil and Gas Producing Activities (unaudited).............. F-24
CONSOLIDATED FINANCIAL STATEMENTS OF CMS NOMECO INTERNATIONAL, INC.
(FORMERLY WALTER INTERNATIONAL, INC.):
Report of Independent Public Accountants.............................................. F-30
Consolidated Balance Sheets as of December 31, 1994 and January 31, 1995
(unaudited)......................................................................... F-31
Consolidated Statements of Operations and Accumulated Deficit for the year ended
December 31, 1994 and for the one month ended January 31, 1995 (unaudited).......... F-32
Consolidated Statements of Cash Flows for the year ended December 31, 1994 and for the
one month ended January 31, 1995 (unaudited)........................................ F-33
Notes to Consolidated Financial Statements............................................ F-34
Supplemental Information -- Oil Producing Activities (unaudited)...................... F-40
CONSOLIDATED FINANCIAL STATEMENTS OF WALTER INTERNATIONAL, INC.:
Report of Independent Auditors........................................................ F-42
Consolidated Balance Sheets as of December 31, 1992 and 1993.......................... F-43
Consolidated Statements of Operations and Accumulated Deficit for the years ended
December 31, 1992 and 1993.......................................................... F-44
Consolidated Statements of Cash Flows for the years ended December 31, 1992 and
1993................................................................................ F-45
Notes to Consolidated Financial Statements............................................ F-46
COMBINED FINANCIAL STATEMENTS OF AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES:
Report of Independent Auditors........................................................ F-53
Combined Balance Sheets as of December 31, 1993 and 1994.............................. F-54
Combined Statements of Operations for the years ended December 31, 1992, 1993 and
1994................................................................................ F-55
Combined Statements of Stockholder's Equity for the years ended December 31, 1992,
1993 and 1994....................................................................... F-56
Combined Statements of Cash Flows for the years ended December 31, 1992, 1993 and
1994................................................................................ F-57
Notes to Combined Financial Statements................................................ F-58
Supplemental Information -- Oil Producing Activities (unaudited)...................... F-61
Combined Balance Sheet as of January 31, 1995 (unaudited)............................. F-63
Combined Statement of Operations for the one month ended January 31, 1995 (unaudited)
and Combined Statement of Stockholder's Equity for the one month ended January 31,
1995 (unaudited).................................................................... F-64
Combined Statement of Cash Flows for the one month ended January 31, 1995
(unaudited)......................................................................... F-65
Notes to Combined Financial Statements (unaudited).................................... F-66
CONSOLIDATED FINANCIAL STATEMENTS OF TERRA ENERGY LTD.:
Report of Independent Public Accountants.............................................. F-67
Consolidated Balance Sheets as of December 31, 1994 and July 31, 1995 (unaudited)..... F-68
Consolidated Statements of Earnings for the year ended December 31, 1994 and for the
seven months ended July 31, 1994 (unaudited) and 1995 (unaudited)................... F-69
</TABLE>
F-1
<PAGE> 93
<TABLE>
<CAPTION>
PAGE
<S> <C>
Consolidated Statements of Shareholders' Equity for the year ended December 31, 1994
and for the seven months ended July 31, 1995 (unaudited)............................ F-70
Consolidated Statements of Cash Flows for the year ended December 31, 1994 and for the
seven months ended July 31, 1994 (unaudited) and 1995 (unaudited)................... F-71
Notes to Consolidated Financial Statements............................................ F-72
Supplemental Information -- Oil and Gas Producing Activities (unaudited).............. F-81
PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS OF WALTER INTERNATIONAL, INC. (UNAUDITED):
Pro Forma Statement of Operations for the one month ended January 31, 1995 and the
nine months ended September 30, 1995................................................ F-84
Pro Forma Balance Sheet as of September 30, 1995...................................... F-85
Pro Forma Statement of Operations for the year ended December 31, 1994................ F-86
</TABLE>
F-2
<PAGE> 94
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors,
CMS NOMECO Oil & Gas Co.:
We have audited the accompanying consolidated balance sheets of CMS NOMECO
Oil & Gas Co. (a Michigan corporation and wholly owned subsidiary of CMS
Enterprises Company) and subsidiaries as of December 31, 1993 and 1994, 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, 1994. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of CMS NOMECO
Oil & Gas Co. and subsidiaries as of December 31, 1993 and 1994, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1994 in conformity with generally accepted accounting
principles.
As explained in note 1.i to the consolidated financial statements, the
Company, effective January 1, 1992, changed its method of accounting for
postretirement benefits other than pension costs.
Arthur Andersen LLP
Detroit, Michigan,
January 27, 1995.
F-3
<PAGE> 95
CMS NOMECO OIL & GAS CO.
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------- SEPTEMBER 30,
1993 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
ASSETS
Current Assets:
Cash.................................................... $ 932 $ 1,117 $ 5,255
Temporary cash investments.............................. -- 4,969 3,813
Accounts Receivable:
Revenues and other, less allowances of $226 in 1993,
1994 and 1995...................................... 9,680 10,973 55,893
Income tax benefits................................... 5,442 3,527 11,516
Affiliates............................................ 2,170 83 1,665
Other................................................... 1,059 1,435 13,200
-------- -------- -----------
19,283 22,104 91,342
Investments and other assets................................. 7,088 12,539 23,121
Property, Plant and Equipment, at cost (full cost method).... 841,524 934,460 1,073,981
Less accumulated depreciation, depletion and
amortization.......................................... 465,534 496,403 526,038
-------- -------- -----------
375,990 438,057 547,943
-------- -------- -----------
Total assets....................................... $402,361 $472,700 $ 662,406
======== ======== ===========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt.................... $ 9,579 $ 9,579 $ 6,677
Accounts payable........................................ 5,558 3,611 49,308
Accrued interest........................................ 1,561 1,349 1,171
Accrued taxes and other................................. 2,317 1,955 9,215
-------- -------- -----------
19,015 16,494 66,371
Long-term debt............................................... 109,141 119,462 192,371
Deferred Credits:
Deferred income taxes................................... 47,343 43,349 54,590
Other................................................... 3,873 4,509 7,985
-------- -------- -----------
51,216 47,858 62,575
Stockholder's Equity:
Common stock, no par value, authorized 55.0 million
shares, issued and outstanding 20.0 million shares.... 80,900 137,000 169,726
Retained earnings....................................... 142,089 151,886 171,363
-------- -------- -----------
222,989 288,886 341,089
-------- -------- -----------
Total liabilities and stockholder's equity......... $402,361 $472,700 $ 662,406
======== ======== ===========
</TABLE>
The accompanying notes are an integral part of these statements.
F-4
<PAGE> 96
CMS NOMECO OIL & GAS CO.
CONSOLIDATED STATEMENTS OF INCOME
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1992 1993 1994 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS, EXCEPT PER SHARE
AMOUNTS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate.......................... $26,553 $26,635 $26,831 $18,479 $45,423
Natural gas................................. 34,391 40,995 39,904 30,550 32,927
Other operating............................. 8,408 6,275 12,333 10,107 17,738
------- ------- ------- ------- -------
69,352 73,905 79,068 59,136 96,088
Operating Expenses:
Depreciation, depletion and amortization.... 32,566 35,605 34,919 25,358 34,072
Cost center write-offs...................... 5,744 9,648 5,612 452 2,184
Operating and maintenance................... 13,476 15,005 19,323 14,050 23,204
General and administrative.................. 4,489 5,599 6,345 4,346 5,609
Production and other taxes.................. 3,997 4,221 3,838 3,010 3,463
Cost of products sold....................... 1,427 1,127 973 682 773
------- ------- ------- ------- -------
61,699 71,205 71,010 47,898 69,305
Pretax operating income.......................... 7,653 2,700 8,058 11,238 26,783
Other income..................................... 163 382 239 152 522
Interest expense, net............................ 4,954 3,844 4,023 2,624 6,455
------- ------- ------- ------- -------
Income (loss) before income taxes................ 2,862 (762) 4,274 8,766 20,850
Income tax provision (benefit)................... (2,100) (5,900) (5,523) (2,148) 386
Income before accounting change and
extraordinary item............................. 4,962 5,138 9,797 10,914 20,464
------- ------- ------- ------- -------
Extraordinary item, early retirement of debt, net
of income taxes................................ -- -- -- -- (987)
Cumulative effect of accounting change, net of
income taxes................................... (1,124) -- -- -- --
------- ------- ------- ------- -------
Net income....................................... $ 3,838 $ 5,138 $ 9,797 $10,914 $19,477
======= ======= ======= ======= =======
Net income per common share before extraordinary
item and accounting change..................... $ 0.25 $ 0.26 $ 0.49 $ 0.55 $ 1.02
Cumulative effect of accounting change and
extraordinary item, net of income taxes........ (.06) -- -- -- (.05)
------- ------- ------- ------- -------
Net income per common share...................... $ 0.19 $ 0.26 $ 0.49 $ 0.55 $ 0.97
======= ======= ======= ======= =======
Average common shares outstanding (000's)........ 20,000 20,000 20,000 20,000 20,000
======= ======= ======= ======= =======
</TABLE>
The accompanying notes are an integral part of these statements.
F-5
<PAGE> 97
CMS NOMECO OIL & GAS CO.
CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
COMMON RETAINED
STOCK EARNINGS
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Balance at December 31, 1991............................................. $ 65,600 $133,113
Net income.......................................................... -- 3,838
Contributions from parent........................................... 5,800 --
-------- --------
Balance at December 31, 1992............................................. 71,400 136,951
Net income.......................................................... -- 5,138
Contributions from parent........................................... 9,500 --
-------- --------
Balance at December 31, 1993............................................. 80,900 142,089
Net income.......................................................... -- 9,797
Contributions from parent........................................... 56,100 --
-------- --------
Balance at December 31, 1994............................................. 137,000 151,886
Net income (unaudited).............................................. -- 19,477
Contributions from parent (unaudited)............................... 32,726 --
-------- --------
Balance at September 30, 1995 (unaudited)................................ $169,726 $171,363
======== ========
</TABLE>
The accompanying notes are an integral part of these statements.
F-6
<PAGE> 98
CMS NOMECO OIL & GAS CO.
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------------- -------------------
1992 1993 1994 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Cash Flow from Operating Activities:
Net income.......................... $ 3,838 $ 5,138 $ 9,797 $ 10,914 $ 19,477
Principal noncash items:
Depreciation, depletion and
amortization................... 32,566 35,605 34,919 25,358 34,072
Cost center write-offs............ 5,744 9,648 5,612 452 2,184
Deferred income taxes, net........ (1,307) (6,588) (4,331) (3,547) 1,641
Investment tax credit, net........ (200) (132) (55) (43) --
Net change in:
Accounts receivable............... 4,790 1,134 4,368 (1,845) (17,955)
Other current assets.............. 342 (489) (376) (301) (3,078)
Accounts payable.................. (3,823) 1,309 (1,947) 1,054 14,900
Accrued interest.................. 137 (146) (212) (1,056) (230)
Accrued taxes and other
liabilities.................... 978 69 (1,686) 1,969 389
Accrued postretirement benefits... 1,704 176 346 -- --
Other, net........................ (38) 247 486 671 1,807
-------- -------- --------- -------- --------
44,731 45,971 46,921 33,626 53,207
Cash Flow from Financing Activities:
Revolving credit additions
(retirements), net.................. 12,600 26,900 19,900 21,200 24,300
Equity contributions from parent....... 5,800 9,500 56,100 52,000 9,000
Proceeds from bank loans............... 4,182 857 -- -- --
Repayment of bank loans................ -- (418) (1,008) (756) (972)
Repayment of notes..................... -- (5,000) (8,571) (8,571) (36,428)
-------- -------- --------- -------- --------
22,582 31,839 66,421 63,873 (4,100)
Cash Flow from Investing Activities:
Exploration and development
expenditures...................... (53,287) (75,678) (71,185) (56,063) (46,881)
Purchases of oil and gas
properties........................ (13,600) (865) (33,528) (33,192) (143)
Proceeds from sale of properties.... 991 5,024 7,278 3,101 5,256
Investments in Yemen................ -- (2,720) (5,489) (3,739) (2,304)
Interest capitalized................ (2,163) (3,511) (5,264) (3,961) (2,053)
-------- -------- --------- -------- --------
(68,059) (77,750) (108,188) (93,854) (46,125)
Net increase (decrease) in cash and
temporary cash investments............. (746) 60 5,154 3,645 2,982
-------- -------- --------- -------- --------
Cash And Temporary Cash Investments:
Beginning of period................. 1,618 872 932 932 6,086
-------- -------- --------- -------- --------
End of period....................... $ 872 $ 932 $ 6,086 $ 4,577 $ 9,068
======== ======== ========= ======== ========
Supplementary Information:
Interest payments net of amounts
capitalized....................... $ 4,666 $ 3,904 $ 3,860 $ 1,698 $ 7,892
Income tax payments (refunds)....... (7,643) 518 2,177 2,082 5,550
</TABLE>
The accompanying notes are an integral part of these statements.
F-7
<PAGE> 99
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES
CMS NOMECO Oil & Gas Co. (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. Certain
reclassifications have been reflected in the prior years' amounts to conform
with the 1994 presentation. Beginning in June 1995, transportation expense,
which had been shown as an operating expense, has been deducted from operating
revenues and prior periods have been reclassified.
The consolidated financial statements and related information as of and for
the nine months ended September 30, 1994 and 1995 included herein are unaudited
and, in the opinion of management, reflect all adjustments (consisting of only
recurring adjustments) necessary for a fair presentation of financial position,
results of operations and cash flows.
These unaudited consolidated financial statements should be read in
conjunction with the Company's consolidated financial statements as of and for
the year ended December 31, 1994. The consolidated results of operations for the
nine months ended September 30, 1994 and 1995 are not necessarily indicative of
operating results for a full year. Additionally, all other financial statement
information contained in the Notes to Consolidated Financial Statements, which
occurred subsequent to December 31, 1994, is unaudited.
A summary of significant accounting policies is set forth below:
A. BASIS OF PRESENTATION
The consolidated financial statements include the Company and its
subsidiaries. All significant intercompany accounts and transactions have been
eliminated.
B. 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.
C. TEMPORARY CASH INVESTMENTS
All highly liquid investments with an original maturity of three months or
less are considered temporary cash investments.
D. OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting and capitalizes all
costs related to its exploration and development program, including the cost of
nonproductive drilling and surrendered acreage, in cost centers on a
country-by-country basis. Such capitalized costs include lease acquisition,
geological and geophysical work, delay rentals, drilling, completing and
equipping oil and gas wells, together with internal costs directly attributable
to property acquisition, exploration and development activities. The capitalized
costs in each cost center are amortized on an overall unit-of-production method
based on total estimated proved oil and gas reserves. Additionally, certain
costs associated with major development projects and all costs of unevaluated
leases are excluded from the depletion base until reserves associated with the
projects are proved or until impairment occurs. Costs associated with
exploration and development activities in non-producing cost centers are not
amortized until proved reserves are discovered and produced or a determination
is made that the value of the property is less than the costs incurred.
To the extent that capitalized costs (net of accumulated depreciation,
depletion and amortization) less deferred taxes exceed the sum of discounted
estimated future net cash flows from proved oil and natural gas
F-8
<PAGE> 100
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
reserves (using unescalated prices and costs and a 10% per annum discount rate)
and the lower of cost or market value of unproved properties after income tax
effects, such excess costs are charged against earnings. Accordingly, the
Company has written off $0.5 million ($0.3 million after taxes) and $0.2 million
($0.1 million after taxes) for the nine months ended September 30, 1994 and
1995, respectively, $1.9 million ($1.2 million after taxes) in 1992, $7.7
million ($5.0 million after taxes) in 1993 and $4.9 million ($3.2 million after
taxes) in 1994 for prediscovery non-U.S. expenditures. Also, the Company wrote
down the value of Colombia ($3.1 million in 1992 and $1.9 million in 1993),
Papua New Guinea ($0.7 million in 1994) and U.S. ($2.0 million in third quarter
1995) properties in excess of the cost center ceiling. These charges are
included in cost center write-offs on the Consolidated Statements of Income.
E. INCOME TAXES
The Company follows Statement of Financial Accounting Standards ("SFAS")
No. 109, Accounting for Income Taxes. Accordingly, the Company uses an asset and
liability method to record the deferred tax consequences of its temporary
differences. Provision is made for deferred income taxes resulting from
temporary differences arising from the capitalization of certain exploration and
development costs for book purposes which are deducted currently for income tax
purposes, and for other temporary differences between book income and taxable
income. As these temporary differences reverse, the related deferrals are
credited to income. The Company does not provide deferred taxes on the
undistributed earnings of its non-U.S. subsidiaries as such earnings are
intended to be permanently reinvested.
The deferred investment tax credit was being amortized to income over a
ten-year period; none remains at December 31, 1994.
SFAS No. 109 requires classifying any deferred tax liability and asset as
current or non-current based on the classification of the related asset or
liability and expanding the disclosure requirements related to deferred tax
assets and liabilities. Additionally, a deferred tax asset is recognized only if
it is apparent that the temporary difference will reverse in the foreseeable
future.
F. PENSION 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
$46,000, $83,000 and $59,000 for the years ended December 31, 1992, 1993 and
1994. respectively.
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.
G. ACCOUNTING FOR INVESTMENTS
The Company uses the pro rata consolidation method of accounting for all of
its working interests, except for the two stock investments in less than
majority owned companies described below.
The Company's ownership share of Command Petroleum Holdings N.L.
("Command") stock (3.3% as of December 31, 1993 and 2.7% as of December 31,
1994, respectively) requires the Company to follow the cost method of accounting
for its investment in Command. The book value of this investment as of December
31, 1994 was $2.2 million and the fair market value was $2.8 million. The
investment was written down to the lower of cost or fair market value which was
$2.0 million as of December 31, 1992. The 1992 charge against income of $0.8
million is included in cost center write-offs on the Consolidated Statements of
Income.
F-9
<PAGE> 101
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1993 and 1994, the Company invested $2.7 million and $5.5 million,
respectively, in Comeco Petroleum Inc. ("Comeco"). The Company currently owns
50% of Comeco, and accounts for this investment under the equity method of
accounting. Comeco owns a 28.57% working interest in the East Shabwa Block in
Yemen.
H. SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
The Company participates in CMS Energy's Supplemental Executive Retirement
Plan ("SERP") for certain management employees. Benefits are based on the
employees' service and earnings as defined in the SERP. In 1988, a trust was
established and partially funded. 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. SERP expenses amounted
to $320,000 in 1992, $190,000 in 1993 and $263,000 in 1994. As of December 31,
1993 and 1994, the Company's share of trust assets was approximately $1.9
million at cost and the projected benefit obligation was $1.4 million and $1.7
million, respectively.
I. HEALTH CARE AND LIFE INSURANCE BENEFITS
The Company provides health care and life insurance benefit plans for its
employees and retirees through insurance companies. The postretirement plans are
noncontributory and currently unfunded. In 1992, the Company changed its method
of accounting for the cost of these plans from a pay-as-you-go (cash) method to
an accrual method as required by SFAS No. 106, Employers' Accounting for
Postretirement Benefits Other than Pensions, and recognized the December 31,
1992 unfunded transition obligation as a one-time cumulative accounting
adjustment. The funded status of the postretirement benefit plans is reconciled
with the liability recorded as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Accumulated Postretirement Benefit Obligation:
Retirees............................................................. $ 162 $ 388
Fully eligible active plan participants.............................. 261 377
Other active plan participants....................................... 1,542 1,551
------ ------
1,965 2,316
Plan assets and unrecorded losses.................................... 15 (209)
------ ------
Recorded liability................................................... $1,980 $2,107
====== ======
</TABLE>
The 1992, 1993 and 1994 cost was comprised of $199,000, $132,000 and
$194,000, respectively, for service plus $143,000, $144,000 and $152,000,
respectively, for interest.
For measurement purposes, a 10% annual rate of increase was assumed in the
per capita cost of covered health care benefits for 1995. The rate was assumed
to gradually decrease to 6.0% per annum by the year 2004 and thereafter. The
health care cost trend rate assumption has an impact on the accumulated
postretirement benefit obligation and on future amounts accrued. A one
percentage point increase each year in the assumed health care cost would
increase the accumulated postretirement benefit obligation as of December 31,
1994 by $283,000 and increase the 1994 cost by $27,000. For the years ended
December 31, 1993 and 1994, the weighted average discount rate was 7.25% and
8.0% per annum, respectively, and the expected long term rate of return on plan
assets was 8.5% and 7.0% per annum, respectively.
F-10
<PAGE> 102
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
J. NET INCOME PER COMMON SHARE
Net income per common share is based upon the number of common shares
outstanding during each period.
K. NEW ACCOUNTING STANDARDS
In December 1994, the American Institute of Certified Public Accountants
issued Statement of Position 94-6, Disclosure of Certain Significant Risks and
Uncertainties, effective for 1995 year-end financial statements. The Company
does not believe that it will be significantly affected by the Statement, which
requires disclosures about the nature of a company's operations and the use of
estimates in the financial statements.
L. COMMON STOCK SPLIT
These financial statements and Notes thereto reflect retroactively (i) the
increase in the authorized shares of Common Stock to 55.0 million, (ii) the
issuance of 9.4 million shares of Common Stock, which increased the Common Stock
outstanding from 14.6 million shares to 24.0 million shares, based on a stock
split of approximately 1.644 for 1.0 effected on October 25, 1995, and (iii) the
cancellation of 4.0 million shares of Common Stock which decreased the amount
outstanding from 24.0 million shares to 20.0 million shares, based on a reverse
stock split of approximately 0.833 for 1.0 effected on January 19, 1996. All per
share amounts in the financial statements reflect this split.
M. SUPPLEMENTAL NONCASH ACTIVITIES
During 1995, CMS Energy acquired all of the outstanding capital stock of
both Walter International, Inc. and subsidiaries ("Walter") and Terra Energy,
Ltd. and subsidiaries ("Terra"), as discussed further in Notes 2 and 3, payable
in Common Stock of CMS Energy. Upon consummating the acquisitions, the stock of
Walter and Terra were transferred from CMS Energy to the Company, and the
Company has recorded in the consolidated balance sheet as of September 30, 1995
the fair value of the Walter and Terra assets and liabilities, a noncash
contribution from CMS Energy of $23.8 million, cash contributions from CMS
Energy of $4.5 million and $67.8 million for notes payable to CMS Energy. These
acquisitions were recorded under the purchase method of accounting. The fair
value of Walter's and Terra's assets and liabilities at the date of the
respective acquisitions are presented in Note 2.
N. EMPLOYEE WELL PARTICIPATION PROGRAM
Various employees are eligible to participate in the Company's Employee
Well Participation Program, which consists of two plans ("Plan A and Plan B").
The Employee Well Participation Program, which was recently terminated as to any
future wells drilled or acquired, was in effect from April 1, 1980 to October 4,
1995. Under Plan A, participating employees receive monthly cash incentive
payments which are charged to compensation expense and thus a component of
general and administrative expenses in the respective years paid. Under Plan B,
selected employees receive grants of vested property interests which are
recognized in the financial statements as compensation expense, with a
corresponding reduction in the Company's investment in the properties to which
these interests relate. Plan A and Plan B expenses amounted to approximately
$375,000, $443,000 and $1,922,000 for the years ended December 31, 1992, 1993
and 1994, respectively.
2. PURCHASES OF OIL AND GAS PROPERTIES
During 1994, the Company purchased 9.1 MMBbls of estimated proved oil
reserves and 9.4 billion cubic feet ("Bcf") of estimated proved gas reserves in
three separate acquisitions totaling $33.5 million. The Company participated in
four separate reserve acquisitions in 1992. These purchases added approximately
2.7 million barrels of oil equivalent ("MMBoe") of estimated proved reserves at
an aggregate net cost of $13.6 million.
F-11
<PAGE> 103
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
1995 PURCHASES OF OIL AND GAS PROPERTIES (UNAUDITED)
In February 1995, the Company acquired Walter (through contributions from
CMS Energy, "the Walter Acquisition"). This acquisition increased certain line
items on the Consolidated Balance Sheet as follows:
<TABLE>
<CAPTION>
(DOLLARS IN
THOUSANDS)
<S> <C>
Cash and temporary cash investments....................................... $ 7,411
Accounts receivable....................................................... 9,488
Other current assets...................................................... 3,654
Property, plant and equipment............................................. 37,457
Current maturities of long-term debt...................................... 1,968
Accounts payable.......................................................... 7,615
Accrued interest.......................................................... 52
Accrued taxes and other................................................... 1,621
Long-term debt............................................................ 16,280
Deferred income taxes and other credits................................... 3,248
Additional paid-in capital................................................ 27,226
</TABLE>
In August 1995, the Company acquired Terra (through contributions from CMS
Energy, "the Terra Acquisition"). This acquisition increased certain line items
on the Consolidated Balance Sheet as follows:
<TABLE>
<CAPTION>
(DOLLARS IN
THOUSANDS)
<S> <C>
Cash and temporary cash investments....................................... $ 8,745
Accounts receivable....................................................... 27,048
Other current assets...................................................... 5,033
Investments and other assets.............................................. 7,940
Property, plant and equipment............................................. 55,100
Current maturities of long-term debt...................................... 2,600
Accounts payable.......................................................... 23,182
Accrued taxes and other................................................... 5,250
Long-term debt............................................................ 62,476
Deferred income taxes and other credits................................... 9,358
Additional paid-in capital................................................ 1,000
</TABLE>
The assets purchased have been included in property, plant and equipment at
cost. Results of operations include income from the purchased properties
beginning with the month of closing.
PRO FORMA INFORMATION (UNAUDITED)
The following pro forma statement of income information has been prepared
to give effect to the acquisition of Walter and Terra as if such transactions
had occurred at January 1, 1994. The other property acquisitions in 1994, noted
above, are deemed to be insignificant for inclusion in the pro forma
information. The historical results of operations have been adjusted to reflect
(i) revenues and expenses attributable to the properties, (ii) the difference
between the acquired properties' historical depreciation, depletion and
amortization and such expense calculated based on the value allocated to the
acquired assets, and (iii) adjustment of income tax expense to reflect the
combined results of operations. Management does not believe the pro forma
amounts purport to be indicative of the results of operations that would have
been reported had the acquisitions occurred as of the dates indicated below, or
that may be reported in the future.
F-12
<PAGE> 104
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
<TABLE>
<CAPTION>
PRO FORMA
------------------------------
NINE MONTHS
YEAR ENDED ENDED
DECEMBER 31, SEPTEMBER 30,
1994 1995
(DOLLARS IN THOUSANDS,
EXCEPT PER SHARE AMOUNTS)
<S> <C> <C>
Operating revenues................................................. $111,217 $ 104,714
Pretax operating income............................................ 23,891 33,229
Income before extraordinary item................................... 22,827 26,262
Net income......................................................... 22,827 25,275
Net income per share............................................... $ 1.14 $ 1.26
</TABLE>
3. LONG-TERM DEBT
Long-term debt consisted of the following:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- SEPTEMBER 30,
1993 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
$130,000,000 revolving credit agreement ("Credit
Agreement") payable in 36 monthly principal
installments beginning November 1, 1996,
variable interest rate, 7.3% average rate per
annum for the year ended December 31, 1994..... $ 69,100 $ 89,000 $ 113,300
Senior serial notes, Series A, payable in annual
principal installments of $5.0 million on each
March 1 through 1997, interest at 9.3% per
annum payable semi- annually on each March 1
and September 1*............................... 20,000 15,000 --
Senior serial notes, Series B, payable in annual
principal installments of approximately $3.6
million on each March 1 through 2000, interest
at 9.45% per annum payable semi-annually on
each March 1 and September 1*.................. 25,000 21,428 --
Notes payable to CMS Energy, interest at LIBOR
plus 2.0% per annum, maturity dates of November
1, 1999........................................ -- -- 67,840
OPIC guaranteed loans............................ 4,620 3,613 14,172
Terra debt assumed............................... -- -- 3,736
-------- -------- ---------
Total long-term debt................... 118,720 129,041 199,048
Less current maturities of long-term debt........ 9,579 9,579 6,677
-------- -------- ---------
$109,141 $119,462 $ 192,371
======== ======== =========
</TABLE>
- ------------------------------
* Repaid in full August 10, 1995 with additional bank borrowings under the
Credit Agreement.
F-13
<PAGE> 105
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1994, principal maturities of long-term debt over the
next five years are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN
THOUSANDS)
<S> <C>
1995...................................................................... $ 9,579
1996...................................................................... 14,523
1997...................................................................... 39,243
1998...................................................................... 33,824
1999...................................................................... 28,291
Thereafter................................................................ 3,581
---------
$ 129,041
=========
</TABLE>
In November 1993, the Company amended the terms of its Credit Agreement and
increased the amount of the commitment to $110.0 million. In March 1995, the
commitment was increased to $130.0 million, and in November 1995 it was
increased to $140.0 million. Borrowings under the agreement are revolving credit
loans for three years which convert to term loans on November 1, 1996. The term
loans are payable in 36 monthly installments through November 1, 1999. The
Credit Agreement provides various options to the Company relative to interest
rates. As of December 31, 1994 and September 30, 1995, the average rate in
effect was 7.3% per annum and 7.2% per annum, respectively, and amounts
outstanding were $89.0 million and $113.3 million, respectively. The Credit
Agreement requires a commitment fee.
The Company also had a series of note agreements dated as of March 1, 1990
pursuant to which $36.4 million of senior serial notes were outstanding as of
December 31, 1994. The $27.9 million of notes outstanding were repaid in full
August 10, 1995, at a premium of $1.5 million resulting in an after-tax
extraordinary item of $987,000 being reflected on the Consolidated Statements of
Income.
In 1992, the Company utilized an additional borrowing alternative through
Overseas Private Investment Corporation ("OPIC") project financing in Equatorial
Guinea ($3.6 million outstanding as of December 31, 1994). As of September 30,
1995, $14.2 million of project financing debt is outstanding under agreements
with OPIC. These OPIC guaranteed loans funded development drilling for the Alba
Field in Equatorial Guinea ($5.4 million) and acquisition financing for the
Yombo Filed in the Congo ($8.8 million).
At December 31, 1994, the Company also had a $4.4 million stand-by letter
of credit in support of the Ecuador project. This letter of credit expired in
1995 and has not been renewed.
The aggregate borrowing base under the Credit Facility is limited to the
estimated loan value of the Company's oil and gas reserves, subject to certain
exclusions, based upon forecast rates of production and current commodity
pricing assessments, as periodically redetermined by the Banks which are parties
to the Credit Agreement. The Banks have broad discretion in determining which of
the Company's reserves to include in the borrowing base. The Company is in early
stages of negotiations to, among other things, increase commitment levels and
expand the borrowing base under the Credit Facility.
The total borrowing base at December 31, 1994, was $134.7 million. Because
of adjustments to the borrowing base for outstanding letters of credit and
project financing debt in Equatorial Guinea, the total amount available for
borrowing from all sources as of December 31, 1994 was $133.7 million. Of the
total amount available, $129.0 million in borrowings were outstanding as of
December 31, 1994.
Under the terms of the Credit Agreement, the Company must (i) maintain a
ratio of current assets to current liabilities at least equal to 0.75 to 1.0,
(ii) maintain a ratio of total liabilities to tangible net worth of no more than
0.75 to 1.0, (iii) maintain a minimum tangible net worth of $150.0 million, and
(iv) maintain a ratio of cash flow after dividends to fixed charges for the most
recent four quarters of 2.0 to 1.0. Restrictive covenants under the Credit
Agreement 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
F-14
<PAGE> 106
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Banks have the right to require the Company to repay all advances under the
Credit Agreement within 90 days after notification to the banks that (i) CMS
Energy no longer beneficially owns a majority of the outstanding voting stock of
the Company or (ii) all or substantially all of the assets of the Company are
sold.
As of September 30, 1995, the Company's current ratio was 1.60 to 1.0, its
total liabilities to tangible net worth ratio was 0.72 to 1.0, its tangible net
worth was $302.0 million and its ratio of cash flow after dividends to fixed
charges was 4.9 to 1.0.
The fair value of these facilities, because of prepayment premiums on the
senior notes, is estimated to exceed the recorded amounts by approximately $2.5
million at December 31, 1993 and $2.1 million at December 31, 1994.
In August 1995, the Company issued a note in the principal amount of
approximately $61.3 million (the "Terra Note") 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 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 (the "Walter Note") to CMS Energy in connection with
borrowings made to repay $6.5 million of indebtedness of Walter immediately upon
the closing of the Walter acquisition (the Terra Note and the Walter Note
together referred to herein as the "CMS Notes"). The CMS Notes bear interest at
the rate of London Interbank Offered Rate ("LIBOR") plus 2.0% per annum and have
a maturity date of November 1, 1999. Amounts outstanding under the CMS Notes are
expressly subordinate to the Company's Credit Agreement. Certain limitations are
placed on the Company's obligation to make payments on the loans under the CMS
Notes in the event of default under the terms of the Credit Agreement.
In connection with the Terra Acquisition, the Company assumed $3.7 million
of long-term debt comprised of $1.9 million of capitalized leases and $1.8
million outstanding under a term loan for financing of a processing plant under
construction.
In December 1994, CMS Energy arranged for the issuance of a standby letter
of credit, currently in the amount of $45.0 million, to secure the Company's
performance under the operating services agreement with respect to the Colon
Unit in Venezuela. The Company has agreed to reimburse CMS Energy on demand for
any draw made under the letter of credit and to pay to CMS Energy a fee of
2.125% per annum of the face amount of the letter of credit.
The Company has entered into an interest rate swap agreement with a bank
which effectively fixed the interest rate on $20.0 million of floating rate
debt. Under the agreement, the Company will pay the bank interest at the rate of
5.81% per annum over the term of the agreement and the bank will pay the Company
the three-month LIBOR rate. The swap agreement, which will terminate March 24,
1997, requires quarterly settlement payments. As of December 31, 1994, the bank
owed the Company $24,000 for the first quarter 1995 settlement.
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 are 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 Credits) are recognized by the Company to the extent utilized in the
consolidated return. Because the Company has been (and is expected to continue
to be) included in the consolidated federal income tax return filed by CMS
Energy, these Section 29 Credits have either been used currently to reduce the
tax liability of the CMS Energy consolidated group or have created a minimum tax
credit carryforward for use in future years. If the taxable income of the CMS
Energy consolidated group in future years were to be less than projected, the
Section 29 Credits would be deferred or eliminated. Moreover, if the Company
were deconsolidated from the CMS Energy consolidated group, the Company's
ability to realize any benefit from past or future Section 29
F-15
<PAGE> 107
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Credits would be materially restricted. The Company has no plans, and has been
advised by CMS Energy that CMS Energy has no plans, to effect any transaction in
the foreseeable future that would cause a deconsolidation of the Company from
the CMS Energy consolidated group. To the extent required by local law, the
Company and certain of its subsidiaries file income and other tax returns in
those non-U.S. countries in which the Company does business.
Significant components of income tax expense were as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1992 1993 1994 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Current tax (benefit).................... $(1,173) $ 820 $(1,137) $ 1,442 $(1,788)
Deferred tax (benefit)................... (1,307) (8,474) (4,331) (3,547) 1,642
Tax rate change.......................... -- 1,886 -- -- --
Amortization of investment tax credit.... (200) (132) (55) (43) --
------- ------- ------- ------- -------
$(2,680) $(5,900) $(5,523) $(2,148) $ (146)
======= ======= ======= ======= =======
Operating................................ $(2,100) $(5,900) $(5,523) $(2,148) $ 386
Other.................................... (580) -- -- -- (532)
------- ------- ------- ------- -------
$(2,680) $(5,900) $(5,523) $(2,148) $ (146)
======= ======= ======= ======= =======
</TABLE>
Income taxes shown above for the nine months ended September 30, 1995
include a $532,000 benefit which has been deducted from the "extraordinary item"
on the Consolidated Statements of Income. Income tax expense for 1993 includes
$1.9 million to increase prior years' deferred taxes to the revised statutory
rate of 35.0% per annum. Income taxes shown above for 1992 include $580,000
which has been deducted from the "cumulative effect of accounting change" on the
Consolidated Statements of Income.
Total income tax provision (benefit) was as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
--------------------------- -----------------
1992 1993 1994 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
U.S.:
Current............................. $(2,418) $ 59 $(1,777) $ 600 $(1,291)
Deferred............................ (2,121) (7,137) (5,103) (3,849) (376)
Non-U.S.:
Current............................. 1,245 761 640 842 (497)
Deferred............................ 614 417 717 259 2,018
------- ------- ------- ------- -------
Total.......................... $(2,680) $(5,900) $(5,523) $(2,148) $ (146)
======= ======= ======= ======= =======
</TABLE>
The Company's wholly owned subsidiaries have approximately $132.9 million
of net operating loss carryforwards generated in foreign taxing jurisdictions.
These foreign net operating loss carryforwards are available to offset income
taxable only in the jurisdictions 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 jurisdictions.
F-16
<PAGE> 108
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The principal components of the Company's deferred tax assets (liabilities)
recognized in the balance sheet are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------- SEPTEMBER 30,
1993 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Unsuccessful well and lease costs.................. $(132,248) $(144,669) $(152,180)
Intangible drilling costs.......................... (37,881) (38,204) (38,492)
Capitalized internal direct costs.................. (10,194) (15,423) (15,359)
Other.............................................. (10,878) (9,425) (10,440)
--------- --------- ---------
Gross deferred tax liabilities..................... (191,201) (207,721) (216,471)
Accumulated depreciation, depletion and
amortization..................................... 124,898 135,696 130,148
Alternative minimum tax credit carryforward........ 18,120 27,229 28,260
Other.............................................. 742 1,684 3,710
--------- --------- ---------
Gross deferred tax assets.......................... 143,760 164,609 162,118
--------- --------- ---------
Net deferred tax liability (includes current)...... $ (47,441) $ (43,112) $ (54,353)
========= ========= =========
</TABLE>
The actual income tax expense (benefits) differs from the amount computed
by applying the statutory U.S. Federal tax rate to income before income taxes as
follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
----------------------------- ------------------
1992 1993 1994 1994 1995
(UNAUDITED)
<S> <C> <C> <C> <C> <C>
(DOLLARS IN THOUSANDS)
Net income........................... $ 3,838 $ 5,138 $ 9,797 $10,914 $19,477
Income tax provision (benefit)....... (2,680) (5,900) (5,523) (2,148) (146)
------- ------- ------- ------- -------
1,158 (762) 4,274 8,766 19,331
Statutory U.S. income tax rate....... 34% 35% 35% 35% 35%
------- ------- ------- ------- -------
Expected income tax provision
(benefit).......................... 394 (267) 1,496 3,068 6,766
Increase (Decrease) In Taxes From:
Section 29 credits.............. (4,425) (5,605) (8,460) (6,000) (8,950)
Intercompany interest income.... -- 130 1,185 824 1,180
Effect of tax rate change....... -- 1,886 -- -- --
Command stock transactions...... 328 (2,147) -- -- --
Foreign taxes, net of U.S.
benefit....................... 1,247 318 533 263 955
Permanent differences........... 53 (435) (268) (103) 113
Other, net...................... (277) 220 (9) (200) (210)
------- ------- ------- ------- -------
Income tax provision (benefit)....... $(2,680) $(5,900) $(5,523) $(2,148) $ (146)
======= ======= ======= ======= =======
</TABLE>
5. RELATED PARTY TRANSACTIONS
Accounts receivable -- affiliates as of December 31, 1993 includes a $2.0
million equity infusion from CMS Energy which was paid to the Company in January
1994.
The Company sells natural gas to affiliates at rates approximating the
average price of gas paid to other area producers. Total sales to an affiliate,
Consumers Power Company, were approximately $3.4 million in 1992, $2.6 million
in 1993, $0.7 million in 1994 and $14.1 million for the nine months ended
September 30, 1995. Other intercompany transactions, principally services, are
billed at cost. Gas sales to the Midland Cogeneration Venture amounted to
approximately $6.4 million in 1992, $12.2 million in 1993 and $9.2 million in
1994.
F-17
<PAGE> 109
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In 1993, the Company received $2.6 million for its share of proceeds from
the sale of certain northern Michigan pipelines to an affiliate, CMS Gas
Transmission and Storage Company.
6. SIGNIFICANT CUSTOMERS
Revenues from sales to the Company's largest customers as a percent of
total Company revenues were:
<TABLE>
<CAPTION>
1992 1993 1994
<S> <C> <C> <C>
Midland Cogeneration Venture........................................ 9% 15% 11%
Total Petroleum Company............................................. 11% 8% 5%
</TABLE>
7. COMMITMENTS AND CONTINGENCIES
The Company estimates its capital expenditures for 1995 will total $180.0
million and certain commitments have been made in connection therewith.
A. HERITAGE RESOURCES, INC.
On December 18, 1987, Tribal Drilling Company ("Tribal") and certain other
plaintiffs, including J. Stuart Hunt, an affiliate of Tribal and a director of
the Company, filed a lawsuit in Dallas County, Texas (the "Dallas County
Lawsuit") seeking, among other things, a declaratory judgment against Heritage
Resources, Inc. ("Heritage") to the effect that Heritage was not qualified to
serve as the operator of Sections 21, 22 and 23 of the Crittendon Field located
in Winkler County, Texas, that Heritage had been properly removed as operator
pursuant to a vote of non-operator working interest owners and that Tribal is
the duly elected replacement operator. The Company, which was not originally a
plaintiff in the Dallas County Lawsuit, has non-operating working interests in
Sections 21 and 23 of the Crittendon Field. Pursuant to the court's order to
join all indispensable parties, on April 20, 1988 plaintiffs filed an amended
petition for declaratory relief which included the Company as one of the
plaintiffs. Heritage and certain related parties subsequently filed
counterclaims against all of the approximately 20 plaintiffs in the Dallas
County Lawsuit, including the Company, alleging various causes of action,
including without limitation claims for breach of contract, slander of title,
tortious interference with contract, tortious interference with business
relations, fraud, conspiracy and intentional infliction of emotional distress.
In the Dallas County Lawsuit, Heritage seeks approximately $100 million in
actual damages, exemplary damages not to exceed $1 billion, attorneys' fees and
declaratory relief. Trial of the Dallas County lawsuit, including counterclaims,
is currently scheduled for May 1996.
On December 18, 1987, Heritage and certain related parties filed two
separate lawsuits, since consolidated, in Winkler County, Texas (the "Winkler
County Lawsuit") against certain but not all non-operator working interest
owners of Sections 21 and 22 of the Crittendon Field. The Company was not a
party to the Winkler County Lawsuit. In the Winkler County Lawsuit, the
plaintiffs in many respects alleged the same course of conduct that is the
subject of the Dallas County Lawsuit, including Heritage's counterclaims. In
October 1992, a jury in the Winkler County lawsuit returned a verdict in favor
of plaintiffs and against the defendants in that litigation in an aggregate
amount in excess of $80 million plus attorneys' fees in excess of $20 million.
Certain defendants subsequently entered into a settlement with the plaintiffs
and the non-settling plaintiffs have appealed the judgments in the Winkler
County Lawsuit to the Texas Court of Appeals in El Paso, Texas. The Court of
Appeals has indicated that it may rule on the appeal by early 1996.
The Company believes that it has meritorious defenses to the counterclaims
in the Dallas County lawsuit and intends to defend itself vigorously in such
lawsuit. Management believes it is unlikely that the ultimate outcome of this
matter will have a material adverse effect on the Company's financial condition
or results of operations. However, the outcome of a jury trial is difficult to
predict, and there can be no assurance that the resolution of Heritage's
counterclaims against the Company will not have such a material adverse effect.
F-18
<PAGE> 110
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
B. ECUADOR
The Company has a 14% working interest in a consortium which is conducting
oil development and production activities in several fields within the Oriente
Block 16 in the Republic of Ecuador and Tivacuno Area in Eastern Ecuador, from
which production began in 1994. This project is operated by Maxus Energy
Corporation, a recently-acquired subsidiary of YPF Sociedad Anonima ("YPF").
Production from Block 16 and related fields in the Oriente Basin of the
Ecuadorian Amazon region has steadily increased since start-up in mid-1994, with
new wells and fields continuing to be brought on stream. As of June 30, 1995,
these fields represented approximately 14.1% of the Company's estimated total
proved reserves of oil and natural gas on a Boe basis. With lower worldwide oil
prices and increases in total project costs reducing the overall economic
benefit of these fields to the Ecuadorian government, the Ministry of Energy and
Mines in Ecuador has notified the members of the consortium with interests in
such fields that they should investigate alternatives for improving project
economics to the Ecuadorian government, including the renegotiation of the
service contract governing the Company's interest in these fields. The
Ecuadorian government has significant leverage to force changes due to its broad
governmental and regulatory powers. Authorizations have been and may in the
future be withheld and/or delayed to the economic detriment of the consortium
unless the discussions are productive. Discussions with the Ecuadorian
government concerning various alternatives began in late September 1995 and will
likely continue for the next several months. Although the Company cannot
currently predict what impact, if any, these discussions will have on the
project's economics, and there can be no assurance that these discussions or
their outcome will not have a material adverse effect on the Company's estimated
reserves, financial condition or results of operations; in management's opinion
the ultimate outcome will not have a material adverse impact on the Company's
financial condition or results of operations.
C. DUAL CONSOLIDATED LOSSES
As a result of the Walter Acquisition and related transactions, the Company
acquired certain assets located in the Congo which, prior to such transactions,
were owned by affiliates of Amoco Corporation ("Amoco"). As a result of certain
agreements entered into in connection with the Walter Acquisition, CMS Energy
and the Company could become jointly and severally liable to Amoco or to the
Internal Revenue Service for the recapture of "dual consolidated losses"
utilized by Amoco in prior years if a "triggering event" were to occur with
respect to such assets or with respect to the stock of Walter or certain of its
subsidiaries. Among the triggering events that could result in a recapture of
these dual consolidated losses would be a sale of the assets in question under
certain circumstances to an unrelated party. Another triggering event could be
the inability to continue to include Walter in the CMS Energy consolidated group
for federal income tax purposes. Such tax deconsolidation could occur if, for
instance, the Company issued sufficient shares of its Common Stock to unrelated
parties so that CMS Energy and its affiliates no longer owned at least 80% of
the Company's Common Stock. A tax deconsolidation could also occur if CMS Energy
reduced its holdings in the parent, the parent reduced its equity interest in
the Company to an extent that the parent no longer owned at least 80% of the
stock of the Company, or another U.S. corporation acquired 80% or more of CMS
Energy's stock. The Company has no plans, and has been advised by CMS Energy
that CMS Energy has no plans, to effect any transaction in the foreseeable
future that would cause a deconsolidation of the Company from the CMS Energy
consolidated group.
The amount of such potential liability could be up to $78.2 million, plus
an interest factor thereon. However, CMS Energy has agreed to indemnify the
Company for such liability if the triggering event results from acts or
omissions (i) of CMS Energy or any of its subsidiaries (other than the Company)
which occur after the initial public sale of the Company's Common Stock; (ii) of
the Company or any of its subsidiaries if such acts or omissions are approved by
the Board of Directors of the Company, which approval includes the affirmative
vote of a majority of the employees of CMS Energy or any of its subsidiaries
(other than the Company or any of its subsidiaries) who serve on the Company's
Board of Directors; or (iii) of any person if
F-19
<PAGE> 111
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
such acts or omissions occur prior to the initial public sale of the Company's
Common Stock. In return, the Company has agreed to indemnify CMS Energy for any
such dual consolidated loss tax liability if the triggering event results from
acts or omissions of the Company on or after the date of the initial public sale
of the Company's Common Stock which have not been approved by the Board of
Directors of the Company in the manner described in the preceding sentence. The
Company's subsidiary, Walter (now named CMS NOMECO International, Inc.), could
also be secondarily liable to Amoco for up to $59.0 million in potential
recapture tax, plus an interest factor thereon, if Nuevo Energy Company
("Nuevo"), an unaffiliated company, were to fail to satisfy its potential
liability to Amoco with respect to the recapture of dual consolidated losses
relating to certain other assets located in the Congo acquired by Nuevo's
affiliate from an affiliate of Amoco simultaneously with Walter's acquisition of
its Congolese assets. Because the net assets of Nuevo currently appear to be
adequate to satisfy any obligation which Nuevo may have with respect to such
other assets, the Company believes that it is unlikely that Walter would have to
make a payment to satisfy its secondary liability, although there can be no
assurance that this will be the case. However, if Walter were required to make
such a payment, it would have a claim against Nuevo, but would not be able to
recover such payment from CMS Energy under the above-described indemnity.
As a result of the Company's November 1993 acquisition (the "Yemen
Acquisition") of its ownership interest in Pecten Yemen Company ("PYC"), a
predecessor of Comeco Petroleum, Inc. from a member of the Shell Petroleum Inc.
consolidated group (the "SPI Group"), the Company agreed to become jointly and
severally liable for tax liabilities incurred by the SPI Group as a result of
the recapture of dual consolidated losses generated by PYC and utilized by the
SPI Group for tax purposes in prior years, if a "triggering event" were to occur
with respect to the stock or assets of PYC after such acquisition. It is
estimated that the Company's potential joint and several liability for dual
consolidated loss recapture tax liability incurred by the SPI Group would be
approximately $15.8 million plus an interest factor thereon. CMS Energy has not
agreed to indemnify the Company for this potential tax claim. However, if the
Company were required to make a payment in satisfaction of such liability due to
a triggering event that it did not solely cause, it would have a claim against
the other stockholders of Comeco for at least the amount by which such payment
exceeded $7.9 million, plus an interest factor thereon.
In addition to the potential recapture of the dual consolidated losses
arising from the Walter Acquisition, the Yemen Acquisition and related
transactions, the Company and its other domestic affiliates have incurred losses
in certain other foreign countries. The additional tax liability that could be
recaptured upon a triggering event (including the Company's obligations to other
parties under agreements similar to the indemnification agreement with Amoco and
the SPI Group described in the preceding paragraphs) would be approximately
$10.0 million as of December 31, 1994, plus an interest factor thereon.
D. HEDGING ARRANGEMENTS
The Company periodically enters into oil and gas price hedge arrangements
to mitigate its exposure to price fluctuations on the sale of oil and natural
gas. As of December 31, 1994, the Company was party to gas price collar
contracts on 7.3 Bcf of gas for the delivery months of January through December
1995 at prices ranging from $2.05 to $2.35 per MMBtu. The Company also had an
oil collar contract for 1,000 barrels ("Bbls") per day with a floor of $18.00
per Bbl and a ceiling of $19.95 per Bbl. The contracts are accounted for as
hedges; accordingly, any changes in market value and gains or losses from
settlements are deferred and recognized at such time as the hedged transaction
is completed. The Company received $241,000 in 1994 for settlement of January
1995 contracts on 0.6 Bcf of gas. At December 31, 1994, the fair value of these
hedge arrangements was not materially different than the book value.
The Company has also hedged certain of its gas supply obligations to the
Midland Cogeneration Venture in the years 2001 through 2006 by entering into an
agreement with Louis Dreyfus on May 1, 1989 to purchase the economic equivalent
of 10,000 MMBtu per day at a fixed, escalated price starting at $2.82 per MMBtu
in 2001. The settlement periods are each one year period ending December 31,
2001 through 2006 on
F-20
<PAGE> 112
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
3.65 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. If a party's exposure at any time
exceeds $2.0 million, that party is required to obtain a letter of credit in
favor of the other party for the excess over $2.0 million, to a maximum of $10.0
million. At December 31, 1994, the seller had arranged a letter of credit in the
Company's favor for $3.0 million.
E. OTHER
The Company is party to certain other 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 and other matters.
Management cannot predict the ultimate resolution of these matters but it
believes resulting liabilities, if any, will not have a material adverse effect
upon the Company's financial position or results of operations.
8. FINANCIAL INSTRUMENTS
The carrying amounts of cash, temporary cash investments and current
liabilities approximate their fair values due to their short-term nature. The
estimated fair values of long-term investments are based on quoted market prices
or, in the absence of specific market prices, on quoted market prices of similar
investments or other valuation techniques. The carrying amounts of all long-term
investments in financial instruments approximate fair value. The carrying amount
of long-term debt was $118.7 million and $129.0 million and the fair value of
long-term debt was $121.2 million and $131.1 million as of December 31, 1993 and
1994, respectively. Although the current fair value of the long-term debt may
differ from the current carrying amount, settlement of the reported debt is
generally not expected until maturity.
The fair values of the Company's off-balance-sheet financial instruments
are based on the amounts estimated to terminate or settle the instruments. The
fair value of interest rate swap agreements was $24,000 as of December 31, 1994.
Effective January 1, 1994, the Company adopted SFAS No. 115, Accounting for
Certain Investments in Debt and Equity Securities, which did not materially
impact the Company's financial position or results of operations.
9. LEASES
The Company and its subsidiaries lease various assets, including vehicles,
office equipment and office space under leases expiring on various dates through
1999. Rental expense under these leases was $527,000 and $541,000 for the years
ended December 31, 1993 and 1994, respectively.
Minimum rental commitments under the Company's non-cancelable leases at
December 31, 1994, were:
<TABLE>
<CAPTION>
(DOLLARS IN
THOUSANDS)
<S> <C>
1995...................................................................... $ 467
1996...................................................................... 431
1997...................................................................... 442
1998...................................................................... 442
1999...................................................................... 416
---------
$ 2,198
========
</TABLE>
F-21
<PAGE> 113
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
10. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment were as follows at December
31, 1993 and 1994:
<TABLE>
<CAPTION>
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Oil and Gas Properties:
Proved.................................................... $ 770,532 $ 866,156
Unproved.................................................. 47,591 48,401
--------- ---------
818,123 914,557
Other properties............................................... 23,401 19,903
Less accumulated depreciation, depletion and amortization...... (465,534) (496,403)
--------- ---------
Net property, plant and equipment.............................. $ 375,990 $ 438,057
========= =========
</TABLE>
Depreciation, depletion and amortization for oil and gas properties for the
years ended December 31, 1992, 1993 and 1994 were $32.4 million, $35.4 million
and $34.6 million, respectively.
11. GEOGRAPHIC AREA INFORMATION
Pertinent information with respect to the Company's business is presented
in the following table:
<TABLE>
<CAPTION>
OIL AND GAS
------------------------------------------------------
UNITED SOUTH AFRICA &
STATES AMERICA MIDDLE EAST OTHER TOTAL OTHER TOTAL
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
1992:
Revenues............... $ 54,105 $ -- $ 2,879 $ 4,634 $ 61,618 $ 7,734 $ 69,352
Pretax operating
income............... 9,351 (3,070) 1,377 356 8,014 (361) 7,653
Depreciation, depletion
and amortization..... 30,703 -- 510 1,161 32,374 192 32,566
Capital expenditures... 39,291 12,774 3,232 8,771 64,068 3,991 68,059
Identifiable assets at
December 31.......... 295,824 34,286 12,376 22,168 364,654 5,620 370,274
1993:
Revenues............... $ 55,939 $ 1,816 $ 4,971 $ 5,659 $ 68,385 $ 5,520 $ 73,905
Pretax operating
income............... 9,198 (1,805) 2,736 (4,254) 5,875 (3,175) 2,700
Depreciation, depletion
and amortization..... 31,699 947 1,075 1,690 35,411 194 35,605
Capital expenditures... 24,208 42,188 4,257 1,766 72,419 5,331 77,750
Identifiable assets at
December 31.......... 299,039 66,481 12,258 17,859 395,637 6,724 402,361
1994:
Revenues............... $ 58,292 $ 7,719 $ 4,520 $ 4,345 $ 74,876 $ 4,192 $ 79,068
Pretax operating
income............... 13,475 1,512 1,962 (3,839) 13,110 (5,052) 8,058
Depreciation, depletion
and amortization..... 28,751 3,002 852 2,034 34,639 280 34,919
Capital expenditures... 25,940 69,530 6,436 2,478 104,384 3,804 108,188
Identifiable assets at
December 31.......... 300,374 138,095 11,749 15,746 465,964 6,736 472,700
</TABLE>
F-22
<PAGE> 114
CMS NOMECO OIL & GAS CO.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
12. OTHER OPERATING REVENUES
Other operating revenues for the periods indicated were as follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED DECEMBER 31, SEPTEMBER 30,
------------------------- -------------------
1992 1993 1994 1994 1995
(UNAUDITED)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Plant and refinery sales................. $7,734 $5,520 $ 4,192 $ 3,403 $ 3,442
Gas contract dispositions................ -- -- 4,800 4,800 9,858
Hedging:
Gas................................. (963) (889) 2,285 1,113 2,826
Oil................................. -- -- 95 -- (224)
Other.................................... 1,637 1,644 961 791 1,836
------ ------ ------- ------- -------
$8,408 $6,275 $12,333 $10,107 $17,738
====== ====== ======= ======= =======
</TABLE>
During 1994 and 1995, the Company disposed of two long-term gas contracts
to unrelated third parties for aggregate consideration of $4.8 million and $9.9
million, respectively. Upon disposing of these contracts, the Company has no
future obligations under either contract.
F-23
<PAGE> 115
CMS NOMECO OIL & GAS CO.
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 this Prospectus.
Data relating to U.S. processing plants and an Australian refinery are
excluded. Data related to the Company's equity investment in Yemen is shown
separately.
The following estimates, which were prepared by the Company's petroleum
engineers, of proved developed and proved undeveloped reserve quantities and
related standardized measure of discounted estimated future net cash flows 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 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.
1. ESTIMATED PROVED RESERVES OF OIL AND GAS
<TABLE>
<CAPTION>
TOTAL U.S. SOUTH AFRICA & OTHER
------------ ------------ AMERICA MIDDLE EAST -----------
OIL GAS OIL GAS OIL OIL OIL GAS
(OIL IN MMBBLS AND GAS IN BCF)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Estimated Proved Developed and
Undeveloped Reserves:
December 31, 1991................. 28.5 191.2 5.3 187.1 19.2 1.8 2.2 4.1
Revisions and other changes..... 0.8 (20.4) 0.2 (20.1) (0.1) 0.8 (0.1) (0.3)
Extensions and discoveries...... 7.4 45.4 0.1 44.7 5.4 0.5 1.4 0.7
Purchases of reserves........... 1.0 9.9 0.2 6.8 0.8 -- -- 3.1
Production...................... (1.6) (17.6) (1.1) (17.4) -- (0.1) (0.4) (0.2)
---- ----- ---- ----- ---- ---- ---- ----
December 31, 1992................. 36.1 208.5 4.7 201.1 25.3 3.0 3.1 7.4
Revisions and other changes..... 0.4 7.2 (0.4) 7.1 -- 0.2 0.6 0.1
Extensions and discoveries...... 0.1 2.9 0.1 2.9 -- -- -- --
Purchases of reserves........... -- 1.7 -- 1.7 -- -- -- --
Production...................... (1.9) (18.5) (1.0) (18.2) (0.2) (0.3) (0.4) (0.3)
---- ----- ---- ----- ---- ---- ---- ----
December 31, 1993................. 34.7 201.8 3.4 194.6 25.1 2.9 3.3 7.2
Revisions and other changes..... (1.3) (9.7) (0.3) (9.4) (2.0) 0.6 0.4 (0.3)
Extensions and discoveries...... 0.4 50.2 0.4 50.2 -- -- -- --
Acquisitions of reserves........ 20.2 9.4 -- 9.4 20.2 -- -- --
Production...................... (2.1) (20.5) (0.8) (20.3) (0.7) (0.3) (0.3) (0.2)
---- ----- ---- ----- ---- ---- ---- ----
December 31, 1994................. 51.9 231.2 2.7 224.5 42.6 3.2 3.4 6.7
==== ===== ==== ===== ==== ==== ==== ====
Estimated Proved Developed Reserves:
December 31, 1991................. 25.9 188.0 5.1 183.9 19.2 0.6 1.0 4.1
December 31, 1992................. 31.7 205.0 4.5 198.8 25.3 0.9 1.0 6.2
December 31, 1993................. 31.2 200.0 3.3 193.4 25.1 1.5 1.3 6.6
December 31, 1994................. 37.4 211.7 2.5 205.9 31.5 2.6 0.8 5.8
Equity Interest in Estimated Proved
Reserves of Pecten Yemen:
December 31, 1993................. 1.5 -- -- -- -- 1.5 -- --
December 31, 1994................. 2.9 -- -- -- -- 2.9 -- --
</TABLE>
F-24
<PAGE> 116
2. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PROVED RESERVES
<TABLE>
<CAPTION>
SOUTH AFRICA &
TOTAL U.S. AMERICA MIDDLE EAST(4) OTHER
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
December 31, 1992:
Future Cash Flows:
Revenues(1)...................... $1,017,443 $493,846 $395,380 $ 59,298 $68,919
Less:
Production costs(2)........... 405,723 191,206 188,458 14,932 11,127
Development costs(2).......... 100,316 4,690 84,997 3,593 7,036
---------- -------- -------- --------- -------
Future cash flows before taxes..... 511,404 297,950 121,925 40,773 50,756
Income tax expense(3)............ 29,573 2,263 5,866 16,258 5,186
---------- -------- -------- --------- -------
Future net cash flows.............. 481,831 295,687 116,059 24,515 45,570
Less discount to present value at a
10% annual rate.................. 164,489 61,018 77,785 7,513 18,173
---------- -------- -------- --------- -------
Standardized measure of discounted
future net cash flows............ $ 317,342 $234,669 $ 38,274 $ 17,002 $27,397
========== ======== ======== ========= =======
December 31, 1993:
Future Cash Flows:
Revenues(1)...................... $1,036,387 $542,747 $378,467 $ 51,052 $64,121
Less:
Production costs(2)........... 332,517 135,679 180,145 13,013 3,680
Development costs(2).......... 81,274 8,947 57,639 3,393 11,295
---------- -------- -------- --------- -------
Future cash flows before taxes..... 622,596 398,121 140,683 34,646 49,146
Income tax expense(3)............ 58,500 21,341 22,185 13,174 1,800
---------- -------- -------- --------- -------
Future net cash flows.............. 564,096 376,780 118,498 21,472 47,346
Less discount to present value at a
10% annual rate.................. 247,900 161,737 62,182 6,069 17,912
---------- -------- -------- --------- -------
Standardized measure of discounted
future net cash flows............ $ 316,196 $215,043 $ 56,316 $ 15,403 $29,434
========== ======== ======== ========= =======
December 31, 1994:
Future Cash Flows:
Revenues(1)...................... $1,235,512 $539,409 $580,927 $ 58,948 $56,228
Less:
Production costs(2)........... 376,550 191,130 158,708 15,603 11,109
Development costs(2).......... 103,611 11,507 80,496 3,253 8,355
---------- -------- -------- --------- -------
Future cash flows before taxes..... 755,351 336,772 341,723 40,092 36,764
Income tax expenses
(benefit)(3).................. 67,073 (16,015) 64,905 16,462 1,721
---------- -------- -------- --------- -------
Future net cash flows.............. 688,278 352,787 276,818 23,630 35,043
Less discount to present value at a
10% annual rate.................. 278,046 138,293 115,926 8,532 15,295
---------- -------- -------- --------- -------
Standardized measure of discounted
future net cash flows............ $ 410,232 $214,494 $160,892 $ 15,098 $19,748
========== ======== ======== ========= =======
</TABLE>
- ------------------------------
(1) Oil, 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. Beginning in June 1995,
transportation expense, which had been shown as a production cost, has been
deducted from operating revenues and prior periods have been reclassified.
(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.
F-25
<PAGE> 117
(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 $71.8 million, $83.2 million and $97.4
million of U.S. income tax credits for Antrim gas production at December 31,
1992, 1993 and 1994, respectively.
(4) Does not include $2.2 million and $3.0 million at December 31, 1993 and
1994, respectively, of discounted future net cash flows attributable to the
Company's interest in the East Shabwa Block in Yemen, which is accounted for
using the equity method.
3. RECONCILIATION OF THE CHANGE IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER
31,
-------------------
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
New discoveries.......................................................... $ 3,698 $ 42,148
Acquisitions of reserves in place........................................ 1,829 118,492
Revisions to reserves.................................................... 11,707 (12,882)
Sales and transfers...................................................... (50,067) (45,428)
Changes in prices........................................................ 50,343 (57,483)
Changes in lifting costs................................................. (28,979) (2,012)
Accretion of discount.................................................... 33,427 34,868
Net change in income taxes............................................... (13,361) (970)
Changes in timing of production and other................................ (9,743) 17,303
-------- --------
Net change during year.............................................. $ (1,146) $ 94,036
======== ========
</TABLE>
4. NET INVESTMENT IN PROVED AREAS(1)
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Developed properties..................................................... $770,532 $866,156
Undeveloped properties
Subject to depletion................................................ 20,192 10,800
Not subject to depletion............................................ 27,399 37,601
-------- --------
818,123 914,557
Less accumulated depreciation, depletion and amortization................ 445,587 480,226
-------- --------
$372,536 $434,331
======== ========
</TABLE>
- ------------------------------
(1) Excluded are approximately $1.1 million of consolidated non-U.S. investments
at December 31, 1993. These investments, which are in areas under
exploration by the Company, are not subject to depletion. As of December 31,
1994, the Company's non-U.S. investments in Australia, Colombia, Ecuador,
Equatorial Guinea and New Zealand are subject to depletion. Additionally,
the Company's net investments attributable to its investment in East Shabwa
Block reserves in Yemen, which are accounted for using the equity method,
were $2.7 million and $8.2 million as of December 31, 1993 and 1994,
respectively.
F-26
<PAGE> 118
5. EXPLORATION, DEVELOPMENT AND ACQUISITION EXPENDITURES IN PROVED AREAS
<TABLE>
<CAPTION>
SOUTH AFRICA &
TOTAL(1) U.S. AMERICA MIDDLE EAST OTHER
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Year Ended December 31, 1992:
Exploration................................ $ 5,115 $ 4,178 $ 63 $ 321 $ 553
Development................................ 44,634 26,484 12,710 2,910 2,530
Property acquisitions...................... 14,317 8,630 -- -- 5,687
-------- ------- ------- ------- ------
$ 64,066 $39,292 $12,773 $ 3,231 $8,770
======== ======= ======= ======= ======
Year Ended December 31, 1993:
Exploration................................ $ 2,360 $ 1,579 $ 211 $ 296 $ 274
Development................................ 60,218 15,533 42,222 1,267 1,196
Property acquisitions...................... 7,146 7,096 -- -- 50
-------- ------- ------- ------- ------
$ 69,724 $24,208 $42,433 $ 1,563 $1,520
======== ======= ======= ======= ======
Year Ended December 31, 1994:
Exploration................................ $ 7,333 $ 5,722 $ 568 $ 68 $ 975
Development................................ 58,300 11,860 44,682 371 1,387
Property acquisitions...................... 33,075 8,288 24,781 -- 6
-------- ------- ------- ------- ------
$ 98,708 $25,870 $70,031 $ 439 $2,368
======== ======= ======= ======= ======
</TABLE>
- ------------------------------
(1) Excluded are approximately $3.9 million in 1992, $5.4 million in 1993 and
$4.0 million in 1994 invested in unproved areas and non-oil and gas
producing properties. Included are $13.6 million in 1992, $0.9 million in
1993 and $33.5 million in 1994 for investments in and purchases of estimated
proved reserves.
The Company's share of exploration, development and property acquisition
expenditures for 1993 and 1994 in its East Shabwa Block reserves in Yemen which
is accounted for using the equity method are as follows:
<TABLE>
<CAPTION>
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Exploration......................................................... $ -- $2,425
Development......................................................... -- 59
Property acquisitions............................................... 2,720 3,004
------ ------
$2,720 $5,488
====== ======
</TABLE>
F-27
<PAGE> 119
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, 1992, 1993 and
1994. Income taxes are computed by applying the appropriate statutory rate to
the results of operations before income taxes. Applicable tax credits and
allowances related to oil and gas producing activities have been taken into
account in computing income tax expenses. The results of operations below do not
include general and administrative expenses, general taxes and net interest
expense. Beginning in June 1995, transportation expense, which had been shown as
an operating expense, has been deducted from operating revenues and prior
periods have been reclassified.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1992
--------------------------------------------------
SOUTH AFRICA &
TOTAL U.S. AMERICA MIDDLE EAST OTHER
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate......................... $26,553 $19,139 $ -- $ 2,879 $4,535
Natural gas................................ 34,391 34,292 -- -- 99
Other operating............................ 674 674 -- -- --
------- ------- ------- --------- ------
61,618 54,105 -- 2,879 4,634
Operating Expenses:
Depreciation, depletion and amortization... 32,374 30,703 -- 510 1,161
Cost center write-offs..................... 5,744 -- 3,050 -- 2,694
Operating and maintenance.................. 12,279 10,844 20 992 423
Production taxes........................... 3,207 3,207 -- -- --
------- ------- ------- --------- ------
53,604 44,754 3,070 1,502 4,278
Pretax operating income......................... 8,014 9,351 (3,070) 1,377 356
Income tax benefit.............................. (2,100)
-------
Income before accounting change................. 10,114
Cumulative effect accounting change............. (1,124)
-------
Net income...................................... $ 8,990
=======
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1993
---------------------------------------------------
SOUTH AFRICA &
TOTAL U.S. AMERICA MIDDLE EAST OTHER
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate........................ $26,635 $14,427 $ 1,816 $ 4,971 $ 5,421
Natural gas............................... 40,995 40,757 -- -- 238
Other operating........................... 755 755 -- -- --
------- ------- ------- --------- -------
68,385 55,939 1,816 4,971 5,659
Operating Expenses:
Depreciation, depletion and
amortization............................ 35,411 31,699 947 1,075 1,690
Cost center write-offs.................... 9,648 -- 1,900 -- 7,748
Operating and maintenance................. 14,191 11,936 620 1,160 475
Production taxes.......................... 3,260 3,106 154 -- --
------- ------- ------- --------- -------
62,510 46,741 3,621 2,235 9,913
Pretax operating income........................ 5,875 9,198 (1,805) 2,736 (4,254)
Income tax benefit............................. (5,900)
-------
Net income..................................... $11,775
=======
</TABLE>
F-28
<PAGE> 120
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1994
---------------------------------------------------
SOUTH AFRICA &
TOTAL U.S. AMERICA MIDDLE EAST OTHER
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate......................... $26,831 $10,502 $7,719 $ 4,520 $ 4,090
Natural gas................................ 39,904 39,649 -- -- 255
Other operating............................ 8,141 8,141 -- -- --
------- ------- ------- ------- -------
74,876 58,292 7,719 4,520 4,345
Operating Expenses:
Depreciation, depletion and amortization... 34,639 28,751 3,002 852 2,034
Cost center write-offs..................... 5,612 -- -- -- 5,612
Operating and maintenance.................. 18,705 13,627 2,834 1,706 538
Production taxes........................... 2,810 2,439 371 -- --
------- ------- ------- ------- -------
61,766 44,817 6,207 2,558 8,184
Pretax operating income......................... 13,110 13,475 1,512 1,962 (3,839)
Income tax benefit.............................. (5,523)
-------
Net Income...................................... $18,633
=======
</TABLE>
There is no income or expense from oil and gas producing activities
attributable to the Company's investment in Yemen for the years 1992 to 1994
which is accounted for using the equity method. Exploratory activities continue
in 1995.
F-29
<PAGE> 121
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To CMS NOMECO
International, Inc.:
We have audited the accompanying consolidated balance sheet of CMS NOMECO
International, Inc. and subsidiaries (formerly Walter International, Inc. and
subsidiaries) as of December 31, 1994, and the related consolidated statements
of operations and accumulated deficit and cash flows for the year then ended.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides 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 NOMECO
International, Inc. and subsidiaries as of December 31, 1994, and the results of
their operations and their cash flows for the year then ended in conformity with
generally accepted accounting principles.
Arthur Andersen LLP
Houston, Texas,
July 17, 1995.
F-30
<PAGE> 122
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JANUARY 31,
DECEMBER 31, 1995
1994 (UNAUDITED)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents...................................... $ 541,247 $ 2,018,000
Accounts receivable............................................ 1,149,995 1,471,588
Inventory...................................................... 188,323 271,140
Other current assets........................................... 1,612 1,612
------------ -----------
Total current assets...................................... 1,881,177 3,762,340
Property, Plant and Equipment, at Cost:
Oil and gas properties, full-cost basis
Proved properties being amortized............................ 15,472,534 15,423,511
Unproved properties and properties under development not
being amortized............................................. 1,117,221 1,117,221
Furniture and office equipment................................. 69,245 74,581
------------ -----------
16,659,000 16,615,313
Less-accumulated depreciation, depletion and amortization...... (9,265,792) (9,368,971)
------------ -----------
Net property, plant and equipment......................... 7,393,208 7,246,342
------------ -----------
Restricted cash (Note 1)............................................ 466,461 718,323
Other assets, net of amortization of $41,576 and $43,079,
respectively...................................................... 58,729 57,226
------------ -----------
Total assets.............................................. $ 9,799,575 $11,784,231
============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities....................... $ 1,739,767 $ 3,206,650
Advances from joint venture participants....................... 27,321 363,720
Current maturities of long-term debt (Note 7).................. 2,266,110 2,266,110
------------ -----------
Total current liabilities................................. 4,033,198 5,836,480
Long-term debt (Note 7)............................................. 5,219,390 5,219,390
Commitments And Contingencies (Notes 4 and 8)
Redeemable Preferred Stock (Note 3):
14% Senior cumulative preferred stock, $1.00 par value, 3,000
shares authorized and issued (aggregate liquidation preference
of $5.1 million).............................................. 3,000 3,000
Stockholders' Equity (Note 3):
Common stock, $0.01 par value, 1,000,000 shares authorized and
100,000 shares issued......................................... 1,000 1,000
Additional paid-in capital..................................... 5,934,910 5,934,910
Accumulated deficit............................................ (5,391,923) (5,210,549)
------------ -----------
Total stockholders' equity................................ 543,987 725,361
------------ -----------
Total liabilities and stockholders' equity................ $ 9,799,575 $11,784,231
============ ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-31
<PAGE> 123
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
<TABLE>
<CAPTION>
ONE
MONTH ENDED
YEAR ENDED JANUARY 31,
DECEMBER 31, 1995
1994 (UNAUDITED)
<S> <C> <C>
Revenues:
Oil sales........................................................... $ 3,957,697 $ 426,287
Interest and other income........................................... 53,338 5,056
------------ -----------
4,011,035 431,343
Expenses:
Lease operating expense............................................. 1,574,781 46,190
General and administrative expense.................................. 405,018 22,568
Interest expense.................................................... 820,631 78,032
Depreciation, depletion and amortization............................ 587,695 103,179
------------ -----------
3,388,125 249,969
Income before income taxes.......................................... 622,910 181,374
Income taxes (Note 2)............................................... 14,000 --
------------ -----------
Net income.......................................................... 608,910 181,374
Accumulated deficit, beginning of period............................ (6,000,833) (5,391,923)
------------ -----------
Accumulated deficit, end of period.................................. $ (5,391,923) $(5,210,549)
============ ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-32
<PAGE> 124
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
ONE MONTH
ENDED
YEAR ENDED JANUARY 31,
DECEMBER 31, 1995
1994 (UNAUDITED)
<S> <C> <C>
Cash Flows from Operating Activities:
Net income...................................................... $ 608,910 $ 181,374
Adjustments to reconcile net income to net cash provided by
operating activities --
Depreciation, depletion and amortization...................... 587,695 103,179
Increase in accounts receivable............................... (426,016) (321,593)
Decrease (Increase) in inventory and other current assets..... 93,385 (81,314)
Increase in accounts payable and accrued liabilities.......... 755,996 1,466,883
Increase (Decrease) in advances from joint venture
participants................................................. (511,935) 336,399
------------ -----------
Net cash provided by operating activities.................. 1,108,035 1,684,928
Cash Flows from Investing Activities:
Additions to property, plant and equipment...................... (871,805) --
Other........................................................... -- 43,687
------------ -----------
Net cash provided by (used in) investing activities........ (871,805) 43,687
Cash Flows from Financing Activities:
Proceeds from long-term debt.................................... 610,774 --
Repayment of long-term debt..................................... (1,316,111) --
Cash restricted for payment of financial obligation............. 59,224 (251,862)
------------ -----------
Net cash used in financing activities...................... (646,113) (251,862)
Net increase (decrease) in cash and cash equivalents................. (409,883) 1,476,753
Cash and cash equivalents, beginning of period....................... 951,130 541,247
------------ -----------
Cash and cash equivalents, end of period............................. $ 541,247 $ 2,018,000
============ ===========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-33
<PAGE> 125
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ORGANIZATION
Walter International, Inc. ("Walter"), a Texas corporation, was organized
on May 22, 1987. Walter was organized for the acquisition of oil and gas
properties and the exploration, development and production of oil and gas
reserves in areas outside the continental United States.
In June 1994, Walter entered into a letter of intent with CMS Energy
Corporation ("CMS") to exchange all of the common shares of Walter for shares of
CMS (the "Merger"). This acquisition was finalized in February 1995. In
connection with the Merger, Walter changed its name to CMS NOMECO International,
Inc. ("CII" or the "Company"). Under the terms of the Merger, CMS assumed the
obligations under the Finance Agreement with Overseas Private Investment
Corporation (see Note 7) and discharged all other obligations of the Company
including (a) all the outstanding principal and interest on the revolving line
of credit (see Note 7), (b) all the outstanding principal and interest on the
term loan from a financial institution (see Note 7) and (c) the obligations to
redeem the 14% Senior Cumulative Preferred Stock (see Note 3).
CII's principal asset is an interest in the petroleum reserves associated
with a Production Sharing Contract covering approximately 500,000 acres offshore
Equatorial Guinea, West Africa (the "Alba Field"). CII's wholly owned
subsidiary, CMS NOMECO International Equatorial Guinea ("CIEG"), formerly Walter
International Equatorial Guinea, Inc., is the operator of the Alba Field. During
1992, commercial production from the Alba Field commenced.
B. UNAUDITED FINANCIAL STATEMENTS
The financial statements and related information as of and for the one
month ended January 31, 1995 included herein are unaudited and, in the opinion
of management, reflect all adjustments (consisting of only recurring
adjustments) necessary for a fair presentation of financial position and the
results of operations and cash flows.
These unaudited consolidated financial statements should be read in
conjunction with the Company's consolidated financial statements as of and for
the year ended December 31, 1994. The consolidated results of operations for the
one month ended January 31, 1995, are not necessarily indicative of operating
results for a full year. These financial statements and related information are
reflected for the purpose of presenting information prior to the Merger with
CMS.
C. CONSOLIDATION AND PRESENTATION
The accompanying financial statements consolidate the statements of CII and
its wholly owned subsidiaries (collectively referred to as the "Company") as of
and for the year ended December 31, 1994. All significant intercompany accounts
and transactions have been eliminated.
D. OIL AND GAS PROPERTIES
The Company follows the full-cost method of accounting for its oil and gas
properties. Under this method of accounting, all productive and nonproductive
costs incurred in the acquisition of oil and gas properties and the exploration
for and the development of oil and gas reserves are capitalized in separate cost
centers for each country. No gains or losses are recognized upon the sale or
disposition of oil and gas properties unless the sale or disposition represents
a significant portion of the individual cost center's oil and gas reserves.
Instead, the proceeds from the sale of oil and gas properties are treated as a
reduction of oil and gas property costs.
F-34
<PAGE> 126
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
If the Company's net investment in oil and gas properties in a cost center
exceeds the present value of estimated future net revenues from proved reserves
discounted at 10% and the cost of properties not being amortized, both adjusted
for tax effects, the excess will be charged to expense as additional
depreciation, depletion and amortization.
Evaluated property costs, plus estimated future development costs, in each
cost center are amortized on a composite unit-of-production method, based on
quantities of proved reserves, over the life of the producing properties. The
costs of individual unevaluated properties are excluded from the amortization
calculation until the properties are evaluated.
E. REVENUE RECOGNITION
Oil revenues from producing wells are recognized when the oil is sold. At
December 31, 1994, inventory includes December production valued at market.
F. FURNITURE AND EQUIPMENT
Furniture and equipment is recorded at cost and is depreciated using the
straight-line method based on the estimated useful lives (five to seven years)
of the related assets.
G. MANAGEMENT SERVICE FEES
Fees received by the Company, as operator, for reimbursement of overhead
expenses attributable to exploration, development and production activities are
recorded as a reduction of general and administrative expenses. The Company
received approximately $400,000 in 1994 in reimbursed overhead charges relating
to the Alba Field.
H. STATEMENT OF CASH FLOWS
For purposes of the consolidated statement of cash flows, all highly liquid
investments with an original maturity of three months or less are considered to
be cash equivalents. Cash used in operating activities includes cash payments
for interest by the Company of approximately $1,000,000 during 1994.
I. RESTRICTED CASH
At December 31, 1994, the Company had $466,461 held in escrow to secure
certain payments of CIEG's financing obligations.
J. CONCENTRATION OF CREDIT RISK
The Company is, as operator, principally engaged in the development and
production of the Alba Field and, in 1994, all production was sold to one
customer under a term contract (see Note 4). The Company's accounts receivable
at December 31, 1994, primarily result from oil sales to this one customer and
joint interest billings to other participants in the Alba Field, all of whom are
companies in the oil and gas industry. This concentration of credit risk may
impact the Company's overall credit risk in that these entities may be similarly
affected by industrywide changes in economic or other conditions. However, no
credit losses were experienced during 1994. The Company does not require
collateral for these receivables.
2. INCOME TAXES
The Company accounts for income taxes under the provisions of Statement of
Financial Accounting Standards ("SFAS") No. 109, Accounting for Income Taxes.
SFAS No. 109 requires an asset and liability approach for accounting for income
taxes. Under this approach, deferred tax assets and liabilities are
F-35
<PAGE> 127
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
recognized based on anticipated future tax consequences attributable to
differences between financial carrying amounts of assets and liabilities and
their respective tax bases.
Total income tax provision (benefit) for the year ended December 31, 1994,
was as follows:
<TABLE>
<S> <C>
U.S.:
Current (alternative minimum tax)..................................... $14,000
Deferred.............................................................. --
Non-U.S.:
Current............................................................... --
-------
Total............................................................ $14,000
=======
</TABLE>
At December 31, 1994, deferred tax assets and liabilities computed at the
statutory rate related to temporary differences were as follows:
<TABLE>
<CAPTION>
(DOLLARS
IN THOUSANDS)
<S> <C>
Deferred tax assets..................................................... $ 2,144
Less-valuation allowance................................................ (1,686)
-------
Deferred tax assets, net........................................... 458
Deferred tax liabilities........................................... (458)
-------
Total deferred taxes, net..................................... $ --
=======
</TABLE>
Deferred tax assets are related to tax loss carryforwards. Deferred tax
liabilities are related primarily to the difference between the book and tax
bases of property, plant and equipment. The Company has a valuation allowance of
$1,686,000 at December 31, 1994, relating to the uncertainty of the utilization
of the net operating loss carryforwards to reduce future taxes.
As of December 31, 1994, the Company had approximately $6.1 million of net
operating loss carryforwards remaining for U.S. tax purposes that will expire
between the years 2004 and 2007.
CIEG, the Company's wholly owned subsidiary, has approximately $2.5 million
of net operating loss carryforwards generated in a foreign taxing jurisdiction
which is available to offset income taxable in that foreign jurisdiction. These
foreign net operating loss carryforwards will expire during 1995 if not
utilized. However, the Company anticipates that future payments of income taxes
in the foreign jurisdiction will generate foreign tax credits available to
offset future payments of U.S. federal income taxes. The full realization of any
tax benefits resulting from any foreign tax credits generated would depend upon
the Company's taxable income during the carryforward period.
3. REDEEMABLE PREFERRED STOCK
On December 15, 1989, certain institutional investors purchased from the
Company 3,000 shares of its 14% Senior Cumulative Preferred Stock ("Senior
Preferred") for total cash consideration of $3,000,000 ($2,925,000 net of stock
issuance expenses). Annual dividends of $140 per share are payable quarterly out
of Dedicated Net Cash Flow (as defined). If the dedicated net cash flow is
insufficient to meet any quarterly dividend requirement, the dividends
accumulate in arrears. The aggregate amount of cumulative preferred dividends in
arrears at December 31, 1994, was approximately $2.1 million.
The Company is required to redeem the Senior Preferred at a price of $1,000
per share by making quarterly payments out of Dedicated Net Cash Flow remaining,
if any, after the payment of dividends on the Senior Preferred. Dedicated Net
Cash Flows were not sufficient for the payment of dividends or the redemption of
the Senior Preferred in 1994.
F-36
<PAGE> 128
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Currently, the Company has dedicated to the Senior Preferred the net cash
flows of its interest in the El Franig field in the Medinine concession in
Tunisia. The agreement provides that if, as of January 1 of any year beginning
January 1, 1991, 80% of the future El Franig net cash flow estimated to be
received on or prior to December 31, 1994, is less than the product of the then
outstanding shares of Senior Preferred and the Liquidation Value (as defined),
the Company shall dedicate such additional net cash flows from other properties
as is necessary so that, after such additional dedication, the future dedicated
net cash flow is equal to at least 125% of the then outstanding shares of Senior
Preferred and the Liquidation Value (as defined). As a result, if the Company
relinquishes its right to further develop El Franig (see Note 4) or the reserves
in El Franig cease to be classified by outside petroleum engineers as proved
reserves, the Company will be required to dedicate to the Senior Preferred cash
flows from other proved reserves. Presently, the Company's only other proved
reserves are in the Alba Field. El Franig was not developed by December 31,
1994, and, as a result, dedication of the reserves associated with the Alba
Field was required. Dedication to the Senior Preferred of the net cash flows
from the Alba Field requires the Company to use such net cash flows to pay
dividends on the Senior Preferred (including amounts in arrears) and redeem the
Senior Preferred with any net cash flows remaining.
The Company has the option to redeem additional Senior Preferred shares at
a price of $1,180 per share (plus accrued and unpaid dividends). No such
optional redemption will reduce the obligation of the Company to make any
mandatory redemption.
If at any time any shares of the Senior Preferred are outstanding and (a)
both of the Principal Shareholders (as defined) die; (b) both of the Principal
Shareholders cease to serve as executive officers of the Company or a Change of
Control (as defined) shall occur; (c) the Company directly, or indirectly, were
to create, incur, assume or permit to exist any Lien (as defined) on or with
respect to Dedicated Properties (as defined), except for certain instances as
specified in the agreement such as liens entered into in the ordinary course of
business or in favor of Development Financing (as defined); or (d) the Company
were to sell, assign, lease, convey or otherwise dispose of its assets,
including the sale, assignment or transfer of any royalties, overriding
royalties or other interest in its assets, except for certain instances as
specified in the agreement, the holder of the Senior Preferred shall have the
right to immediately require the Company to repurchase the shares of Senior
Preferred at $1,000 per share (plus accrued and unpaid dividends).
On June 24, 1994, the Company entered into a letter agreement with the
holders of the Senior Preferred to purchase all of the outstanding shares of the
Senior Preferred, all rights to accrued and unpaid dividends and all warrants
granted to the holders for cash consideration of $3.4 million. In February 1995,
in connection with the Merger, CMS purchased all of the outstanding shares of
the Senior Preferred for $3.4 million.
4. COMMITMENTS
During 1990, CIEG, along with other participants, entered into a Production
Sharing Contract ("PSC") with the Republic of Equatorial Guinea to conduct
exploration and development activities in that country. The PSC requires that
CIEG carry out a certain Minimum Work Program (as defined) and meet certain
minimum expenditure obligations. During 1992, CIEG drilled and completed a
development well in the Alba Field and drilled a dry exploratory well in the PSC
area. In April 1992, the date of the first sales of commercial production, CIEG
paid $235,000, its share of a production bonus, to the Republic of Equatorial
Guinea. The PSC further requires CIEG to drill an additional exploratory well by
April 1995. However, CIEG received an extension from the Republic of Equatorial
Guinea for the drilling of the exploratory well until January 1996.
In 1992, CIEG, along with other participants in the Alba Field, entered
into a purchase and sales contract with a European-based petroleum products
trader for the majority of production. The sales price under the contract is
based on an adjusted market price.
F-37
<PAGE> 129
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
During 1990, the Company and its joint venture partners obtained from a
major oil company an interest in two concessions (Douz and Medinine) in Tunisia
for consideration consisting of $5,000,000 cash ($1,250,000 net to the Company),
which was paid in 1990, and a production payment of $20,000,000 payable solely
out of future revenues (excluding government royalty and transportation fees)
from the two concessions. The Company drilled two wells and subsequently
suspended further development operations in the Douz concession due to low
productivity and recorded an impairment provision. At the end of 1994, the
Company decided to proceed with the development of the El Franig field and is
currently negotiating a development program with the Tunisia Government. The
Company has the right to discontinue these activities at any time without
further financial obligation.
The Company's office rent expense was $80,644 in 1994. The Company has
lease commitments for office space of $100,000 in 1995 and $88,000 in 1996.
5. RELATED-PARTY TRANSACTIONS
An affiliated corporation owned by certain stockholders of the Company
(prior to the Merger) has provided the Company with certain administrative and
other staff services. The Company reimbursed the affiliate approximately
$1,200,000 for such services for the year ended December 31, 1994, and payables
due to the affiliated corporation were $295,000 at December 31, 1994.
At December 31, 1994, receivables due from the affiliated corporation were
$30,000 and primarily related to the affiliate's share of joint interest
billings relating to the Alba Field.
6. PHANTOM STOCK PLAN
The Company terminated its phantom stock plan in 1993. The Company incurred
compensation expense in 1992 pursuant to the plan, for which approximately
$43,000 remains payable to a past participant in the plan, and is included in
accounts payable and accrued liabilities at December 31, 1994.
7. LONG-TERM DEBT
Long-term debt and current maturities at December 31, 1994:
<TABLE>
<S> <C>
OPIC guaranteed loans.................................................... $2,935,500
Borrowing on revolving line of credit.................................... 1,000,000
Term Loan................................................................ 3,550,000
----------
7,485,500
Less -- Current maturities............................................... 2,266,110
----------
$5,219,390
==========
</TABLE>
At December 31, 1994, the Company had a $1,000,000 revolving line of credit
with a third-party bank, with interest based on such bank's prime rate. This
line of credit was secured by guarantees from two principal shareholders of the
Company. The interest rate at December 31, 1994, for amounts outstanding under
the credit agreement was 8.78%. In consideration for the guarantees, CII caused
CIEG to deliver, to the two principal shareholders, overriding royalty interests
in the Alba Field equal to a fixed percentage of CIEG's net interest,
respectively. The line of credit matures on January 8, 1996, if not extended by
the lender.
In June 1992, CIEG, along with other consortium members, entered into a
Finance Agreement (the "Agreement") with the Overseas Private Investment
Corporation ("OPIC"), an agency of the United States government, whereby OPIC
guaranteed loans for development drilling in the Alba Field. CIEG's
participation in the OPIC guarantee was approximately $4.3 million with
approximately $3.0 million outstanding as of
F-38
<PAGE> 130
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
December 31, 1994. The Agreement requires the Company maintain an escrow account
for debt service requirements (see Note 1). The principal amount of each
disbursement is to be repaid in 20 equal quarterly installments. The
disbursements bear interest, payable quarterly, based on the three-month London
Interbank Offered Rate ("LIBOR") plus 0.375%, adjusted quarterly. The interest
rate as of December 31, 1994, was 5.8%. For the year 1994, CIEG paid OPIC
guarantee fees of approximately $70,000. CIEG has pledged all of its interests
in the Alba Field and has agreed not to place any other liens on its interest in
the PSC.
In February 1993, the Company obtained a $4.6 million term loan from a
financial institution (the Term Loan) for the purpose of repaying outstanding
indebtedness, overdue trade obligations and joint interest billing obligations.
In accordance with the Term Loan, the Company caused CIEG to deliver an
overriding royalty interest to the lender calculated as a percentage of gross
proceeds, as defined in the Term Loan, received by CIEG from the Alba Field.
During 1994, CIEG paid approximately $168,000 to the lender, relating to the
overriding royalty interest. The interest on the Term Loan is fixed at 10% per
annum on the outstanding principal balance, payable quarterly. Required
principal repayments commenced on June 30, 1993, and are payable in 16 quarterly
installments, as provided in the Term Loan. As of December 31, 1994, the
outstanding balance of the Term Loan was approximately $3.6 million. The Company
has pledged all the outstanding common stock of CIEG as collateral. The Term
Loan and the overriding royalty interest are subordinate to the amounts
guaranteed by OPIC.
On June 24, 1994, in anticipation of the Merger, the Company entered into
an agreement to restructure the Term Loan. The restructuring provided for
additional funding in July 1994 of $525,000, a waiver of any event of default
for the failure to pay the March 1994, June 1994 and September 1994 scheduled
principal payments, and an increase in the fixed rate of interest to 12% per
annum effective June 30, 1994. The restructuring also provided for (a) a
one-time payment to the financial institution of $30,000, (b) a prepayment
premium of $50,000 if any portion of the additional funding or any other
principal amount of the Term Loan is prepaid prior to the maturity date, (c) the
scheduled principal repayments be amended to commence in December 1994 and be
paid in 13 quarterly installments and (d) CIEG to increase the overriding
royalty interest to the financial institution.
On October 8, 1992, CIEG entered into an interest rate and currency
exchange agreement which has effectively fixed the interest rate on
approximately $2.2 million of floating rate debt. Under the agreement, CIEG will
pay the counterparties interest at a fixed rate of 5.91% over the term of the
agreement and the counterparties will pay CIEG the three-month LIBOR. The swap
agreement, which will terminate April 1, 1998, requires quarterly interest
settlement payments and a cash collateral account. CIEG has entered into this
interest rate swap with a bank to eliminate the impact of interest rate
fluctuations with respect to this portion of its floating rate debt. CIEG is
exposed to loss if the counterparty defaults. Such counterparty is a major
international financial institution, and the Company believes the risk of
default is minimal. Interest rate swap transactions generally involve exchanges
of fixed and floating interest payment obligations without exchanges of
underlying principal amounts; therefore, CIEG's exposure to credit loss is
significantly less than the contracted amounts.
Subsequent to year-end, in connection with the Merger, CMS repaid the
outstanding principal and interest on the line of credit and outstanding
principal and interest on the Term Loan. Current maturities in connection with
the remaining OPIC debt are $866,110 in 1995, $866,110 in 1996, $866,100 in 1997
and $337,110 in 1998.
8. SUBSEQUENT EVENT
The Company together with an unaffiliated entity, entered into a stock
purchase agreement with an international oil company to purchase the common
stock of that company's U.S. subsidiaries which are involved in the production
of oil in the Republic of Congo, Africa ("Congo Acquisition") for approximately
$21.5 million, $3.9 million in cash and $17.6 million of debt, of which the
Company's share was $1.9 million in cash and $8.8 million of debt. This Congo
Acquisition was closed in February 1995.
F-39
<PAGE> 131
CMS NOMECO INTERNATIONAL, INC. AND SUBSIDIARIES
(FORMERLY WALTER INTERNATIONAL, INC. AND SUBSIDIARIES)
SUPPLEMENTAL DISCLOSURES OF OIL
EXPLORATION AND PRODUCTION 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 Operations and Accumulated
Deficit for the Company's results of operations from exploration and production
activities.
The following estimates, which were prepared by the Company's petroleum
engineers, of proved developed and proved undeveloped reserve quantities and
related standardized measure of discounted estimated future net cash flows 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 gas properties. Accordingly, these estimates are expected to
change as future information becomes available.
Proved reserves are estimated quantities of 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.
1. ESTIMATED PROVED RESERVES OF OIL
<TABLE>
<CAPTION>
(OIL IN MBBLS)
<S> <C>
Estimated Proved Developed and Undeveloped Reserves:
December 31, 1993......................................................... 3,925
Revisions and other changes............................................. 15
Production.............................................................. (249)
-----
December 31, 1994......................................................... 3,691
=====
Estimated Proved Developed Reserves:
December 31, 1994......................................................... 2,849
=====
</TABLE>
2. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PROVED RESERVES
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994
(DOLLARS IN THOUSANDS)
<S> <C>
Future cash flows:
Revenues(1)........................................................ $ 60,090
Less:
Production costs(2)............................................. 21,383
Development costs(2)............................................ 4,736
--------
Future cash flows before taxes....................................... 33,971
Income tax expense (benefit)(3).................................... 13,485
--------
Future net cash flows..................................................... 20,486
Less discount to present value at a 10% annual rate....................... (6,217)
--------
Standardized measure of discounted future net cash flows.................. $ 14,269
========
</TABLE>
- ------------------------------
(1) Oil revenues are based on year-end prices. There is no consideration for
future discoveries or risks associated with future production of proved
reserves.
(2) Based on economic conditions at year-end. Does not include administrative,
general 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.
F-40
<PAGE> 132
3. RECONCILIATION OF THE CHANGE IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994
(DOLLARS IN THOUSANDS)
<S> <C>
Sales and transfers........................................................ $ (2,383)
Changes in prices.......................................................... 5,440
Accretion of discount...................................................... 1,739
Net change in income taxes................................................. (3,346)
Change in timing and other................................................. (909)
---------
Net change during the year....................................... $ 541
=========
</TABLE>
4. EXPLORATION, DEVELOPMENT AND ACQUISITION EXPENDITURES
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994
(DOLLARS IN THOUSANDS)
<S> <C>
Unproved property acquisition......................................... $988
Development........................................................... 88
</TABLE>
F-41
<PAGE> 133
INDEPENDENT AUDITORS' REPORT
To the Stockholders of
Walter International, Inc.
We have audited the accompanying consolidated balance sheets of Walter
International, Inc. and subsidiaries (the "Company") as of December 31, 1992 and
1993, and the related consolidated statements of operations and accumulated
deficit, and cash flows for the years then ended. These financial statements are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1992 and 1993, and the results of its operations and its cash flows for the
years then ended in conformity with generally accepted accounting principles.
The accompanying consolidated financial statements have been prepared
assuming that the Company will continue as a going concern. As discussed in Note
7, the Company is experiencing difficulty in generating sufficient cash flow to
meet its obligations and sustain its operations, which raises substantial doubt
about its ability to continue as a going concern. Management's plans in regard
to these matters are described in Notes 7 and 8. The consolidated financial
statements do not include any adjustments that might result from the outcome of
this uncertainty.
As discussed in Note 8 to the consolidated financial statements, the
Company has agreed to merge with CMS Energy Corporation. The merger is
contingent upon certain events.
Deloitte & Touche LLP
June 24, 1994
(July 31, 1994, as to Note 8)
F-42
<PAGE> 134
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1992 1993
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents...................................... $ 107,370 $ 951,130
Restricted cash (Note 1)....................................... 128,589 525,685
Accounts receivable:
Joint venture participants................................... 2,097,890 605,770
Trade........................................................ 409,930 9,789
Related parties.............................................. 361,766 50,249
Other........................................................ 518,790 58,171
Inventory...................................................... 24,236 259,873
Other current assets (net of amortization of $25,484 in
1993)......................................................... 4,097 82,176
----------- -----------
Total current assets...................................... 3,652,668 2,542,843
Property, Plant and Equipment, at Cost:
Oil and gas properties -- full cost basis...................... 14,362,022 15,723,697
Furniture and office equipment................................. 59,689 63,497
----------- -----------
14,421,711 15,787,194
Accumulated depreciation, depletion and amortization........... (7,858,430) (8,678,096)
----------- -----------
Net Property, plant and equipment.............................. 6,563,281 7,109,098
Other assets (net of amortization of $9,387 in 1992)................ 90,923 --
----------- -----------
Total assets.............................................. $10,306,872 $ 9,651,941
=========== ===========
LIABILITIES & STOCKHOLDERS' EQUITY
(ACCUMULATED DEFICIT)
Current Liabilities:
Accounts payable and accrued liabilities....................... $ 3,935,293 $ 942,372
Advances from joint venture participants....................... 81,115 539,256
Accounts payable to related parties............................ 235,373 41,399
Current maturities of long-term debt (Note 7).................. 1,593,618 7,276,611
----------- -----------
Total current liabilities................................. 5,845,399 8,799,638
Long-term notes payable (Note 7).................................... 5,432,576 914,226
Commitments And Contingencies (Notes 4 and 7)
Mandatory Redeemable Stock (Note 3):
14% Senior cumulative preferred stock, $1.00 par value, 3,000
shares authorized and issued (mandatory redemption, aggregate
liquidation preference of $4.7 million)....................... 3,000 3,000
Stockholders' Equity
(Accumulated Deficit) (Note 3):
Common stock, $0.01 par value; 1,000,000 shares authorized and
100,000 shares issued......................................... 1,000 1,000
Additional paid-in capital..................................... 5,934,910 5,934,910
Accumulated deficit............................................ (6,910,013) (6,000,833)
----------- -----------
(974,103) (64,923)
----------- -----------
Total liabilities & stockholders' equity (accumulated
deficit)................................................ $10,306,872 $ 9,651,941
=========== ===========
</TABLE>
See notes to consolidated financial statements.
F-43
<PAGE> 135
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND ACCUMULATED DEFICIT
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1992 1993
<S> <C> <C>
Revenues:
Oil sales...................................................... $ 2,175,812 $ 4,197,148
Management service fees........................................ 313,228 504,052
Interest and other income (Note 1)............................. 318,629 41,156
----------- -----------
2,807,669 4,742,356
Expenses:
Lease operating expense........................................ 826,730 1,168,902
General and administrative expense............................. 845,818 932,536
Interest expense............................................... 327,336 895,975
Depreciation, depletion and amortization....................... 315,892 835,763
----------- -----------
2,315,776 3,833,176
Income before income taxes and extraordinary credit................. 491,893 909,180
Income taxes (Note 2)............................................... (167,244) --
----------- -----------
Income before extraordinary credit.................................. 324,649 909,180
Extraordinary credit from utilization of tax loss carryforward...... 167,244 --
----------- -----------
Net income.......................................................... 491,893 909,180
Beginning accumulated deficit....................................... (7,401,906) (6,910,013)
----------- -----------
Ending accumulated deficit.......................................... $(6,910,013) $(6,000,833)
=========== ===========
</TABLE>
See notes to consolidated financial statements.
F-44
<PAGE> 136
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1992 1993
<S> <C> <C>
Cash Flows From Operating Activities:
Net income..................................................... $ 491,893 $ 909,180
Adjustments To Reconcile Net Income To Net Cash Provided By
(Used In) Operating Activities:
Depreciation, depletion and amortization..................... 315,892 835,763
(Increase) decrease in accounts receivable................... (1,667,402) 2,664,397
Increase in inventory........................................ (24,236) (235,637)
Increase (decrease) in accounts payable and accrued
liabilities................................................. 1,011,929 (3,186,895)
Other........................................................ (516,302) (3,253)
----------- -----------
Net cash provided by (used in) operating activities....... (388,226) 983,555
Cash Flows From Investing Activities:
Additions to property, plant and equipment..................... (4,922,787) (1,365,483)
Restricted cash for property addition.......................... 484,316 --
Increase (decrease) in advances from joint venture
participants................................................. (667,006) 458,141
----------- -----------
Net cash used in investing activities..................... (5,105,477) (907,342)
Cash Flows From Financing Activities:
Proceeds from notes payable.................................... 6,987,391 5,806,429
Repayment of notes payable..................................... (1,345,000) (4,641,786)
Cash restricted for payment of financial obligation............ (128,589) (397,096)
----------- -----------
Net cash provided by financing activities................. 5,513,802 767,547
Net increase in cash and cash equivalents........................... 20,099 843,760
Cash and cash equivalents at beginning of year...................... 87,271 107,370
----------- -----------
Cash and cash equivalents at end of year............................ $ 107,370 $ 951,130
=========== ===========
</TABLE>
See notes to consolidated financial statements.
F-45
<PAGE> 137
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. ORGANIZATION
Walter International, Inc. ("WII"), a Texas corporation, was organized on
May 22, 1987. WII was organized for the acquisition of oil and gas properties
and the exploration, development and production of oil and gas reserves in areas
outside the continental United States. WII's principal asset is an interest in
the petroleum reserves associated with the Alba Production Sharing Contract
covering approximately 500,000 acres offshore Equatorial Guinea, West Africa
(the "Alba Field"). WII's wholly-owned subsidiary, Walter International
Equatorial Guinea, Inc. ("WIEG"), is the operator of the Alba Field. During
1992, commercial production from the Alba Field commenced.
B. FINANCIAL STATEMENT PRESENTATION
The accompanying financial statements consolidate the statements of WII and
its wholly-owned subsidiaries (collectively referred to as the "Company") at
December 31, 1992 and 1993. All significant intercompany accounts and
transactions have been eliminated.
C. OIL AND GAS PROPERTIES
The Company follows the full-cost method of accounting for its oil and gas
properties. Under this method of accounting, all costs incurred in the
acquisition of oil and gas properties and the exploration for and the
development of oil and gas reserves are capitalized in separate cost centers for
each country. No gains or losses are recognized upon the sale or disposition of
oil and gas properties unless the sale or disposition represents a significant
portion of the individual cost center's oil and gas reserves.
If the Company's net investment in oil and gas properties in a cost center
exceeds the present value of estimated future net revenues from proved reserves
discounted at 10%, adjusted for tax effects, the excess will be charged to
expense as additional depreciation, depletion and amortization.
The costs of proven properties, including the estimated cost to complete
proven undeveloped properties in each cost center, are amortized on a composite
unit-of-production method based on the proved reserves as determined by an
outside petroleum engineer.
D. REVENUE RECOGNITION
Revenue, net of the overriding royalty interests paid to a third-party
investor and the two principal shareholders (see Note 7), is recognized by the
Company based on monthly production. At December 31, 1993, inventory includes
December production of condensate valued at the contracted sales amount. All
condensate sold during the years ended December 31, 1992 and 1993 was sold to a
single purchaser on the spot market (see Note 4).
E. FURNITURE AND EQUIPMENT
Furniture and equipment is recorded at cost and is depreciated using the
straight-line method based on the estimated useful lives of the related assets.
F. MANAGEMENT SERVICE FEES
Fees received by the Company, as operator, for reimbursement of overhead
expenses attributable to exploration, development and production activities are
included in revenue. The Company received approximately $504,000 and $313,000 in
1993 and 1992, respectively, in reimbursed overhead charges relating to the Alba
Field.
F-46
<PAGE> 138
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
G. STATEMENT OF CASH FLOWS
For purposes of the consolidated statements of cash flows, all highly
liquid investments with an original maturity of three months or less are
considered to be cash equivalents. Cash used in operating activities includes
cash payments for interest by the Company of approximately $175,000 and $814,000
during 1992 and 1993, respectively.
H. RESTRICTED CASH
At December 31, 1992 and 1993, the Company had approximately $129,000 and
$526,000, respectively, held in escrow to secure certain payments of WIEG's
financing obligations.
I. CONCENTRATION OF CREDIT RISK
The Company is, as operator, principally engaged in the development and
production of the Alba Field. Currently, all production is sold to one customer
in accordance with a term contract (see Note 4).
J. INTEREST AND OTHER INCOME
Other income in 1992 includes approximately $317,000 resulting from the
Company's reversal of interest accrued in prior periods on past due trade
obligations.
K. RECLASSIFICATIONS
Certain minor reclassifications have been made to prior year's amounts to
conform with current reporting practices.
2. INCOME TAXES
Effective January 1, 1993, the Company adopted Statement of Financial
Accounting Standards No. 109 ("SFAS No. 109"), Accounting for Income Taxes. SFAS
No. 109 requires application of an asset and liability approach for financial
accounting and reporting for income taxes. The effect of adopting SFAS No. 109
was not material to the Company's consolidated financial statements.
The Company had U.S. taxable income of approximately $0.9 million for the
year ended December 31, 1993 before the utilization of net operating loss
carryforwards. As of December 31, 1993, the Company had approximately $6.8
million of net operating loss carryforwards remaining for U.S. tax purposes that
will expire between the years 2004 and 2007.
WIEG, the Company's wholly-owned subsidiary, has approximately $6.0 million
of net operating loss carryforwards generated in a foreign taxing jurisdiction
which is available to offset income taxable in that foreign jurisdiction. These
foreign net operating loss carryforwards will expire between the years 1994 and
1995, if not utilized. However, the Company anticipates that future payments of
income taxes in the foreign jurisdiction will generate foreign tax credits
available to offset future payments of U.S. federal income taxes. The full
realization of any tax benefits resulting from any foreign tax credits generated
would depend upon the Company's taxable income during the carryforward period.
At December 31, 1993, the Company had no provision for income taxes because
of a reduction in the valuation allowance during 1993. The Company recognized an
extraordinary credit in the 1992 "Consolidated Statement of Operations and
Accumulated Deficit" from utilizing a portion of such operating loss
carryforward. Provision for income taxes is obtained by applying the statutory
U.S. federal income tax rate of 34% of the income before income taxes and
extraordinary credit.
F-47
<PAGE> 139
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1993, deferred tax assets and liabilities computed at the
statutory rate related to temporary differences as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
<S> <C>
Deferred tax assets................................................. $ 2,312
Valuation allowance................................................. (1,926)
--------
Deferred tax assets -- net.......................................... 386
Deferred tax liabilities............................................ (386)
--------
Total deferred taxes -- net......................................... $ --
========
</TABLE>
Deferred tax assets are related to tax loss carryforwards. Deferred tax
liabilities are related primarily to the difference between the book and the tax
basis of property, plant and equipment. The Company has a valuation allowance of
$1,926,000 at December 31, 1993 relating to the uncertainty of the utilization
of the net operating loss carryforwards to reduce future taxes.
3. STOCK TRANSACTIONS
On December 15, 1989, certain institutional investors purchased from the
Company 3,000 shares of its 14% Senior Cumulative Preferred Stock ("Senior
Preferred") for total cash consideration of $3,000,000 ($2,925,000 net of stock
issuance expenses). Annual dividends of $140 per share are payable quarterly out
of dedicated net cash flow (as defined). If the dedicated net cash flow is
insufficient to meet any quarterly dividend requirement, the dividends
accumulate in arrears. The aggregate amount of cumulative preferred dividends in
arrears at December 31, 1993 was approximately $1,697,000.
The Company is required to redeem the Senior Preferred at a price of $1,000
per share by making quarterly payments out of dedicated net cash flow remaining,
if any, after the payment of dividends on the Senior Preferred. Dedicated cash
flows were not sufficient for the payment of dividends or the redemption of the
Senior Preferred in 1992 or 1993.
Currently, the Company has dedicated to the Senior Preferred the net cash
flows of its interest in El Franig concession in Tunisia. The agreement provides
that if, as of January 1 of any year, beginning January 1, 1991, 80% of the
future Franig net cash flow estimated to be received on or prior to December 31,
1994 is less than the product of the then outstanding shares of Senior Preferred
and the liquidation value, the Company shall dedicate such additional net cash
flows from other properties as is necessary so that after such additional
dedication, the future dedicated net cash flow is equal to at least 125% of the
then outstanding shares of Senior Preferred and the liquidation value. As a
result, if the Company relinquishes its right to further develop El Franig (see
Note 4) or the reserves in El Franig cease to be classified by outside petroleum
engineers as proved reserves, the Company will be required to dedicate to the
Senior Preferred cash flows from other proven reserves. Presently, the Company's
only other proven reserves are in the Alba Field. The Company estimates that El
Franig will not be developed by December 31, 1994, and as a result, dedication
of the reserves associated with the Alba Field may be required. Dedication to
the Senior Preferred of the net cash flows from the Alba Field would require the
Company to use such net cash flows to pay dividends on the Senior Preferred
(including amounts in arrears) and redeem the Senior Preferred with any net cash
flows remaining.
The Company has the option to redeem additional Senior Preferred shares at
a price of $1,180 per share (plus accrued and unpaid dividends). No such
optional redemption will reduce the obligation of the Company to make any
mandatory redemption.
If at any time any shares of the Senior Preferred are outstanding: (a) both
of the Principal Shareholders (as defined) die; (b) both of the Principal
Shareholders cease to serve as executive officers of the Company or a change of
control (as defined) shall occur; (c) the Company directly, or indirectly, were
to create, incur,
F-48
<PAGE> 140
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
assume or permit to exist any Lien (as defined) on or with respect to dedicated
properties (as defined), except for certain instances as specified in the
agreement such as liens entered into in the ordinary course of business or in
favor of development financing (as defined); or (d) the Company were to sell,
assign, lease, convey or otherwise dispose of its assets, including the sale,
assignment or transfer of any royalties, overriding royalties or other interest
in its assets, except for certain instances as specified in the agreement and as
set forth in Notes 1, 4 and 7, the holder of the Senior Preferred shall have the
right to immediately require the Company to repurchase the shares of Senior
Preferred at $1,000 per share (plus accrued and unpaid dividends).
4. COMMITMENTS
During 1990, WIEG, along with other participants, entered into a Production
Sharing Contract (the "PSC") with the Republic of Equatorial Guinea to conduct
exploration and development activities in that country. The PSC requires that
WIEG carry out a certain minimum Work Program (as defined) and meet certain
minimum expenditure obligations. During 1992, WIEG drilled and completed a
development well in the Alba Field and drilled a dry exploratory well in the PSC
area. In April 1992, the date of the first sales of commercial production, WIEG
paid $235,000, its share of a production bonus, to the Republic of Equatorial
Guinea. The PSC further requires WIEG to drill an additional exploratory well by
April 1995 (see Note 7).
In 1992, WIEG, along with other participants in the Alba Field, entered
into a purchase and sales contract with a European-based petroleum products
trader for the majority of 1993 production. The sales price under the contract
is based on an adjusted market price.
During 1990, the Company and its joint venture partners obtained from a
major oil company an interest in two concessions (Douz and Medinine) in Tunisia
for consideration consisting of $5,000,000 cash ($1,250,000 net to the Company),
which was paid in March 1990, and a production payment of $20,000,000 payable
solely out of future revenues (excluding government royalty and transportation
fees) from the two concessions. The Company drilled two wells and subsequently
suspended further development operations in the Douz concession due to low
productivity and recorded an impairment provision. The concession agreement, as
modified, requires that the Company undertake to decide whether or not to
proceed with the development of El Franig field in the Medinine concession by
December 1994, if not extended. The Company has the right to discontinue these
activities at any time without further financial obligation.
5. RELATED PARTY TRANSACTIONS
An affiliated corporation owned by certain stockholders of the Company has
provided the Company with certain administrative and other staff services. The
Company was charged approximately $167,000 and $180,000 for such services for
the years ended December 31, 1992 and 1993, respectively.
Receivables from related parties primarily relate to the affiliate's share
of joint interest billings relating to the Alba Field.
6. PHANTOM STOCK PLAN
The Company terminated its phantom stock plan in 1993. The Company incurred
approximately $111,000 of compensation expense in 1992 pursuant to the Plan, for
which approximately $52,000 remains payable to a past participant in the plan,
and is included in accounts payable and accrued liabilities at December 31,
1993.
7. FINANCING
In February 1992, the Company received $3,000,000 from a revolving line of
credit with a third-party bank based on such bank's prime rate. This line of
credit was secured by guarantees from a third-party investor (letter of credit)
and the two principal shareholders (personal assets) of the Company of
$2,000,000 and
F-49
<PAGE> 141
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
$1,000,000, respectively. During 1993, a repayment on the line of credit reduced
the amount available to $1,000,000, of which $914,226 was outstanding at
December 31, 1993, and the third-party investor's guaranty was released. The
interest rate at December 31, 1993 for amounts outstanding under the credit
agreement was 6.28%. In consideration for the guaranties, WII caused WIEG to
deliver, to the third-party investor and the two principal shareholders,
overriding royalty interests in the Alba Field equal to a fixed percentage of
WIEG's net interest, respectively. The line of credit matures on January 6,
1995, if not extended by the lender.
In June 1992, WIEG, along with other consortium members, entered into a
Finance Agreement (the "Agreement") with the Overseas Private Investment
Corporation ("OPIC"), an agency of the United States government, whereby OPIC
guaranteed loans for development drilling in the Alba Field. WIEG's
participation in the OPIC guarantee was approximately $4.3 million.
Approximately $1.2 million and $3.1 million was distributed to WIEG during 1993
and 1992, respectively, under the Agreement. The Agreement requires the Company
maintain an escrow account for debt service requirements (see Note 1). The
disbursements bear interest, payable quarterly, based on the three-month London
Interbank Offered Rate ("LIBOR") plus three-eighths percent, adjusted quarterly.
The interest rate as of December 31, 1993 and 1992 was 3.75% and 3.81%,
respectively. For the years 1993 and 1992, WIEG paid OPIC guarantee and
commitment fees of approximately $76,000 and $40,000 in the aggregate,
respectively. The principal amount of each disbursement is to be repaid in 20
equal quarterly installments. The amount outstanding as of December 31, 1993 and
1992 was approximately $3.8 million and $3.1 million, respectively. WIEG has
pledged all of its interests in the Alba Field and the PSC and has agreed not to
place any other liens on its interest in the PSC.
In February 1993, the Company obtained a $4.6 million term loan from a
financial institution (the "Term Loan") for the purpose of repaying outstanding
indebtedness, including a portion of the revolving line of credit, overdue trade
obligations and joint interest billing obligations. In accordance with the Term
Loan, the Company caused WIEG to deliver an overriding royalty interest to the
lender calculated as a percentage of Gross Proceeds, as defined in the Term
Loan, received by WIEG from the Alba Field. During 1993, WIEG paid approximately
$91,000 to the lender, relating to the overriding royalty interest, and is
recorded as additional interest expense in the 1993 consolidated statement of
operations and accumulated deficit. The interest on the Term Loan is fixed at
10% on the outstanding principal balance outstanding, payable quarterly.
Required principal repayments commenced on June 30, 1993 and are payable in 16
quarterly installments, as provided in the Term Loan. As of December 31, 1993,
the outstanding balance of the Term Loan was approximately $3.5 million. The
Company has pledged all the outstanding common stock of WIEG as collateral. The
Term Loan and the overriding royalty interest are subordinate to the amounts
guaranteed by OPIC.
On October 8, 1992, WIEG entered into an Interest Rate and Currency
Exchange Agreement which has effectively fixed the interest rate on
approximately $3.1 million of floating rate debt. Under the agreement, WIEG will
pay the counterparties interest at a fixed rate of 5.91% over the term of the
loan and the counterparties will pay WIEG the three-month LIBOR. The swap
agreement, which will terminate April 1, 1998, requires quarterly interest
settlement payments and a cash collateral account. WIEG has entered into this
interest rate swap with a bank to eliminate the impact of interest rate
fluctuations with respect to this portion of its floating rate debt. WIEG is
exposed to loss if the counterparty defaults. Such counterparty is a major
international financial institution, and the Company believes the risk of
default is minimal. Interest rate swap transactions generally involve exchanges
of fixed and floating interest payment obligations without exchanges of
underlying principal amounts; therefore, WIEG's exposure to credit loss is
significantly less than the contracted amounts.
F-50
<PAGE> 142
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Notes Payable Consist of the Following at December 31:
<TABLE>
<CAPTION>
1992 1993
<S> <C> <C>
OPIC guaranteed loans......................................... $3,124,122 $3,801,611
Borrowing on revolving line of credit......................... 2,564,226 914,226
Term Loan..................................................... -- 3,475,000
Current liabilities refinanced (subsequent to December 31,
1992) on a long-term basis.................................. 1,337,846 --
---------- ----------
7,026,194 8,190,837
Less current maturities....................................... 1,593,618 7,276,611
---------- ----------
$5,432,576 $ 914,226
========== ==========
</TABLE>
The Company was granted a waiver dated June 24, 1994, from the lender, for
any event of default resulting from its inability to meet the scheduled March
31, 1994 and June 30, 1994 principal payments under the Term Loan. The Company's
ability to meet its financial obligations under the restructured Term Loan (if
not repaid commensurate with a proposed merger by the Company with an
unaffiliated entity -- see Note 8), and the Company's ability to finance future
exploratory and development drilling requirements under existing concession
agreements, is dependent on the successful consummation of the aforementioned
proposed merger or management's ability to seek other long-term financing
alternatives. The Company has experienced difficulty in generating sufficient
cash flow to meet its debt obligations and sustain its operations, which raises
substantial doubt about its ability to continue as a going concern. As a result,
the entire balance of the Company's OPIC guaranteed loans and the Term Loan at
December 31, 1993, have been classified as current liabilities in the 1993
consolidated balance sheet. The line of credit, which matures on January 6, 1995
and secured by the personal assets of the two principal shareholders, remains
classified as a long-term note payable in the 1993 consolidated balance sheet.
8. SUBSEQUENT EVENTS
In June 1994, the Company, together with an unaffiliated entity, entered
into a Stock Purchase Agreement ("SPA") with an international oil company to
purchase the common stock of that company's United States subsidiaries which are
involved in the production of oil in the Republic of Congo, Africa ("Congo
Acquisition").
In June 1994, the Company entered into a Letter of Intent with CMS Energy
Corporation ("CMS") to exchange all of the common shares of the Company for
shares of CMS (the "Merger"). Under the terms of the Merger, CMS will assume the
obligations under the OPIC Agreement (see Note 7) and discharge all other
obligations of the Company including (a) all the outstanding principal and
interest on the line of credit (see Note 7), (b) all the outstanding principal
and interest on the Term Loan (see Note 7), and (c) the obligations to redeem
the Senior Preferred (see Note 3) pursuant to the terms of a proposed offer
dated June 24, 1994 discussed below. The Merger is contingent upon, among other
things, the following: (a) the successful completion of the Congo Acquisition,
(b) receipt of the necessary approvals, from the limited partners of the
partnerships that own the Senior Preferred, to redeem the Senior Preferred, and
(c) completion of due diligence by CMS.
On June 24, 1994, in anticipation of the Merger, the Company entered into
an agreement to restructure the Term Loan (see Note 7). The restructuring
provided for additional funding in July 1994 of $525,000, a waiver of any event
of default for the failure to pay the March 1994 and June 1994 scheduled
principal payments, and an increase in the fixed rate of interest to 12% per
annum effective June 30, 1994. The restructuring also provides for a one-time
payment to the financial institution of $30,000 and a prepayment premium of
$50,000 if any portion of the additional funding or any other principal amount
of the Term Loan is prepaid prior to the maturity date. If the restructured Term
Loan is not repaid by September 15, 1994, the
F-51
<PAGE> 143
WALTER INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
restructuring further provides that (a) the September 1994 scheduled principal
repayment be waived, (b) the scheduled principal repayments be amended to
commence in December 1994 and to be paid in 13 quarterly installments, and (c)
the Company will cause WIEG to increase the overriding royalty interest to the
financial institution.
On June 24, 1994, the Company entered into a letter agreement with the
holder of the Senior Preferred (see Note 3) to purchase all of the outstanding
shares of the Senior Preferred, all rights to accrued and unpaid interest, and
all warrants granted to the holders for cash consideration of $3.4 million
(liquidation preference of $4.7 million). This agreement is contingent on the
consummation of the Merger referenced above, as well as the approval of the
proposed terms of the letter agreement by the limited partners of the
partnerships that own the Senior Preferred.
F-52
<PAGE> 144
INDEPENDENT AUDITORS' REPORT
The Board of Directors
The Nuevo Congo Company and
Walter International Congo, Inc.
(formerly Amoco Congo Exploration and
Petroleum Companies):
We have audited the accompanying combined balance sheets of Amoco Congo
Exploration and Petroleum Companies as of December 31, 1993 and 1994, and the
related combined statements of operations, stockholder's equity, and cash flows
for each of the years in the three-year period ended December 31, 1994. These
combined financial statements are the responsibility of the Companies'
management. Our responsibility is to express an opinion on these combined
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the combined financial statements referred to above present
fairly, in all material respects, the financial position of Amoco Congo
Exploration and Petroleum Companies at December 31, 1993 and 1994, and the
results of their operations and their cash flows for each of the years in the
three-year period ended December 31, 1994 in conformity with generally accepted
accounting principles.
KPMG Peat Marwick LLP
Houston, Texas
April 18, 1995
F-53
<PAGE> 145
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED BALANCE SHEETS
DECEMBER 31, 1993 AND 1994
<TABLE>
<CAPTION>
1993 1994
(DOLLARS IN THOUSANDS,
EXCEPT SHARE DATA)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents..................................... $ 13,221 $ 10,703
Accounts receivable........................................... 7,170 1,221
Allowance for doubtful accounts............................... -- (429)
Inventories:
Crude oil................................................... 1,753 6,144
Supplies.................................................... 8,099 8,720
--------- ---------
Total inventories........................................ 9,852 14,864
Prepaid expenses.............................................. 755 800
--------- ---------
Total current assets..................................... 30,998 27,159
Property, Plant and Equipment:
Proved properties (Successful efforts method)................. 32,544 32,658
Office furniture and equipment................................ 5,818 5,784
--------- ---------
38,362 38,442
Less accumulated depreciation, depletion and amortization.......... (29,743) (32,285)
--------- ---------
Net property plant and equipment......................... 8,619 6,157
Deferred charges................................................... 695 393
--------- ---------
$ 40,312 $ 33,709
========= =========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Accounts payable.............................................. $ 5,901 $ 6,927
Due to affiliates............................................. 2,955 26
--------- ---------
Total current liabilities................................ 8,856 6,953
Stockholder's Equity:
Common stock, $100 par value. Authorized and issued 10 shares
Amoco Congo Exploration Company and 10 shares Amoco Congo
Petroleum Company............................................ 2 2
Additional paid-in capital.................................... 455,892 433,820
Accumulated deficit........................................... (424,438) (407,066)
--------- ---------
Total stockholder's equity............................... 31,456 26,756
--------- ---------
$ 40,312 $ 33,709
========= =========
</TABLE>
See accompanying notes to combined financial statements.
F-54
<PAGE> 146
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
<TABLE>
<CAPTION>
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenues:
Oil revenues............................................ $ 45,082 $49,480 $37,249
Other income............................................ 929 292 296
-------- ------- -------
Total revenues..................................... 46,011 49,772 37,545
Operating Expenses:
Lease operating expense................................. 21,735 15,103 10,557
Write-down of proved properties......................... 19,688 6,038 --
Depreciation, depletion and amortization................ 14,940 4,397 2,664
General and administrative.............................. 19,747 12,096 6,952
Interest expense........................................ 13,933 739 --
-------- ------- -------
Total expenses..................................... 90,043 38,373 20,173
Income (loss) before income taxes.................. (44,032) 11,399 17,372
Income taxes................................................. -- -- --
-------- ------- -------
Net income (loss).................................. $(44,032) $11,399 $17,372
======== ======= =======
</TABLE>
See accompanying notes to combined financial statements.
F-55
<PAGE> 147
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED STATEMENTS OF STOCKHOLDER'S EQUITY
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
<TABLE>
<CAPTION>
TOTAL
ADDITIONAL STOCKHOLDER'S
COMMON PAID-IN ACCUMULATED (DEFICIT)
STOCK CAPITAL DEFICIT EQUITY
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Balances at December 31, 1991................. $ 2 $ 130,266 $(391,805) $(261,537)
Net loss...................................... -- -- (44,032) (44,032)
Cash contributions............................ -- 61,767 -- 61,767
------ ---------- ---------- -----------
Balances at December 31, 1992................. 2 192,033 (435,837) (243,802)
------ ---------- ---------- -----------
Net income.................................... -- -- 11,399 11,399
Cash contributions............................ -- 275,214 -- 275,214
Dividends..................................... -- (11,355) -- (11,355)
------ ---------- ---------- -----------
Balances at December 31, 1993................. 2 455,892 (424,438) 31,456
------ ---------- ---------- -----------
Net income.................................... -- -- 17,372 17,372
Cash contributions............................ -- 6,883 -- 6,883
Dividends..................................... -- (28,955) -- (28,955)
------ ---------- ---------- -----------
Balances at December 31, 1994................. $ 2 $ 433,820 $(407,066) $ 26,756
====== ========== ========== ===========
</TABLE>
See accompanying notes to combined financial statements.
F-56
<PAGE> 148
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 1992, 1993 AND 1994
<TABLE>
<CAPTION>
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income (loss).............................................. $(44,032) $ 11,399 $17,372
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided
By (Used In) Operating Activities:
Depreciation, depletion, amortization and write-down of
proved properties....................................... 34,628 10,435 2,664
Change in oil inventory................................. (4,113) 6,800 (4,381)
Net change in assets and liabilities:
Decrease (increase) in accounts receivable.............. 2,010 (4,402) 5,949
Decrease (increase) in due to/from affiliates........... (2,993) 3,775 (2,929)
Decrease (increase) in supply inventories............... 7,339 1,681 (631)
Increase (decrease) in accounts payable and accrued
expenses............................................. 2,668 (13,834) 1,025
Decrease in other assets................................ 484 307 686
-------- --------- -------
Net cash provided by (used in) operating
activities......................................... (4,009) 16,161 19,755
Cash Flows from Investing Activities:
Capital expenditures...................................... (43,819) (2,469) (238)
Sale of property, plant and equipment..................... -- 700 37
-------- --------- -------
Net cash used in investing activities................ (43,819) (1,769) (201)
Cash Flows from Financing Activities:
Principal payments on notes payable....................... (12,000) (273,000) --
Dividends................................................. -- (11,355) (28,955)
Capital contributions..................................... 61,767 275,214 6,883
-------- --------- -------
Net cash provided by (used in) financing
activities......................................... 49,767 (9,141) (22,072)
Net increase (decrease) in cash and cash equivalents........... 1,939 5,251 (2,518)
Cash and cash equivalents at beginning of year................. 6,031 7,970 13,221
-------- --------- -------
Cash and cash equivalents at end of year....................... $ 7,970 $ 13,221 $10,703
======== ========= =======
Supplemental cash flow disclosures:
Interest paid............................................. $ 13,983 $ 739 $ --
======== ========= =======
</TABLE>
See accompanying notes to combined financial statements.
F-57
<PAGE> 149
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
DECEMBER 31, 1992, 1993 AND 1994
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
A. DESCRIPTION OF BUSINESS AND BASIS OF PRESENTATION
Amoco Congo Exploration Company and Amoco Congo Petroleum Company
(collectively referred to as "Amoco Congo Exploration and Petroleum Companies"
or the "Company") are wholly-owned subsidiaries of Amoco Production Company (the
"Parent"). The Company's combined financial statements include the accounts of
Amoco Congo Exploration and Petroleum Companies. All significant intercompany
transfers have been eliminated.
The primary business of the Company is the exploration and production of
hydrocarbons from the Yombo-Masseko-Youbi exploration permit located
approximately fifty miles offshore of the People's Republic of Congo. Amoco
Congo Exploration and Petroleum Companies have a total combined working interest
of 87.5% and total combined net revenue interest of 63.47% in the permit. Of the
combined working interest, 43.75% represents a carried interest associated with
another interest owner which converts to a working interest at payout of the
property. The net revenue interest is burdened by a 15.04% royalty interest
payable to the Congo government and by a 12.5% interest associated with the
carried interest owner.
B. REVENUE RECOGNITION
The Company recognizes revenue when the sale is completed and risk of loss
transfers to a third party purchaser. Crude oil in inventory is stated at year
end market prices less transportation costs; the Company recognizes changes in
the market value of inventory from one period to the next as oil revenues.
C. CASH EQUIVALENTS
Cash equivalents consist of overnight repurchase agreements and
certificates of deposit with an initial term of less than three months. For
purposes of the statements of cash flows, the Company considers all highly
liquid debt instruments with original maturities of three months or less to be
cash equivalents.
D. SUPPLY INVENTORIES
Material and supply inventories are stated at the lower of current market
value or cost. Cost is determined using the first-in, first-out method or
average cost.
E. PROPERTY, PLANT AND EQUIPMENT
The Company uses the successful efforts method of accounting for its oil
operations. The costs of unproved leaseholds are capitalized pending the results
of exploration efforts. Unproved leaseholds with significant acquisition costs
are assessed periodically, on a property-by-property basis, and a loss is
recognized to the extent, if any, the cost of the property has been impaired.
Unproved leaseholds whose acquisition costs are not individually significant are
aggregated, and the portion of such costs estimated to ultimately prove
nonproductive, based on experience, are amortized over an average holding
period. As unproved leaseholds are determined to be productive, the related
costs are transferred to proved leaseholds. Exploratory dry holes and geological
and geophysical charges are expensed. Depletion of proved leaseholds and
amortization and depreciation of the costs of all development and successful
exploratory drilling are provided by the unit-of-production method based upon
estimates of proved oil reserves on a field-by-field basis. Estimated costs (net
of salvage value) of dismantling and abandoning oil production facilities are
computed and included in depreciation and depletion using the unit-of-production
method. The total estimated future dismantlement and abandonment cost being
amortized as of December 31, 1994 was approximately $9.0 million. Should the net
capitalized costs exceed the estimated future undiscounted after tax net cash
flows from proved oil
F-58
<PAGE> 150
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
reserves, such excess costs would be charged to expense. In 1993 and 1992,
write-downs of proved oil properties of approximately $6.0 million and $19.7
million, respectively, were charged to operating expenses.
In March 1995, Statement of Financial Accounting Standards No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed of, was issued and is effective for years beginning after December
15, 1995. The statement will change the Company's method of recognition and
measurement of impairments for long-lived assets. The Company has not determined
the impact of adoption; however, it is not believed the impact will have a
material effect on the Company's financial condition.
Other property, plant and equipment are depreciated on a straight-line
basis over their estimated useful lives. Leasehold improvements, which are
recorded at cost, are amortized on a straight-line basis over their estimated
useful lives or the life of the lease, whichever is shorter.
F. INCOME TAXES
The Company follows the asset and liability method of accounting for income
taxes under the provisions of Statement of Financial Accounting Standards No.
109 ("SFAS 109"), Accounting for Income Taxes. Under the asset and liability
method of SFAS 109, deferred tax assets and liabilities are recognized for the
future tax consequences attributable to differences between the financial
statement carrying amounts of existing assets and liabilities and their
respective tax bases and operating loss and tax credit carryforwards. Deferred
tax assets and liabilities are measured using enacted tax rates expected to
apply to taxable income in the years in which those temporary differences are
expected to be recovered or settled. Under SFAS 109, the effect on deferred tax
assets and liabilities of a change in tax rates is recognized in income in the
period that includes the enactment date.
The Company files a consolidated income tax return with its Parent. The
Company recognizes income tax expense under the separate company method which
applies SFAS 109 as though the Company was filing a separate income tax return.
Accordingly, deferred income tax assets are recognized when it is more likely
than not that the Company will realize the benefits as a reduction of future
taxable income.
<TABLE>
<CAPTION>
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Deductible temporary differences resulting from proved properties...... $ 66,452 $ 61,500
Net operating loss utilized by parent.................................. 48,921 47,966
Valuation allowance on deferred tax assets............................. (115,373) (109,466)
--------- ---------
Total deferred income tax.................................... $ -- $ --
========= =========
</TABLE>
The Company generated substantial net operating losses for federal income
tax purposes which were utilized by the Parent. Under the Parent's tax sharing
agreement, the Company received no benefit from the Parent's utilization of
these net operating losses until utilized on the separate company method to
reduce the Company's taxable income.
On a separate company basis, the Company has approximately $141.0 million
of net operating loss carryforwards available to offset the Company's taxable
income in future years which begin to expire in 2006.
The significant components of deferred income tax expense attributable to
income from continuing operations for the years ended December 31, 1992, 1993
and 1994 are as follows:
<TABLE>
<CAPTION>
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Deferred tax expense (benefit)........................... $(14,930) $ 3,996 $ 5,907
Increase (decrease) in beginning-of-the-year balance of
the valuation allowance for deferred tax assets........ 14,930 (3,996) (5,907)
-------- ------- -------
$ -- $ -- $ --
======== ======= =======
</TABLE>
F-59
<PAGE> 151
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
2. LEASES
The Company has several noncancellable operating leases, primarily for
housing and office space, that expire at various times over the next nine years.
The operating base lease becomes cancelable as of March 19, 1995 upon twelve
months notice and payment of an early termination fee. As management does not
currently intend to cancel the operating base lease, the future minimum lease
payments are included in all years presented below. The office facility is
leased based on two year terms. As management currently intends to continually
renew the lease upon expiration, the future minimum lease payments are included
in the presentation below. Rental expense for operating leases was $1,878,692,
$1,700,349, and $1,336,510 for the years ended December 31, 1992, 1993, and
1994, respectively.
Future minimum lease payments under noncancelable operating leases (with
initial or remaining lease terms in excess of one year) are:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31,
<S> <C>
1995............................................................ $ 771,854
1996............................................................ 739,512
1997............................................................ 739,512
1998............................................................ 739,512
1999............................................................ 739,512
Later years, through 2001....................................... 800,154
----------
Total minimum lease payments.......................... $4,530,056
==========
</TABLE>
3. BUSINESS CONCENTRATIONS
The Company operates outside of the United States in the exploration and
production of oil reserves. The Company's major customers include domestic and
foreign companies.
Accrued revenues and accounts receivable relate to oil producing activities
and are deemed by management to be collectible.
During the year ended December 31, 1994, the Company settled a matter with
the Congo government regarding the calculation of royalties due to the Congo
government. The settlement of this matter resulted in an approximate $2.9
million reduction in oil revenues in 1994.
The following sales customers accounted for 10% or more of revenues of the
Company:
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
------------------
1992 1993 1994
<S> <C> <C> <C>
Exxon............................................................... 29% -- --
J. Aron............................................................. 18 -- --
Stinnes............................................................. -- 70% 98%
Vitol............................................................... -- 17 --
</TABLE>
4. SUBSEQUENT EVENTS
On June 30, 1994, Amoco Production Company, the sole owner of all of the
Company's issued and outstanding stock, entered into an agreement to sell all
issued and outstanding shares of the Company, effective as of December 1, 1993,
to Walter International, Inc. and Nuevo Energy Company, for a sales price of
$31,500,000. The sales price is payable in cash of $21,500,000 and a promissory
note of $10,000,000. Additionally, a production payment in an amount to be
agreed upon at a later date, is payable to the seller in quarterly installments,
based upon production beginning as of the effective date of the sale. The sale
to Walter
F-60
<PAGE> 152
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
International, Inc. and Nuevo Energy Company closed on February 24, 1995 and the
names of the companies were changed to The Nuevo Congo Company and Walter
International Congo, Inc.
5. SUPPLEMENTAL OIL PRODUCING ACTIVITIES (UNAUDITED)
Capitalized costs relating to oil producing activities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------
1993 1994
(DOLLARS IN
THOUSANDS)
<S> <C> <C>
Proved properties................................................ $ 32,544 $ 32,658
Accumulated depreciation, depletion and amortization............. (27,414) (28,907)
-------- --------
$ 5,130 $ 3,751
======== ========
</TABLE>
Costs incurred in oil property acquisition, exploration and development
activities are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Development costs............................................. $43,262 $2,032 $114
======= ====== ====
</TABLE>
Results of operations for oil producing activities are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Revenues................................................. $ 45,082 $49,480 $37,249
Lifting costs:
Lease operating expense................................ 21,735 15,103 10,557
-------- ------- -------
23,347 34,377 26,692
Depreciation, depletion and amortization and write-down
of oil properties...................................... 34,628 10,435 2,664
-------- ------- -------
Results of operations from producing activities.......... $(11,281) $23,942 $24,028
======== ======= =======
</TABLE>
The Company's standardized measure of discounted future net cash flows and
changes therein as of December 31, 1992, 1993 and 1994 are provided based on the
present value of future net revenues from proved oil reserves estimated by Amoco
Production Company in-house petroleum engineers in accordance with guidelines
established by the Securities and Exchange Commission. These estimates were
computed by applying appropriate current prices for oil to estimated future
production of proved oil reserves over the economic lives of the reserves and
assuming continuation of existing economic conditions. Year end 1994
calculations were made utilizing average prices for oil that existed at December
31, 1994 of $13.00 per barrel ("Bbl"). Income taxes are computed by applying the
statutory federal income tax rate of the net cash inflows relating to proved oil
reserves less the tax bases of the properties involved and giving effect to any
net operating loss carryforwards, tax credits and allowances relating to such
properties. As a result of the net operating losses, no income tax expense is
included in the Company's standardized measure of discounted future net cash
flows. The reserve volumes provided by the in-house petroleum engineers are
estimates only and should not be construed as being exact quantities. These
reserves may or may not be recovered and may increase or decrease as a result of
future operations of the Company and changes in market conditions.
F-61
<PAGE> 153
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS -- (CONTINUED)
Reserve quantity information is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
-------------------------
1992 1993 1994
OIL OIL OIL
(MBBL) (MBBL) (MBBL)
<S> <C> <C> <C>
Proved Developed Reserves:
Beginning of year.............................................. 21,973 8,306 15,359
Revisions of previous estimates................................ (10,748) 10,424 (154)
Production..................................................... (2,919) (3,371) (3,080)
------- ------ ------
End of year.................................................... 8,306 15,359 12,125
======= ====== ======
</TABLE>
Standardized measure of discounted future net cash flows is as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
---------------------
1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Future cash in flows.............................................. $ 149,600 $ 157,628
Future development costs.......................................... (13,900) (13,000)
Future production costs........................................... (130,570) (103,120)
--------- ---------
Future net cash flows before discounting.......................... 5,130 41,508
10% annual discount............................................... (1,258) (10,955)
--------- ---------
Standardized measure of discounted future net cash flows.......... $ 3,872 $ 30,553
========= =========
</TABLE>
Principal sources of change in the standardized measure of discounted future net
cash flows is as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1992 1993 1994
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C>
Standardized measure of discounted future net cash
flows, beginning of year............................. $ 2,451 $ 10,965 $ 3,872
Revisions of previous quantity estimates less
related costs................................... (21,587) 10,819 (523)
Net changes in prices, net of production costs.... 37,236 728 47,533
Development costs incurred during period and
changes in estimated future development costs... (8,167) (4,665) 579
Sales of oil produced during period, net of
lifting costs................................... (24,790) (34,432) (26,692)
Accretion of discount............................. 245 1,097 387
Changes of production rates (timing) and other.... 25,577 19,360 5,397
-------- -------- --------
8,514 (7,093) 26,681
-------- -------- --------
Standardized measure of discounted future net cash
flows, end of year................................... $ 10,965 $ 3,872 $ 30,553
======== ======== ========
</TABLE>
F-62
<PAGE> 154
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED BALANCE SHEET
JANUARY 31, 1995
<TABLE>
<CAPTION>
UNAUDITED
(DOLLARS IN THOUSANDS)
ASSETS
<S> <C>
Current Assets:
Cash and cash equivalents............................................ $ 9,359
Accounts receivable.................................................. 15,855
Allowance for doubtful accounts...................................... (429)
Inventories:
Crude oil.......................................................... 1,144
Supplies........................................................... 8,875
---------
Total inventories............................................... 10,019
Prepaid expenses.......................................................... 1,015
---------
Total current assets............................................ 35,819
Property, Plant and Equipment:
Proved properties (Successful efforts method)........................ 32,752
Office furniture and equipment....................................... 5,691
---------
38,443
Less accumulated depreciation, depletion and amortization................. (32,460)
---------
Net property plant and equipment................................ 5,983
Other assets.............................................................. 131
---------
$ 41,933
=========
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Accounts payable..................................................... $ 12,251
Due to affiliates.................................................... 137
---------
Total current liabilities....................................... 12,388
Stockholder's Equity (Deficit):
Common stock, $100 par value. Authorized and issued 10 shares Amoco
Congo Exploration Company and 10 shares Amoco Congo Petroleum
Company............................................................. 2
Additional paid-in capital........................................... 434,006
Accumulated deficit.................................................. (404,463)
---------
Total stockholder's equity...................................... 29,545
---------
$ 41,933
=========
</TABLE>
See accompanying notes to unaudited combined financial statements.
F-63
<PAGE> 155
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED STATEMENT OF OPERATIONS
ONE MONTH ENDED JANUARY 31, 1995
<TABLE>
<CAPTION>
UNAUDITED
(DOLLARS IN THOUSANDS)
<S> <C>
Revenues:
Oil revenues......................................................... $4,333
------
Total revenues.................................................. 4,333
Operating Expenses:
Lease operating expense.............................................. 977
Depreciation, depletion and amortization............................. 175
General and administrative........................................... 567
Other expense........................................................ 11
------
Total expenses.................................................. 1,730
Income before income taxes...................................... 2,603
Income taxes.............................................................. --
------
Net income...................................................... $2,603
======
</TABLE>
COMBINED STATEMENT OF STOCKHOLDER'S EQUITY
<TABLE>
<CAPTION>
ADDITIONAL TOTAL
COMMON PAID-IN ACCUMULATED STOCKHOLDER'S
STOCK CAPITAL DEFICIT EQUITY
UNAUDITED
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Balances at December 31, 1994....................... $2 $433,820 $(407,066) $26,756
--
-------- --------- -------
Net income.......................................... -- -- 2,603 2,603
Cash contributions.................................. -- 186 -- 186
--
-------- --------- -------
Balances at January 31, 1995........................ $2 $434,006 $(404,463) $29,545
== ======== ========= =======
</TABLE>
See accompanying notes to unaudited combined financial statements.
F-64
<PAGE> 156
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
COMBINED STATEMENT OF CASH FLOWS
ONE MONTH ENDED JANUARY 31, 1995
<TABLE>
<CAPTION>
UNAUDITED
(DOLLARS IN THOUSANDS)
<S> <C>
Cash Flows from Operating Activities:
Net income........................................................... $ 2,603
Adjustments to Reconcile Net Income to Net Cash (Used In) Operating
Activities:
Depreciation, depletion and amortization of proved properties........ 175
Change in oil inventory.............................................. 4,845
Net Change In Assets and Liabilities:
Increase in accounts receivable.................................... (14,634)
Increase due to affiliates......................................... 111
Increase in prepaid expenses....................................... (215)
Increase in accounts payable....................................... 5,324
Decrease in other assets........................................... 262
--------
Net cash used in operating activities........................... (1,529)
Cash Flows from Investing Activities:
Capital expenditures................................................. (94)
Sale of property, plant and equipment................................ 93
--------
Net cash used in investing activities........................... (1)
Cash Flows from Financing Activities:
Capital contributions................................................ 186
--------
Net cash provided by financing activities.......................... 186
Net decrease in cash and cash equivalents................................. (1,344)
Cash and cash equivalents at beginning of period.......................... 10,703
--------
Cash and cash equivalents at end of period................................ $ 9,359
========
Supplemental Cash Flow Disclosures:
Interest paid........................................................ $ --
========
</TABLE>
See accompanying notes to unaudited combined financial statements.
F-65
<PAGE> 157
AMOCO CONGO EXPLORATION AND PETROLEUM COMPANIES
NOTES TO COMBINED FINANCIAL STATEMENTS
JANUARY 31, 1995
(UNAUDITED)
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying unaudited combined financial statements include, in the
opinion of management, all adjustments of a normal recurring nature necessary to
present fairly the combined financial position of Amoco Congo Exploration and
Petroleum Companies ("Amoco Congo Companies") at January 31, 1995 and the
related combined results of operations and changes in cash flows for the month
then ended. These financial statements are reflected for the purpose of
presenting information prior to the sale of all of the issued and outstanding
stock of Amoco Congo Exploration Company and Amoco Congo Petroleum Company.
2. ACCOUNTS RECEIVABLE
There has been a substantial increase in accounts receivable since December
31, 1994, as a result of the Amoco Congo Companies having had two liftings of
oil in January 1995, which were the first two liftings since November 1994.
3. SUBSEQUENT EVENTS
On June 30, 1994, Amoco Production Company, the sole owner of all of the
Company's issued and outstanding stock, entered into an agreement to sell all
issued and outstanding shares of the Company, effective as of December 1, 1993,
to Walter International, Inc. and Nuevo Energy Company, for a sales price of
$31,500,000. The sales price is payable in cash of $21,500,000 and a promissory
note of $10,000,000. Additionally, a production payment, in an amount to be
agreed upon at a later date, is payable to the seller in quarterly installments,
based upon production beginning as of the effective date of the sale. The sale
with Walter International, Inc. and Nuevo Energy Company closed on February 24,
1995 and the names of the companies were changed to The Nuevo Congo Company and
Walter International Congo, Inc. The $10,000,000 promissory note was settled
through net cash proceeds generated by the properties for the period between the
effective and closing dates.
F-66
<PAGE> 158
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors and Shareholders,
Terra Energy Ltd. and Subsidiaries
We have audited the accompanying consolidated balance sheet of Terra Energy
Ltd. (a Michigan corporation) and subsidiaries as of December 31, 1994, and the
related consolidated statements of earnings, shareholders' equity, and cash
flows for the year then ended. 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 audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides 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 Terra Energy
Ltd. and subsidiaries as of December 31, 1994, and the results of their
operations and cash flows for the year then ended in conformity with generally
accepted accounting principles.
As explained in Note 2a. to the consolidated financial statements, the
Company has given retroactive effect to the change in the method of accounting
for its oil and gas producing activities from the successful efforts method to
the full cost method.
Arthur Andersen LLP
Detroit, Michigan,
February 1, 1996.
F-67
<PAGE> 159
TERRA ENERGY LTD. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
JULY 31,
DECEMBER 31, 1995
1994 (UNAUDITED)
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents...................................... $ 15,690,255 $ 7,002,390
Investments -- marketable securities........................... 27,100 27,100
Accounts receivable............................................ 31,136,407 43,155,706
Notes and land contract receivable............................. 147,946 134,864
Inventory and other current assets............................. 1,280,976 1,623,436
Assets held for sale........................................... -- 4,369,571
Deferred income taxes.......................................... 144,000 149,400
------------ -----------
Total current assets...................................... 48,426,684 56,462,467
Oil And Gas Properties -- At Cost (Full Cost Method):
Proved oil and gas properties.................................. 8,845,045 7,899,598
Unproved oil and gas leases.................................... 4,110,811 3,021,789
Accumulated depreciation, depletion, amortization and valuation
allowance..................................................... (3,828,104) (3,070,152)
------------ -----------
Net oil and gas properties................................ 9,127,752 7,851,235
Deferred income taxes............................................... 567,381 990,609
Other Assets:
Property and equipment, net.................................... 1,131,743 1,046,614
Lease financing receivable..................................... 1,127,556 756,105
Unconsolidated long-term investments........................... 195,361 243,891
Notes and land contract receivable............................. 1,667,905 1,612,087
Intangibles resulting from business acquisition, net of
accumulated amortization...................................... 284,375 225,827
Other.......................................................... 2,024 1,648
------------ -----------
Total other assets........................................ 4,408,964 3,886,172
------------ -----------
Total assets.............................................. $ 62,530,781 $69,190,483
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities:
Accounts payable............................................... $ 15,109,086 $14,590,308
Joint interest advances........................................ 7,046,030 6,674,268
Oil and gas distributions payable.............................. 10,831,028 9,553,220
Current maturities of long-term debt........................... 776,016 4,078,338
Taxes -- other than income taxes............................... 101,387 5,612,205
Other accrued expenses......................................... 4,548,559 4,185,232
Accrued income taxes........................................... 1,434,936 850,136
------------ -----------
Total current liabilities................................. 39,847,042 45,543,707
Deferred gain on sale of oil and gas properties..................... 165,000 119,500
Long-term debt...................................................... 1,702,085 1,185,137
Commitments and Contingencies
Shareholders' Equity:
Common Stock, $.00026 par value; 20,000,000 shares authorized;
9,519,500 shares issued and outstanding at December 31, 1994,
and 12,065,422 shares issued and outstanding at July 31,
1995.......................................................... 2,475 3,137
Additional paid-in capital..................................... 193,665 193,665
Retained earnings.............................................. 20,620,514 22,145,337
------------ -----------
Total shareholders' equity................................ 20,816,654 22,342,139
------------ -----------
Total liabilities and shareholders' equity................ $ 62,530,781 $69,190,483
========== ==========
</TABLE>
The accompanying notes are an integral part of these statements.
F-68
<PAGE> 160
TERRA ENERGY LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EARNINGS
<TABLE>
<CAPTION>
SEVEN MONTHS ENDED
YEAR ENDED JULY 31,
DECEMBER 31, ------------------------
1994 1994 1995
(UNAUDITED)
<S> <C> <C> <C>
Revenues:
Oil and gas sales................................... $ 8,072,286 $3,883,310 $10,226,871
Management and operator fees........................ 2,722,566 1,396,938 1,963,869
Gain on sales of assets............................. 2,900,000 2,900,000 994,069
Interest and dividends.............................. 695,835 337,325 540,889
Equity in gain of affiliated partnerships........... 673,631 168,744 34,343
Other............................................... 768,132 94,821 580,827
------------ ---------- -----------
Total revenues................................. 15,832,450 8,781,138 14,340,868
Operating Costs and Expenses:
Cost of products sold............................... 2,994,786 525,877 5,802,848
General and administrative.......................... 6,467,427 2,802,994 5,481,516
Depreciation, depletion and amortization............ 954,919 702,134 464,214
Lease operating..................................... 1,005,327 624,533 377,646
Production and other state taxes.................... 279,419 214,303 267,216
Interest............................................ 64,301 46,692 36,033
Equity in loss of affiliated partnerships........... 46,318 -- --
------------ ---------- -----------
Total operating costs and expenses............. 11,812,497 4,916,533 12,429,473
Write down of notes receivable, net of notes payable..... (1,450,992) -- --
Earnings before income taxes and minority interest in
subsidiary............................................. 2,568,961 3,864,605 1,911,395
Minority interest in subsidiary.......................... 216,512 142,912 --
Income taxes............................................. 517,669 861,616 386,572
------------ ---------- -----------
Net earnings................................... $ 1,834,780 $2,860,077 $ 1,524,823
========== ========= ==========
</TABLE>
The accompanying notes are an integral part of these statements.
F-69
<PAGE> 161
TERRA ENERGY LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
ADDITIONAL
OUTSTANDING COMMON PAID-IN RETAINED
SHARES STOCK CAPITAL EARNINGS TOTAL
<S> <C> <C> <C> <C> <C>
Balance as previously stated........... 9,519,500 $2,475 $ 193,665 $20,853,065 $21,049,205
Full cost adjustments............. -- -- -- (2,067,331) (2,067,331)
----------- ------ ---------- ----------- -----------
Balance:
January 1, 1994................... 9,519,500 2,475 193,665 18,785,734 18,981,874
Net Earnings........................... -- -- -- 1,834,780 1,834,780
----------- ------ ---------- ----------- -----------
Balance:
December 31, 1994................. 9,519,500 2,475 193,665 20,620,514 20,816,654
Stock issuances:
Stock option (unaudited).......... 2,545,922 662 -- -- 662
Net earnings (unaudited)............... -- -- -- 1,524,823 1,524,823
----------- ------ ---------- ----------- -----------
Balance:
July 31, 1995 (unaudited)......... 12,065,422 $3,137 $ 193,665 $22,145,337 $22,342,139
========== ====== ======== ========== ==========
</TABLE>
The accompanying notes are an integral part of these statements.
F-70
<PAGE> 162
TERRA ENERGY LTD. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
SEVEN MONTHS ENDED
YEAR ENDED JULY 31,
DECEMBER 31, --------------------------
1994 1994 1995
(UNAUDITED)
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net earnings..................................... $ 1,834,780 $ 2,860,077 $ 1,524,823
Adjustments To Reconcile Net Earnings To Net Cash
Provided By (Used In) Operations:
Depreciation, depletion and amortization....... 954,919 702,134 464,214
Increase in deferred income taxes.............. (113,508) (457,455) (417,828)
Recognition of deferred gain on sale of
properties.................................. (78,000) (45,500) (45,500)
Gain on sale of assets......................... (2,900,000) (2,900,000) (994,069)
Write down of notes receivable................. 1,450,992 -- --
Changes In Assets And Liabilities That Provided
(Used) Cash:
Accounts receivable......................... (15,403,917) (14,554,724) (11,822,874)
Inventory and other current assets.......... (662,822) (1,230,813) (342,460)
Accounts payable............................ 4,774,271 9,292,830 (518,778)
Joint interest advances..................... 6,633,664 378,098 (371,762)
Oil and gas distributions payable........... 2,566,349 2,107,666 (1,277,808)
Accrued income taxes........................ 1,273,936 843,064 (584,800)
Taxes and other accrued expenses............ 3,811,199 (395,439) 5,147,491
Minority interest in subsidiary............. (6,813) (6,813) --
Equity in net income of affiliated
partnerships................................ (627,313) (168,744) (34,343)
Equity in net income of affiliate.............. (42,426) -- (46,422)
------------ ----------- ------------
Net cash flows provided by (used in)
operating activities...................... 3,465,311 (3,575,619) (9,320,116)
Cash Flows from Investing Activities:
Purchases of oil and gas properties.............. (12,705,648) (5,164,406) (4,124,057)
Purchases of property and equipment.............. (670,888) (205,513) (442,199)
Proceeds from sale of assets..................... 15,883,828 4,825,516 6,505,881
(Increase) decrease in long-term investments..... 1,035,160 (234,142) 32,235
(Increase) decrease in lease financing
receivable..................................... 82,652 (123,879) 175,026
(Increase) decrease in notes receivable.......... (82,779) 21,154 68,900
Increase in other assets......................... (1,000) -- --
Increase in assets held for sale................. -- -- (4,369,571)
------------ ----------- ------------
Net cash flows provided by (used in)
investing activities...................... 3,541,325 (881,270) (2,153,785)
Cash Flows from Financing Activities:
Proceeds from long-term debt..................... 46,678 -- 3,044,201
Payments of long-term debt....................... (1,092,720) (977,570) (258,827)
Stock options exercised.......................... -- -- 662
------------ ----------- ------------
Net cash flows provided by (used in)
financing activities...................... (1,046,042) (977,570) 2,786,036
Net increase (decrease) in cash and cash
equivalents......................................... 5,960,594 (5,434,459) (8,687,865)
Cash and cash equivalents at beginning of period...... 9,729,661 9,729,661 15,690,255
------------ ----------- ------------
Cash and cash equivalents at end of period............ $ 15,690,255 $ 4,295,202 $ 7,002,390
=========== ========== ===========
Supplemental Cash Flow Information:
Cash Paid During The Year For:
Interest....................................... $ 117,342 $ 77,156 $ 43,506
Income taxes................................... $ 1,253,064 $ 650,000 $ 1,400,000
</TABLE>
The accompanying notes are an integral part of these statements.
F-71
<PAGE> 163
TERRA ENERGY LTD. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
1. ORGANIZATION AND BUSINESS
Terra Energy Ltd. (the "Company"), a Michigan corporation, is a domestic,
independent oil and gas exploration and production company. The Company has the
following subsidiaries that have been consolidated into these financial
statements:
Terra Pipeline Company ("TPC") is a 100% owned Michigan corporation.
TPC is engaged in the collection of oil and gas revenues from oil and gas
purchasers on behalf of other interest owners and the distribution of such
revenues to these owners. In addition, TPC handles the joint interest
billing responsibilities associated with the Company's producing oil and
gas properties.
Energy Acquisition Operating Corp. ("EAOC") is a 100% owned Michigan
corporation. EAOC provides natural gas transportation services in the
Michigan natural gas market. Effective April 1, 1994 the Company purchased
the remaining 5% ownership in EAOC.
Kristen Corporation ("Kristen") is a 100% owned Michigan corporation
engaged in natural gas marketing in the Michigan natural gas market.
Cronus Development Corp. ("Cronus") is a 100% owned Michigan
corporation. Cronus is engaged in the acquisition of oil and gas leasehold
interests for future exploration and development.
Wellcorps, L.L.C. ("Wellcorp") is a 55% owned Michigan limited
liability company. Wellcorp is engaged in the oil and gas service segment
providing workover rig services to producers with Michigan operations.
The Company also serves as managing partner of a general partnership which
owns and operates a pipeline located in Antrim and Otsego counties of Michigan.
TPC also serves as the managing partner of a limited partnership which owns and
operates a pipeline and gas processing plant located in Newaygo and Oceana
counties of Michigan. These partnerships are discussed more fully in Note 7.
2. SIGNIFICANT ACCOUNTING POLICIES
A. FINANCIAL STATEMENTS
For purposes of these financial statements, the Company has given
retroactive effect to the change in the method of accounting for the Company's
oil and gas producing activities from the successful efforts method to the full
cost method. This change was made in order to present comparative information
between the Company and an unrelated third party which acquired all of the
issued and outstanding stock of the Company in August 1995 (see Note 19). This
unrelated third party also follows the full cost method of accounting for its
oil and gas producing activities.
The financial statements and related information as of and for the seven
months ended July 31, 1994 and 1995 included herein are unaudited and, in the
opinion of management, reflect all adjustments (consisting of only recurring
adjustments, except as discussed in Note 19) necessary for a fair presentation
of financial position and the results of operations and cash flows.
Additionally, all other financial statement information contained in the Notes
to Financial Statements, which occurred subsequent to December 31, 1994, is
unaudited.
These unaudited consolidated financial statements should be read in
conjunction with the Company's consolidated financial statements as of and for
the year ended December 31, 1994. The consolidated results of operations for the
seven months ended July 31, 1995 and 1994 are not necessarily indicative of
operating results for a full year.
B. PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company,
TPC, EAOC, Kristen, Cronus and Wellcorp. All significant intercompany accounts
and transactions have been eliminated in consolidation.
F-72
<PAGE> 164
C. CASH AND CASH EQUIVALENTS
Cash and cash equivalents are comprised of cash, certificates of deposit
and U.S. Government Securities with original maturities of three months or less.
D. MARKETABLE SECURITIES
Marketable securities are carried at the lower of cost or market value.
E. ACCOUNTS RECEIVABLE
Accounts receivable -- trade consist primarily of amounts due to the
Company by co-owners of oil and gas properties for which the Company serves as
operator and has responsibility for payment to vendors for goods and services
related to joint operations. The Company provides an allowance for doubtful
accounts for those balances considered to be uncollectible.
F. INVENTORY
Inventory was valued at the lower of cost (first-in, first-out method) or
market.
G. OIL AND GAS PROPERTIES
The Company follows the full cost method of accounting for its oil and gas
producing activities.
Acquisition costs for proved and unproved properties are capitalized when
incurred. Costs of unproved properties are transferred to proved properties when
proved reserves are discovered. Exploration and development costs, including
geological and geophysical costs and costs of carrying and retaining unproved
properties, are capitalized as incurred. There has been no income recognized in
connection with contractual services performed in connection with properties in
which the Company holds an ownership or other economic interest, rather, these
amounts are credited to oil and gas properties. Costs incurred to operate and
maintain wells and equipment and to lift oil and gas to the surface are
generally expensed.
The net cost of proved oil and gas properties are annually subjected to a
test of recoverability by comparing the net cost for these properties to the
estimated present value of future net cash flows from proved reserves.
Sales of oil and gas properties are accounted for as adjustments to the
cost of oil and gas properties, with no gain or loss recognized.
Depreciation, depletion and amortization of oil and gas properties is
computed on a units-of-production method based on proved reserves. Costs
associated with unproved properties are not amortized until proved reserves are
discovered. The provision for depreciation, depletion and amortization is
calculated by applying the ratio to capitalized property costs.
H. OTHER ASSETS -- PROPERTY AND EQUIPMENT
Property and equipment is recorded at cost and depreciation is calculated
using the straight-line and declining balance methods over the respective
estimated useful life of the related asset.
I. INCOME TAXES
The Company adopted Statement of Financial Accounting Standards ("SFAS")
No. 109, Accounting for Income Taxes, in 1993. The standard prescribes a
liability method for calculating the provision for income taxes, replacing the
deferred method previously used by the Company.
J. NEW ACCOUNTING STANDARDS
In March 1995, the Financial Accounting Standards Board issued SFAS No.
121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of, effective for 1996 year-end
F-73
<PAGE> 165
financial statements. The Company does not believe that it will be significantly
affected by the statement, which establishes accounting standards for the
impairment of long-lived assets.
K. 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.
3. ACCOUNTS RECEIVABLE
Accounts receivable consisted of the following components as of December
31, 1994:
<TABLE>
<S> <C>
Trade................................................................... $21,905,528
Oil and gas sales....................................................... 8,535,122
Related parties......................................................... 70,913
Lease financing......................................................... 624,844
-----------
Total accounts receivable..................................... $31,136,407
===========
</TABLE>
4. NOTES AND LAND CONTRACT RECEIVABLE
Notes and land contract receivable consisted of the following components as
of December 31, 1994:
<TABLE>
<S> <C>
Producing property sale.................................................. $1,720,016
Other.................................................................... 95,835
----------
Total.......................................................... 1,815,851
Less current portion..................................................... 147,946
----------
Total long-term notes and land contract receivable............. $1,667,905
==========
</TABLE>
The Company recorded a valuation allowance at December 31, 1994 in the
amount of $1,612,000 to reduce the outstanding balance of the notes receivable,
resulting from the producing property sale, to the estimated fair market value
of the producing properties securing these notes receivable. This valuation was
recorded net of a note payable valuation allowance on the same property of
approximately $161,000.
5. INVENTORY
Inventory consists primarily of casing and tubular goods utilized in the
Company's exploration activities. The Company realized a gain of approximately
$158,000 for 1994, from the disposition of certain inventory items. This gain on
sale of inventory is reported as other income on the Company's Consolidated
Statement of Earnings.
6. PROPERTY AND EQUIPMENT
Property and equipment consist of the following as of December 31, 1994:
<TABLE>
<S> <C>
Land..................................................................... $ 497,168
Building and improvements................................................ 399,482
Office and transportation equipment...................................... 545,208
Field equipment.......................................................... 263,912
----------
Total.......................................................... 1,705,770
Less accumulated depreciation and amortization........................... 574,027
----------
Net property and equipment..................................... $1,131,743
==========
</TABLE>
F-74
<PAGE> 166
7. UNCONSOLIDATED LONG-TERM INVESTMENTS
The Company's investment in unconsolidated subsidiaries is as follows as of
December 31, 1994:
<TABLE>
<S> <C>
Partnerships using the equity method of accounting........................ $154,188
Corporation using the equity method of accounting......................... 32,235
Corporations using the cost method of accounting.......................... 8,938
--------
Total........................................................... $195,361
========
</TABLE>
Net earnings of the above investments which are included in the earnings of
the Company are as follows for the year ended December 31, 1994:
<TABLE>
<S> <C>
Partnerships using the equity method of accounting........................ $627,313
--------
Corporation using the equity method of accounting......................... $ 42,426
========
</TABLE>
The Company has a consolidated net interest of 44.768% in Newaygo/Oceana
Pipeline Limited Partnership ("NOPLP"). The Company's 100% owned subsidiary,
TPC, is the general partner of this limited partnership. NOPLP owns and operates
a gas pipeline in Newaygo and Oceana counties of Michigan. The Company provides
administrative and accounting services to NOPLP for an agreed-upon fee. Due to
the shut-in status of the properties connected to the gas pipeline, the
partnership is currently inactive.
The Company's consolidated net interest in Terra-Hayes Pipeline Company
("THPC") was 26.58% at December 31, 1994. The Company is the managing partner in
this general partnership. THPC owns and operates a gas pipeline in Antrim and
Otsego counties of Michigan. The Company provides administrative and accounting
services to THPC and, pursuant to the terms of the partnership agreement,
received reimbursements for such services.
The Company has a net interest of 40% in an oil and gas drilling and
completion consulting firm, which provides supervisory and management services
for substantially all of the Company's drilling, completion and facility
construction operations.
The Company has a net interest of 10% in Nepenthe Corp. ("Nepenthe"), a
corporation owning outside operated oil and gas interests and real estate. In
January 1995, Nepenthe acquired this interest from the Company for $120,000.
The Company is a shareholder in four corporations that provide pumping and
other related services to the Company for substantially all of the Company's
producing oil and gas properties. The Company also provides these corporations
with financial, accounting, tax administration, engineering, consulting and
advisory services including full access and use of the Company's extensive field
communications system, under the terms of a general services contract.
Fees charged to the Company by these partnerships and corporations are
approximately as follows for the year ended December 31, 1994:
<TABLE>
<S> <C>
Corporation using the equity method of accounting........................ $ 870,000
Corporations using the cost method of accounting......................... $2,498,000
</TABLE>
Fees charged by the Company to these partnerships and corporations are
approximately as follows for the year ended December 31, 1994:
<TABLE>
<S> <C>
Partnerships using the equity method of accounting........................ $ 51,000
Corporations using the cost method of accounting.......................... $514,000
</TABLE>
8. INTANGIBLES RESULTING FROM BUSINESS ACQUISITION
Effective December 1, 1991 the Company exercised an option obtained upon
the formation of EAOC to acquire an additional 50% ownership in EAOC from a
third party in exchange for $830,000. The Company is amortizing its basis in
this acquisition on a pro-rata basis over the expected life of the asset
acquired in this
F-75
<PAGE> 167
purchase. The Company has not modified its amortization of this asset as a
result of the sale of the gas purchase contract discussed in Note 16 due to the
retention of all firm transportation rights provided for in said gas purchase
contract.
9. LONG-TERM DEBT
Long-term debt consisted of the following components as of December 31,
1994:
<TABLE>
<S> <C>
Land contracts........................................................... $ 117,254
Capitalized leases....................................................... 2,188,845
Property sale financing.................................................. 172,002
----------
2,478,101
Less current maturities of long-term debt and capitalized leases......... 776,016
----------
Total long-term debt........................................... $1,702,085
=========
</TABLE>
A schedule of the combined amount of all debt subject to mandatory
redemption during the years ended December 31 may be summarized as follows:
<TABLE>
<S> <C>
1995..................................................................... $ 776,016
1996..................................................................... 836,475
1997..................................................................... 427,099
1998..................................................................... 190,461
1999..................................................................... 99,764
2000 and after........................................................... 148,286
----------
Total.......................................................... $2,478,101
=========
</TABLE>
Land contracts included above are payable monthly at varied interest rates
through April 2003.
Installments loans are secured by vehicles and payable monthly at varied
interest rates through November 1996.
The present value of future capital lease payments associated with capital
leases for gas compression equipment includes $736,129 classified as a current
liability and $1,452,716 classified as long-term debt. Lease payments under
these capital leases are due through September 1999.
In August 1993, the Company entered into an unsecured term loan agreement
with its bank providing for a term loan in the amount of $1,300,000. The loan
bears interest at 0.5% over the bank's prime rate and is repayable over 30 equal
monthly installments commencing on October 1, 1993. The loan was repaid in full
in April 1994.
At December 31, 1994, the Company also had a $2,000,000 unused short-term
line of credit with a bank secured by a general lien on all of the Company's
assets. Borrowings under this agreement bear interest at the bank's prime rate.
10. DEFERRED GAIN ON SALE OF OIL AND GAS PROPERTIES
In 1989 the Company sold a carved out overriding royalty interest in
certain proved properties to several purchasers for an aggregate consideration
of $585,000. The purchase and sales agreement provides that the purchasers are
entitled to a guaranteed minimum monthly return on the purchase price of 1.67%
until the purchasers recover the purchase price plus an additional 50% of the
purchase price. At such time, the Company's guarantee shall terminate and the
purchasers are entitled only to their respective share of gas revenues from
these properties. Under the terms of such guarantee, the Company made payments
of $52,335 in 1994, in addition to the purchaser's share of net proceeds
realized from the sale of gas production. The Company is crediting a pro-rata
portion of the deferred gain resulting from the sale of these assets to oil and
gas properties each year based upon the repayments made to the purchasers in
each respective year until termination of the Company's guarantee. Aggregate
payments made in 1994 amounted to $117,000.
F-76
<PAGE> 168
11. INCOME TAXES
The provision for income taxes is as follows for the year ended December
31, 1994:
<TABLE>
<S> <C>
Current income taxes payable............................................. $ 704,777
Decrease in deferred income taxes payable................................ (113,508)
Tax attributable to minority interest in subsidiary...................... (73,600)
---------
Income taxes........................................................ $ 517,669
=========
</TABLE>
Deferred income taxes on the consolidated balance sheet reflect the net tax
effects of temporary differences between the carrying amounts of assets and
liabilities for financial reporting purposes and the amounts used for federal
and state income tax purposes. Significant components of the Company's deferred
tax assets as of December 31, 1994 are as follows:
<TABLE>
<S> <C>
Intangible drilling and other costs deducted for income tax purposes and
capitalized for financial statement purposes.......................... $(4,266,000)
Excess of accrual basis net income for financial statement purposes over
cash basis net income reported for income tax purposes and other...... 3,022,381
Excess of financial statement depletion over depletion computed for
income tax purposes................................................... 960,000
Gain from the sale of oil and gas properties recognized for income tax
purposes but not for financial statement purposes..................... 70,000
Gain from the sale of oil and gas properties recognized for financial
statement purposes but recognized for income tax purposes in a
different accounting period........................................... (199,000)
Alternative minimum tax credit utilized................................. 1,124,000
-----------
Total differences............................................. $ 711,381
===========
</TABLE>
The differences between the Company's income tax expense and amount
calculated utilizing the federal statutory rate are as follows for the year
ended December 31, 1994:
<TABLE>
<S> <C>
Amount computed using the statutory rate................................. $ 823,357
Benefit of the percentage depletion allowance deducted for income tax
purposes............................................................... (97,000)
Alternative minimum tax credit utilized.................................. (203,688)
Other.................................................................... (5,000)
---------
Income taxes................................................... $ 517,669
=========
</TABLE>
As of December 31, 1994 approximately $2,266,000 of alternative minimum tax
credit is available to be applied against future regular income taxes. For
financial statement purposes, $1,124,000 of this balance has been used to reduce
deferred income taxes as of December 31, 1994.
12. COMMITMENTS AND CONTINGENCIES
Irrevocable Letters of Credit
The Company has obtained several irrevocable letters of credit in the
aggregate amount of approximately $825,000 which serve as performance bonds
required by state oil and gas regulations. These letters of credit are generally
renewed annually upon their anniversary dates, and they are collaterized by the
Company's office facilities and related real estate.
Leasing Arrangements
The Company has entered into certain noncancellable leasing agreements for
gas compression equipment used on gas wells. These capital and operating leases
are generally for three to five year terms, which are renewable.
For capital leases the Company records an asset and a liability at the
inception of the lease equal to the present value of future minimum lease
payments. A portion of the asset, which is recorded in oil and gas
F-77
<PAGE> 169
properties, represents the Company's ownership interest in each well where the
equipment is located. These leased assets amounts to $608,586 at December 31,
1994. The remaining portion of the asset is recorded as a receivable for lease
payments due from working interest owners in various producing properties where
the leased equipment is in service. The current and long-term portions of this
lease financing receivable at December 31, 1994 were $624,844 and $1,127,556,
respectively, and were recorded in accounts receivable and other assets,
respectively. The capital lease liability is included in long-term debt and is
more fully described in Note 9.
The following is a schedule by year of future minimum rental payments
required under operating leases that have initial or remaining noncancellable
lease terms in excess of one year as of December 31, 1994:
<TABLE>
<CAPTION>
OPERATING
YEAR ENDING DECEMBER 31, LEASES
<S> <C>
1995........................................................... $181,389
1996........................................................... 122,087
1997........................................................... 50,698
1998........................................................... 14,639
1999........................................................... --
--------
Total minimum rentals................................ $368,813
========
</TABLE>
The above rental payments represent the Company's portion of the total
rental payments due under the leases based on the Company's net working interest
in each producing property on which the equipment was being used as of December
31, 1994. The Company, as operator, charges the remaining working interest
owners participating in each producing property for their proportionate share of
such monthly equipment rental payments.
The Company's total rental expense for all operating leases for the year
ended December 31, 1994 was approximately $247,000.
13. TRANSACTIONS WITH RELATED PARTIES
The Company and certain officers and directors are joint owners in various
unproved and producing properties. Transactions with related parties investing
in oil and gas exploration activities are carried out in the same manner as
transactions with unrelated working interest partners. Estimated costs are
usually billed prior to commencement of a project and cost incurred are netted
against the advances as the project progresses.
14. SHAREHOLDERS' EQUITY
COMMON STOCK
Effective April 1, 1988, the Company signed a stock option agreement with
an officer of the Company, wherein the officer will earn an option to purchase
up to 503,132 shares of the Company's common stock over a period of five years.
The option price is $162,500 for all the shares or $0.32298 per share, and the
option will expire if not exercised before March 31, 2003.
Effective January 1, 1991, the Company entered into a stock option
agreement with the same officer, wherein the officer will earn an option to
purchase up to 1,437,519 additional shares of the Company's common stock vesting
on a pro-rata basis between January 1, 1991 and March 12, 1994. Also effective
January 1, 1991, the Company entered into a stock option agreement with another
officer, wherein the officer will earn an option to purchase up to 605,271
shares of the Company's common stock vesting on a pro-rata basis between January
1, 1991 and December 31, 1995. Both of these stock option agreements provide for
an option price of $0.50 per share, and the options covered by these two
agreements will expire if not exercised on or before January 1, 2001. At the
time of issuance of the stock option agreements, the exercise prices of the
stock options granted thereby were believed to have represented the fair value
of the shares issuable upon exercise of these options.
F-78
<PAGE> 170
15. DEFINED CONTRIBUTION PLAN
The Company has a 401(K) profit sharing plan covering substantially all
employees. Company contributions to the plan are discretionary and are allocated
based on employee compensation. The Company has contributed approximately
$120,000 to the plan for the 1994 plan year.
16. SALE OF OIL AND GAS PROPERTIES AND GAS PURCHASE CONTRACT
In two transactions during 1991 and 1992 the Company sold producing
properties with a book value of approximately $967,000 for a total sales price
of $2,300,000. The purchase and sales agreement provided that the Company
guarantee certain minimum annual cash flow distributions aggregating $2,400,000
cumulatively through December 31, 1995. Payments of $263,331 were due under the
guarantee provisions and were included in other accrued expenses at December 31,
1994.
During 1994, the Company sold to several purchasing parties producing and
unproved oil and gas leases with a book value of $1,395,000 and $1,983,000,
respectively. The aggregate sales consideration was $1,811,000 and $11,110,000,
respectively. The sales of these properties are accounted for as adjustments of
capitalized costs.
Effective April 1, 1994 the Company also sold its interest in a gas
purchase contract owned by its subsidiary, EAOC, for a cash consideration of
$2,900,000. This gain on the sale of the gas purchase contract has been
reflected in the consolidated statement of earnings. As discussed in Note 8,
EAOC did not sell the firm transportation rights provided to the seller under
said contract. EAOC continues to provide transportation services to the Company
for the delivery of gas to market for purchase by a third party purchaser.
17. FINANCIAL INSTRUMENTS WITH OFF-BALANCE SHEET RISK AND CONCENTRATIONS OF
CREDIT RISK
OFF-BALANCE SHEET RISK
The Company does not consider itself to have any material financial
instruments with off-balance sheet risks other than those disclosed in Note 12.
CONCENTRATIONS OF CREDIT RISK
Financial instruments that potentially subject the Company to credit risk
include cash on deposit with one financial institution in which these deposits
exceed the Federally insured amount. The Company places its temporary cash
investment with high credit quality financial institutions. At December 31, 1994
the majority of the cash is either insured by the U.S. Federal Deposit Insurance
Corporation or has pledged securities by the financial institution in which the
cash is deposited.
The Company extends credit to various companies in the oil and gas industry
in the normal course of business. Within this industry, certain concentrations
of credit risk exist. The Company, in its role as operator of co-owned
properties, assumes responsibility for payment to vendors for goods and services
related to joint operations and extends credit to co-owners of these properties.
This concentration of credit risk may be similarly affected by changes in
economic or other conditions and may, accordingly, impact the Company's overall
credit risk. However, management believes that its accounts receivable are well
diversified, thereby reducing potential credit risk to the Company.
At December 31, 1994 accounts and notes receivable relating to these
co-owners were approximately $7,983,000 and $1,676,000, respectively. The notes
receivable are secured by certain producing property interests as discussed in
Note 16.
F-79
<PAGE> 171
18. SCHEDULE OF NONCASH INVESTING AND FINANCING ACTIVITIES
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31, 1994
<S> <C>
INVESTMENT
Write-down to fair market value......................................... $ 135,000
NOTES RECEIVABLE
Exchange for oil and gas property....................................... $ 800,000
Valuation write-down.................................................... $ 1,450,992
</TABLE>
19. SUBSEQUENT EVENTS (UNAUDITED)
The Company has entered into two sales agreements providing for the sale of
a natural gas transmission pipeline and a CO2 processing plant currently under
construction. The book value of these assets approximating $4,370,000 has been
reclassified to Assets Held for Sale as of July 31, 1995. The Company has also
obtained bank financing in the amount of $5,130,000 covering construction costs
of the CO2 processing plant. The loan agreement provides that interest is
payable monthly at the banks prime rate and that the loan would be repaid in
full on October 1, 1995. As of July 31, 1995, the outstanding balance under this
loan agreement was $3,000,000.
On August 31, 1995, the Company's shareholders exchanged 100% of the
outstanding common stock of the Company for common stock in a publicly traded
international energy company. The Company will operate as a separate business
unit conducting domestic oil and gas exploration, development and production
activities.
Prior to the above transaction, (i) certain oil and gas properties and
property and equipment were sold to some of the Company's shareholders for
$5,000,000, which resulted in the inclusion of $5,000,000 in accounts receivable
at July 31, 1995. The gain on the sale of the property and equipment of $994,069
is reflected in the consolidated statements of earnings, while the sales of the
oil and gas properties are reflected as adjustments of capitalized costs; (ii)
stock options were exercised, resulting in an increase in the number of
outstanding shares of stock of 2,545,922 and an increase in common stock of
$662; and (iii) employee bonuses were authorized for approximately $3.6 million,
which were reflected as general and administrative expenses in the consolidated
statements of earnings for the seven months ended July 31, 1995.
F-80
<PAGE> 172
TERRA ENERGY LTD. AND SUBSIDIARIES
SUPPLEMENTAL OIL AND GAS DISCLOSURES OF EXPLORATION AND PRODUCTION 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 Earnings for the Company's
results of operations from exploration and production activities.
The following estimates, which were prepared by the Company's petroleum
engineers, of proved developed and proved undeveloped reserve quantities and
related standardized measure of discounted estimated future net cash flows 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 gas properties. Accordingly, these estimates are expected to
change as future information becomes available. All of the Company's reserves
are located in the United States.
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.
1. ESTIMATED PROVED RESERVES OF OIL AND GAS
<TABLE>
<CAPTION>
TOTAL
---------------
OIL GAS
(OIL IN MBBLS
AND GAS IN BCF)
<S> <C> <C>
Estimated Proved Developed and Undeveloped Reserves:
December 31, 1993...................................................... 81 70
Extensions and discoveries........................................... -- 7
Production........................................................... 27 (2)
--- ---
December 31, 1994...................................................... 54 75
=== ===
Estimated Proved Developed Reserves:
December 31, 1994...................................................... 54 71
=== ===
</TABLE>
2. STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS FROM ESTIMATED
PROVED RESERVES
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
<S> <C>
December 31, 1994:
Future Cash Flows, Net of Transportation:
Revenues(1)........................................................ $123,409
Less:
Production costs(2)................................................ 59,288
Development costs(2)............................................... 752
--------
Future cash flows before taxes....................................... 63,369
Income tax expense (benefit)(3).................................... --
--------
Future net cash flows................................................ 63,369
Less discount to present value at a 10% annual rate.................. 25,824
--------
Standardized measure of discounted future net cash flows............. $ 37,545
========
</TABLE>
- ------------------------------
(1) Oil, 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 proved reserves.
(2) Based on economic conditions at year-end. Does not include administrative,
general 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 $20.0 million of U.S. income tax credits for
Antrim gas production at December 31, 1994.
F-81
<PAGE> 173
3. RECONCILIATION OF THE CHANGE IN THE STANDARDIZED MEASURE OF DISCOUNTED FUTURE
NET CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994
(DOLLARS IN THOUSANDS)
<S> <C>
New discoveries........................................................... $ 3,646
Sales and transfers....................................................... (2,469)
Changes in prices......................................................... (1,379)
Accretion of discount..................................................... 3,520
Net change in income taxes................................................ (821)
Change in timing of production and other.................................. (150)
--------
Net change during the year...................................... $ 2,347
========
</TABLE>
4. NET INVESTMENT IN PROVED AREAS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994
(DOLLARS IN THOUSANDS)
<S> <C>
Developed properties...................................................... $ 22,541
Undeveloped properties
Subject to depletion................................................. --
Not subject to depletion............................................. 4,111
--------
26,652
Less accumulated depletion and amortization............................... (5,561)
--------
$ 21,091
========
</TABLE>
5. EXPLORATION, DEVELOPMENT AND ACQUISITION EXPENDITURES IN PROVED AREAS
<TABLE>
<CAPTION>
YEAR ENDED
DECEMBER 31,
1994(1)
(DOLLARS IN THOUSANDS)
<S> <C>
Exploration............................................................... $ 115
Development............................................................... 5,884
Property acquisitions..................................................... 6,818
</TABLE>
- ------------------------------
(1) Excluded is approximately $218,000 invested in unproved areas and non-oil
and gas producing properties. Included are $2,366,000 for investment and
purchases of estimated proved reserves.
F-82
<PAGE> 174
PRO FORMA CONSOLIDATED FINANCIAL INFORMATION OF WALTER
On February 24, 1995, Walter acquired certain oil and gas properties of the
Amoco Congo Companies ("Congo Acquisition"). The acquisition has been accounted
for using the purchase method of accounting. The following unaudited Pro Forma
Consolidated Statements of Operations (i) for the year ended December 31, 1994
and (ii) for the one month ended January 31, 1995 and the nine months ended
September 30, 1995 assume the Congo Acquisition was consummated as of January 1,
1994 and January 1, 1995, respectively. As the Congo Acquisition was consummated
on February 24, 1995, the unaudited Pro Forma Consolidated Balance Sheet as of
September 30, 1995 is identical to the historical consolidated balance sheet as
of September 30, 1995.
The unaudited Pro Forma Consolidated Financial Information do not purport
to be indicative of the results of operations or financial position of Walter
had the Congo Acquisition occurred on the dates assumed, nor is such Pro Forma
Consolidated Financial Information necessarily indicative of the future results
of operations of Walter. The Pro Forma Consolidated Financial Information should
be read in conjunction with the historical Consolidated Financial Statements of
Walter and the Amoco Congo Companies contained elsewhere herein.
F-83
<PAGE> 175
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE ONE MONTH ENDED JANUARY
31, 1995
AND THE NINE MONTHS ENDED SEPTEMBER 30, 1995
(UNAUDITED)
<TABLE>
<CAPTION>
WALTER AND WALTER WALTER
AMOCO PRO FORMA PRO FORMA
WALTER CONGO PRO FORMA (JANUARY 31, (SEPTEMBER 30,
HISTORICAL(1) HISTORICAL(2) ADJUSTMENTS 1995) 1995)
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate............. $15,126 $ 2,592 $2,592 $ 17,718
Other operating................ 363 -- -- 363
------- ------- ------ --------
15,489 2,592 2,592 18,081
Operating Expenses:
Depreciation, depletion and
amortization................. 3,238 191 $ 241(3) 432 3,670
Operating and maintenance...... 5,712 534 534 6,246
General and administrative..... 531 306 306 837
Production and other taxes..... 71 5 5 76
------- ------- ----- ------ --------
9,552 1,036 241 1,277 10,829
Pretax operating income............. 5,937 1,556 (241) 1,315 7,252
Other income................... 109 5 -- 5 114
Interest expense, net.......... 757 78 (51)(4) 27 784
------- ------- ----- ------ --------
Income before income taxes.......... 5,289 1,483 (190) 1,293 6,582
Income tax provision
(benefit).................... 1,987 -- --(5) -- 1,987
------- ------- ----- ------ --------
Net income................ $ 3,302 $ 1,483 $(190) $1,293 $ 4,595
======= ======= ===== ====== ========
</TABLE>
- ------------------------------
Notes to Pro Forma Consolidated Statement of Operations For the One Month Ended
January 31, 1995 and the Nine Months Ended September 30, 1995:
(1) The Company acquired Walter on February 27, 1995. Walter (along with an
unrelated company) acquired Amoco Congo Companies on February 24, 1995. This
column reflects the historical results of operations of Walter (including
Walter's effective interest in the Amoco Congo Companies) for the eight
months ended September 30, 1995.
(2) This column reflects the combined historical results of operations of Walter
and Amoco Congo Companies (based on Walter's effective interest in the Amoco
Congo Companies) for the one month ended January 31, 1995. Walter's income
for the period was approximately $181,000 and Walter's 50% effective
interest in the Amoco Congo Companies' net income was approximately
$1,302,000. See the Consolidated Financial Statements of Walter and the
Combined Financial Statements of Amoco Congo Companies included elsewhere in
this Prospectus.
(3) Adjustment to reflect the "unit-of-production" depreciation, depletion and
amortization of oil and gas properties for the month ending January 31,
1995, using the full cost method, based on the purchase prices assigned by
the Company to Walter and to Walter's proportionate share of Amoco Congo
Companies.
(4) Adjustment to reflect the repayment of approximately $10.0 million of debt
and preferred stock (and the corresponding interest expense for the one
month ended January 31, 1995), with funds provided to the Company by CMS
Energy as part of the Walter Acquisition.
(5) Adjustment to income tax expense to reflect the combined results of
operations.
F-84
<PAGE> 176
PRO FORMA CONSOLIDATED BALANCE SHEET AS OF SEPTEMBER 30, 1995
(UNAUDITED)
<TABLE>
<CAPTION>
WALTER WALTER
HISTORICAL(1) PRO FORMA
(DOLLARS IN THOUSANDS)
<S> <C> <C>
ASSETS
Current Assets:
Cash.............................................................. $ 1,757 $ 1,757
Temporary cash investments........................................ 3,752 3,752
Accounts receivable............................................... 12,716 12,716
Other............................................................. 5,582 5,582
------- -------
23,807 23,807
Property, plant and equipment, at cost................................. 51,381 51,381
Less accumulated depreciation, depletion and amortization......... (3,270) (3,270)
------- -------
48,111 48,111
------- -------
Total assets................................................. $71,918 $71,918
======= =======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities:
Current maturities of long-term debt.............................. $ 3,069 $ 3,069
Accounts payable.................................................. 20,239 20,239
Accrued interest.................................................. 130 130
Accrued taxes and other........................................... 945 945
------- -------
24,383 24,383
Long-term debt......................................................... 8,246 8,246
Deferred income taxes and other credits................................ 991 991
Stockholder's Equity:
Common and preferred stock........................................ 1 1
Additional paid-in capital........................................ 34,995 34,995
Retained deficit.................................................. 3,302 3,302
------- -------
38,298 38,298
------- -------
Total liabilities and stockholder's equity................... $71,918 $71,918
======= =======
</TABLE>
- ------------------------------
Notes to Pro Forma Consolidated Balance Sheet as of September 30, 1995:
(1) The Company acquired Walter on February 27, 1995. Walter (along with an
unrelated company) acquired Amoco Congo Companies on February 24, 1995.
Therefore, Walter's historical balance sheet as of September 30, 1995
includes the balances of Amoco Congo Companies (based on Walter's
proportionate share of Amoco Congo Companies).
F-85
<PAGE> 177
PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS FOR THE YEAR ENDED DECEMBER 31,
1994
(UNAUDITED)
<TABLE>
<CAPTION>
AMOCO
WALTER CONGO PRO FORMA WALTER
HISTORICAL(1) HISTORICAL(2) ADJUSTMENTS PRO FORMA
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C>
Operating Revenues:
Oil and condensate........................ $ 3,958 $18,625 $22,583
Other operating........................... -- 148 148
------- ------- -------
3,958 18,773 22,731
Operating Expenses:
Depreciation, depletion and
amortization............................ 588 1,332 $ 3,024(3) 4,944
Operating and maintenance................. 1,575 5,279 6,854
General and administrative................ 405 3,476 3,881
------- ------- ------- -------
2,568 10,087 3,024 15,679
Pretax operating income........................ 1,390 8,686 (3,024) 7,052
Other income.............................. 53 -- 53
Interest expense, net..................... 820 -- (610)(4) 210
------- ------- ------- -------
Income before income taxes..................... 623 8,686 (2,414) 6,895
Income tax provision (benefit)............ 14 -- --(5) 14
------- ------- ------- -------
Net income........................... $ 609 $ 8,686 $(2,414) $ 6,881
======= ======= ======= =======
</TABLE>
- ------------------------------
Notes to Pro Forma Consolidated Statement of Operations for the Year Ended
December 31, 1994:
(1) The Company acquired Walter on February 27, 1995. This column reflects the
historical results of operations of Walter for the twelve months ended
December 31, 1994.
(2) Walter (along with an unrelated company) acquired Amoco Congo Companies on
February 24, 1995. This column reflects the historical results of operations
of Amoco Congo Companies (based on Walter's 50% effective interest in Amoco
Congo Companies' net income) for the twelve months ended December 31, 1994.
See the Combined Financial Statements of Amoco Congo Companies included
elsewhere in this Prospectus.
(3) Adjustment to reflect the "unit-of-production" depreciation, depletion and
amortization of oil and gas properties, using the full cost method, based on
the purchase prices assigned by the Company to Walter and to Walter's
proportionate share of Amoco Congo Companies.
(4) Adjustment to reflect the repayment of approximately $10.0 million in debt
and preferred stock (and the corresponding interest expense), with funds
provided to the Company by CMS Energy as part of the Walter Acquisition.
(5) Adjustment to income tax expense to reflect the combined results of
operations.
F-86
<PAGE> 178
APPENDIX A
[LETTERHEAD]
October 2, 1995
CMS NOMECO Oil & Gas Co.
One Jackson Square
Post Office Box 1150
Jackson, Michigan 49204
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 NOMECO Oil & Gas Co. (NOMECO) as of June 30, 1995. The income data were
estimated using the Securities and Exchange Commission (SEC) guidelines for
future cost and price parameters.
The estimated reserves and future income amounts presented in this report
are related to hydrocarbon prices. June 1995 hydrocarbon prices were used in the
preparation of this report as required by SEC guidelines; however, actual future
prices may vary significantly from June 1995 prices. Therefore, volumes of
reserves actually recovered and amounts of income actually received may differ
significantly from the estimated quantities presented in this report. An
EXECUTIVE 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 NOMECO OIL & GAS CO.
AS OF JUNE 30, 1995
EXECUTIVE SUMMARY
<TABLE>
<CAPTION>
PROVED
---------------------------------------------------------------
DEVELOPED
----------------------------- TOTAL
PRODUCING NON-PRODUCING UNDEVELOPED PROVED
------------ ------------- ------------ --------------
<S> <C> <C> <C> <C>
NET REMAINING RESERVES
- ----------------------
Oil/Condensate -- Barrels.......... 27,491,431 6,606,754 31,580,462 65,678,647
Plant Products -- Barrels.......... 243,771 0 3,019,775 3,263,546
Gas -- MMCF........................ 226,327 28,180 43,543 298,050
INCOME DATA
- -----------
Future Gross Revenue............... $997,236,494 $ 144,420,217 $545,734,325 $1,687,391,036
Deductions......................... 359,568,519 55,667,267 209,915,951 691,593,806(1)
------------ ------------ ------------ --------------
Future Net Income (FNI)............ $637,667,975 $ 88,752,950 $335,818,374 $ 995,797,230
Discounted FNI @ 10%................. $436,063,136 $ 51,749,958 $191,721,994 $ 629,027,227
</TABLE>
- -------------------------
(1) Total proved net income includes operating and development costs of
-$66,442,069 and 10 percent discounted costs of -$50,507,861 which are not
allocated back to the producing, non-producing, and undeveloped categories.
These costs are total project costs required for the NOMECO concessions in
Ecuador and Venezuela.
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.
A-1
<PAGE> 179
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 in the attached "Definitions of Producing Status
Categories".
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, 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 was made to quantify or
otherwise account for any accumulated gas production imbalances that may exist.
Liquid hydrocarbon reserves account for approximately 57 percent and gas
reserves account for 35 percent of total future gross revenue from proved
reserves. The remaining 8 percent of future gross revenue which is shown as
"Other Income" is comprised of Section 29 Tax Credits and post-production cost
credit in the Antrim shale, and from secondary gas contracts in Michigan.
The cash flows prepared relative to the Terra Energy, Ltd. properties which
were acquired in August, 1995 do not take into account gas purchase contracts
held by Terra providing for gas sales prices exceeding the "spot" prices used in
the cash flows; nor do the cash flows take into account transportation
arrangements to which Terra is a party providing for cost-free transportation of
gas on the wet header system. These contract agreements will have additional
value to NOMECO and an estimate of the value may be determined based on our
estimated future production rates and the estimated future gas prices.
The discounted future net income shown above was calculated using a
discount rate of 10 percent per annum compounded monthly.
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 Bulletins. Our definition of
proved reserves is included in the attached "Definitions of Reserves".
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.
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
A-2
<PAGE> 180
production rates. For reserves not yet on production, sales were estimated to
commence at an anticipated date furnished by NOMECO.
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
NOMECO furnished us with prices in effect at June 30, 1995 and these prices
were held constant except for known and determinable escalations. In accordance
with Securities and Exchange Commission guidelines, changes in liquid and gas
prices subsequent to June 30, 1995 were not taken into account in this report.
Future prices used in this report are discussed in more detail in the attached
"Hydrocarbon Pricing Parameters".
COSTS
Operating costs for the projects, leases, and wells in this report are
based on the operating expense reports of NOMECO 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 NOMECO
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 considered by NOMECO to be insignificant and not
included for the properties in this report. No deduction 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
While it may reasonably be anticipated that the future prices received for
the sale of production and the operating costs and other costs relating to such
production may also increase or decrease from existing levels, such changes
were, in accordance with rules adopted by the SEC, omitted from consideration in
making this evaluation.
The estimates of reserves presented herein were based upon a detailed study
of the properties in which NOMECO 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. NOMECO 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 NOMECO were accepted without independent
verification. The estimates presented in this report are based on data available
through August 1995.
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.
A-3
<PAGE> 181
This report was prepared for the exclusive use of CMS NOMECO Oil & Gas Co.
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
PETROLEUM ENGINEERS
John R. Warner
--------------------------------------
John R. Warner, P.E.
Group Vice President
JRW/sw
A-4
<PAGE> 182
DEFINITIONS OF RESERVES
SEC PARAMETERS
SEC DEFINITIONS
Proved reserves of crude oil, condensate, natural gas, and natural gas
liquids are estimated quantities that geological and engineering data
demonstrate with reasonable certainty to be recoverable in the future from known
reservoirs under existing operating conditions using the cost and price
parameters discussed in other sections of this report. Reservoirs are considered
proved if economic producibility is supported by actual production or formation
tests. In certain instances, proved reserves are assigned on the basis of a
combination of core analysis and electrical and other type logs which indicate
the reservoirs are analogous to reservoirs in the same field which are producing
or have demonstrated the ability to produce on a formation test. The area of a
reservoir considered proved includes (1) that portion delineated by drilling and
defined by fluid contacts, if any, and (2) the adjoining portions not yet
drilled that can be reasonably judged as economically productive on the basis of
available geological and engineering data. In the absence of data on fluid
contacts, the lowest known structural occurrence of hydrocarbons controls the
lower proved limit of the reservoir. Proved reserves are estimates of
hydrocarbons to be recovered from a given date forward. They may be revised as
hydrocarbons are produced and additional data become available. Proved natural
gas reserves are comprised of non-associated, associated and dissolved gas. An
appropriate reduction in gas reserves has been made for the expected removal of
natural gas liquids, for lease and plant fuel, and for the exclusion of
non-hydrocarbon gases if they occur in significant quantities and are removed
prior to sale.
Reserves that can be produced economically through the application of
improved recovery techniques are included in the proved classification when
these qualifications are met: (1) 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, and (2) it is
reasonably certain the project will proceed. Improved recovery includes all
methods for supplementing natural reservoir forces and energy, or otherwise
increasing ultimate recovery from a reservoir, including (1) pressure
maintenance, (2) cycling, and (3) secondary recovery in its original sense.
Improved recovery also includes the enhanced recovery methods of thermal,
chemical flooding, and the use of miscible and immiscible displacement fluids.
Estimates of proved reserves do not include crude oil, natural gas, or
natural gas liquids being held in underground or surface storage.
A-5
<PAGE> 183
DEFINITIONS OF PRODUCING STATUS CATEGORIES
DEVELOPED PRODUCING
Producing reserves are recoverable from completion intervals currently open
and producing to market. Improved recovery reserves are considered to be
producing only after an improved recovery project has been installed and is in
operation.
DEVELOPED NON-PRODUCING
Shut-in reserves are recoverable from completion intervals now open, but
which had not started producing as of the date of our estimate.
Behind pipe reserves are recoverable from zones behind casing in existing
wells, which will require additional completion work or a future recompletion
prior to the start of production.
UNDEVELOPED
Undeveloped reserves are recoverable by new wells on undrilled acreage,
from existing wells where a relatively large expenditure is required for
recompletion and from acreage where the application of an improved recovery
project is planned and the costs required to place the project in operation are
relatively large. Reserves on undrilled acreage are limited to those drilling
units offsetting productive units that are reasonably certain of production when
drilled. Proved reserves for other undrilled units are included only where it
can be demonstrated with certainty that there is continuity of production from
the existing productive formation.
A-6
<PAGE> 184
HYDROCARBON PRICING PARAMETERS
SECURITIES AND EXCHANGE COMMISSION PARAMETERS
OIL AND CONDENSATE
NOMECO furnished us with oil and condensate prices in effect at June 30,
1995 and these prices were held constant to depletion of the properties. In
accordance with Securities and Exchange Commission guidelines, changes in liquid
prices subsequent to June 30, 1995 were not considered in this report.
PLANT PRODUCTS
NOMECO furnished us with plant product prices in effect at June 30, 1995
and these prices were held constant to depletion of the properties.
GAS
NOMECO furnished us with gas prices in effect at June 30, 1995 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
seasonable 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.
A-7
<PAGE> 185
------------------------------------------------------
------------------------------------------------------
NO PERSON HAS BEEN AUTHORIZED TO GIVE ANY INFORMATION OR TO MAKE ANY
REPRESENTATIONS OTHER THAN THOSE CONTAINED IN THIS PROSPECTUS, AND, IF GIVEN OR
MADE, SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL OR THE
SOLICITATION OF AN OFFER TO BUY ANY SECURITIES OTHER THAN THE SECURITIES TO
WHICH IT RELATES OR AN OFFER TO SELL OR THE SOLICITATION OF AN OFFER TO BUY SUCH
SECURITIES IN ANY CIRCUMSTANCES IN WHICH SUCH OFFER OR SOLICITATION IS UNLAWFUL.
NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE HEREUNDER SHALL, UNDER
ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THERE HAS BEEN NO CHANGE IN THE
AFFAIRS OF THE COMPANY SINCE THE DATE HEREOF OR THAT THE INFORMATION CONTAINED
HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO ITS DATE.
------------------------
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
Prospectus Summary........................ 3
Risk Factors.............................. 9
The Company............................... 16
Use of Proceeds........................... 17
Dividend Policy........................... 17
Dilution.................................. 18
Capitalization............................ 19
Pro Forma Consolidated Financial
Information............................. 20
Report of Independent Public
Accountants............................. 21
Selected Historical Consolidated Financial
Data.................................... 25
Management's Discussion and Analysis of
Financial Condition and Results of
Operations.............................. 26
Business and Properties................... 38
Management................................ 65
Ownership of Capital Stock................ 70
Relationship and Certain Transactions with
CMS Energy.............................. 73
Description of Capital Stock.............. 77
Shares Eligible for Future Sale........... 80
Underwriting.............................. 81
Legal Matters............................. 82
Experts................................... 83
Available Information..................... 84
Certain Definitions....................... 85
Index to Financial Statements............. F-1
Letter of Ryder Scott Company............. A-1
</TABLE>
------------------------
UNTIL , 1996 (25 DAYS AFTER THE DATE OF THIS PROSPECTUS),
ALL DEALERS EFFECTING TRANSACTIONS IN THE COMMON STOCK, WHETHER OR NOT
PARTICIPATING IN THIS DISTRIBUTION, MAY BE REQUIRED TO DELIVER A PROSPECTUS.
THIS IS IN ADDITION TO THE OBLIGATION OF DEALERS TO DELIVER A PROSPECTUS WHEN
ACTING AS UNDERWRITERS AND WITH RESPECT TO THEIR UNSOLD ALLOTMENTS OR
SUBSCRIPTIONS.
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
------------------------------------------------------
4,000,000 SHARES
CMS NOMECO OIL & GAS CO.
COMMON STOCK
LOGO
------------------------
PROSPECTUS
------------------------
DONALDSON, LUFKIN & JENRETTE
SECURITIES CORPORATION
BEAR, STEARNS & CO. INC.
SALOMON BROTHERS INC
REPRESENTATIVES OF THE UNDERWRITERS
------------------------------------------------------
------------------------------------------------------
<PAGE> 186
PART II. INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 13. OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.
The following is a statement of the various expenses to be paid by the
Registrant in connection with the Offering. All amounts shown are estimates
except for the SEC registration fee.
<TABLE>
<S> <C>
Securities and Exchange Commission Registration Fee............... $ 34,483
New York Stock Exchange Listing Fee............................... 46,400
NASD Fee.......................................................... 10,500
Printing and Engraving Expenses................................... 250,000
Petroleum Engineering Fees and Expenses........................... 432,000
Legal Fees and Expenses........................................... 375,000
Accounting Fees and Expenses...................................... 360,000
Blue Sky Fees and Expenses........................................ 5,000
Transfer Agent and Registrar Fees and Expenses.................... 5,000
Miscellaneous..................................................... 181,617
----------
Total: $1,700,000
==========
</TABLE>
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, 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
II-1
<PAGE> 187
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.
Neither Registrant nor its subsidiaries has made any sales of unregistered
securities since December 31, 1992 except for the stock split effected as
described in the Prospectus.
ITEM 16. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES.
<TABLE>
<CAPTION>
EXHIBIT NO.
<S> <C> <C>
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 counsel.*
10.1 -- Consulting and Non-Compete Agreement, dated as of February 1, 1995, by and
between the Registrant and Richard J. Burgess.*
10.2 -- Employee Well Participation Program, Plan A and Plan B.*
10.3 -- Reimbursement Agreement, dated as of December 9, 1994, between CMS Energy
Corporation and Registrant.*
10.4 -- Key Employee Incentive Compensation Plan.*
10.5 -- Supplemental Executive Retirement Plan for Employees of Consumers Power Company
("Consumers"), filed as Exhibit 10(o) to Consumers' Form 10-K Report for the
year 1993, File No. 1-5611, and incorporated herein by reference.
10.6 -- Gas Purchase Agreement, dated as of January 1, 1995, between the Registrant and
Consumers.*
10.7 -- Natural Gas Purchase Agreement, dated as of May 1, 1989, between the Registrant
and Midland Cogeneration Venture Limited Partnership.*
10.8 -- Gas Purchase Contract, dated as of December 1, 1987, between the Registrant and
Consumers.*
10.9(a) -- Gas Purchase Contract, dated as of December 1, 1985, between the Registrant and
Consumers.*
10.9(b) -- Modification and Amendment to Gas Purchase Contract, dated as of December 1,
1986, by and between Registrant and Consumers.*
10.9(c) -- Modification and Amendment to Gas Purchase Contract, dated as of December 1,
1987, by and between Registrant and Consumers.*
10.9(d) -- Modification and Amendment to Gas Purchase Contract, dated as of March 1, 1988,
by and between Registrant and Consumers.*
10.10 -- Gas Purchase Contract, dated as of November 2, 1978, between the Registrant and
Consumers.*
10.11 -- Services Agreement, dated as of October 1, 1989, between the Registrant and
Consumers.*
10.12 -- Services Agreement, dated as of October 25, 1995, between the Registrant and
CMS Energy.*
</TABLE>
II-2
<PAGE> 188
<TABLE>
<CAPTION>
EXHIBIT NO.
<S> <C> <C>
10.13 -- Services Agreement, dated as of October 25, 1995, between the Registrant and
CMS Enterprises.*
10.14 -- Registration Rights Agreement, dated as of October 25, 1995, between the
Registrant and CMS Enterprises.*
10.15 -- 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.*
10.16 -- Indemnification Agreement, dated as of October 20, 1995, between the Registrant
and CMS Energy.*
10.17 -- Agreement and Plan of Merger, dated as of August 29, 1995, among CMS Energy,
CMS Merging Corporation, Terra Energy Ltd., Martin G. Lagina, Craig J. Tester,
Dr. Thomas James and Nancy M. James, Dr. James Lowell and Mary K. Lowell, The
Revocable Living Trust of Dr. Leonard J. Scherock under Agreement dated May 1,
1990, Robert M. Boeve and Wayne Sterenberg.*
10.18 -- Covenant Not to Compete, dated as of August 31, 1995, among CMS Energy
Corporation, Martin G. Lagina, Craig J. Tester, Robert M. Boeve and Wayne
Sterenberg.*
10.19 -- Transfer Agreement, dated as of August 31, 1995, among the Registrant, CMS
Energy and CMS Enterprises.*
10.20 -- Promissory Note, dated as of August 31, 1995, issued by the Registrant to CMS
Enterprises.*
10.21 -- Agreement and Plan of Merger, dated as of January 24, 1995, among CMS Energy,
CMS Merging Corporation, Walter International, Inc., J.C. Walter, Jr., J.C.
Walter III, Carole Walter Looke, F. Fox Benton, Jr., Gordon A. Cain, The Cain
1988 Descendants Trust, William C. Oehmig, Prudential-Bache Energy Growth Fund,
L.P. G-2, Prudential-Bache Energy Growth Fund, L.P. G-3, Prudential-Bache
Energy Growth Fund, L.P. G-4, F. Fox Benton III, Howard A. Chapman, G.W. Frank,
Robert D. Jolly and Arthur L. Smalley.*
10.22 -- Promissory Note, dated as of July 17, 1995, issued by the Registrant to CMS
Energy.*
10.23 -- 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.*
10.24 -- CMS Tax Agreement, dated as of February 24, 1995, between Amoco Corporation,
Amoco Production Company, CMS Energy Corporation, CMS Enterprises, Inc.,
CMS-Nomeco Oil & Gas Co., Walter International, Inc. Walter Holdings, Inc. and
Walter International Congo, Inc.*
10.25 -- Inter-Purchaser Agreement, dated as of December 28, 1994, by and among Walter
International, Inc., Walter Congo Holdings, Inc., Walter International Congo,
Inc., Nuevo Energy Company, The Congo Holding Company and the Nuevo Congo
Company.*
10.26 -- Stock Purchase Agreement, dated as of June 30, 1994, by and between Amoco
Production Company, Walter International, Inc., Nuevo Energy Company, Walter
International Congo, Inc., Walter Congo Holdings, Inc., The Nuevo Congo Company
and the Congo Holdings Company.*
10.27 -- Swap Agreement, dated as of May 8, 1992, by and between Registrant and Louis
Dreyfus Exchanges Ltd.*
10.28 -- Finance Agreement, dated as of December 28, 1994, among Walter International
Congo, Inc., Walter Congo Holdings, Inc., and Overseas Private Investment
Corporation.*
10.29(a) -- Amended and Restated Credit Agreement, dated as of November 1, 1993, as
amended, among the Registrant, the Banks, all as defined therein, and NBD Bank,
N.A., as Agent, and the Exhibits thereto.*
</TABLE>
II-3
<PAGE> 189
<TABLE>
<CAPTION>
EXHIBIT NO.
<S> <C> <C>
10.29(b) -- Second Amendment to Credit Agreement and Assumption Agreement, dated as of
March 1, 1995, among the Registrant, the Banks, all as defined therein, and NBD
Bank as Agent.*
10.29(c) -- Third Amendment to Credit Agreement, dated as of August 31, 1995, among the
Registrant, the Banks, all as defined therein, and NBD Bank, as Agent.*
10.29(d) -- Fourth Amendment to Credit Agreement, dated as of November 20, 1995, among the
Registrant, the Banks, all as defined therein, and NBD Bank, as Agent.*
10.30 -- Form of Long-Term Incentive Performance Plan.
10.31 -- Form of Executive Incentive Compensation Plan.
10.32 -- Form of Royalty Rights Purchase Agreement.
15.1 -- Letters of Arthur Andersen LLP regarding unaudited financial statements.
15.2 -- Letters of KPMG Peat Marwick LLP regarding unaudited financial statements.
21.1 -- Subsidiaries of the Registrant.
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Deloitte & Touche LLP.
23.3 -- Consent of KPMG Peat Marwick LLP.
23.4 -- Consent of counsel (included in Exhibit 5.1).*
23.5 -- Consent of Ryder Scott Company.
24.1 -- Powers of Attorney.*
27.1 -- Financial Data Schedule.*
</TABLE>
- -------------------------
* Previously filed with Securities and Exchange Commission.
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) 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 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.
(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) 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.
II-4
<PAGE> 190
(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.
II-5
<PAGE> 191
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant
has duly caused this Amendment No. 2 to the Registration Statement to be signed
on its behalf by the undersigned, thereunto duly authorized, in the City of
Jackson, State of Michigan, on the 7th day of February, 1996.
CMS NOMECO Oil & Gas Co.
By: /s/ WILLIAM H. STEPHENS, III
--------------------------------------
William H. Stephens, III
Executive Vice President
and General Counsel
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 2 to the Registration Statement has been signed by the following persons in
the capacities indicated on the 7th day of February, 1996.
<TABLE>
<CAPTION>
NAME TITLE
<C> <S>
/s/ GORDON L. WRIGHT President, Chief Executive Officer and
- ------------------------------------------ Director (Principal Executive Officer)
(Gordon L. Wright)
/s/ PAUL E. GEIGER Vice President, Secretary and Treasurer
- ------------------------------------------ (Principal Financial and Accounting Officer)
(Paul E. Geiger)
* Director
- ------------------------------------------
(Victor J. Fryling)
* Director
- ------------------------------------------
(Richard J. Burgess)
* Director
- ------------------------------------------
(Frank M. Burke, Jr.)
* Director
- ------------------------------------------
(J. Stuart Hunt)
* Director
- ------------------------------------------
(Thomas K. Matthews, II)
* Director
- ------------------------------------------
(William T. McCormick, Jr.)
</TABLE>
II-6
<PAGE> 192
<TABLE>
<CAPTION>
NAME TITLE
<C> <S>
* Director
- ------------------------------------------
(S. Kinnie Smith, Jr.)
* Director
- ------------------------------------------
(P.W.J. Wood)
* Director
- ------------------------------------------
(Alan M. Wright)
*By: /s/ WILLIAM H. STEPHENS, III
- ------------------------------------------
William H. Stephens, III
Attorney-in-fact
</TABLE>
II-7
<PAGE> 193
EXHIBIT INDEX
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
- --------- ------------------------------------------------------------------------------
<S> <C> <C>
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 counsel.*
10.1 -- Consulting and Non-Compete Agreement, dated as of February 1, 1995, by and
between the Registrant and Richard J. Burgess.*
10.2 -- Employee Well Participation Program, Plan A and Plan B.*
10.3 -- Reimbursement Agreement, dated as of December 9, 1994, between CMS Energy
Corporation and Registrant.*
10.4 -- Key Employee Incentive Compensation Plan.*
10.5 -- Supplemental Executive Retirement Plan for Employees of Consumers Power
Company ("Consumers"), filed as Exhibit 10(o) to Consumers' Form 10-K Report
for the year 1993, File No. 1-5611, and incorporated herein by reference.
10.6 -- Gas Purchase Agreement, dated as of January 1, 1995, between the Registrant
and Consumers.*
10.7 -- Natural Gas Purchase Agreement, dated as of May 1, 1989, between the
Registrant and Midland Cogeneration Venture Limited Partnership.*
10.8 -- Gas Purchase Contract, dated as of December 1, 1987, between the Registrant
and Consumers.*
10.9(a) -- Gas Purchase Contract, dated as of December 1, 1985, between the Registrant
and Consumers.*
10.9(b) -- Modification and Amendment to Gas Purchase Contract, dated as of December 1,
1986, by and between Registrant and Consumers.*
10.9(c) -- Modification and Amendment to Gas Purchase Contract, dated as of December 1,
1987, by and between Registrant and Consumers.*
10.9(d) -- Modification and Amendment to Gas Purchase Contract, dated as of March 1,
1988, by and between Registrant and Consumers.*
10.10 -- Gas Purchase Contract, dated as of November 2, 1978, between the Registrant
and Consumers.*
10.11 -- Services Agreement, dated as of October 1, 1989, between the Registrant and
Consumers.*
10.12 -- Services Agreement, dated as of October 25, 1995, between the Registrant and
CMS Energy.*
10.13 -- Services Agreement, dated as of October 25, 1995, between the Registrant and
CMS Enterprises.*
10.14 -- Registration Rights Agreement, dated as of October 25, 1995, between the
Registrant and CMS Enterprises.*
10.15 -- 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.*
10.16 -- Indemnification Agreement, dated as of October 20, 1995, between the
Registrant and CMS Energy.*
</TABLE>
<PAGE> 194
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
- --------- ------------------------------------------------------------------------------
<S> <C> <C>
10.17 -- Agreement and Plan of Merger, dated as of August 29, 1995, among CMS Energy,
CMS Merging Corporation, Terra Energy Ltd., Martin G. Lagina, Craig J. Tester,
Dr. Thomas James and Nancy M. James, Dr. James Lowell and Mary K. Lowell, The
Revocable Living Trust of Dr. Leonard J. Scherock under Agreement dated May 1,
1990, Robert M. Boeve and Wayne Sterenberg.*
10.18 -- Covenant Not to Compete, dated as of August 31, 1995, among CMS Energy
Corporation, Martin G. Lagina, Craig J. Tester, Robert M. Boeve and Wayne
Sterenberg.*
10.19 -- Transfer Agreement, dated as of August 31, 1995, among the Registrant, CMS
Energy and CMS Enterprises.*
10.20 -- Promissory Note, dated as of August 31, 1995, issued by the Registrant to CMS
Enterprises.*
10.21 -- Agreement and Plan of Merger, dated as of January 24, 1995, among CMS Energy,
CMS Merging Corporation, Walter International, Inc., J.C. Walter, Jr., J.C.
Walter III, Carole Walter Looke, F. Fox Benton, Jr., Gordon A. Cain, The Cain
1988 Descendants Trust, William C. Oehmig, Prudential-Bache Energy Growth
Fund, L.P. G-2, Prudential-Bache Energy Growth Fund, L.P. G-3,
Prudential-Bache Energy Growth Fund, L.P. G-4, F. Fox Benton III, Howard A.
Chapman, G.W. Frank, Robert D. Jolly and Arthur L. Smalley.*
10.22 -- Promissory Note, dated as of July 17, 1995, issued by the Registrant to CMS
Energy.*
10.23 -- 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.*
10.24 -- CMS Tax Agreement, dated as of February 24, 1995, between Amoco Corporation,
Amoco Production Company, CMS Energy Corporation, CMS Enterprises, Inc.,
CMS-Nomeco Oil & Gas Co., Walter International, Inc. Walter Holdings, Inc. and
Walter International Congo, Inc.*
10.25 -- Inter-Purchaser Agreement, dated as of December 28, 1994, by and among Walter
International, Inc., Walter Congo Holdings, Inc., Walter International Congo,
Inc., Nuevo Energy Company, The Congo Holding Company and the Nuevo Congo
Company.*
10.26 -- Stock Purchase Agreement, dated as of June 30, 1994, by and between Amoco
Production Company, Walter International, Inc., Nuevo Energy Company, Walter
International Congo, Inc., Walter Congo Holdings, Inc., The Nuevo Congo
Company and the Congo Holdings Company.*
10.27 -- Swap Agreement, dated as of May 8, 1992, by and between Registrant and Louis
Dreyfus Exchanges Ltd.*
10.28 -- Finance Agreement, dated as of December 28, 1994, among Walter International
Congo, Inc., Walter Congo Holdings, Inc., and Overseas Private Investment
Corporation.*
10.29(a) -- Amended and Restated Credit Agreement, dated as of November 1, 1993, as
amended, among the Registrant, the Banks, all as defined therein, and NBD
Bank, N.A., as Agent, and the Exhibits thereto.*
10.29(b) -- Second Amendment to Credit Agreement and Assumption Agreement, dated as of
March 1, 1995, among the Registrant, the Banks, all as defined therein, and
NBD Bank as Agent.*
10.29(c) -- Third Amendment to Credit Agreement, dated as of August 31, 1995, among the
Registrant, the Banks, all as defined therein, and NBD Bank, as Agent.*
</TABLE>
<PAGE> 195
<TABLE>
<CAPTION>
EXHIBIT
NO. DESCRIPTION
- --------- ------------------------------------------------------------------------------
<S> <C> <C>
10.29(d) -- Fourth Amendment to Credit Agreement, dated as of November 20, 1995, among the
Registrant, the Banks, all as defined therein, and NBD Bank, as Agent.*
10.30 -- Form of Long-Term Incentive Performance Plan.
10.31 -- Form of Executive Incentive Compensation Plan.
10.32 -- Form of Royalty Rights Purchase Agreement.
15.1 -- Letters of Arthur Andersen LLP regarding unaudited financial statements.
15.2 -- Letters of KPMG Peat Marwick LLP regarding unaudited financial statements.
21.1 -- Subsidiaries of the Registrant.
23.1 -- Consent of Arthur Andersen LLP.
23.2 -- Consent of Deloitte & Touche LLP.
23.3 -- Consent of KPMG Peat Marwick LLP.
23.4 -- Consent of counsel (included in Exhibit 5.1).*
23.5 -- Consent of Ryder Scott Company.
24.1 -- Powers of Attorney.*
27.1 -- Financial Data Schedule.*
</TABLE>
- -------------------------
* Previously filed with Securities and Exchange Commission.
<PAGE> 1
EXHIBIT 10.30
CMS NOMECO OIL & GAS CO. LONG TERM PERFORMANCE INCENTIVE PLAN
ARTICLE I, PURPOSE
The CMS Nomeco Oil & Gas Co. Long Term Performance Incentive Plan (hereinafter
called the "Plan") is a Plan to provide incentive compensation to key employees
of the Corporation, based upon such key employees' individual contributions to
the long-term growth of and profitability of the Corporation, and in order to
encourage such key employees to identify with shareholder concerns and their
current and continuing interest in the development and financial success of the
Corporation. Because it is expected that the efforts of the key employees
selected for participation in the Plan will have a significant impact on the
results of the Corporation's operations in future years, the Plan is intended
to assist the Corporation in attracting and retaining as key employees
individuals of superior ability and in motivating their activities on behalf of
the Corporation.
ARTICLE II, DEFINITIONS
2.1 Definitions: When used in the Plan, the following words and phrases
shall have the following meanings:
a. "Beneficiary" means the beneficiary or beneficiaries designated in
accordance with Article VII to receive the amount, if any, payable
under the Plan upon the death of a Participant.
b. "Board" means the Board of Directors of the Corporation.
c. "Committee" means those members of the Executive and Remuneration
Committee of the Board who, at the time of any award or determination
by the Committee hereunder, are not, and at all times within one year
prior thereto shall not have been, eligible for selection as persons to
whom incentive compensation may be awarded pursuant to the Plan, or to
whom incentive or nonqualified Stock Options may be granted pursuant to
any other plan of the Corporation.
d. "Common Stock" means Common Stock of the Corporation as that term is
defined in its Articles of Incorporation at the time of an award or
grant under this Plan.
e. "Common Stock Outstanding" means the number of shares of Common Stock
issued and outstanding on the date of grant or award. In case of a
reorganization, recapitalization, stock split, stock dividend,
combination of shares, merger, consolidation, rights offering, or any
other change in the capital structure of the Corporation, the Committee
shall make such adjustment, if any, as it may deem appropriate in the
determination of Common Stock Outstanding.
f. "Corporation" means CMS NOMECO Oil & Gas Co., its successors and
assigns, and each of its Subsidiaries, or any of them individually.
<PAGE> 2
2
g. "Eligible Employee" means an officer or other key employee who at the
end of the fiscal year is a regular full-time salaried employee of the
Corporation or, to the extent the Committee may determine, a person
whose services to the Corporation terminated before the end of the
fiscal year, who, in the opinion of the Committee, made a significant
contribution to the successful management of the Corporation. A
director of the Corporation is not an Eligible Employee unless he is
also a regular full-time salaried employee of the Corporation
h. "Incentive Option" means an option to purchase Common Stock which meets
the requirements set forth in the Plan and also meets the definition of
an Incentive Stock Option set forth in Section 422 of the Internal
Revenue Code of 1986, as amended (the "Code").
i. "Nonqualified Option" means an option to purchase Common Stock which
meets the requirements set forth in the Plan but does not meet the
definition of an Incentive Stock Option set forth in Section 422 of the
Code.
j. "Optionee" means any person to whom an option or right has been granted
or who becomes a holder of an option or right under Article VI of the
Plan.
k. "Participant" means a person to whom an award of Restricted Common
Stock has been made which has not been paid, forfeited, or otherwise
terminated or satisfied under the Plan.
l. "Profit Sharing Grant" means the amount granted by the Committee to
those Eligible Employees who are selected for participation in the
Profit Sharing provisions of the Plan as outlined in Article VIII.
m. "Restricted Common Stock" means Common Stock delivered subject to the
restrictions described in Article VII.
n. "Shareholders" means the shareholders of the Corporation.
o. "Stock Appreciation Right" shall mean a right, that may or may not be
granted in conjunction with a Stock Option, to receive the appreciation
in value of the current share price over the option price, and any
underlying Stock Options must then be surrendered.
p. "Stock Option" means an option to purchase shares of Common Stock,
granted pursuant to this Plan.
q. "Subsidiary" means a corporation, domestic or foreign, 80 percent or
more of the voting stock of which is owned directly or indirectly by
the Corporation.
ARTICLE III, EFFECTIVE DATE, DURATION, SCOPE AND ADMINISTRATION OF THE PLAN
3.1 This Plan shall be effective November 1, 1995 and shall continue until
terminated by the Board as provided in Article IX.
<PAGE> 3
3
3.2 The Committee shall have full power and authority to construe,
interpret and administer the Plan. All decisions, actions or
interpretations of the Committee shall be final, conclusive and binding
upon all parties. If any person objects to any such interpretation or
action formally or informally, the expenses of the Committee and its
agents and counsel shall be chargeable against any amounts otherwise
payable under the Plan to or on account of the Participant or Optionee.
3.3 No member of the Committee shall be personally liable by reason of any
contract or other instrument executed by him or on his behalf in his
capacity as a member of the Committee nor for any mistake of judgment
made in good faith, and the Corporation shall indemnify and hold
harmless each member of the Committee and each other officer, employee
or director of the Corporation to whom any duty or power relating to
the administration or interpretation of the Plan may be allocated or
delegated, against any cost or expense (including counsel fees) or
liability (including any sum paid in settlement of a claim with the
approval of the Board) arising out of any act or omission to act in
connection with the Plan unless arising out of such person's own fraud
or bad faith.
ARTICLE IV, PARTICIPATION, STOCK AWARDS AND OPTION GRANTS
4.1 Each year the Committee shall designate as Participants and/or
Optionees in the Plan those Eligible Employees who, in the opinion of
the Committee, have significantly contributed to the successful
management of the Corporation.
4.2 Each year, the Committee may award shares of Common Stock, and/or may
grant Stock Options which qualify as "Incentive Stock Options" within
the meaning of Section 422 of the Code or Stock Options which do not
qualify as Incentive Stock Options and/or Stock Appreciation Rights
and/or Profit Sharing Grants to each Eligible Employee whom it has
designated as an Optionee or Participant for such year. The
determination of the Committee as to each such award and grant shall be
final.
ARTICLE V, SHARES RESERVED UNDER THE PLAN
5.1 There is hereby reserved for award under this Plan an aggregate number
of whole shares of Common Stock equal as nearly as possible to, but not
more than, 1% of the aggregate shares of Common Stock Outstanding on
the date of grant or award, less any shares previously awarded or
granted under the Plan. Any shares or options which are forfeited may
thereafter again be awarded or made subject to grant under the Plan.
The number of shares made available for option and sale under Article
VI of this Plan, plus the number of shares awarded under Article VII of
this Plan will not exceed, at any time, the number of shares of Common
Stock reserved pursuant to this Article V.
5.2 If a dividend shall be declared upon the Common Stock payable in shares
of Common Stock, the number of shares of Common Stock then subject to
any option and the number of shares reserved for issuance pursuant to
the Plan but not yet covered by an option shall be adjusted by adding
to each such option or share the number of shares which would be
distributable thereon if such share had been outstanding on the date
fixed for determining the
<PAGE> 4
4
shareholders entitled to receive such stock dividend. In the event
that the outstanding shares of the Common Stock shall be changed into
or exchanged for a different number or kind of shares of stock or other
securities of the Corporation or of another corporation, whether
through reorganization, recapitalization, stock split-up, combination
of shares, merger or consolidation or otherwise, then there shall be
substituted for each share of Common Stock subject to any such option
and for each share of Common Stock reserved for issuance pursuant to
the Plan but not yet covered by an option, the number and kind of
shares of stock or other securities into which each outstanding share
of Common Stock shall be so changed or for which each such share shall
be exchanged. In the event there shall be any change, other than as
specified above in this Section 5.2, in the number or kind of
outstanding shares of Common Stock of the Corporation or of any stock
or other securities into which such Common Stock shall have been
changed or for which it shall have been exchanged, then if the
Committee shall in its sole discretion determine that such change
equitably requires an adjustment in the number or kind of shares
theretofore reserved for issuance pursuant to the Plan but not yet
covered by an option and of the shares then subject to an option or
options, such adjustment shall be made by the Committee and shall be
effective and binding for all purposes of the Plan and each Stock
Option agreement. In the case of any such substitution or adjustment
as provided for in this paragraph, the option price in each Stock
Option agreement for each share covered thereby prior to such
substitution or adjustment will be the option price for all shares of
stock or other securities which shall have been substituted for such
share or to which such share shall have been adjusted pursuant to this
section. No adjustment or substitution provided for in this Section
5.2 shall require the Corporation in any Stock Option agreement to sell
a fractional share, and the total substitution or adjustment with
respect to each Stock Option agreement shall be limited accordingly.
5.3 Individual Grant Limit: The maximum shares of Restricted Common Stock
awarded under this Plan and Common Stock subject to Stock Options,
including Stock Appreciation Rights granted in conjunction with Stock
Options, granted under this Plan for any one Eligible Employee for any
one year will not exceed 50,000 shares of Common Stock.
ARTICLE VI, STOCK OPTIONS AND STOCK APPRECIATION RIGHTS
6.1 The Committee may from time to time provide for the option and sale of
shares of Common Stock, which may consist in whole or in part of the
authorized and unissued or reacquired Common Stock.
6.2 Optionees: The Committee shall determine and designate from time to
time, in its discretion, those Eligible Employees to whom Stock Options
and Stock Appreciation Rights are to be granted and who thereby become
Optionees under the Plan.
6.3 Allotment of Shares: The Committee shall determine and fix the number
of shares of Common Stock subject to options to be offered to each
Optionee.
6.4 Option Price: The Committee shall establish the option price at the
time any option is granted at not less than 100% of the fair market
value of
<PAGE> 5
5
the Common Stock on the date on which such option is granted; provided,
however, that with respect to an Incentive Option granted to an
employee who at the time of the grant owns (after applying the
attribution rules of Section 425(d) of the Code) more than 10% of the
total combined voting stock of the Corporation or of any parent or
Subsidiary, the option price shall not be less than 110% of the fair
market value of the Common Stock subject to the Incentive Option on the
date such option is granted.
6.5 Stock Appreciation Rights: At the discretion of the Committee, any
Stock Option granted under this Plan may, at the time of such grant,
include a Stock Appreciation Right. A Stock Appreciation Right shall
pertain to, and be granted only in conjunction with, a related
underlying Stock Option, and shall be exercisable only at the time and
to the extent the related underlying Stock Option is exercisable and
only if the fair market value of the Common Stock exceeds the Stock
Option price in the related underlying Stock Option. An Optionee who
is granted a Stock Appreciation Right may elect to surrender the
related underlying Stock Option with respect to all or part of the
number of shares subject to the related underlying Stock Option and
exercise in lieu thereof the Stock Appreciation Right with respect to
the number of shares as to which the Stock Option is surrendered.
The exercise of the underlying Stock Option shall terminate the related
Stock Appreciation Right to the extent of the number of shares
purchased upon exercise of the underlying Stock Option. The exercise
of a Stock Appreciation Right shall terminate the related
underlying Stock Option to the extent of the number of shares with
respect to which the Stock Appreciation Right is exercised. Upon
exercise of a Stock Appreciation Right, an Optionee shall be entitled
to receive, without payment to the Corporation (except for applicable
withholding taxes), an amount equal to the excess of (i) the then
aggregate fair market value of the number of shares with respect to
which the Optionee exercises the Stock Appreciation Right, over (ii)
the aggregate Stock Option price per share for such number of shares.
Such amount may be paid by the Corporation, at the election of the
Optionee, in cash, Common Stock or any combination thereof; provided,
however, that the Committee shall have sole discretion to approve or
disapprove an election of an Optionee to receive cash upon exercise of
a Stock Appreciation Right.
The Committee may also in its discretion grant to any Eligible Employee
a Stock Appreciation Right that is not granted in conjunction with an
underlying Stock Option. Any such Stock Appreciation Right that is not
granted in conjunction with a Stock Option will not result in a
decrease in the number of shares available under the Plan. Such
Stock Appreciation Right shall operate and be available to the Optionee
to the same extent and under the same circumstances as if the Stock
Appreciation Right had been granted in conjunction with an underlying
Stock Option as described elsewhere in this Plan. Notwithstanding
anything to the contrary in the Plan, upon exercise of a Stock
Appreciation Right for which there is no underlying Stock Option,
payment to the Optionee shall be made only in cash.
6.6 Granting and Exercise of Stock Options and Stock Appreciation Rights:
The granting of Stock Options and Stock Appreciation Rights hereunder
shall be
<PAGE> 6
6
effected in accordance with determinations made by the Committee
pursuant to the provisions of the Plan, by execution of instruments
in writing in form approved by the Committee.
Each Stock Option and Stock Appreciation Right granted hereunder shall
be exercisable at any such time or times or in any such installments as
may be determined by the Committee at the time of the grant, subject to
the limitation that for each Incentive Stock Option and related Stock
Appreciation Right granted, a maximum of $100,000 (based on the price
at the date of exercise) may be exercised per year, plus any unused
carry-over from a previous year(s). Except as provided in Section
6.10, Stock Options and Stock Appreciation Rights may be exercised only
while the Optionee is an employee of the Corporation.
Successive Stock Options and Stock Appreciation Rights may be granted
to the same Optionee, whether or not the Stock Option(s) and Stock
Appreciation Right(s) previously granted to such Optionee remain
unexercised. An Optionee may exercise a Nonqualified Option or related
Stock Appreciation Right, if then exercisable, notwithstanding that
Stock Options and Stock Appreciation Rights previously granted to such
Optionee remain unexercised.
6.7 Payment of Stock Option Price: At the time of the exercise in whole or
in part of any Stock Option granted hereunder, payment of the option
price in full in cash or, with the consent of the Committee, in Common
Stock shall be made by the Optionee for all shares so purchased. No
Optionee shall have any of the rights of a Shareholder under any such
Stock Option until the actual issuance of shares to said Optionee, and
prior to such issuance no adjustment shall be made for dividends,
distributions or other rights in respect of such shares, except as
provided in Section 5.2.
6.8 Nontransferability of Stock Options and Stock Appreciation Rights: No
Stock Option or Stock Appreciation Right granted under the Plan to an
Optionee shall be transferable by such Optionee otherwise than by will,
or by the laws of descent and distribution, and such Stock Option and
Stock Appreciation Right shall be exercisable, during the lifetime of
the Optionee, only by the Optionee.
6.9 Term of Stock Options and Stock Appreciation Rights: If not sooner
terminated, each Stock Option and Stock Appreciation Right granted
hereunder shall expire not more than ten years (ten years and one month
in the case of a Nonqualified Option and any related Stock Appreciation
Right) from the date of the granting thereof; provided, that with
respect to an Incentive Option and a related Stock Appreciation Right
granted to an Optionee who, at the time of the grant, owns (after
applying the attribution rules of Section 425(d) of the Code) more than
10% of the total combined voting stock of all classes of stock of the
Corporation or of any parent or Subsidiary, such Stock Option and Stock
Appreciation Right shall expire not more than five years after the date
of granting thereof.
6.10 Termination of Employment: If the employment of an Optionee by the
Corporation shall be terminated due to a reason other than the
Optionee's death, the Committee may, in its discretion, permit the
exercise of Stock
<PAGE> 7
7
Options and Stock Appreciation Rights granted to such Optionee for a
period not to exceed one year following such termination of employment
or three years following termination of employment upon retirement in
accordance with a pension plan of the Corporation; provided, however,
that no Incentive Option or related Stock Appreciation Right may be
exercised after three months following an Optionee's termination of
employment, unless such termination of employment is due to the
Optionee's death or disability. If the termination is due to the
Optionee's disability, the Committee may permit the Incentive Option
and related Stock Appreciation Right to be exercised for one year
following the Optionee's termination of employment. If the employment
of an Optionee by the Corporation shall be terminated due to the
Optionee's death, any Stock Option, or related Stock Appreciation
Right, transferred by will or the laws of descent and distribution, may
be exercised for one year following the Optionee's death. In no event,
however, shall a Stock Option or Stock Appreciation Right be
exercisable subsequent to its expiration date and, furthermore, a Stock
Option or Stock Appreciation Right may only be exercised after
termination of an Optionee's employment to the extent exercisable on
the date of termination of employment. Upon the termination of
employment of an Optionee by the Corporation, every Stock Option and
related Stock Appreciation Right shall terminate, except as otherwise
specifically provided in this Plan. Further, no Stock Option or
related Stock Appreciation Right may be exercised after such
termination of employment, except within a time period provided in this
Section 6.10.
6.11 Investment Purpose: Any shares of Common Stock subject to option under
the Plan may be made subject to such other restrictions as the
Committee deems advisable, including without limitation provisions to
comply with federal and state securities laws. In making
determinations of legal requirements the Committee shall rely on an
opinion of counsel for the Corporation.
6.12 Withholding Payments: If upon the exercise of a Nonqualified Option
and/or a Stock Appreciation Right or as a result of a disqualifying
disposition (within the meaning of Section 422 of the Code) of shares
acquired upon exercise of an Incentive Option, there shall be payable
by the Corporation any amount for income tax withholding, either the
Corporation shall appropriately reduce the amount of Common Stock or
cash to be paid to the Optionee or the Optionee shall pay such amount
to the Corporation to reimburse it for such income tax withholding.
6.13 Restrictions on Sale of Shares: If, at the time of exercise of any
Stock Option or Stock Appreciation Right granted hereunder, the
Corporation is precluded by any legal, regulatory or contractual
restriction from selling and/or delivering shares pursuant to the terms
of such Stock Option or Stock Appreciation Right, the sale and delivery
of the shares may be delayed until the restrictions are resolved and
only cash may be paid upon exercise of the Stock Appreciation Right.
Further, at no time will any shares be sold or delivered to a
participant if such sale or delivery will result in a deconsolidation
of the stock. At any time during such delay, the Committee, in its
discretion, may permit the Optionee to revoke a Stock Option exercise,
in which event any corresponding Stock Appreciation Right shall be
reinstated.
<PAGE> 8
8
6.14 Compliance With Rule 16b-3: Notwithstanding any other provision of the
Plan to the contrary, the administration of the Plan and the grant,
exercise and terms of Stock Appreciation Rights hereunder shall comply
with Rule 16b-3, or any successor rule, under the Securities Exchange
Act of 1934, as amended (the "Exchange Act").
ARTICLE VII, RESTRICTED COMMON STOCK
7.1 Awards: The Committee may from time to time award restricted shares of
Common Stock to any Eligible Employee it has designated as a
Participant for such year. Awards shall be made to Eligible Employees
on the basis of their contributions to the successful management of the
Corporation in accordance with such rules as the Committee may
prescribe. The Committee may also award restricted shares of Common
Stock conditioned on the attainment of a performance goal that relates
to Shareholder return, measured by factors determined by the Committee
as set forth in the award.
7.2 Restrictions:
a. Any shares of Common Stock awarded or issued under the Plan may
be made subject to such other restrictions as the Committee deems
advisable, including without limitation provisions to comply with
federal and state securities laws. In making determinations of
legal requirements the Committee shall rely on an opinion of
counsel for the Corporation. The restrictions with respect to the
Common Stock awarded will extend for such period, or periods, of
at least twelve months from and after the date of the award, as
may be determined for each award by the Committee (the award
period). Notwithstanding the foregoing, the restrictions shall
terminate upon the death of the Participant or, within the
discretion of the Committee, upon Participant's retirement
pursuant to a pension plan of the Corporation on or after
Participant's 62nd birthday, except as may otherwise be determined
to be necessary or desirable in the opinion of the Committee, to
comply with the law or to prevent Restricted Common Stock from
being subject to federal income tax prior to the termination of
restrictions.
b. Whenever shares of Common Stock are awarded to a Participant, such
shares shall be outstanding, and stock certificates shall be
issued in the name of the Participant, which certificates may
bear a legend stating that the shares are issued subject to the
restrictions set forth in the Plan. All certificates issued for
shares of Common Stock awarded under the Plan shall be deposited
for the benefit of the Participant with the Secretary of the
Corporation as custodian until such time as the shares are vested
and transferable.
c. A Participant who is awarded shares of Common Stock under the
Plan shall have full voting rights on such shares, whether
or not the shares are vested or transferable.
d. Shares of Common Stock awarded to a Participant under the Plan,
whether or not vested or transferable, shall have full dividend
rights with respect to dividends declared after the award, with
such
<PAGE> 9
9
dividends being paid directly to the Participant, regardless of
whether such dividends are paid in cash or in Common Stock.
However, if shares or securities are issued as a result of a
merger, consolidation or similar event, such shares shall be
issued in the same manner, and subject to the same deposit
requirements, vesting provisions and transferability restrictions
as the shares of Common Stock which have been awarded.
e. Deliveries of Restricted Common Stock by the Corporation may
consist in whole or in part of the authorized and unissued or
reacquired Common Stock of the Corporation (at such time or times
and in such manner as it may determine). The Restricted Common
Stock shall be paid and delivered as soon as practicable after the
award period in accordance with Section 7.3.
f. The shares may not be sold, exchanged, transferred, pledged,
hypothecated, or otherwise disposed of by the Participant until
their release. However, nothing herein shall preclude a
Participant from making a gift of any shares of Restricted
Common Stock to a spouse, child, step-child, grandchild, parent or
sibling, or legal dependent of the Participant or to a trust of
which the beneficiary or beneficiaries of the corpus and the
income shall be either such a person or the Participant; provided
that, the Restricted Common Stock so given shall remain subject to
the restrictions, obligations and conditions described in this
Article VII.
g. If a Participant has received an award pursuant to the provisions
of the Plan, is employed by the Corporation at the end of the
award period and the performance goals have been met, then
the Participant shall be fully vested, at the end of the award
period, in the shares of Common Stock awarded to the Participant
for that award period.
h. In the event of termination of employment of a Participant with
the Corporation prior to the last day of an award period for any
reason other than Participant's death, all rights to any shares of
Restricted Common Stock held in a deposit account with respect to
such award, including any additional shares delivered with respect
to such shares as described in subsection 7.2d above shall be
forfeited to the Corporation. However, the Committee may, if the
Committee determines that the circumstances warrant such action,
approve the distribution of all or any part of the Restricted
Common Stock which would otherwise be forfeited. By way of
illustration, but not limitation, circumstances which might
warrant such action on the part of the Committee include
retirement pursuant to a pension plan of the Corporation, or
retirement pursuant to a pension plan of the Corporation by reason
of disability.
7.3 Distribution of Restricted Common Stock
a. Distribution After Award Period: Except as otherwise provided,
distribution of vested awards of Common Stock shall be made as
soon as practicable after the last day of the applicable award
period in the form of full shares of Common Stock, with fractional
shares, if any, being awarded in cash.
<PAGE> 10
10
b. Distribution After Death of Participant: Upon the death of
the Participant, either before or after retirement, any shares of
Restricted Common Stock then held shall, subject to this Article
VII, be delivered within a reasonable time under the
circumstances to Participant's Beneficiary or, in the absence of
an appropriate Beneficiary designation to the Participant's
estate, in such one or more installments as the Committee may then
determine.
7.4 Designation of Beneficiaries
If a Participant dies prior to the receipt in full of any award under
the Plan to which the Participant is entitled, the award shall be
distributed to the Participant's Beneficiary or, in the absence of a
Beneficiary designation, to the Participant's estate. The
designation of a Beneficiary shall be made in writing on a form
prescribed by and filed with the Committee prior to the Participant's
death. If the Committee is in doubt as to the right of any person to
receive such amount, the Committee may retain such amount, without
liability for any interest thereon, until the rights thereto are
determined, or the Committee may pay such amount into any court of
appropriate jurisdiction and such payment shall be a complete discharge
of the liability of the Plan and the Corporation therefor.
7.5 Transferability: Subject to the provision of this Article VII, shares
of Common Stock awarded to a Participant will become freely
transferable by the Participant only at the end of the award period
established with respect to such shares.
7.6 Distribution to Person Other Than Employee: If the Committee shall
find that any person to whom any award is payable under this Article
VII of the Plan is unable to care for such person's affairs because of
illness or accident, or is a minor, or has died, then any payment due
Participant or Participant's estate (unless a prior claim therefor has
been made by a duly appointed legal representative), may, if the
Committee so directs the Corporation, be paid to Participant's spouse,
a child, a relative, an institution maintaining or having custody of
such person, or any other person deemed by the Committee to be a proper
recipient on behalf of such person otherwise entitled to payment. Any
such payment shall be a complete discharge of the liability of the
Committee and the Corporation therefor.
7.7 Restricted Common Stock is intended to constitute an unfunded deferred
compensation arrangement for a select group of management or highly
compensated personnel.
7.8 A forfeiture of shares of Common Stock pursuant to subsection 7.2h of
the Plan shall effect a complete forfeiture of voting rights, dividend
rights and all other rights relating to the award or grant as of the
date of forfeiture.
7.9 Each distribution of Common Stock under this Article VII of the Plan
shall be made subject to such federal, state and local tax withholding
requirements as apply on the distribution date. For this purpose, the
Committee may provide for the withholding of shares of Common Stock or
allow a
<PAGE> 11
11
Participant to pay to the Corporation funds sufficient to satisfy such
withholding requirements.
7.10 Notwithstanding any other provisions in the Plan, in the event of a
Change in Control (as hereinafter defined) each Participant shall be
fully vested in the number of shares of Common Stock awarded to such
Participant for all award periods that, upon such event, have not yet
ended. Distribution of all shares of Common Stock shall be made as
soon as practicable within 7 days after the date of the Change in
Control, as if the applicable award period or periods had ended on such
date. In addition, the Corporation shall reimburse a participant for
legal fees and expenses incurred by such Participant in successfully
seeking to obtain or enforce any right to distribution under this
Section 7.10. For purposes of this Plan, a Change in Control shall
occur upon the occurrence of one or more of the following events:
(i) a change in control of the Corporation would be required to be
reported in response to Item 1(a) of the Current Report on Form
8-K, as in effect on the date hereof, pursuant to Sections 13 or
15(d) of the Exchange Act, whether or not the Corporation is then
subject to such reporting requirement (unless such change in
control was arranged or consummated with the prior approval of the
Board);
(ii) any "person" or "group" within the meaning of Sections 13(d) and
14(d)(2) of the Exchange Act becomes the "beneficial owner" as
defined in Rule 13d-3 under the Exchange Act of more than 30% of
the then outstanding voting securities of the Corporation
otherwise than through a transaction or transactions arranged by
or consummated with the prior approval of the Board;
(iii) during any period of twenty-four consecutive months (not including
any period prior to the adoption of this Plan) Present Directors
and/or New Directors cease for any reason to constitute a majority
of the Board. For purposes of this subsection (iii) "Present
Directors" shall mean individuals who at the beginning of such
consecutive twenty-four month period were members of the Board and
"New Directors" shall mean any director of the Corporation whose
election by the Board or whose nomination for election by the
Shareholders was approved by a vote of at least two-thirds of the
Corporation's Directors then still in office who were Present
Directors or New Directors;
(iv) there is a sale by the Corporation within a three-year period of
assets of the Corporation with either a book value or market value
of 50% or more of the assets of the Corporation;
(v) a bidder as defined in Rule 14d-1(b) under the Exchange Act files
a tender offer statement with the Securities & Exchange Commission
and the Corporation.
Notwithstanding any other provisions of the Plan, the provisions of
this Section 7.10 may not be amended after the date a Change
in Control occurs without the written consent of a majority in number
of Participants.
<PAGE> 12
12
ARTICLE VIII, PROFIT SHARING GRANTS
8.1 Grants: The Committee may from time to time grant an annual profit
sharing amount totaling no more than 2% of the net profits of the
Corporation. For purposes of this Plan the annual profit sharing amount
will be based on the net profit of the Corporation as averaged over a
three year period ending on December 31 prior to the date of grant.
Grants shall be made to Eligible Employees, on the basis of their
contributions to the successful management of the Corporation in
accordance with such rules as the Committee may prescribe. Eligible
Employees who have received awards or grants under Article VI or
Article VII of this Plan will not be eligible for a Profit Sharing
Grant in the same year.
8.2 Individual Grant Amount: The Committee shall determine and fix the
amount of any grant under the Plan to be provided for any Eligible
Employee.
8.3 Restrictions: The Committee may at its sole discretion provide for
restrictions that may delay or prevent the ultimate payout of any
Profit Sharing Grants under this Plan. Such restrictions may include a
provision for equal annual payments over such time as the Committee
deems proper.
8.4 Termination of Employment: In the event of termination of employment
of an Eligible Employee with the Corporation prior to the final payment
of any Profit Sharing Grant for any reason other than the Eligible
Employee's death, all rights to any further payments shall be
forfeited. However, the Committee may, if the Committee determines
that the circumstances warrant such action, approve the payment of all
or any part of the payments which would otherwise be forfeited. By way
of illustration, but not limitation, circumstances which might warrant
such action on the part of the Committee include retirement pursuant to
a pension plan of the Corporation, or retirement pursuant to a pension
plan of the Corporation by reason of disability.
8.5 Payment After Death of Eligible Employee: Upon the death of the
Eligible Employee any grants not yet paid to the Eligible Employee
shall be made to the Eligible Employee's Beneficiary or, in the absence
of an appropriate beneficiary designation, to the Eligible Employee's
estate, in such one or more installments as the Committee may then
determine.
ARTICLE IX, AMENDMENT OR TERMINATION OF THE PLAN
9.1 Right To Amend, Suspend or Terminate Plan: The Board reserves the
right at any time to amend, suspend or terminate the Plan in whole or
in part and for any reason and without the consent of any Optionee,
Participant or Beneficiary; provided, that no such amendment shall:
a. Change the Stock Option price or adversely affect any Stock Option
or Stock Appreciation Right outstanding under the Plan on the
effective date of such amendment or termination, or
b. Adversely affect any award or grant then in effect or rights to
receive any amount to which Participants or Beneficiaries have
become entitled prior to such amendment, or
<PAGE> 13
13
c. Unless approved by the Shareholders, increase the aggregate
number of shares of Common Stock reserved for award or grant
under the Plan, change the group of Eligible Employees under the
Plan or materially increase benefits to Eligible Employees under
the Plan.
9.2 Periodic Review of Plan: In order to assure the continued realization
of the purposes of the Plan, the Committee shall periodically review
the Plan, and the Committee may suggest amendments to the Board as it
may deem appropriate.
9.3 Amendments May Be Retroactive: Subject to Section 9.1 above, any
amendment, modification, suspension or termination of any provisions of
the Plan may be made retroactively.
ARTICLE X, GENERAL PROVISIONS
10.1 Rights to Continued Employment, Award or Option: Nothing contained in
the Plan or in any Stock Option, Stock Appreciation Right, Profit
Sharing Grant or Restricted Common Stock award shall give any employee
the right to be retained in the employment of the Corporation or affect
the right of the Corporation to terminate the employee's employment at
any time. The adoption of the Plan shall not constitute a contract
between the Corporation and any employee. No Eligible Employee shall
receive any right to be granted an option, right or award hereunder nor
shall any such option, right or award be considered as compensation
under any employee benefit plan of the Corporation.
10.2 Governing Law: The provisions of this Plan and all rights thereunder
shall be governed by and construed in accordance with the laws of the
State of Michigan.
IN WITNESS WHEREOF, execution is hereby effected.
ATTEST: CMS NOMECO OIL & GAS CO.
_________________________________ BY:____________________________________
Secretary
<PAGE> 14
14
ADDENDUM
CMS NOMECO OIL & GAS CO. LONG TERM PERFORMANCE INCENTIVE PLAN
The following provisions shall apply only to the initial grant by the Committee
under the Plan, to or on account of an Optionee, of certain Nonqualified
Options under the Plan, which grant is effective as of March 1, 1996 and covers
87,000 shares (hereinafter referred to as the IPO Grant), and shall supersede
any contrary provisions of the Plan with respect to such IPO Grant:
1. The Committee shall not be entitled to charge against any amounts
otherwise payable under the Plan to or on behalf of the
Optionee, any expenses or fees it incurs arising from or related
to an Optionee's formal or informal action regarding the
enforcement of his rights with respect to the exercise of the IPO
Grant.
2. In the event the Optionee's employment with the Corporation is
terminated for any reason on or after March 1, 1996, the
Optionee shall have a reasonable time, not to exceed the later of
September 10, 1996 or 90 days from the date of termination, to
exercise any outstanding IPO Grant Options.
All provisions of the Plan which are not in conflict with this Addendum shall
remain in full force and effect. Further, any contemporaneous or subsequent
grants under the Plan shall not be subject to the terms of this Addendum.
<PAGE> 1
EXHIBIT 10.31
CMS NOMECO OIL & GAS CO.
ANNUAL EXECUTIVE INCENTIVE
COMPENSATION PLAN
FEBRUARY, 1996
1
<PAGE> 2
CMS NOMECO OIL & GAS CO.
ANNUAL EXECUTIVE INCENTIVE COMPENSATION PLAN
I. PURPOSE
The purpose of the Annual Executive Incentive Compensation Plan
(Plan) of CMS NOMECO Oil & Gas Co. (Company) is to:
A. Provide an equitable and competitive level of compensation that
will permit the Company to attract, retain and motivate highly
competent Officers and key employees.
B. Provide a financial incentive for Officers and key employees to
achieve expected levels of individual performance and thereby
assist in the achievement of Company objectives.
II. EFFECTIVE DATE
The effective date of the Plan is November 1, 1995.
III. ELIGIBILITY
Officers and key employees in Salary Grades 11 and above are eligible
for participation in the Plan.
IV. ADMINISTRATION OF THE PLAN
The Plan will be administered by the President of the Company, under
the general direction of the Executive and Remuneration Committee of
the Board of Directors.
V. PERFORMANCE GOALS
The performance goal for the Plan shall consist of three factors:
(A) the net income of CMS ENERGY Corporation (CMS Energy); (B) the
pre-tax operating income of CMS NOMECO Oil & Gas Co.; and (C) the
finding costs for oil and/or gas. Of these three factors, 35% of the
award will be based on CMS Energy net income, 50% will be based on
CMS NOMECO Oil & Gas Co. pre-tax operating income and 15% will be
based on the finding costs for oil and/or gas. In the event less
than 80% of the CMS Energy income goal is achieved, there will not be
a payout under that portion of the Plan. In the event less than 80%
of the CMS NOMECO Oil & Gas Co. income goal is achieved, there will
not be a payout under that portion of the Plan. In the event less
than 80% of the finding costs goal is achieved, there will not be a
payout for that portion of the Plan.
A. CMS ENERGY NET INCOME AWARD -- An income goal will be set each
year. For each 1% (or fraction thereof) increase achieved in
net income above 80% of goal, there will be a corresponding 2.5%
(or pro rata part) increase in the award up to 100% after which
there will be a corresponding 1% (or pro rata part) increase in
the award for each additional 1% (or fraction thereof) increase
in net income above goal. The maximum award is 120%.
B. CMS NOMECO OIL & GAS CO. PRE-TAX OPERATING INCOME AWARD - An
income goal will be set each year. For each 1% (or fraction
thereof) increase achieved in pre-tax operating income above 80%
of goal, there will be a corresponding 2.5% (or pro rata part)
increase in the award up to 100% after which there will be a
corresponding 1% (or pro rata part) increase in the award for
each additional 1% (or fraction thereof) increase in net income
above goal. The maximum award is 120%.
C. CMS NOMECO OIL & GAS CO. FINDING AWARD -- A finding cost goal
will be established by the Committee to reflect the costs of
adding proved reserves. For each 1% (or fraction thereof)
increase
2
<PAGE> 3
in meeting the goal above 80% of goal, there will be a corresponding 2.5%
(or pro rata part) increase in the award until the percent of a standard
award granted equals 100%, after which there will be a corresponding 1%
(or pro rata part) increase in the award for each additional 1% (or
fraction thereof) increase in goal achievement. The maximum award is 120%
of the standard award.
<TABLE>
<CAPTION>
ACTUAL INCOME PERCENT OF
AS A PERCENT OF GOAL AWARD GRANTED
-------------------- -------------
<S> <C>
Less Than 80.0% 0
80.0% 50.0%
85.0% 62.5%
90.0% 75.0%
95.0% 87.5%
100.0% 100.0%
105.0% 105.0%
110.0% 110.0%
115.0% 115.0%
120.0% and Above 120.0%
</TABLE>
<TABLE>
<CAPTION>
FINDING COSTS PERCENT OF
GOAL ACHIEVED AWARD GRANTED
---------------------- -------------
<S> <C>
Less Than 80.0% 0
80.0% 50.0%
85.0% 62.5%
90.0% 75.0%
95.0% 87.5%
100.0% 100.0%
105.0% 105.0%
110.0% 110.0%
115.0% 115.0%
120.0% and Above 120.0%
</TABLE>
VI. ANNUAL AWARD FUND
Standard incentive awards for each eligible executive will amount to a
percentage of the midpoint of his/her salary grade in the Performance
Year. The midpoints and salary ranges are determined each year and are
subject to review and approval by the Committee. The percentage will
vary by position level as indicated below:
<TABLE>
<CAPTION>
STANDARD INCENTIVE
SALARY AWARD AS A % OF
POSITION GRADE SALARY GRADE MIDPOINT
------------------------- ------ ---------------------
<S> <C> <C>
President E-6 55.0
Executive Vice President/
Senior Vice President E-4 45.0
Vice President E-3 40.0
Vice President E-2 35.0
Vice President/Managers/
Directors and Equivalent E-1 30.0
Managers/Directors 13 25.0
Managers/Directors 12 20.0
Managers/Directors and
Equivalent 11 15.0
</TABLE>
3
<PAGE> 4
The award for individual participants will be based on three factors: (1)
Company performance as measured by achievements of the net income goals of
CMS Energy Corporation and CMS NOMECO Oil & Gas Co.; (2) Company
performance measured by achievement of the finding costs goals; and (3)
individual performance; ie, performance must be fully effective or better to
be eligible for an award. Assuming a minimum of fully effective
performance, individual awards may be adjusted in a range from 70% to 130%
of the Company performance level in order to take into account individual
performance. Each individual's performance will be measured against
specific, quantifiable objectives for the Performance Year as established
and approved by each participant's immediate supervisor. Accordingly, each
year the levels will be as follows:
<TABLE>
<S> <C>
115-130% Exceptional
100-115% Exceeds
70-100% Fully Effective
0 Unacceptable
</TABLE>
Final individual awards will be calculated as follows:
<TABLE>
<S><C>
Individual Standard CMS Net NOMECO Pre-tax FindingCosts Individual
- ---------- = -------- x [.35 x ------------ / .50 x ------------------ / .15 x ------------ ] x --------------
Award Award Income Award Opr Income Award Award Performance
</TABLE>
VII. PAYMENT OF AWARDS
CURRENT AWARDS
All awards for the Performance Year will be paid in cash no later
than March of the following year after review and approval by the
Committee. The amounts required by law to be withheld for income tax
and Social Security taxes will be deducted from the award payments.
PAYMENT IN THE EVENT OF DEATH
Participants may name the beneficiary of their choice in the event
they die prior to receipt of either a current or deferred award. In
the event a beneficiary is not named, the payment will be made to the
first surviving class as follows:
1. Widow or Widower
2. Children
3. Parents
4. Brothers and Sisters
5. Executor or Administrator
Participants may change beneficiary at any time and the change will
be effective as of the date the participants complete and sign the
beneficiary form, whether or not they are living at the time the
request is received by the Company. However, the Company will not be
liable for any payments it makes before receiving a written request.
VIII. CHANGE OF STATUS
A. SALARY GRADE CHANGE
Individual awards will be based on the salary grade level in
effect as of the beginning of the Performance Year or such later
date on which an employee becomes a participant in the Plan
except that an eligible employee promoted to a higher eligible
salary position during the award year may be recommended for an
award based upon the percentage of the Performance Year the
employee is in each participating position.
B. NEW HIRE, TRANSFER, PROMOTION
A newly hired employee or an employee promoted during the
Performance Year to a position qualifying for participation may
be recommended for a pro rata award based on the percentage of
the Performance Year the employee is in the participating
position.
4
<PAGE> 5
C. DEMOTION
No award will be made to an employee who has been demoted during
the Performance Year because of performance. If the demotion is
due to an organization change, a pro rata award may be made
provided the employee otherwise qualifies for an award.
D. TERMINATION
An employee whose services are terminated during the Performance
Year for reasons of misconduct, failure to perform, or other
performance-related reasons, shall not be considered for an
award. If the termination is due to other reasons such as
reorganization, transfer to a subsidiary, etc, and the
termination is not due to a fault of the employee, the employee
may be considered for a pro rata award.
E. RESIGNATION
An employee who resigns to accept employment elsewhere during or
after a performance year, (including self-employment) will not
be eligible for an award. If the resignation is due to other
reasons; eg, ill health in the immediate family, etc, the
employee may be considered for a pro rata award.
F. DEATH, DISABILITY, RETIREMENT, LEAVE OF ABSENCE
An employee whose status as an active employee is changed during
the Performance Year for any of the reasons cited, may be
considered for a pro rata award.
IX. IMPACT ON BENEFIT PLANS
Payments made under this program will be considered as earnings for the
Supplemental Executive Retirement Plan (Salary Grades E-1 and above)
and for life insurance, but not for purposes of the Employees' Savings
Plan, Pension Plan, or other employee benefit programs.
X. TERMINATION OR AMENDMENT OF THE PLAN
The Company at any time may, in writing, terminate or amend the Plan.
5
<PAGE> 1
Draft 03 1/19/96
EXHIBIT 10.32
FORM OF
ROYALTY RIGHTS PURCHASE AGREEMENT
THIS ROYALTY RIGHTS PURCHASE AGREEMENT (the "Agreement"), dated
as of March 1, 1996, (the "Effective Date") is by and between CMS NOMECO Oil &
Gas Co., a Michigan corporation ("CMS NOMECO" or "Purchaser"), and
_________________________________________, (the "Seller").
RECITALS:
The Seller is currently an officer of CMS NOMECO. Through the
"Plan B Program" terminated by CMS NOMECO effective October 31, 1995, the
Seller acquired, and currently possesses, certain overriding royalty interests
in wells as described on Exhibit A hereto (the "Royalty Rights"). CMS NOMECO
intends to make an initial public offering of a portion of its common stock
("IPO"). In furtherance of that goal, CMS NOMECO desires to align the
interests of the Seller as a key management employee with the interests of
prospective shareholders and to acquire the Royalty Rights. Accordingly, CMS
NOMECO has agreed to purchase, and the Seller has agreed to sell, the Royalty
Rights, in exchange for the consideration identified below.
NOW, THEREFORE, it is agreed between the parties as follows:
1. PURCHASE OF ROYALTY RIGHTS. Effective on the Effective
Date, Seller shall sell, and CMS NOMECO shall purchase, all Seller's right,
title and interest in the Royalty Rights, and in exchange therefore, CMS NOMECO
shall pay the Seller the consideration described below in accordance with the
terms stated in this Agreement.
2. FIRST INSTALLMENT PAYMENT. On the Effective Date, CMS
NOMECO shall pay to the Seller cash in the amount of $_______________.
3. REMAINING INSTALLMENT PAYMENTS.
(A) INITIAL CONVERSION VALUATION. On the Effective
Date, the amount of $______________ (the "Conversion Amount") shall be
converted into phantom stock units of CMS Energy Corporation ("CMS Energy")
common stock, or, if the pricing date of the IPO (the "Pricing Date") occurs on
or before the Effective Date, fifty percent (50%) of
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the Conversion Amount shall be converted into phantom stock units of CMS Energy
common stock and fifty percent (50%) of the Conversion Amount into phantom
stock of CMS NOMECO common stock. For conversion purposes, each CMS Energy
phantom stock unit shall be valued at the Trailing Average Price, as that term
is defined below, of CMS Energy common stock on the Effective Date, and each
CMS NOMECO phantom stock unit shall be valued at the initial offering price per
share of CMS NOMECO common stock as set forth in the prospectus governing the
IPO. Whenever used herein, the term Trailing Average Price means the average of
the closing prices of a security per share as reported in The Wall Street
Journal for the ten trading days preceding (and not including) a specified
date.
(B) SECOND (IPO) CONVERSION. If the Pricing Date
occurs after the Effective Date, the value of the CMS Energy phantom stock
units described in Subsection 3(a) shall be redetermined as of the Pricing
Date, based on the Trailing Average Price of CMS Energy common stock as of the
Pricing Date. Fifty percent of the value so determined shall be converted into
phantom stock units of CMS NOMECO common stock effective as of the Pricing Date
("the "IPO Conversion"). For conversion purposes, each CMS NOMECO phantom
stock unit shall be valued at the initial offering price of one share of CMS
NOMECO common stock set forth in the prospectus governing the IPO. If no IPO
occurs, the entire Conversion Amount shall remain in phantom stock units of CMS
Energy common stock.
(C) PHANTOM STOCK ACCOUNT. The phantom stock units
determined under paragraphs 3(a) and 3(b) shall be credited to a phantom stock
account ("Account") established and maintained for the Seller by CMS NOMECO.
The Account shall be an unfunded record of the phantom units allocated to the
Seller under this Agreement solely for accounting purposes, shall not require a
segregation of CMS NOMECO assets, and shall remain subject to the claims of
general creditors against CMS NOMECO. Immediately following the Conversion
Date, the IPO Conversion, at least annually thereafter, and from time to time
upon reasonable request of the Seller, CMS NOMECO shall furnish the Seller with
a statement in the form of Exhibit B to this Agreement, showing the number of
CMS NOMECO and CMS Energy phantom stock units allocated to the Seller as of
such dates.
(D) ADJUSTMENTS FOR STOCK DIVIDENDS/SPLITS, ETC.
In the event of any stock dividend, stock split, reclassification, merger,
consolidation, or similar transaction affecting the shares of common stock of
CMS NOMECO or CMS Energy underlying the Seller's phantom stock units, such
phantom stock units shall automatically be adjusted at the same time and in the
same manner as the outstanding shares of common stock are adjusted.
(E) INSTALLMENT PAYMENT DATES. On the first,
second, third, fourth and fifth anniversaries of the Conversion Date, the then
value of the Seller's aggregate remaining phantom stock units shall be
determined, and the Seller shall receive a cash
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installment payment from CMS NOMECO calculated on a declining balance basis,
representing the following percentages of the then value of the Seller's
aggregate remaining phantom stock units:
ANNIVERSARY DATE PERCENTAGE PAYMENT
March 1, 1997 21% of balance
March 1, 1998 26% of balance
March 1, 1999 36% of balance
March 1, 2000 56% of balance
March 1, 2001 100% of balance
For installment payment valuation purposes, each phantom stock
unit shall be valued at the Trailing Average Price of CMS Energy or CMS NOMECO
common stock, as applicable. Each installment payment shall be comprised of an
equal percentage of CMS Energy and CMS NOMECO phantom stock units. The phantom
stock units in the Seller's Account shall be reduced by the number of phantom
stock units paid out in each installment.
(F) DIVIDEND EQUIVALENT PAYMENTS. CMS NOMECO will
pay to Seller, on each date on which CMS NOMECO or CMS Energy pay a dividend
with respect to its common stock in cash or other property (other than its
common stock), an amount equal to the dividends the phantom stock units at that
time remaining in the Seller's Account would have received if such units were
actual shares of common stock of CMS NOMECO or CMS Energy, as applicable.
4. ACCELERATION EVENT.
(A) ACCELERATION OF INSTALLMENTS. If (A) the
Seller's employment with CMS NOMECO terminates due to the Seller's death; or
(B) the Seller terminates his employment due to a serious health problem of the
Seller or his immediate family and, within 10 days after such termination and
written request of CMS NOMECO, executes and delivers to CMS NOMECO a covenant
not to complete through March 1, 2001, in the form attached hereto as Exhibit
D; or (C) the Seller's employment is terminated by CMS NOMECO for any reason
(including misconduct by the Seller); or (D) the Seller terminates his
employment within 3 months after having incurred an adverse change in
officer-level responsibilities or other terms and conditions of employment of
the Seller; or (E) the Seller terminates his employment within 3 months after
receiving notice from CMS NOMECO of his employment transfer to a work location
other than Jackson, Michigan or Houston, Texas (provided that the transfer to
any work location within a 50 mile radius of Jackson, Michigan or Houston,
Texas shall be disregarded under this Subsection 4(a)); or (F) the Seller
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terminates his employment within 3 months following a Change in Control of CMS
NOMECO (as defined below) or CMS Energy (as defined in the CMS Energy
Corporation Performance Incentive Plan) (each such event (A) through (F) of
this Subsection 4(a) being referred to as an "Acceleration Event"), then all
remaining unpaid installments automatically shall become due as of Seller's
date of termination, and CMS NOMECO shall make a final cash installment payment
to the Seller or the Seller's estate or beneficiary, as applicable, within 30
days thereafter equal to the then value, based on the Trailing Average Price of
CMS Energy and CMS NOMECO common stock, as applicable, of the Seller's
aggregate remaining phantom stock units as of such due date (the "Regular
Acceleration Event Installment"). For purposes of this Subsection 4(a),
"Control" means ownership of 50% or more of the voting stock of or equity
interests in an entity and a "Change in Control of CMS NOMECO" shall be deemed
to have occurred if CMS Energy, directly or indirectly through an affiliate
controlled by, or under common control with CMS Energy, no longer holds a 50%
equity or asset ownership interest in CMS NOMECO.
(B) SUPPLEMENTAL ACCELERATION EVENT INSTALLMENT
PAYMENT. Within 30 days after the occurrence of an Acceleration Event, CMS
NOMECO shall pay to the Seller or the Seller's estate or beneficiary, as
applicable, an additional installment amount as set forth in Exhibit C hereto
(the "Supplemental Acceleration Event Installment").
(C) FORFEITURE EVENT. If, and only if, the Seller
resigns his employment with CMS NOMECO before March 1, 2001 under circumstances
other than as contemplated by Clauses (B), (D), (E) or (F) of Subsection 4(a),
then no Regular or Supplemental Acceleration Event Installment shall be paid
and all remaining installment payments outstanding as of the date of such
resignation automatically shall be forfeited.
5. SELLER'S REPRESENTATIONS AND WARRANTIES. Seller
represents and warrants to CMS NOMECO that Seller has and is conveying hereby
good title to the Royalty Rights, free and clear of all liens, encumbrances or
assignments, other than those liens, encumbrances, assignments, adverse claims
and other title defects burdening or affecting the interests when received by
the Seller from CMS NOMECO or created by CMS NOMECO thereafter.
6. PRE-TRANSFER PRODUCTION PAYMENTS. The payment of
production revenue with respect to the Royalty Rights for production that
occurs prior to the Effective Date shall be paid to the Seller at the time such
payment is received by CMS NOMECO.
7. NONTRANSFERABILITY AND NONALIENATION. The Seller's
rights, title and interest in this Agreement and the installment payments
hereunder may not be transferred, pledged, assigned or otherwise alienated or
hypothecated during the Seller's lifetime, except into trust for estate
planning purposes, and any transfer in violation of this covenant without
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the consent of CMS NOMECO shall be void.
8. SECURITIES LAW RESTRICTIONS.
(A) PHANTOM STOCK CASH PAYMENT EXEMPTION. At the
time that the IPO is completed, this Agreement is intended to qualify for the
"derivative security" cash payment exemption set forth in Rule 16a-1(c)(3) of
the Securities Exchange Act of 1934, as amended ("Exchange Act") by satisfying
the provisions of (a)(1), (a)(2) and (c)(2) of Rule 16b-3 of the Exchange Act.
(B) PLAN REQUIREMENTS. If a plan is required to
satisfy the aforementioned exemption, then this Agreement, when aggregated with
the purchase agreements issued by CMS NOMECO to the other top five CMS NOMECO
executives to purchase their respective "Plan B Program" royalty interests,
shall constitute a "plan" for purposes of the cash payment exemption under Rule
16a-1(c)(3) of the Exchange Act. The maximum number of CMS NOMECO shares under
such plan shall be the aggregate number of shares of CMS NOMECO Common Stock
underlying the CMS NOMECO phantom stock units allocated among all six purchase
agreements. In the event that the IPO is completed and under Rule 16a-1(c)(3)
of the Exchange Act there is a need for a "disinterested committee" within the
definition of Rule 16b-3 of the Exchange Act, the disinterested committee and
not the CMS NOMECO Board of Directors shall administer the terms of the plan.
9. EMPLOYMENT OF SUCCESSORS. Nothing herein confers any
right or obligation on the Seller to continue in the employ of CMS NOMECO, nor
shall it affect in any way the Seller's right or the right of CMS NOMECO to
terminate the Seller's employment at any time. This Agreement shall be binding
upon and inure to the benefit of any successor or successors of CMS NOMECO.
10. DISPUTES. As part of the consideration for this
Agreement, the Seller and the Seller's successors and assigns agree that any
dispute or disagreement which shall arise under or as a result of this
Agreement shall be determined by arbitration under the Commercial Arbitration
Rules of the American Arbitration Association with venue in the Detroit
metropolitan area. Any such determination of a dispute under this Agreement
shall be final, binding and conclusive for all purposes.
11. NOTICES. Every notice relating to this Agreement shall
be in writing and if given by mail shall be given by registered or certified
mail with return receipt requested. All notices to CMS NOMECO shall be
delivered to the [Chairman of the Board] of CMS NOMECO at its headquarters.
All notices by CMS NOMECO to the Seller shall be delivered to the Seller
personally or addressed to the Seller at the Seller's last residence
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address as then contained in CMS NOMECO's records or such other address as the
Seller may designate. Either party by notice to the other may designate a
different address to which notices shall addressed. Any notice given by CMS
NOMECO to the Seller at the Seller's last designated address shall be effective
to bind any other person who shall acquire rights hereunder.
12. MISCELLANEOUS. This Agreement contains the entire
agreement of the parties relating to the subject matter hereof and supersedes
any prior written or oral agreements or understandings relating to the subject
matter hereof. No modification or amendment of this Agreement shall be valid
unless in writing and signed by or on behalf of the parties hereto. A waiver
of the breach of any term or condition of this Agreement shall not be deemed to
constitute a waiver of any subsequent breach of the same or any other term or
condition. This Agreement is intended to be performed in accordance with, and
only to the extent permitted by, all applicable laws, ordinances, rules and
regulations. If any provisions of this Agreement, or the application thereof
to any person or circumstance, shall, for any reason and to any extent, be held
invalid or unenforceable, such invalidity and unenforceability shall not affect
the remaining provisions hereof and the application of such provisions to other
persons or circumstances, all of which shall be enforced to the greatest extent
permitted by law. The headings in this Agreement are inserted for convenience
of reference only and shall not be a part of or control or affect the meaning
of any provision hereof.
13. GOVERNING LAW. This Agreement shall be construed under
and governed by the laws of the State of Michigan.
This Agreement is hereby executed on this the ____ day of __________, 199__.
PURCHASER:
CMS NOMECO OIL & GAS CO.
By: _________________________
[_______________________]
Its:[__________________]
SELLER:
[____________________________]
[Name of Executive]
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EXHIBIT A
ROYALTY RIGHTS
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EXHIBIT B
PHANTOM STOCK ACCOUNT
Name of Account Holder (Seller) ___________________________________
CMS ENERGY PHANTOM STOCK UNITS
<TABLE>
<CAPTION>
NUMBER VALUE OF
DATE AMOUNT UNIT VALUE OF UNITS BALANCE
- -------- ------------- -------------- -------- ------------
<S> <C> <C> <C> <C>
</TABLE>
CMS NOMECO PHANTOM STOCK UNITS
<TABLE>
<CAPTION>
NUMBER VALUE OF
DATE AMOUNT UNIT VALUE OF UNITS BALANCE
- -------- ------------- --------------- -------- ------------
<S> <C> <C> <C> <C>
</TABLE>
TOTAL ACCOUNT VALUE _________________
<PAGE> 9
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EXHIBIT C
SUPPLEMENTAL ACCELERATION
EVENT INSTALLMENT
If an Acceleration Event occurs under Subsection 4(a) of the Agreement, the
amount of the Supplemental Acceleration Event Installment payment payable
pursuant to Subsection 4(b) shall be determined as follows:
Date of Amount of Supplemental
Acceleration Event Acceleration Event Installment Payment
- -------------------------------- --------------------------------------
On or but prior
after to
- ------ ---------
<PAGE> 1
EXHIBIT 15.1
Independent Accountants' Review Report
To the Board of Directors,
CMS NOMECO Oil & Gas Co.:
We have reviewed the accompanying consolidated balance sheet of CMS NOMECO Oil
& Gas Co. (a Michigan corporation and wholly owned subsidiary of CMS
Enterprises Company) and subsidiaries as of September 30, 1995, and the
related consolidated statements of income, stockholder's equity and cash flows
for the nine months ended September 30, 1995. These consolidated financial
statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures
to financial data and making inquiries of persons responsible for financial
and accounting matters. It is substantially less in scope than an audit
conducted in accordance with generally accepted auditing standards, the
objective of which is the expression of an opinion regarding the financial
statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that
should be made to the consolidated financial statements referred to above
for them to be in conformity with generally accepted accounting principles.
Arthur Andersen LLP
Detroit, Michigan
October 20, 1995.
<PAGE> 2
EXHIBIT 15.1
To CMS NOMECO Oil & Gas Co.:
We are aware that CMS NOMECO Oil & Gas Co. has included in this registration
statement our report dated October 20, 1995, covering our review of the
unaudited interim financial information contained therein. Pursuant to
Regulation C of the Securities Act of 1933, that report is not considered a
part of the registration statement prepared or certified by our Firm or a
report prepared or certified by our Firm within the meaning of Sections 7 and
11 of the Act.
Arthur Andersen LLP
Detroit, Michigan
February 1, 1996.
<PAGE> 1
EXHIBIT 15.2
Independent Accountants' Review Report
The Board of Directors
The Nuevo Congo Company and
Walter International Congo, Inc.
(formerly Amoco Congo Exploration and
Petroleum Companies):
We have reviewed the accompanying combined balance sheet of Amoco Congo
Exploration and Petroleum Companies (Amoco Congo) as of January 31, 1995, and
the related combined statements of operations, stockholder's equity, and cash
flows for the month then ended. These combined financial statements are the
responsibility of the Companies' management.
We conducted our review in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures to
financial data and making inquiries of persons responsible for financial and
accounting matters. It is substantially less in scope than an audit conducted
in accordance with generally accepted auditing standards, the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly we do not express such an opinion.
Based on our review we are not aware of any material modifications that should
be made to the combined financial statements referred to above for them to be
in conformity with generally accepted accounting principles.
KPMG Peat Marwick LLP
Houston, Texas
October 17, 1995
<PAGE> 2
EXHIBIT 15.2
CMS NOMECO Oil & Gas Co.
Jackson, Michigan
Re: Registration Statement No. 33-63693
Ladies and Gentlemen:
With respect to the subject registration statement, we acknowledge our
awareness of the use therein of our report dated October 17, 1995 related to
our review of the combined interim financial information of Amoco Congo
Exploration and Petroleum Companies.
Pursuant to Rule 436(c) under the Securities Act of 1933, such report is not
considered part of a registration statement prepared or certified by an
accountant or a report prepared or certified by an accountant within the
meaning of sections 7 and 11 of the Act.
Very truly yours,
KPMG Peat Marwick LLP
Houston, Texas
February 1, 1996.
<PAGE> 1
Exhibit 21.1
CMS NOMECO OIL & GAS CO.
CORPORATE STRUCTURE
(ALL ENTITIES 100% OWNED UNLESS OTHERWISE INDICATED)
CMS NOMECO Oil & Gas Co.
CMS NOMECO Colombia Oil Company
NOMECO Ecuador Oil Company
NOMECO Thailand Oil Company
Comeco Petroleum Holdings, Inc. - 50% Shareholder
CMS NOMECO Pipeline Company
Explotaciones CMS NOMECO Inc.
CMS NOMECO Services Company
CMS NOMECO Peru Company
NOMECO China Oil Co.
CMS NOMECO Equatorial Guinea Oil & Gas Co.
NOMECO Australia Pty. Limited
NOMECO Exploration (Thailand) Limited
CMS NOMECO Holdings Ltd.
CMS NOMECO International Ltd.
CMS NOMECO Ecuador LDC
CMS NOMECO Argentina LDC
CMS NOMECO Venezuela LDC
CMS NOMECO Alba LDC
CMS NOMECO E.G. LDC
CMS NOMECO International Inc.
Walter International Tunisia, Inc.
CMS NOMECO International Equatorial Guinea, Inc.
Walter International Transportation, Inc.
CMS NOMECO International Venezuela, Inc.
Walter Congo Holdings, Inc.
Walter International Congo, Inc.
<PAGE> 2
Terra Energy, Ltd.
Terra Pipeline Company
Kristin Corporation
Energy Acquisition Operating Corporation
Wellcorps LLC (55%)
Thunder Bay Pipeline Company, LLC (50%)
<PAGE> 1
Exhibit 23.1
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the inclusion in this
prospectus of our report dated January 27, 1995 on the consolidated financial
statements of CMS NOMECO Oil & Gas Co. and subsidiaries as of December 31, 1993
and 1994, and for the three years ended December 31, 1994, our report dated
February 1, 1996 on the Pro Forma Consolidated Statement of Income for the year
ended December 31, 1994, our report dated July 17, 1995 on the consolidated
financial statements of CMS NOMECO International, Inc. and subsidiaries as of
December 31, 1994, and for the year then ended, and our report dated February
1, 1996 on the consolidated financial statements of Terra Energy Ltd. and
subsidiaries as of December 31, 1994, and for the year then ended all included
herein and to all references to our Firm included in this prospectus.
Arthur Andersen LLP
Detroit, Michigan,
February 1, 1996.
<PAGE> 1
EXHIBIT 23.2
INDEPENDENT AUDITORS' CONSENT
CMS Nomeco Oil & Gas Co.
Detroit, Michigan
We consent to the use in this Registration Statement of CMS Nomeco Oil & Gas
Co. on Form S-1 of our report dated June 24, 1994 (July 31, 1994, as to Note 8)
(such report expresses an unqualified opinion and includes an explanatory
paragraph referring to substantial doubt about Walter International, Inc.'s
ability to continue as a going concern), appearing in the Prospectus, which is
a part of this Registration Statement, and to the references to us under the
heading "Experts" in such Prospectus.
DELOITTE & TOUCHE LLP
Houston, Texas
February 1, 1996.
<PAGE> 1
EXHIBIT 23.3
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
The Board of Directors
CMS NOMECO Oil & Gas Co.:
We consent to the use of our audit report dated April 18, 1995, on the combined
financial statements of Amoco Congo Exploration and Petroleum Companies as of
December 31, 1994 and 1993, and for each of the years in the three-year period
then ended included herein and to the reference to our firm under the heading
"Experts" in the prospectus.
KPMG Peat Marwick LLP
Houston, Texas
February 1, 1996.
<PAGE> 1
[RYDER SCOTT COMPANY PETROLEUM ENGINEERS LETTERHEAD]
Exhibit 23.5
CONSENT OF RYDER SCOTT COMPANY
We hereby consent to the reference to our firm under the caption
"Experts" and the references to the results of our reserve report, dated
October 2, 1995 (the "Reserve Letter") and the inclusion of the summary
letter relating to such reserve report, together with appropriate attachments
thereto, in the Registration Statement and related Prospectus of CMS NOMECO
Oil & Gas Co. (the "Company") on Form S-1 filed with the Securities and
Exchange Commission.
[SIG]
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
[SIG]
Houston, Texas
February 5, 1996
