<PAGE> 1
AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 17, 1997
REGISTRATION NO. 333-29001
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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AMENDMENT NO. 2
To
FORM S-4
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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ENERGY CORPORATION OF AMERICA
(Exact name of Registrant as specified in its charter)
<TABLE>
<S> <C> <C>
WEST VIRGINIA 1311 841235822
(State or other jurisdiction of (Primary Standard Industrial (I.R.S. Employer
incorporation or organization) Classification Code Number) Identification Number)
JOSEPH E. CASABONA
EXECUTIVE VICE PRESIDENT
4643 SOUTH ULSTER STREET, SUITE 1100 4643 SOUTH ULSTER STREET, SUITE 1100
DENVER, COLORADO 80237 DENVER, COLORADO 80237
(303) 694-2667 (303) 694-2667
(Address, including zip code and telephone (Address, including zip code and telephone
number, including area code, of registrant's number, including area code, of agent for
principal executive office) service)
</TABLE>
COPY TO:
THOMAS P. MASON
ANDREWS & KURTH L.L.P.
4200 TEXAS COMMERCE TOWER
HOUSTON, TEXAS 77002-3090
(713) 220-4200
Approximate date of commencement of proposed sale of the securities to the
public: As soon as practicable following the effectiveness of this Registration
Statement.
If the securities being registered on this Form are being offered in
connection with the formation of a holding company and there is compliance with
General Instruction G, check the following box. [ ]
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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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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 JULY 17, 1997
PROSPECTUS
ENERGY CORPORATION OF AMERICA
[ECA
LOGO]
OFFER TO EXCHANGE
$1,000 PRINCIPAL AMOUNT OF 9 1/2% SENIOR SUBORDINATED NOTES DUE 2007, SERIES A
FOR EACH $1,000 PRINCIPAL AMOUNT OF OUTSTANDING
9 1/2% SENIOR SUBORDINATED NOTES DUE 2007
($200,000,000 IN AGGREGATE PRINCIPAL AMOUNT OUTSTANDING)
------------------------
THE EXCHANGE OFFER WILL EXPIRE AT 5:00 P.M.,
NEW YORK CITY TIME, ON , 1997, UNLESS EXTENDED
------------------------
Energy Corporation of America, a West Virginia corporation (the "Company"),
hereby offers, upon the terms and subject to the conditions set forth in this
Prospectus and the accompanying Letter of Transmittal, to exchange $1,000
principal amount of its 9 1/2% Senior Subordinated Notes, Due 2007, Series A
(the "Exchange Notes"), in a transaction registered under the Securities Act of
1933, as amended (the "Securities Act"), pursuant to a Registration Statement
(as defined in "Other Information") of which this Prospectus constitutes a part,
for each $1,000 principal amount of the outstanding 9 1/2% Senior Subordinated
Notes due 2007 (the "Old Notes"), of which $200,000,000 aggregate principal
amount is outstanding (the "Exchange Offer"). The Exchange Notes and the Old
Notes are sometimes referred to herein collectively as the "Notes."
The Company will accept for exchange any and all Old Notes that are validly
tendered and not withdrawn prior to 5:00 p.m., New York City time, on the date
the Exchange Offer expires, which will be August , 1997 unless the Exchange
Offer is extended (the "Expiration Date"). Tenders of Old Notes may be withdrawn
at any time prior to 5:00 p.m., New York City time, on the Expiration Date. The
Exchange Offer is not conditioned upon any minimum principal amount of Old Notes
being tendered for exchange. However, the Exchange Offer is subject to certain
conditions that may be waived by the Company and to the terms and provisions of
the Registration Rights Agreement (as defined in "Summary of Terms of Exchange
Offer -- Registration Rights Agreement"). See "The Exchange Offer." Old Notes
may be tendered only in denominations of $1,000 and integral multiples thereof.
The Company has agreed to pay the expenses of the Exchange Offer. There will be
no cash proceeds to the Company from the Exchange Offer. See "Use of Proceeds."
The Exchange Notes will be obligations of the Company entitled to the
benefits of the indenture relating to the Notes (the "Indenture"). The form and
terms of the Exchange Notes are identical in all material respects to the form
and terms of the Old Notes, except that (i) the offering of the Exchange Notes
has been registered under the Securities Act, (ii) the Exchange Notes will not
be subject to transfer restrictions and (iii) certain provisions relating to an
increase in the stated interest rate on the Old Notes provided for under certain
circumstances will be eliminated. See "Description of the Notes -- Terms of the
Notes". Following the Exchange Offer, any holders of Old Notes will continue to
be subject to the existing restrictions on transfer thereof and, as a general
matter, the Company will not have any further obligation to such holders to
provide for registration under the Securities Act of transfers of the Old Notes
held by them. To the extent that Old Notes are tendered and accepted in the
Exchange Offer, a holder's ability to sell untendered and tendered but
unaccepted Old Notes could be adversely affected. See "The Exchange
Offer -- Purpose and Effect of the Exchange Offer."
(continued on next page)
------------------------
SEE "RISK FACTORS" BEGINNING ON PAGE 14 FOR A DISCUSSION OF CERTAIN FACTORS
WHICH INVESTORS SHOULD CONSIDER IN CONNECTION WITH THE EXCHANGE OFFER AND AN
INVESTMENT IN THE EXCHANGE NOTES OFFERED HEREBY.
------------------------
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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THE DATE OF THIS PROSPECTUS IS , 1997.
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The Old Notes were sold by the Company on May 23, 1997, to Chase Securities
Inc. and Prudential Securities Incorporated (the "Initial Purchasers") in
transactions not registered under the Securities Act in reliance upon the
exemption provided in Section 4(2) of the Securities Act (the "Offering"). The
Initial Purchasers placed the Old Notes with qualified institutional buyers (as
defined in Rule 144A under the Securities Act) ("Qualified Institutional Buyers"
or "QIBs"), each of whom agreed to comply with certain transfer restrictions and
other restrictions. Accordingly, the Old Notes may not be reoffered, resold or
otherwise transferred in the United States unless such transaction is registered
under the Securities Act or an applicable exemption from the registration
requirements of the Securities Act is available. The Exchange Notes are being
offered hereby in order to satisfy the obligations of the Company under the
Registration Rights Agreement.
The Exchange Notes will bear interest at a rate of 9 1/2% per annum,
payable semi-annually on May 15 and November 15 of each year, commencing
November 15, 1997. Holders of Exchange Notes of record on November 1, 1997, will
receive on November 15, 1997, an interest payment in an amount equal to (x) the
accrued interest on such Exchange Notes from the date of issuance thereof to
November 15, 1997, plus (y) the accrued interest on the previously held Old
Notes from the date of issuance of such Old Notes (May 23, 1997) to the date of
exchange thereof. Interest will not be paid on Old Notes that are accepted for
exchange. The Notes mature on May 15, 2007.
The Notes are unsecured obligations of the Company and are subordinated in
right of payment to all existing and future Senior Debt (as defined in
"Description of the Notes -- Certain Definitions") of the Company, which will
include borrowings under the Company's $50 million credit facility described
herein. There are currently no amounts outstanding under such facility. The
Notes are effectively subordinated in right of payment to the liabilities of the
subsidiaries of the Company. As of March 31, 1997, on a pro forma basis giving
effect to the application of the proceeds of the Offering, the aggregate
principal amount of indebtedness outstanding of the subsidiaries of the Company
would have been $86.6 million and such subsidiaries would have had $46.4 million
of additional borrowing availability under existing revolving lines of credit.
Old Notes were initially represented by a single, global Old Note (the "Old
Global Note") in registered form, registered in the name of Cede & Co., as
nominee for The Depository Trust Company ("DTC" or the "Depositary"), as
depositary. The Exchange Notes exchanged for Old Notes represented by the Old
Global Note will be initially represented by a single, global Exchange Note (the
"Exchange Global Note") in registered form, registered in the name of the
Depositary. See "Book-Entry; Delivery and Form." References herein to "Global
Note" shall be references to the Old Global Note and the Exchange Global Note.
Based on an interpretation of the Securities Act by the staff of the
Securities and Exchange Commission (the "SEC"), Exchange Notes issued pursuant
to the Exchange Offer in exchange for Old Notes may be offered for resale,
resold and otherwise transferred by a holder thereof (other than (i) a
broker-dealer who purchased such Old Notes directly from the Company for resale
pursuant to Rule 144A or any other available exemption under the Securities Act
or (ii) a person that is an "affiliate" (within the meaning of Rule 405 of the
Securities Act) of the Company), without compliance with the registration and
prospectus delivery provisions of the Securities Act, provided that the holder
is acquiring the Exchange Notes in its ordinary course of business and is not
participating, and has no arrangement or understanding with any person to
participate, in the distribution of the Exchange Notes. Holders of Old Notes
wishing to accept the Exchange Offer must represent to the Company that such
conditions have been met.
Each broker-dealer that receives Exchange Notes for its own account
pursuant to the Exchange Offer must agree that it will deliver a prospectus in
connection with any resale of such Exchange Notes. The Letter of Transmittal
states that by so acknowledging and by delivering a prospectus, a broker-dealer
will not be deemed to admit that it is an "underwriter" within the meaning of
the Securities Act. This Prospectus, as it may be amended or supplemented from
time to time, may be used by a broker-dealer in connection with resales of
Exchange Notes received in exchange for Old
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Notes where such Old Notes were acquired by such broker-dealer as a result of
market-making activities or other trading activities. The Company has agreed
that, for a period of 180 days after the Expiration Date, it will make this
Prospectus available to any broker-dealer for use in connection with any such
resale. See "Plan of Distribution."
Prior to the Exchange Offer, there has been no public market for the Old
Notes or the Exchange Notes. The Company does not intend to apply for listing of
the Exchange Notes on any securities exchange or for quotation through The
Nasdaq Stock Market. There can be no assurance that an active market for the
Exchange Notes will develop. To the extent that a market for the Exchange Notes
does develop, future trading prices of the Exchange Notes will depend on many
factors, including, among other things, prevailing interest rates, and the
market for similar securities as well as the Company's results of operations and
its financial condition. See "Risk Factors."
NO DEALER, SALESPERSON OR OTHER INDIVIDUAL HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATIONS NOT CONTAINED IN THIS PROSPECTUS IN
CONNECTION WITH THE EXCHANGE OFFER COVERED BY THIS PROSPECTUS. IF GIVEN OR MADE,
SUCH INFORMATION OR REPRESENTATIONS MUST NOT BE RELIED UPON AS HAVING BEEN
AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN OFFER TO SELL,
OR A SOLICITATION OF AN OFFER TO BUY, THE EXCHANGE NOTES IN ANY JURISDICTION
WHERE, OR TO ANY PERSON TO WHOM, IT IS UNLAWFUL TO MAKE SUCH OFFER OR
SOLICITATION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE MADE
HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATIONS THAT THERE HAS
NOT BEEN ANY CHANGE IN THE FACTS SET FORTH IN THIS PROSPECTUS OR IN THE AFFAIRS
OF THE COMPANY SINCE THE DATE HEREOF.
NOTICE TO NEW HAMPSHIRE RESIDENTS
NEITHER THE FACT THAT A REGISTRATION STATEMENT OR AN APPLICATION FOR A
LICENSE HAS BEEN FILED WITH THE STATE OF NEW HAMPSHIRE NOR THE FACT THAT A
SECURITY IS EFFECTIVELY REGISTERED OR A PERSON IS LICENSED IN THE STATE OF NEW
HAMPSHIRE CONSTITUTES A FINDING BY THE SECRETARY OF STATE THAT ANY DOCUMENT
FILED UNDER RSA 421-B IS TRUE, COMPLETE AND NOT MISLEADING. NEITHER ANY SUCH
FACT NOR THE FACT THAT AN EXEMPTION OR EXCEPTION IS AVAILABLE FOR A SECURITY OR
A TRANSACTION MEANS THAT THE SECRETARY OF STATE HAS PASSED IN ANY WAY UPON THE
MERITS OR QUALIFICATIONS OF, OR RECOMMENDED OR GIVEN APPROVAL TO, ANY PERSON,
SECURITY, OR TRANSACTION. IT IS UNLAWFUL TO MAKE, OR CAUSE TO BE MADE, TO ANY
PROSPECTIVE PURCHASER, CUSTOMER, OR CLIENT ANY REPRESENTATION INCONSISTENT WITH
THE PROVISIONS OF THIS PARAGRAPH.
OTHER INFORMATION
The Company has filed with the SEC a registration statement (the
"Registration Statement") under the Securities Act on Form S-4 (Reg. No.
333-29001) with respect to the Exchange Notes offered hereby. This Prospectus
does not contain all of the information set forth in the Registration Statement
and the exhibits thereto, certain parts which are omitted in accordance with the
rules and regulations of the SEC. Statements made in this Prospectus as to the
contents of any contract, agreement or other document referred to are not
necessarily complete. With respect to each such contract, agreement or other
document filed as an exhibit to the Registration Statement, reference is made to
the exhibit for a more complete description of the matter involved. The
Registration Statement and any amendments thereto, including exhibits filed or
incorporated by reference as a part thereof, are available for inspection and
copying at the Public Reference Section of the SEC, at Judiciary Plaza, 450
Fifth Street, N.W., Washington, D.C. 20549, at prescribed rates, and at the
SEC's regional offices at Citicorp Center, 500 West Madison Street, Suite 1400,
Chicago, Illinois 60661-2511 and 7 World Trade Center, Suite 1300, New York, New
York 10048. The SEC maintains
iii
<PAGE> 5
a web site (http:www.sec.gov) that contains reports, proxy and information
statements and other information regarding registrants, such as the Company,
that file electronically with the SEC. The Company intends to furnish its
noteholders with annual reports containing audited financial statements
certified by independent public accountants.
iv
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SUMMARY
The following summary is qualified in its entirety by, and should be read
in conjunction with, the more detailed information and financial data, including
the financial statements and notes thereto, appearing elsewhere in this
Prospectus. Unless the context otherwise requires, all references herein to
"ECA" or the "Company" include Energy Corporation of America and its
consolidated subsidiaries. Certain industry terms are defined in the Glossary.
THE COMPANY
Energy Corporation of America is a privately held, integrated energy
company primarily engaged in natural gas distribution in West Virginia and in
the development, production, transportation and marketing of natural gas and oil
in the Appalachian Basin. For the fiscal year ended June 30, 1996, the Company
had total revenues of $375.8 million and EBITDA of $56.8 million. During the
first nine months of fiscal 1997, the Company had revenues of $305.2 million and
EBITDA of $44.4 million.
The Company operates the largest natural gas distribution utility in West
Virginia, supplying natural gas sales and transportation service to
approximately 200,000 customers in 45 of the 55 counties in West Virginia. The
Company distributes approximately 57% of the total natural gas volumes
distributed to end users in West Virginia. In fiscal 1996, the Company owned and
operated approximately 3,900 miles of natural gas distribution pipelines and
sold or transported 65.2 Bcf of gas.
The Company is engaged in the development, production, transportation and
marketing of natural gas and oil in the Appalachian Basin. As of March 31, 1997,
the Company had estimated proved reserves of 172.9 Bcfe (95% natural gas and 90%
developed) with a Present Value (as defined in the Glossary) of $125.8 million.
For the fiscal year ended June 30, 1996, the Company's net gas and oil
production was approximately 13.0 Bcfe. The Company is one of the largest
operators in the Appalachian Basin where it holds interests in 4,755 gross
(2,503 net) wells, substantially all of which it operates. In addition, the
Company has recently commenced an exploration and development program in the
Rocky Mountains and New Zealand, having acquired leasehold interests in
approximately 431,000 gross acres (291,000 net acres) in the Rocky Mountain area
and approximately 5.2 million gross acres (2.6 million net acres) in New
Zealand.
The Company has developed a significant gas marketing and aggregation
business and owns and operates 2,000 miles of gathering and intrastate natural
gas pipelines in West Virginia and Pennsylvania. During fiscal 1996, the Company
aggregated and sold 150.0 Mmcf/day of natural gas, of which 41.1 Mmcf/day
represents gas produced from wells operated by the Company.
The Company has grown significantly since 1988 through acquisitions of oil
and gas companies or properties which have added proved reserves of
approximately 202.0 Bcfe, at an average acquisition cost of approximately $0.70
per Mcfe, and an interest in approximately 4,500 producing wells. In order to
capitalize on opportunities arising from the deregulation of the transportation
and distribution of natural gas, beginning in 1993 the Company broadened its
strategy from its traditional concentration on oil and gas exploration and
production to concentrate on building an integrated energy company focused on
controlling reserves and maximizing upstream and downstream values. As part of
its strategy, the Company acquired its natural gas distribution business in June
1995. During fiscal year 1996, approximately 25% of natural gas sold by the gas
distribution utility operation came from the Company's own production.
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BUSINESS STRENGTHS
The Company believes it has certain strengths with respect to its business
activities, including the following:
- LOW COST OPERATIONS. Based on recent filings with the West Virginia
Public Service Commission (the "WVPSC"), the Company's natural gas
distribution utility operations and maintenance expense was $0.55 per
throughput Mcf as compared to $1.53 per throughput Mcf for its largest
competitor. The low cost structure of the Company's utility operation has
enabled it to be the lowest price provider of natural gas to residential
and commercial customers in its service area while realizing a reasonable
rate of return. The Company's residential rate for gas service for 1996,
as reported by the WVPSC, was $6.25 per Mcf of gas compared to an average
of $7.01 per Mcf of gas for its major competitors in West Virginia. The
Company is also a low cost producer of oil and natural gas, with lifting
and operating costs of $0.57 per Mcfe in fiscal 1996.
- DIVERSIFIED CASH FLOW STREAMS. The Company generates cash flow from its
utility operation, gas marketing activities and development and
production activities. The cash flows from these activities tend to be
complimentary. The utility operation generally benefits from lower gas
prices while the development and production activities generally benefit
from higher gas and oil prices. The integration of these activities has
resulted in greater stability in the Company's cash flows.
- LEADING WEST VIRGINIA GAS DISTRIBUTION UTILITY. The Company operates the
largest natural gas distribution utility in West Virginia. The Company is
a leader in achieving innovative rate regulation in West Virginia, having
proposed and received in November 1995 a three year moratorium on rates
charged to its utility customers. The moratorium provides incentives to
the Company to increase efficiencies and pursue ancillary opportunities.
The Company believes that the opportunities afforded by the rate
moratorium will more than offset the additional risk resulting from fixed
utility rates.
- HIGHLY DEVELOPED RESERVE BASE WITH LONG RESERVE LIFE. Approximately 90%
of the Company's reserves are classified as proved developed producing
and have an estimated remaining average reserve life index in excess of
13 years. The Company's Appalachian Basin properties are characterized by
predictable and stable production profiles that decline gradually over
their estimated economic life of approximately 25 years. As a result of
the highly developed and long lived nature of its Appalachian Basin
properties and the relatively low cost to drill development wells on
these properties, the Company believes it has a low reinvestment
requirement to maintain reserve quantities and production levels.
- PREMIUM PRICING. The Company generally benefits from premium pricing for
its Appalachian Basin production due to the geographic proximity of its
reserves to the Northeast markets. In addition, the Company benefits from
a balance of long, intermediate and short term fixed price gas contracts.
- HIGH DEGREE OF OPERATIONAL CONTROL. Over 90% of the Company's proved
reserves at March 31, 1997 are attributable to wells operated by the
Company, giving the Company significant control over the amount and
timing of capital and operating expenditures.
- EXPERIENCED MANAGEMENT. The Company's management has substantial
operational expertise and experience in the gas distribution utility
industry and in the oil and gas industry, particularly with respect to
the Appalachian Basin. This experience provides a significant base upon
which to expand the Company's operations as cash flow and additional
capital become available for investment.
2
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BUSINESS STRATEGY
The Company seeks to maximize shareholder value and increase cash flow by
(i) balancing a portfolio of higher risk, higher reward opportunities with its
traditional moderate risk, moderate reward natural gas distribution utility and
Appalachian Basin oil and gas development and production activities, (ii)
increasing gas throughput volumes while reducing costs in its gas distribution
utility operation, (iii) increasing oil and gas reserves and production through
a managed risk exploration and development program and (iv) increasing gross
profit margin through vertical integration by implementing the following
operating strategies:
- MAINTAIN LOW COST STRUCTURE. The Company's management team is focused on
maintaining a low cost structure to maximize cash flow and earnings. As
part of this focus, the Company's strategy is to participate only in
businesses in which it believes it can be in the lowest quartile of
operating and administrative costs compared to its peers. The Company
believes that it has achieved operating efficiencies through the
economies of scale resulting from its geographic focus in the Appalachian
Basin and through the application of technology to its operating
activities. The Company believes that maintaining its low cost structure
makes it less sensitive to market fluctuations in the sales price of
natural gas and oil.
- VERTICAL INTEGRATION. The Company believes that the integration of its
utility operation, its extensive transportation and marketing system and
its stable, long-lived Appalachian Basin production allows it to capture
both downstream and upstream margins and to increase operating
flexibility. The Company expects to allocate its capital spending among
its utility, exploration and production and gas marketing businesses in
order to increase the vertical integration of its business.
- BALANCED DEVELOPMENT AND EXPLORATION PROGRAM. In the Appalachian Basin,
the Company has drilled 444 low risk development wells since 1987,
achieving a success rate of 95%. Recently, the Company began drilling in
Ohio's Rose Run Trend where 18 of 20 wells have been completed
successfully. Outside the Appalachian Basin, the Company seeks
exploration opportunities in which it can (i) add value through technical
expertise, (ii) accumulate large leasehold interests in areas which have
high quality reservoirs, and (iii) limit its initial capital requirements
due to low entry costs and relatively low drilling costs in relation to
reserve potential. After completing its technical evaluation of each
project, the Company seeks to enter into joint development arrangements
with industry partners in order to share initial exploration expenditures
and to limit exposure to dry hole costs. To accelerate its entry into the
Rocky Mountain region, the Company has established a joint venture with
Thomasson Partner Associates, Inc., a geological and geophysical firm
that specializes in generating exploration projects in that region
utilizing advanced technologies, including advanced imaging applications
of 3-D seismic data.
- SELECTIVE ACQUISITIONS. The Company seeks to pursue acquisitions that are
complimentary to its existing operations, that are expected to be
immediately additive to cash flow and earnings and that provide long term
growth opportunities. The Company focuses on acquisitions that are
located principally within the Company's operating areas and provide
opportunities to (i) expand its natural gas utility business, (ii) reduce
operating costs, (iii) increase reserves, (iv) enhance margins through
marketing opportunities, and (v) increase operating leverage.
3
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SUMMARY OF TERMS OF EXCHANGE OFFER
The Exchange Offer relates to the exchange of up to $200,000,000 aggregate
principal amount of Exchange Notes for up to an equal aggregate principal amount
of Old Notes. The Exchange Notes will be obligations of the Company entitled to
the benefits of the Indenture. The form and terms of the Exchange Notes are
identical in all material respects to the form and terms of the Old Notes,
except that (i) the offering of the Exchange Notes has been registered under the
Securities Act, (ii) the Exchange Notes will not be subject to transfer
restrictions and (iii) certain provisions relating to an increase in the stated
interest rate on the Old Notes provided for under certain circumstances will be
eliminated. See "Description of the Notes."
REGISTRATION RIGHTS
AGREEMENT................ The Old Notes were sold by the Company on May 23,
1997 to the Initial Purchasers pursuant to a
Purchase Agreement, dated May 20, 1997 (the
"Purchase Agreement"). Pursuant to the Purchase
Agreement, the Company and the Initial Purchasers
entered into a registration rights agreement which,
among other things, grants the holders of the Old
Notes certain exchange and registration rights (the
"Registration Rights Agreement"). The Exchange
Offer is intended to satisfy certain obligations of
the Company under the Registration Rights
Agreement.
THE EXCHANGE OFFER......... $1,000 principal amount of Exchange Notes will be
issued in exchange for each $1,000 principal amount
of Old Notes validly tendered and accepted pursuant
to the Exchange Offer. As of the date hereof,
$200,000,000 in aggregate principal amount of Old
Notes are outstanding. The Company will issue the
Exchange Notes to tendering holders of Old Notes
promptly following the Expiration Date.
The terms of the Exchange Notes are identical in
all material respects to the Old Notes except for
certain transfer restrictions and registration
rights relating to the Old Notes and except that
the Old Notes provide that if, by November 5, 1997,
(i) the Exchange Offer has not been consummated, or
(ii) a shelf registration statement relating to the
sale of the Old Notes has not been declared
effective, the Company will pay liquidated damages
in an amount equal to $0.192 per week per $1,000
principal amount of the Old Notes outstanding from
and including November 5, 1997 until but excluding
the date of the consummation of the Exchange Offer
or the date such shelf registration statement is
declared effective, as the case may be.
In addition, to comply with the securities laws of
certain states of the United States, it may be
necessary to qualify for sale or register
thereunder the Exchange Notes prior to offering or
selling such Exchange Notes. The Company has
agreed, pursuant to the Registration Rights
Agreement, subject to certain limitations specified
therein, to register or qualify the Exchange Notes
for offer or sale under the securities laws of such
states as any holder reasonably requests in
writing. Unless a holder so requests, the Company
does not intend to register or qualify the offer or
sale of the Exchange Notes in any such
jurisdiction.
RESALE..................... Based on existing interpretations of the Securities
Act by the staff of the SEC set forth in several
no-action letters to third parties,
4
<PAGE> 10
and subject to the immediately following sentence,
the Company believes that Exchange Notes issued
pursuant to the Exchange Offer in exchange for Old
Notes may be offered for resale, resold and
otherwise transferred by a holder thereof (other
than (i) a broker-dealer who purchased such Old
Notes directly from the Company for resale pursuant
to Rule 144A or any other available exemption under
the Securities Act or (ii) a person that is an
"affiliate" (within the meaning of Rule 405 of the
Securities Act) of the Company), without compliance
with the registration and prospectus delivery
provisions of the Securities Act, provided that the
holder is acquiring the Exchange Notes in its
ordinary course of business and is not
participating, and has no arrangement or
understanding with any person to participate, in
the distribution of the Exchange Notes. However,
any purchaser of Notes who is an affiliate of the
Company or who intends to participate in the
Exchange Offer for the purpose of distributing the
Exchange Notes, or any broker-dealer who purchased
the Old Notes from the Company to resell pursuant
to Rule 144A or any other available exemption under
the Securities Act, (i) will not be able to rely on
the interpretations by the staff of the SEC set
forth in the above-mentioned no-action letters,
(ii) will not be able to tender its Old Notes in
the Exchange Offer and (iii) must comply with the
registration and prospectus delivery requirements
of the Securities Act in connection with any sale
or transfer of the Notes unless such sale or
transfer is made pursuant to an exemption from such
requirements. The Company does not intend to seek
its own no-action letter and there is no assurance
that the staff of the SEC would make a similar
determination with respect to the Exchange Notes as
it has in such no-action letters to third parties.
See "The Exchange Offer -- Purpose and Effect of
the Exchange Offer" and "Plan of Distribution."
Each broker-dealer that receives Exchange Notes for
its own account pursuant to the Exchange Offer must
acknowledge that it will deliver a prospectus in
connection with any resale of such Exchange Notes.
The Letter of Transmittal states that by so
acknowledging and by delivering a prospectus, a
broker-dealer will not be deemed to admit that it
is an "underwriter" within the meaning of the
Securities Act. This Prospectus, as it may be
amended or supplemented from time to time, may be
used by a broker-dealer in connection with resales
of Exchange Notes received in connection with
resales of Exchange Notes received in exchange for
Old Notes where such Old Notes were acquired by
such broker-dealer as a result of market-making
activities or other trading activities. The Company
has agreed that, for a period of 180 days after the
Expiration Date, it will make this Prospectus
available to any broker-dealer for use in
connection with any such resale. See "Plan of
Distribution."
EXPIRATION DATE............ 5:00 p.m., New York City time, on August , 1997,
unless the Exchange Offer is extended, in which
case the term "Expiration Date" means the latest
date and time to which the Exchange Offer is
extended. See "The Exchange Offer -- Expiration
Date; Extensions; Amendments."
5
<PAGE> 11
ACCRUED INTEREST ON THE
EXCHANGE NOTES AND THE
OLD NOTES................ The Exchange Notes will bear interest at a rate of
9 1/2% per annum, payable semi-annually on May 15
and November 15 of each year, commencing November
15, 1997. Holders of Exchange Notes of record on
November 1, 1997, will receive on November 15,
1997, an interest payment in an amount equal to (x)
the accrued interest on such Exchange Notes from
the date of issuance thereof to November 15, 1997,
plus (y) the accrued interest on the previously
held Old Notes from the date of issuance of such
Old Notes (May 23, 1997) to the date of exchange
thereof. Interest will not be paid on Old Notes
that are accepted for exchange. The Notes mature on
May 15, 2007.
CONDITIONS TO THE EXCHANGE
OFFER.................... The Company may terminate the Exchange Offer if it
determines that its ability to proceed with the
Exchange Offer could be materially impaired due to
the occurrence of certain conditions. The Company
does not expect any of such conditions to occur,
although there can be no assurance that such
conditions will not occur. Holders of Old Notes
will have certain rights under the Registration
Rights Agreement should the Company fail to
consummate the Exchange Offer. See "The Exchange
Offer -- Conditions to the Exchange Offer" and
"Description of the Notes -- Registered Exchange
Offer; Registration Rights."
PROCEDURES FOR TENDERING
OLD NOTES.................. Each holder of Old Notes wishing to accept the
Exchange Offer must complete, sign and date the
Letter of Transmittal, or a facsimile thereof, in
accordance with the instructions contained herein
and therein, and mail or otherwise deliver such
Letter of Transmittal, or such facsimile, together
with the Old Notes to be exchanged and any other
required documentation, to The Bank of New York, as
Exchange Agent, at the address set forth herein and
therein or effect a tender of Old Notes pursuant to
the procedures for book-entry transfer as provided
for herein and therein. By executing the Letter of
Transmittal, each holder will represent to the
Company that, among other things, the Exchange
Notes acquired pursuant to the Exchange Offer are
being acquired in the ordinary course of business
of the person receiving such Exchange Notes,
whether or not such person is the holder, that
neither the holder nor any such other person has
any arrangement or understanding with any person to
participate in the distribution of such Exchange
Notes and that neither the holder nor any such
other person is an "affiliate," as defined in Rule
405 under the Securities Act, of the Company. See
"The Exchange Offer -- Procedures for Tendering."
Following consummation of the Exchange Offer,
holders of Old Notes not tendered as a general
matter will not have any further registration
rights, and the Old Notes will continue to be
subject to certain restrictions on transfer.
Accordingly, the liquidity of the market for the
Old Notes could be adversely affected. see "The
Exchange Offer -- Consequences of Failure to
Exchange."
6
<PAGE> 12
SPECIAL PROCEDURES FOR
BENEFICIAL OWNERS........ Any beneficial owner whose Old Notes are registered
in the name of a broker, dealer, commercial bank,
trust company or other nominee and who wishes to
tender in the Exchange Offer should contact such
registered holder promptly and instruct such
registered holder to tender on his behalf. If such
beneficial owner wishes to tender on his own
behalf, such beneficial owner must, prior to
completing and executing the Letter of Transmittal
and delivering his Old Notes, either (a) make
appropriate arrangements to register ownership of
the Old Notes in such holder's name or (b) obtain a
properly completed bond power from the registered
holder or endorsed certificates representing the
Old Notes to be tendered. The transfer of record
ownership may take considerable time, and
completion of such transfer prior to the Expiration
Date may not be possible. See "The Exchange
Offer -- Procedures for Tendering."
GUARANTEED DELIVERY
PROCEDURES............... Holders of Old Notes who wish to tender their Old
Notes and whose Old Notes are not immediately
available, or who cannot deliver their Old Notes
(or complete the procedure for book-entry transfer)
and deliver a properly completed Letter of
Transmittal and any other documents required by the
Letter of Transmittal to the Exchange Agent prior
to the Expiration Date may tender their Old Notes
according to the guaranteed delivery procedures set
forth in "The Exchange Offer -- Guaranteed Delivery
Procedures."
WITHDRAWAL RIGHTS.......... Tenders of Old Notes may be withdrawn at any time
prior to the Expiration Date by furnishing a
written or facsimile transmission notice of
withdrawal to the Exchange Agent containing the
information set forth in "The Exchange
Offer -- Withdrawal of Tenders."
ACCEPTANCE OF OLD NOTES AND
DELIVERY OF EXCHANGE
NOTES.................... Subject to certain conditions (as summarized above
in "Termination of the Exchange Offer" and
described more fully in "The Exchange
Offer -- Termination"), the Company will accept for
exchange any and all Old Notes that are properly
tendered in the Exchange Offer prior to the
Expiration Date. See "The Exchange
Offer -- Procedures for Tendering." The Exchange
Notes issued pursuant to the Exchange Offer will be
delivered promptly following the Expiration Date.
EXCHANGE AGENT............. The Bank of New York, the Trustee under the
Indenture, is serving as exchange agent (the
"Exchange Agent") in connection with the Exchange
Offer. The mailing and hand delivery address of the
Exchange Agent is The Bank of New York,
Reorganization Section, 101 Barclay Street -- 7E,
New York, New York 10286 Attention: Walter Gitlin.
For assistance and request for additional copies of
this Prospectus, the Letter of Transmittal or the
Notice of Guaranteed Delivery, the telephone number
for the Exchange Agent is (212) 815-3687, and the
facsimile number for the Ex-
7
<PAGE> 13
change Agent is (212) 571-3080. All communications
should be directed to the attention of Walter
Gitlin.
EFFECT ON HOLDERS OF OLD
NOTES.................... Holders of Old Notes who do not tender their Old
Notes in the exchange offer will continue to hold
their Old Notes and will be entitled to all the
rights and limitations applicable thereto under the
Indenture. All untendered, and tendered but
unaccepted, Old Notes will continue to be subject
to the restrictions on transfer provided for in the
Old Notes and the Indenture. To the extent that Old
Notes are tendered and accepted in the Exchange
Offer, the trading market, if any, for the Old
Notes could be adversely affected. See "Risk
Factors -- Consequences of Exchange and Failure to
Exchange."
See "The Exchange Offer" for more detailed information concerning the terms of
the Exchange Offer.
8
<PAGE> 14
SUMMARY OF TERMS OF EXCHANGE NOTES
ISSUER..................... Energy Corporation of America.
THE NOTES.................. $200.0 million aggregate principal amount of 9 1/2%
Senior Subordinated Notes due 2007, Series A.
MATURITY................... May 15, 2007.
INTEREST PAYMENT DATES..... May 15 and of November 15 each year, commencing on
November 15, 1997.
MANDATORY REDEMPTION....... None.
OPTIONAL REDEMPTION........ Except as otherwise described below, the Exchange
Notes will not be redeemable at the Company's
option prior to May 15, 2002. Thereafter, the
Exchange Notes will be subject to redemption at the
option of the Company, in whole or in part, at the
redemption prices set forth herein, plus accrued
and unpaid interest thereon to the applicable
redemption date. In addition, prior to May 15, 2000
the Company may, at its option, on any one or more
occasions, redeem up to 33 1/3% of the original
principal amount of the Notes at a redemption price
equal to 109.50% of the principal amount thereof,
plus accrued and unpaid interest, if any, to the
redemption date with all or a portion of the net
proceeds of public sales of Common Stock of the
Company; provided that at least 66 2/3% of the
original aggregate principal amount of the Notes
remains outstanding immediately after the
occurrence of such redemption. See "Description of
the Notes -- Optional Redemption."
CHANGE OF CONTROL.......... Upon the occurrence of a Change of Control (as
defined in "Description of the Notes -- Certain
Definitions"), the Company will generally be
required to offer to repurchase all or a portion of
each holder's Exchange Notes, at an offer price in
cash equal to 101% of the aggregate principal
amount of such Exchange Notes, plus accrued and
unpaid interest, if any, to the date of repurchase,
and to repurchase all Exchange Notes tendered
pursuant to such offer. Concurrently with the
closing of the Offering, the Company entered into a
Credit Agreement (the "Credit Agreement") with
General Electric Capital Corporation providing for
a revolving credit facility in the aggregate
principal amount of $50.0 million (the "Revolving
Credit Facility"). The Credit Agreement prohibits
the Company from repurchasing any Exchange Notes
pursuant to a Change of Control offer prior to the
repayment in full of the Senior Debt under the
Credit Agreement. Therefore, if a Change of Control
were to occur, there can be no assurance that the
Company will have the financial resources to
repurchase the Exchange Notes. See "Risk
Factors -- Risks Relating to a Change of Control"
and "Description of the Notes -- Repurchase at the
Option of holders -- Change of Control."
RANKING.................... The Exchange Notes will be unsecured obligations of
the Company and will be (i) subordinated in right
of payment to all existing and future Senior Debt
of the Company, which will include borrowings under
the Credit Agreement, (ii) pari passu in right of
9
<PAGE> 15
payment with all Pari Passu Debt of the Company and
(iii) senior in right of payment to all other
subordinated indebtedness of the Company. The
Exchange Notes will be effectively subordinated in
right of payment to the liabilities of the
subsidiaries of the Company (including trade
obligations). As of March 31, 1997, on a pro forma
basis after giving effect to the Offering and the
application of the proceeds therefrom, (i) the
Company would not have had any Senior Debt
outstanding, (ii) the Company would not have had
any Pari Passu Debt outstanding and (iii) the
aggregate principal amount of indebtedness
outstanding of the subsidiaries of the Company
would have been $86.6 million. The Exchange Notes
will also be effectively subordinated to all
secured indebtedness of the Company and its
subsidiaries. See "Capitalization," "Description of
the Notes -- Subordination" and "Description of
Other Indebtedness."
CERTAIN COVENANTS.......... The Exchange Notes will be issued pursuant to the
Indenture which contains certain covenants that
will, among other things, limit the ability of the
Company and its Restricted Subsidiaries (as defined
in "Description of the Notes -- Certain
Definitions") to incur additional indebtedness and
issue Disqualified Stock (as defined in
"Description of the Notes -- Certain Definitions"),
pay dividends, make distributions, make
investments, make certain other Restricted Payments
(as defined in "Description of the Notes -- Certain
Definitions"), enter into certain transactions with
affiliates, dispose of certain assets, incur liens
securing Indebtedness (as defined in "Description
of the Notes -- Certain Definitions") of any kind
other than Permitted Liens (as defined in
"Description of the Notes -- Certain Definitions")
and engage in mergers and consolidations. See
"Description of the Notes -- Certain Covenants."
RISK FACTORS
See "Risk Factors" for a discussion of certain factors that should be
considered in connection with an investment in the Notes offered hereby,
including information regarding the Company's highly leveraged capital
structure, the uncertainty of oil and gas prices and certain other risks
associated with an investment in the Notes offered hereby.
PRINCIPAL EXECUTIVE OFFICES
The Company's principal executive offices are located at 4643 South Ulster
Street, Suite 1100, Denver, Colorado 80237 and its phone number is (303)
694-2667. The Company is a West Virginia corporation originally incorporated in
Colorado in 1992.
10
<PAGE> 16
SUMMARY FINANCIAL INFORMATION
The following tables present summary historical and pro forma financial
data, reserve data and operating data for the Company. The summary historical
financial information for each year in the three year period ended June 30, 1996
and for the nine months ended March 31, 1997 and as of the respective period end
have been derived from the consolidated financial statements of the Company. The
consolidated financial statements as of March 31, 1997 and June 30, 1996 and for
the nine-month period ended March 31, 1997 and the years ended June 30, 1996 and
1995 are included elsewhere herein together with the report of Deloitte & Touche
LLP, independent auditors. The summary historical data for the nine months ended
March 31, 1996 have been derived from the Company's consolidated financial
statements which have not been audited, but reflect, in the opinion of
management, all adjustments which include only normal recurring adjustments
necessary to present fairly the information contained herein. Interim results
are not necessarily indicative of results to be expected for any fiscal year.
This information should be read in conjunction with "Capitalization",
"Management's Discussion and Analysis of Financial Condition and Results of
Operations" and the consolidated financial statements of the Company, including
the notes thereto, included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED JUNE 30, MARCH 31,
-------------------------------- -----------------------
1994 1995 1996 1996 1997
-------- -------- -------- ----------- --------
(DOLLARS IN THOUSANDS, EXCEPT RATIOS)
<S> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(1)(2):
Revenues:
Oil and gas sales................................ $ 30,545 $ 29,277 $ 31,940 $ 23,861 $ 27,002
Utility gas sales and transportation............. 182,929 157,320 146,965
Gas marketing and pipeline sales................. 59,563 103,015 146,398 101,961 120,257
Well operations and service...................... 5,134 3,955 14,003 10,562 10,700
Other revenue(3)................................. 547 9,247 524 414 229
-------- -------- -------- -------- --------
Total revenue.............................. 95,789 145,494 375,794 294,118 305,153
-------- -------- -------- -------- --------
Costs and expenses:
Field operating.................................. 11,657 11,510 21,796 16,325 15,162
Utility operations and maintenance............... 23,841 17,849 15,480
Utility gas purchased(4)......................... 95,157 75,927 85,705
Gas marketing and pipeline costs................. 54,978 100,251 138,067 94,320 112,913
Taxes, other than income......................... 1,250 1,560 16,165 13,706 15,039
General and administrative....................... 6,271 6,689 23,967 17,380 16,479
Depreciation, depletion and amortization......... 8,308 12,041 18,817 15,113 14,980
Interest expense................................. 7,501 8,744 23,182 18,164 17,005
Exploration and impairment costs................. 1,681 281 6,756 2,637 3,613
-------- -------- -------- -------- --------
Total costs and expenses......................... 91,646 141,076 367,748 271,421 296,376
-------- -------- -------- -------- --------
Operating income........................... 4,143 4,418 8,046 22,697 8,777
Other (income) and expenses (including taxes)...... 2,299 3,233 226 4,856 (3,458)
-------- -------- -------- -------- --------
Net income................................. $ 1,844 $ 1,185 $ 7,820 $ 17,841 $ 12,235
======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(5)........................................ $ 21,633 $ 25,484 $ 56,801 $ 58,611 $ 44,375
Adjusted EBITDA(6)............................... 21,633 25,484 41,432 45,303 32,110
Net cash provided by operating activities........ 7,466 14,020 17,094 8,107 6,699
Net cash used in investing activities............ (40,878) (92,440) (22,823) (12,154) (9,551)
Net cash provided by/(used in) financing
activities..................................... 21,884 90,631 (198) (3,664) 2,986
Pro forma interest expense(7).................... N/A N/A 23,554 N/A 17,666
Pro forma adjusted interest expense(8)........... N/A N/A 19,000 N/A 14,250
Capital expenditures(9).......................... 23,679 93,226 39,445 31,576 21,555
Ratios:
EBITDA to interest expense..................... 2.88x 2.91x 2.45x 3.23x 2.61x
EBITDA to pro forma interest expense........... N/A N/A 2.41x N/A 2.51x
Earnings to fixed charges(10).................. .84x 1.35x 1.44x 2.34x 1.98x
Total long-term debt to EBITDA(11)(12)......... 5.20x 10.50x 4.66x N/A N/A
Adjusted EBITDA to adjusted pro forma interest
expense(6)(8)................................ N/A N/A 2.18 N/A 2.25
BALANCE SHEET DATA (at end of period)(13)(14):
Cash and cash equivalents.......................... $ 7,913 $ 20,124 $ 14,197 $ 12,412 $ 14,331
Total assets....................................... $222,491 $471,497 $461,504 $506,967 $454,446
Long-term debt(11)................................. $112,430 $267,647 $264,698 $259,391 $231,808
Stockholders' equity............................... $ 31,241 $ 31,613 $ 37,550 $ 48,496 $ 47,905
</TABLE>
See Notes to Summary Financial Information
11
<PAGE> 17
NOTES TO SUMMARY FINANCIAL INFORMATION
(1) The fiscal year ended June 30, 1996 includes $8.3 million of revenues, $3.2
million of EBITDA and $0.9 million of net income attributable to the
Company's interest in certain producing properties which were sold in March
1997.
(2) The Company acquired its natural gas distribution operation in June 1995
and, accordingly, the fiscal year ended June 30, 1996 was the first fiscal
year that the operating results of the natural gas distribution operation
were included in the Company's consolidated operations.
(3) For the year ended June 30, 1995, other revenue includes an $8.8 million
contract settlement with Columbia Gas Transmission Corporation and The
Columbia Gas Systems, Inc. (collectively, "Columbia Gas"). The settlement
relates to damages paid by Columbia Gas as a result of its rejection in
bankruptcy of certain gas purchase contracts.
(4) For the nine months ended March 31, 1997, utility gas purchased includes a
$6.0 million adjustment for refunds due a subsidiary of the Company from
Columbia Gas relating to a settlement approved by the Federal Energy
Regulatory Commission on April 17, 1997. In addition, the Company will
benefit in future periods from the lower rates established in such
settlement.
(5) EBITDA represents operating income of the Company and its subsidiaries on a
consolidated basis plus exploration and impairment expense, interest
expense, depletion, depreciation, and amortization expense. Such definition
of EBITDA may not be the same as the definition of EBITDA utilized by
comparable companies. EBITDA is not presented as an indicator of the
Company's operating performance or as a measure of liquidity calculated in
accordance with generally accepted accounting principles.
(6) Adjusted EBITDA represents EBITDA as adjusted to give effect to contractual
restrictions contained in note purchase agreements to which certain
subsidiaries of the Company were parties prior to the Offering that limit
the amount of cash dividends that may be paid by such subsidiaries to the
Company. All such note purchase agreements were terminated after the
Offering except that to which Mountaineer is a party. See "Description of
Other Indebtedness -- Indebtedness of Subsidiaries -- Mountaineer."
(7) Reflects interest expense pro forma for the Offering as if it had occurred
at the beginning of fiscal 1996. It also excludes interest expense
attributable to the interests in certain oil and gas properties sold in
March 1997.
(8) Reflects interest expense pro forma for the Offering less annual interest
expense of $4.6 million associated with debt at certain of the Company's
subsidiaries referred to in footnote (6) above.
(9) Capital expenditures for 1995 includes $73.2 million for the acquisition of
the Company's natural gas distribution utility and related properties.
(10) For the purposes of determining the ratio of earnings to fixed charges,
earnings are defined as income before taxes plus fixed charges. Fixed
charges consist of interest expense. Earnings were $1.3 million short of an
earnings to fixed charges ratio of 1.0 to 1.0.
(11) Long-term debt (i) includes current maturities of long-term debt and (ii)
excludes short-term borrowing under lines of credit.
(12) On a pro forma basis after giving effect to the Offering and the
application of the net proceeds therefrom, the ratio of total long-term
debt to EBITDA would have been 4.58x in fiscal 1996.
(13) As of March 31, 1997, after giving pro forma effect to the Offering and the
application of the net proceeds therefrom, the amount of cash and cash
equivalents would have been $28.2 million and the amount of long-term debt
would have been $260.2 million.
(14) The Company acquired its natural gas distribution operation in June 1995
and, accordingly, the balance sheet of the Company at June 30, 1995
includes the assets and liabilities of this operation as of such date.
12
<PAGE> 18
SUMMARY RESERVE AND OPERATING DATA
(DOLLARS IN THOUSANDS, EXCEPT PER UNIT AMOUNTS)
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED JUNE 30, MARCH 31,
------------------------------ -------------------
1994 1995 1996 1996 1997
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
GAS DISTRIBUTION UTILITY DATA:
Gas distribution revenues.................................. $165,551 $156,754 $182,929 $157,320 $146,965
Gas volumes distributed (Mmcf)............................. 61,485 59,738 65,194 53,112 50,367
Average sales price per Mcf................................ 5.99 6.65 6.40 6.31 6.33
Average purchase price per Mcf sold........................ 3.89 4.38 3.46 3.13 3.90
Average transportation rate per Mcf........................ 0.33 0.29 0.19 0.16 0.27
Miles of distribution pipe................................. 3,819 3,853 3,887 3,871 3,912
Number of customers........................................ 198,392 198,293 199,287 199,201 199,901
EXPLORATION AND PRODUCTION:
Proved reserves (at end of period)(1)(2):
Natural gas equivalents (Mmcfe).......................... 212,335 213,946 199,453 204,952 172,925
Percent natural gas...................................... 80% 80% 80% 80% 95%
Percent proved developed................................. 96% 98% 97% 98% 90%
Production volumes:
Natural gas equivalents (Mmcfe).......................... 11,527 12,190 12,950 9,739 9,664
Reserve life index (years)(3).............................. 18.4 17.6 15.4 15.8 13.5
Future net cash flows(2):
Undiscounted............................................. $400,073 $274,651 $304,237 $251,936 $333,273
Present value............................................ 162,036 127,886 130,778 107,947 125,843
Reserve Report Prices (at period end)(4):
Natural gas (per Mcf).................................... $ 2.84 $ 2.06 $ 2.40 $ 2.40 $ 2.41
Oil and NGLs (per Bbl)................................... $ 14.02 $ 15.32 $ 13.83 $ 13.83 $ 16.24
Reserve additions (Mmcfe):
Acquisitions............................................. 16,357 29,349 7,500 7,500 0
Sales of reserves in place............................... 0 0 (19,700) 0 (34,697)
Extensions, discoveries and other additions.............. 9,965 10,754 5,950 1,106 22,683
Revisions................................................ 1,091 (26,300) 4,715 0 (4,856)
-------- -------- -------- -------- --------
Net additions.......................................... 27,413 13,803 (1,535) 8,606 (16,870)
Costs Incurred:
Acquisitions............................................. $ 4,925 $ 14,190 $ 4,318 $ 4,318 $ 0
Development and exploration.............................. 8,308 12,139 14,997 12,995 10,601
Direct finding costs (per Mcfe)(5)......................... $ 0.50 $ 0.66 $ 1.44 $ 2.01 $ .47
Reserve replacement(6)..................................... 238% 113% 140% 88% 184%
Per Mcfe Data:
Oil and gas sales(7)..................................... $ 2.33 $ 2.10 $ 2.18 $ 2.17 $ 2.42
Lifting and operating expense(8)......................... .54 .58 .57 .56 .44
Production taxes......................................... .10 .12 .10 .13 .14
-------- -------- -------- -------- --------
Operating margin......................................... $ 1.69 $ 1.40 $ 1.51 $ 1.48 $ 1.84
======== ======== ======== ======== ========
GAS MARKETING:
Volume of marketed gas(Bcf)(9)............................. 35.7 52.0 53.0 38.2 41.2
Gross gas marketing and pipeline margin.................... $ 4,585 $ 2,764 $ 8,331 $ 7,641 $ 7,344
</TABLE>
- ---------------
(1) The reduction in reserves and production at and for the fiscal year ended
June 30, 1996 as compared to the fiscal year ended June 30, 1995 are
primarily attributable to the sale of certain oil and gas properties located
in West Virginia and Pennsylvania with proved reserves of 19.7 Bcf at the
time of the sale. The reduction in reserves and production for the nine
months ended March 31, 1997 as compared to the prior nine month period is
attributable to the sale of certain oil and gas properties in California
with proved reserves of approximately 34.7 Bcfe at the time of the sale.
(2) Proved reserves and future net cash flows were estimated at the end of the
period presented in accordance with the Commission's guidelines. Prices and
costs at June 30 for each of the years 1994 through 1997 were used in the
estimates of proved reserves and future net cash flows and were held
constant through the periods of estimated production, except as otherwise
provided by contract, in accordance with the Commission's guidelines. The
present value of future net cash flows was determined by applying a discount
factor of 10% in accordance with the Commission's guidelines.
(3) The reserve life index is calculated as proved reserves divided by annual
production (on an Mcfe basis).
(4) Reflects average prices at period end utilized for purposes of estimating
proved reserves and future net cash flows in accordance with the
Commission's guidelines.
(5) Direct Finding Costs are calculated as costs incurred for reserve additions
through acquisitions and development and exploration divided by reserve
additions.
(6) Reserve replacement is calculated as net reserve additions divided by the
Company's actual production for the period, both on an Mcfe basis. Data
excludes the effects of sales of reserves in place in certain of the periods
presented. See footnote (1) above and "Business and
Properties -- Significant Acquisitions and Dispositions."
(7) Oil and gas sales are based on actual sales for the period and exclude any
deferred revenues attributable to the Royalty Trust transaction or any
arrangement by which the Company presold gas and oil.
(8) Net of well operation and service revenues.
(9) Excludes volumes associated with gas gathering and gas processing
activities.
13
<PAGE> 19
RISK FACTORS
Prior to making an investment decision, prospective investors should
carefully consider, together with the other information contained in this
Prospectus, the following risk factors.
CONSEQUENCES OF EXCHANGE AND FAILURE TO EXCHANGE
Holders of Old Notes who do not exchange their Old Notes for Exchange Notes
pursuant to the Exchange Offer will continue to be subject to the restrictions
on transfer of such Old Notes as set forth in the legend thereon as a
consequence of the issuance of the Old Notes pursuant to exemptions from, or in
transactions not subject to, the registration requirements of the Securities Act
and applicable state securities laws. In general, the Old Notes may not be
offered or sold, unless registered under the Securities Act, except pursuant to
an exemption from, or in a transaction not subject to, the Securities Act and
applicable state securities laws. The Company does not currently anticipate that
it will register the Old Notes under the Securities Act. In addition, upon the
consummation of the Exchange Offer holders of Old Notes which remain outstanding
will not be entitled to any rights to have such Old Notes registered under the
Securities Act or to any similar rights under the Registration Rights Agreement,
subject to certain exceptions. To the extent that Old Notes are tendered and
accepted in the Exchange Offer, a holder's ability to sell untendered, or
tendered but unaccepted, Old Notes could be adversely affected. The Old Notes
provide that if, by November 5, 1997, (i) the Exchange Offer has not been
consummated, or (ii) a shelf registration statement relating to the sale of the
Old Notes has not been declared effective, the Company will pay liquidated
damages in an amount equal to $0.192 per week per $1,000 principal amount of the
Old Notes outstanding from and including November 5, 1997 until but excluding
the date on which the Exchange Offer is consummated or such shelf registration
statement is declared effective.
EFFECTS OF LEVERAGE
The Company is highly leveraged. On a pro forma basis giving effect to the
Offering and borrowings incurred under the Credit Agreement concurrently with
the closing of the Offering, at March 31, 1997 the Company's outstanding
long-term indebtedness would have been $260.2 million. The Company's level of
indebtedness will have several important effects on its future operations,
including (i) a substantial portion of the Company's cash flow from operations
must be dedicated to the payment of interest on its indebtedness and will not be
available for other purposes, (ii) covenants contained in the Company's debt
obligations will require the Company to meet certain financial tests, and other
restrictions will limit its ability to borrow additional funds or to dispose of
assets and may affect the Company's flexibility in planning for, and reacting
to, changes in its businesses, including possible acquisition activities and
(iii) the Company's ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate purposes
or other purposes may be impaired. The Company's ability to meet its debt
service obligations and to reduce its total indebtedness will be dependent upon
the Company's future performance, which will be subject to natural gas prices
and other factors affecting the operations of the Company, many of which are
beyond its control. There can be no assurance that the Company's future
performance will not be adversely affected by some or all of these factors.
HOLDING COMPANY STRUCTURE
The Company conducts all of its operations through subsidiaries.
Accordingly, the Company relies on dividends and cash advances from its
subsidiaries to provide funds necessary to meet its obligations, including the
payment of principal and interest on the Notes. The ability of any such
subsidiary to pay dividends or make cash advances is subject to applicable laws
and contractual restrictions, including restrictions under credit agreements
between such subsidiary and third party lenders, as well as the financial
condition and operating requirements of such subsidiary. One of the Company's
subsidiaries, Mountaineer Gas Company ("Mountaineer"), a direct subsidiary of
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Eastern Systems Corporation ("ESC"), is a party to a note purchase agreement
relating to its 7.59% Senior Notes due October 1, 2010, which note purchase
agreement prohibits Mountaineer from making any restricted payment unless, after
giving effect to the payment, (i) no default has occurred, (ii) Mountaineer
would be permitted to incur $1.00 of additional funded indebtedness under such
note purchase agreement and (iii) the aggregate amount of all restricted
payments made by Mountaineer and its restricted subsidiaries since the date of
the issuance of such notes on October 12, 1995 does not exceed $8.0 million plus
90% of the cumulative consolidated net income of Mountaineer from the date of
the issuance of such Notes. As of March 31, 1997, the aggregate amount of all
restricted payments made by Mountaineer and its restricted subsidiaries since
the date of the issuance of such Notes was $8.3 million, and such note purchase
agreement would have permitted Mountaineer to make additional restricted
payments of $23.7 million through March 31, 1997. In addition to the 7.59%
Senior Notes, Mountaineer is a party to three credit facilities which contain
restrictive covenants which are substantially similar to those contained in
Mountaineer's 7.59% Senior Notes. See "Description of Other Indebtedness."
SUBORDINATION OF NOTES
The Notes are unsecured obligations of the Company and are subordinated in
right of payment to all existing and future Senior Debt of the Company, which
will include borrowings under the Credit Agreement. The Notes rank pari passu in
right of payment with all other existing and future Pari Passu Debt of the
Company. The Notes rank senior to other indebtedness of the Company that
expressly provides that it is subordinated in right of payment of the Notes. The
Notes are effectively subordinated in right of payment to the liabilities of the
subsidiaries of the Company (including claims of trade creditors and tort
claimants). In the event of bankruptcy, liquidation or reorganization of the
Company, the assets of the Company will be available to pay obligations on the
Notes only after all Senior Debt has been paid in full, and there may not be
sufficient assets remaining to pay amounts due on any or all of the Notes
outstanding. As of March 31, 1997, on a pro forma basis giving effect to the
Offering and the application of the net proceeds therefrom, (i) the Company
would not have had any outstanding Senior Debt, (ii) the Company would not have
had any outstanding Pari Passu Debt, (iii) the aggregate principal amount of
indebtedness outstanding of the subsidiaries of the Company would have been
$86.6 million and (iv) such subsidiaries would have had $46.4 million of
additional borrowing availability under existing revolving lines of credit.
Additional Senior Debt may be incurred by the Company and its subsidiaries from
time to time, subject to certain restrictions. In addition to being subordinated
to all existing and future Senior Debt of the Company, the Notes will be
effectively subordinated to all secured debt of the Company and its
subsidiaries. The Company's obligations under the Credit Agreement will be
secured by a mortgage on substantially all of the oil and gas properties of
Eastern American Energy Corporation ("Eastern American"), the subsidiary of the
Company that owns and operates substantially all of the Company's oil and gas
properties in the Appalachian Basin. See "Description of the Notes -- Ranking
and Subordination" and "Description of Other Indebtedness."
CAPITAL AVAILABILITY
The Company's ability to conduct exploration and development activities and
to make acquisitions is dependent in large part upon its ability to obtain
financing for such activities. The Company expects to utilize borrowings under
the Credit Agreement, along with cash from operations, to fund these activities.
If funds under the Credit Agreement are not available to fund these activities,
the Company may seek to obtain financing for these activities from the sale of
equity securities or other debt financing. There can be no assurance that any
such other financing would be available on terms acceptable to the Company.
Should sufficient capital not be available, the Company may not be able to
continue to implement its strategy. See "Description of Other Indebtedness."
If oil or gas prices decline below their current levels, the availability
of funds and the ability to pay outstanding amounts under the Credit Agreement
could be materially adversely affected. The
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Indenture for the Notes also contains restrictions on the Company's ability to
incur additional indebtedness, and other contractual arrangements to which the
Company may become subject in the future could contain similar restrictions. In
addition, credit agreements relating to certain of the Company's subsidiaries
currently restrict the ability of such subsidiaries to incur indebtedness and to
guarantee the payment of indebtedness of the Company. The Company's subsidiaries
could also become subject in the future to other contractual restrictions that
contain similar restrictions. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources."
VOLATILITY OF OIL AND GAS PRICES
The Company's financial condition, operating results and future growth and
the carrying value of its oil and gas properties are substantially dependent on
prevailing prices of, and demand for, oil and gas. The Company's ability to
maintain or increase its borrowing capacity and to obtain additional capital on
attractive terms is also substantially dependent upon oil and gas prices.
Historically the markets for oil and gas have been volatile and are likely to
continue to be volatile in the future. Prices for oil and gas are subject to
large fluctuations in response to relatively minor changes in the supply of and
demand for oil and gas, market uncertainty and a variety of additional factors
beyond the control of the Company. These factors include weather conditions in
the United States and elsewhere, the economic conditions in the United States
and elsewhere, the actions of the Organization of Petroleum Exporting Countries
("OPEC"), governmental regulation, political stability in the Middle East and
elsewhere, the supply and demand of oil and gas, the price of foreign imports
and the availability and prices of alternate fuel sources. Any substantial and
extended decline in the price of oil or gas would have an adverse effect on the
Company's carrying value of its proved reserves, borrowing capacity, the
Company's ability to obtain additional capital, and its financial condition,
revenues, profitability and cash flows from operations.
Volatile oil and gas prices make it difficult to estimate the value of oil
and gas properties for acquisition and often cause disruption in the market for
oil and gas properties, as buyers and sellers have difficulty agreeing on such
value. Price volatility also makes it difficult to budget for and project the
return on exploration and development projects and potential acquisitions of oil
and gas properties.
SEASONALITY
More than 95% of the natural gas distribution utility's residential and
commercial customers use natural gas for heating purposes. Accordingly, a
significant portion of the Company's utility gas volumes are attributable to
sales during the six month winter heating season, with highest sales volumes
occurring in December, January and February. In fiscal 1996, gas sales from
October through March accounted for approximately 83% of utility gas sales for
that year. In addition, temperatures experienced in the Company's areas of
operations, as well as in other markets in which its production is sold,
significantly impact both the demand for and the prices at which the Company is
able to sell its production. Because a substantial portion of the Company's
revenues are generated by sales of gas used for heating and because weather
conditions also significantly affect prices realized on production sold, the
temperatures experienced in the Company's areas of operations, particularly
during the peak heating season, will have a significant effect on the Company's
financial performance. See "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
UTILITY RATE REGULATION
The Company operates a natural gas distribution utility that is regulated
by the West Virginia Public Service Commission (the "WVPSC"). Under traditional
rate making in West Virginia, the Company's natural gas distribution utility is
prohibited from increasing its base rate unless it obtains
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the approval of the WVPSC. In general, the WVPSC reviews any base rate increase
based upon an analysis of the cost of service, as adjusted for known and
measurable changes in expenses and revenues, and a reasonable return on equity.
In determining the overall rate of return on equity allowed in the rate
proceeding, the WVPSC employs a methodology which computes both the natural gas
distribution utility's cost of debt capital as well as cost of equity capital.
The allowable return on equity is designed to compensate the equity owner at
rates commensurate with the rate of return on investments at comparable risks.
In order to determine the allowable return on equity, the WVPSC utilizes two
market oriented methodologies, the discounted cash flow and the capital asset
pricing model. A further review utilized by the WVPSC to check the
reasonableness of the allowable return on equity involves an analysis of the
overall return required to provide reasonable interest coverage, dividend
pay-out ratios and internally generated cash flow. Finally, the WVPSC utilizes a
sample group of approximately ten to twelve gas distribution utilities located
within and outside of West Virginia for comparison purposes with respect to its
discounted cash flow calculation and the capital asset pricing model. The cost
of debt capital allowed is determined by utilizing the utility's actual interest
rates as set forth in its loan documents, provided the rate is determined to be
reasonable. While the cost of debt capital is normally based on long-term debt,
if the utility uses short-term debt on a regular basis, the WVPSC may determine
that such debt should be treated as a component of the utility's debt capital.
Because the rate regulatory process has certain inherent time delays, rate
orders may not reflect the operating costs at the time new rates are put into
effect.
Any change to the rate the Company's natural gas distribution utility
charges its customers for natural gas costs must be approved by the WVPSC. In
order to obtain approval of changes to gas purchase costs, the Company makes
purchase gas adjustment filings with the WVPSC on an annual basis which include
a forecast for the upcoming twelve month period of gas costs and a true-up
mechanism for the previous period for any over or under-recovery balances. The
WVPSC reviews the Company's gas purchasing activities during the previous year
to determine the prudence of gas purchase expenditures and to determine that
dependable lower-priced supplies of natural gas are not readily available from
other sources. The forecast of gas costs submitted by the Company in its annual
filings incorporates known and measurable pipeline fees during the upcoming
period and an estimate of gas costs based on several natural gas futures
indices. The WVPSC also reviews the Company's forecast of gas costs in such
filings for reasonableness.
All of the requests of natural gas distribution utilities in West Virginia
for rate changes are reviewed by the staff of the WVPSC as well as the Consumer
Advocate Division of the WVPSC. The Consumer Advocate Division is charged with
representing and protecting the interests of residential customers in regulating
the utility.
On October 19, 1995, the WVPSC entered an order that established a three
year moratorium on the rates that the Company may charge its natural gas
distribution system customers. As a consequence of the rate moratorium, the
Company is subject to the risks and benefits of changes in costs, including
changes in costs for natural gas purchased by the Company and changes in
interstate pipeline transportation rates, during the three year term of the
moratorium without the ability to increase rates charged to its customers to
absorb any increases in such costs during this period. In the event that such
costs are in excess of amounts being recovered in approved rates, the inability
of the Company to increase the rates it charges its customers could have a
material adverse effect on the Company's financial condition, results of
operations and cash flows. The WVPSC order provides for certain exceptions to
the moratorium if unforeseen extraordinary circumstances significantly impair
the Company's financial integrity or service reliability, although there can be
no assurance that such relief would be granted. The rate moratorium is scheduled
to expire on October 31, 1998. On May 27, 1997, Mountaineer filed a petition
with the WVPSC to request a proceeding with respect to rates to be charged on
and after November 1, 1998. It is currently anticipated that Mountaineer will
request another rate moratorium at a rate and for a period to be determined
through this process. The Company cannot be certain whether the Moratorium will
be continued past October 31, 1998.
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Dispositions or transfers of the stock or assets of the Company's natural
gas distribution utility require approval of the WVPSC.
UNCERTAINTY OF ESTIMATES OF RESERVES AND FUTURE NET REVENUES
This Prospectus contains estimates of the Company's oil and gas reserves
and the future net revenues which have been prepared by the Company and certain
independent petroleum consultants. Reserve engineering is a subjective process
of estimating the recovery from underground accumulations of oil and gas that
cannot be measured in an exact manner, and the accuracy of any reserve estimate
is a function of the quality of available data and of engineering and geological
interpretation and judgment. Estimates of economically recoverable oil and gas
reserves and of future net cash flows necessarily depend upon a number of
variable factors and assumptions, such as historical production from the area
compared with production from other producing areas, the assumed effects of
regulations by governmental agencies and assumptions concerning future oil and
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 results. Because all reserve estimates are to some
degree speculative, the quantities of oil and gas that are ultimately recovered,
production and operation costs, the amount and timing of future development
expenditures and future oil and gas sales prices may all vary from those assumed
in these estimates and such variances may be material. In addition, different
reserve engineers may make different estimates of reserve quantities and cash
flow based upon the same available data.
The present value of estimated future net cash flows referred to in this
Prospectus should not be construed as the current market value of the estimated
proved oil and gas reserves attributable to the Company's properties. In
accordance with applicable requirements of the Commission, the estimated
discounted 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. The calculation of the estimated
discounted future net cash flows from the Company's oil and gas reserves is
based on prices as of March 31, 1997. Reserve data at March 31, 1997 included in
this Prospectus is based on an average product price of $2.41 per Mcf of gas and
$16.24 per barrel of oil at such date. In addition, the calculation of the
present value of the future net revenues using a 10% discount 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 gas industry in general. Furthermore, the
Company's reserves may be subject to downward or upward revision based upon
actual production, results of future development, supply and demand for oil and
gas, prevailing oil and gas prices and other factors. See "Business and
Properties -- Oil and Gas Reserves."
FINDING AND ACQUIRING ADDITIONAL RESERVES
The Company's future success depends, in part, upon its ability to find or
acquire additional oil and gas reserves that are economically recoverable.
Except to the extent the Company conducts successful exploration or development
activities or acquires properties containing proved reserves, the proved
reserves of the Company will generally decline as they are produced. There can
be no assurance that the Company's anticipated development projects and
acquisition activities will result in significant additional reserves or that
the Company will have success drilling productive wells at economic returns. If
prevailing oil and gas prices were to increase significantly, the Company's
finding costs to add new reserves could increase. The drilling of oil and gas
wells involves a high degree of risk, especially the risk of dry holes or of
wells that are not sufficiently productive to provide an economic return on the
capital expended to drill the wells. The cost of drilling, completing and
operating wells is uncertain, and drilling or production may be curtailed or
delayed as a result of many factors.
The Company's business is capital intensive. To maintain its base of proved
oil and gas reserves, a significant amount of cash flow from operations must be
reinvested in property
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acquisitions, development or exploration activities. 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 investments to
maintain or expand its asset base would be impaired. Without such investment,
the Company's oil and gas reserves would decline.
DEVELOPMENT AND EXPLORATION RISKS
The Company intends to increase its exploration and development activities,
primarily in the Rocky Mountains and New Zealand. Exploration drilling, and to a
lesser extent development drilling, involve a high degree of risk that no
commercial production will be obtained or that the production will be
insufficient to recover drilling and completion costs. The cost of drilling,
completing and operating wells is uncertain. The Company's drilling operations
may be curtailed, delayed or canceled as a result of numerous factors, including
title problems, weather conditions, compliance with governmental requirements
and shortages or delays in the delivery of equipment. Furthermore, completion of
a well does not assure a profit on the investment or a recovery of drilling,
completion and operating costs. See "Business and Properties -- Drilling
Activities."
ACQUISITION RISKS
The Company has in the past acquired oil and gas properties and may in the
future acquire additional oil and gas properties. It generally is not feasible
to review in detail every individual property involved in an acquisition.
Ordinarily, review efforts are focused on the higher-valued properties. However,
even a detailed review of all properties and records may not reveal existing or
potential problems nor will it permit the Company to become sufficiently
familiar with the properties to assess fully their deficiencies and
capabilities. Inspections are not always performed on every well, and
environmental problems, such as groundwater contamination, are not necessarily
observable even when an inspection is undertaken. As a result, the Company may
suffer the loss of one or more acquired properties due to title deficiencies or
may be required to make significant expenditures to cure environmental
contamination with respect to acquired properties. See "Business and
Properties -- Significant Acquisitions and Dispositions."
In June 1995, the Company acquired Mountaineer, a natural gas distribution
utility in West Virginia (hereinafter referred to as the "Mountaineer
Acquisition"). The Company may in the future consider the acquisition of other
natural gas distribution utilities, either in West Virginia or in other states.
The acquisition of a natural gas distribution utility in a state other than West
Virginia would subject the gas distribution utility business conducted in such
other state to be subject to the utility regulation of such state as well as the
Public Utility Holding Company Act, which regulation may affect the rates that
such business may charge its customers, its capital structure, administrative
burdens and other aspects of such business.
OPERATING HAZARDS AND UNINSURED RISKS; PRODUCTION CURTAILMENTS
The oil and gas business involves a variety of operating risks, including,
but not limited to, unexpected formations or pressures, uncontrollable flows of
oil, gas, brine or well fluids into the environment (including groundwater
contamination), blowouts, cratering, fires, explosions, pipeline ruptures or
spills, pollution and other risks, any of which could result in personal
injuries, loss of life, damage to properties, environmental pollution,
suspension of operations and substantial losses. Although the Company carries
insurance which it believes is reasonable, it is not fully insured against all
risks. The Company does not carry business interruption insurance. Losses and
liabilities arising from uninsured or under-insured events could have a material
adverse effect on the financial condition and results of operations of the
Company.
From time to time, due primarily to contract terms, pipeline interruptions
or weather conditions, the producing wells in which the Company owns an interest
have been subject to production curtailments. The curtailments vary from a few
days to several months. In most cases the Company
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is provided only limited notice as to when production will be curtailed and the
duration of such curtailments. The Company is currently not curtailed to any
material extent on any of its production.
GAS CONTRACT RISKS
The Company attempts to balance its gas portfolio by entering into long,
intermediate and short term gas sales contracts, some of which provide for fixed
sales prices (including fixed prices that escalate to predetermined higher fixed
prices). The fixed price sale contracts limit the benefits the Company will
realize if market prices rise above the fixed prices specified in such
contracts. See "Business and Properties -- Significant Gas Sales and Purchase
Contracts."
For the 1996 fiscal year, the Company, excluding the natural gas
distribution utility, was obligated to sell approximately 9.0 Bcf of natural gas
to third parties pursuant to fixed price contracts having an initial term of
more than one year. In addition, for the 1996 fiscal year, a subsidiary of the
Company was obligated to sell up to approximately 9.5 Bcf of natural gas to the
Company's subsidiary that operates the natural gas distribution utility pursuant
to a fixed price contract. See "Business and Properties -- Significant Gas Sales
and Purchase Contracts." For the 1996 fiscal year, the aggregate volume of
natural gas production attributable to the Company's interests in gas and oil
properties was approximately 9.8 Bcf, the Company was the operator of properties
to which were attributable to third party interests an additional 12.2 Bcf of
natural gas and the Company aggregated and marketed an additional 38.9 Bcf of
natural gas owned by third parties. To the extent that the Company is unable to
satisfy its natural gas supply obligations under its natural gas sales contracts
from production attributable to its interests in gas and oil properties, the
Company will be dependent upon its ability to deliver natural gas attributable
to the interests of third parties in properties operated by the Company or from
natural gas purchased from third parties. See " -- Gas Aggregation and
Marketing."
The Company believes that its fixed price sales contracts with third
parties are enforceable and it has not received any notice or other indication
from any of the counterparties that they intend to cease performing any of their
obligations under these contracts. However, there can be no assurance that one
or more of these counterparties will not attempt to totally or partially
mitigate their obligations under these contracts. If any of the purchasers under
the contracts should be successful in doing so, then the Company could be
required to market its production on less attractive terms, which could have a
material adverse effect on the Company's financial condition, results of
operations and cash flow.
The Company's natural gas distribution utility is a party to gas purchase
contracts that require it to purchase natural gas at fixed prices. These
contracts contain terms ranging from 1 day to 5 years at prices ranging from
approximately $1.82 per Mcf to $4.58 per Mcf. In addition, the Company's natural
gas distribution utility purchases a significant portion of its gas volumes from
another subsidiary of the Company. See "Business and Properties -- Significant
Gas Sales and Purchase Contracts." A loan agreement to which the utility is a
party requires it to have in place hedging mechanisms for at least 66 2/3% of
its natural gas purchases, which hedging mechanisms may include fixed price gas
contracts. A rate regulation moratorium currently prohibits the Company from
increasing the rates it charges its customers for natural gas due to increased
costs of gas purchases. As a result, in the event that the Company purchases gas
during the moratorium period at prices that are in excess of amounts being
recovered in its approved rates, the inability of the Company to increase the
rates it charges its customers could have a material adverse effect on the
Company's financial condition, results of operation and cash flows. See
"-- Utility Rate Regulation."
HEDGING RISKS
From time to time, the Company enters into hedging arrangements relating to
its natural gas production. These hedges have in the past involved fixed
arrangements and other arrangements at
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a variety of fixed prices and with a variety of other provisions including price
floors and caps. The Company may in the future enter into oil and natural gas
futures contracts, options and swaps. The Company's hedging activities, while
intended to reduce the Company's sensitivity to changes in market prices of oil
and gas, are subject to a number of risks including instances in which (i)
production is less than expected, (ii) there is a widening of price
differentials between delivery points required by fixed price delivery contracts
to the extent they differ from those on the Company's production or (iii) the
Company's customers or the counterparties to its futures contract fail to
purchase or deliver the contracted quantities of oil or natural gas.
Additionally, the fixed price sales and hedging contracts limit the benefits the
Company will realize if actual prices rise above the contract prices.
GAS AGGREGATION AND MARKETING
The Company's gas aggregation and marketing operations depend in large part
on the ability of the Company to contract with third party producers and
suppliers to purchase their gas, to obtain sufficient volumes of committed
natural gas reserves to replace production from declining wells, to assess and
respond to changing market conditions in negotiating gas purchase and sale
agreements, to maintain satisfactory rights to transport gas through interstate
pipelines and to obtain satisfactory margins between the purchase price of its
natural gas supply and the sales price for its natural gas volumes. In addition,
the Company's operations are subject to changes in regulations relating to
gathering and marketing of oil and gas. The inability of the Company to attract
new sources of third party natural gas or to promptly respond to changing market
conditions or regulations in connection with its aggregation and marketing
operations could adversely affect the Company's financial condition and results
of operations.
COMPETITION
The Company's gas distribution utility and its natural gas production
compete with other forms of energy available to customers, primarily on the
basis of price. These alternate forms of energy include electricity, coal and
fuel oils. Changes in the availability or price of natural gas or other forms of
energy, as well as business conditions, conservation, legislation, regulations
and the ability to convert to alternate fuels and other forms of energy may
affect the demand for natural gas in areas served by the Company. Such factors
may also affect the demand for natural gas produced by the Company.
The Company is also subject to competition from interstate and intrastate
pipeline companies, producers and other utilities which may be able to serve
commercial, industrial and residential customers from their transmission,
gathering and/or distribution facilities. In certain markets, gas has a
competitive price advantage over alternate fuels, while in other markets it is
not as price competitive.
The Company encounters substantial competition with respect to its oil and
gas exploration, production and marketing activities in acquiring oil and gas
properties, marketing oil and gas, securing equipment and personnel and
operating its properties. The competitors in acquisitions, development,
exploration and production include major oil companies, numerous independent oil
and gas companies, individual proprietors and others. Many of these competitors
have financial and other resources which substantially exceed those of the
Company and have been engaged in the energy business for a much longer time than
the Company. Therefore, competitors may be able to pay more for desirable leases
and to evaluate, bid for and purchase a greater number of properties or
prospects than the financial or personnel resources of the Company will permit.
REGULATIONS AFFECTING OPERATIONS
The Company's operations are affected by extensive regulation pursuant to
various federal, state and local laws and regulations relating to the
exploration for and development, production,
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gathering, marketing, transportation and storage of oil and gas. These
regulations, among other things, may affect the rate of oil and gas production.
The Company's operations are subject to numerous laws and regulations governing
plugging and abandonment, the discharge of materials into the environment or
otherwise relating to environmental protection. These laws and regulations
require the acquisition of a permit before drilling commences, restrict the
types, quantities and concentration of various substances that can be released
into the environment in connection with drilling and production activities,
limit or prohibit drilling activities on certain lands lying within wilderness,
wetlands and other protected areas, and impose substantial liabilities for
pollution which might result from the Company's operations.
As a marketer of natural gas, the Company depends on the transportation and
storage services offered by various interstate and intrastate pipeline companies
for the delivery and sale of its own gas supplies as well as those it processes
and/or markets for others. Both the performance of transportation and storage
services by interstate pipelines and the rates charged for such services are
subject to the jurisdiction of the Federal Energy Regulatory Commission (the
"FERC"). In addition, the performance of transportation and storage services by
intrastate pipelines and the rates charged for such services are subject to the
jurisdiction of state regulatory agencies. An inability to obtain transportation
and/or storage services at competitive rates may hinder the Company's marketing
operations and/or affect its sales margins.
ENVIRONMENTAL MATTERS
The Company may be subject to substantial clean-up costs for any toxic or
hazardous substance that may exist with respect to any of its properties.
Moreover, the recent trend toward stricter standards in environmental
legislation and regulation is likely to continue. For instance, legislation has
been proposed in Congress from time to time that would reclassify certain crude
oil and natural gas exploration and production wastes as "hazardous wastes"
which would make the reclassified wastes subject to much 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 gas industry in general. Initiatives to further
regulate the disposal of crude oil and natural gas wastes are also pending in
certain states, and these various initiatives could have a similar impact on the
Company. The Company could incur substantial costs to comply with environmental
laws and regulations.
RISKS RELATING TO A CHANGE OF CONTROL
Upon a Change of Control (as defined in "Description of the
Notes -- Certain Definitions"), holders of the Notes will have the right to
require the Company to repurchase all or any part of such holders' Notes at a
price equal to 101% of the principal amount thereof, plus accrued and unpaid
interest, if any, to the date of repurchase. The events that constitute a Change
of Control under the Indenture relating to the Notes would constitute a default
under the Credit Agreement, which prohibits the purchase of the Notes by the
Company in the event of certain Change of Control events unless and until such
time as the Company's indebtedness under the Credit Agreement is repaid in full.
There can be no assurance that the Company would have sufficient financial
resources available to satisfy all of its obligations under the Credit Agreement
and the Notes in the event of a Change of Control. The Company's failure to
purchase the Notes would result in a default under the Indenture and under the
Credit Agreement, each of which could have adverse consequences for the Company
and the holders of the Notes. See "Description of the Notes -- Repurchase at the
Option of Holders -- Change of Control." The definition of "Change of Control"
in the Indenture includes a sale, lease, conveyance or other disposition of "all
or substantially all" of the assets of the Company and its subsidiaries taken as
a whole to a person or a group of persons. There is little case law interpreting
the phrase "all or substantially all" in the context of an indenture. Because
there is no precise established definition of this phrase, the ability of a
holder of the Notes to require the
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Company to repurchase such Notes as a result of a sale, lease, conveyance or
transfer of all or substantially all of the Company's assets to a person or
group of persons may be uncertain.
CONTROL BY CERTAIN STOCKHOLDERS, OFFICERS AND DIRECTORS
At January 1, 1997, John Mork, Julie Mork, the Alison Mork Trust and the
Kyle Mork Trust beneficially owned an aggregate of 399,283 shares of Common
Stock of the Company representing approximately 59.5% of the outstanding shares
of Common Stock, and members of the Company's Board of Directors and senior
management, including John and Julie Mork and their children's trusts,
beneficially owned an aggregate of 641,745 shares, which represent approximately
95.6% of the Company's outstanding Common Stock. As a result, John and Julie
Mork, as well as the officers and directors of the Company as a group, are in a
position to elect all of the Company's directors, appoint all management
personnel and control actions that require the consent of a majority of the
Company's outstanding voting stock. See "Principal Stockholders and Share
Ownership of Management."
ABSENCE OF MARKET FOR THE EXCHANGE NOTES
There is no existing trading market for the Exchange Notes and there can be
no assurance regarding the future development of such a market for the Exchange
Notes, the ability of holders of the Exchange Notes to sell their Exchange Notes
or the price at which such holders may be able to sell their Exchange Notes. If
a market for the Exchange Notes does develop, future trading prices will depend
on many factors, including, among other things, prevailing interest rates, the
operating results of the Company, and the market for similar securities. The
Company does not intend to apply for listing of the Exchange Notes on any
securities exchange or for quotation through The Nasdaq Stock Market.
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<PAGE> 29
THE EXCHANGE OFFER
PURPOSE AND EFFECT OF THE EXCHANGE OFFER
The Old Notes were sold by the Company on May 23, 1997, to the Initial
Purchasers pursuant to a Purchase Agreement, dated May 20, 1997, between the
Company and the Initial Purchasers (the "Purchase Agreement"). The Initial
Purchasers subsequently resold all of the Old Notes to Qualified Institutional
Buyers, each of whom agreed to comply with certain transfer restrictions and
other conditions. As a condition to the purchase of the Old Notes by the Initial
Purchasers, the Company entered into a registration rights agreement with the
Initial Purchasers (the "Registration Rights Agreement"), which requires, among
other things, that promptly following the issuance and sale of the Old Notes,
the Company file with the SEC the Registration Statement with respect to the
Exchange Notes, use its best efforts to cause the Registration Statement to
become effective under the Securities Act and, upon the effectiveness of the
Registration Statement, offer to the holders of the Old Notes the opportunity to
exchange their Old Notes for a like principal amount of Exchange Notes, which
will be issued without a restrictive legend and may be reoffered and resold by
the holder without restrictions or limitations under the Securities Act subject
to certain exceptions described below. A copy of the Registration Rights
Agreement has been filed as an exhibit to the Registration Statement of which
this Prospectus is a part. The term "holder" with respect to the Exchange Offer
means any person in whose name Old Notes are registered on the Company's books
or any other person who has obtained a properly completed bond power from the
registered holder or any person whose Old Notes are held of record by the
Depositary who desires to deliver such Old Notes by book-entry transfer of the
Depositary. The Old Notes provide that if, by November 5, 1997, (i) the Exchange
Offer has not been consummated, or (ii) a shelf registration statement relating
to the sale of the Old Notes has not been declared effective, the Company will
pay liquidated damages in an amount equal to $0.192 per week per $1,000
principal amount of the Old Notes outstanding from and including November 5,
1997 until but excluding the date the Exchange Offer is consummated or such
shelf registration statement is declared effective.
Based on existing interpretations of the Securities Act by the staff of the
SEC set forth in several no-action letters to third parties, and subject to the
immediately following sentence, the Company believes that Exchange Notes issued
pursuant to the Exchange Offer in exchange for Old Notes may be offered for
resale, resold and otherwise transferred by a holder thereof (other than (i) a
broker-dealer who purchased such Old Notes directly from the Company for resale
pursuant to Rule 144A or any other available exemption under the Securities Act
or (ii) a person that is an "affiliate" (within the meaning of Rule 405 of the
Securities Act) of the Company), without compliance with the registration and
prospectus delivery provisions of the Securities Act, provided that the holder
is acquiring the Exchange Notes in its ordinary course of business and is not
participating, and has no arrangement or understanding with any person to
participate, in the distribution of the Exchange Notes. However, any purchaser
of Old Notes who is an affiliate of the Company or who intends to participate in
the Exchange Offer for the purpose of distributing the Exchange Notes, or any
broker-dealer who purchased the Old Notes from the Company to resell pursuant to
Rule 144A or any other available exemption under the Securities Act, (i) will
not be able to rely on the interpretations by the staff of the SEC set forth in
the above-mentioned no-action letters, (ii) will not be able to tender its Old
Notes in the Exchange Offer and (iii) must comply with the registration and
prospectus delivery requirements of the Securities Act in connection with any
sale or transfer of the Old Notes unless such sale or transfer is made pursuant
to an exemption from such requirements. Accordingly, any holder who tenders in
the Exchange Notes must comply with the registration and prospectus delivery
requirements of the Securities Act in connection with a secondary resale
transaction. See "Plan of Distribution."
As a result of the filing and effectiveness of the Registration Statement
of which this Prospectus is a part, the Company will not be required to pay an
increased interest rate on the Old Notes. Following the consummation of the
Exchange Offer, holders of Old Notes not tendered will not have
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<PAGE> 30
any further registration rights except in certain limited circumstances
requiring the filing of a Shelf Registration Statement (as defined in
"Description of the Notes -- Registered Exchange Offer, Registration Rights"),
and the Old Notes will continue to be subject to certain restrictions on
transfer. See "Description of the Notes -- Registered Exchange Offer;
Registration Rights." Accordingly, the liquidity of the market for the Old Notes
could be adversely affected.
TERMS OF THE EXCHANGE OFFER
Upon the terms and subject to the conditions set forth in this Prospectus
and in the Letter of Transmittal, the Company will accept all Old Notes properly
tendered and not withdrawn prior to 5:00 p.m. New York City time, on the
Expiration Date. After authentication of the Exchange Notes by the Trustee or an
authenticating agent, the Company will issue and deliver $1,000 principal amount
of Exchange Notes in exchange for each $1,000 principal amount of outstanding
Old Notes accepted in the Exchange Offer. Holders may tender some or all of
their Old Notes pursuant to the Exchange Offer in denominations of $1,000 and
integral multiples thereof.
Each holder of Old Notes who wishes to exchange Old Notes for Exchange
Notes in the Exchange Offer will be required to represent that (i) it is not an
affiliate of the Company, (ii) any Exchange Notes to be received by it were
acquired in the ordinary course of its business and (iii) it has no arrangement
or understanding with any person to participate in the distribution (within the
meaning of the Securities Act) of the Exchange Notes.
Each broker-dealer that receives Exchange Notes for its own account in
exchange for Old Notes, where such Old Notes were acquired by such broker-dealer
as a result of market-making activities or other trading activities, must
acknowledge that it will deliver a prospectus in connection with any resale of
such Exchange Notes. See "Plan of Distribution."
The form and terms of the Exchange Notes are identical in all material
respects to the form and terms of the Old Notes, except that (i) the offering of
the Exchange Notes has been registered under the Securities Act, (ii) the
Exchange Notes will not be subject to transfer restrictions and (iii) certain
provisions relating to an increase in the stated interest rate on the Old Notes
provided for under certain circumstances will be eliminated. The Exchange Notes
will evidence the same debt as the Old Notes. The Exchange Notes will be issued
under and entitled to the benefits of the Indenture.
As of the date of this Prospectus, $200,000,000 aggregate principal amount
of the Old Notes is outstanding. In connection with the issuance of the Old
Notes, the Company arranged for the Old Notes to be issued and transferable in
book-entry form through the facilities of the Depositary, acting as depositary.
The Exchange Notes will also be issuable and transferable in book-entry form
through the Depositary.
This Prospectus, together with the accompanying Letter of Transmittal, is
initially being sent to all registered holders of the Old Notes as of the close
of business on July , 1997. The Company intends to conduct the Exchange Offer
in accordance with the applicable requirements of the Exchange Act, and the
rules and regulations of the SEC thereunder, including Rule 14e-1, to the extent
applicable. The Exchange Offer is not conditioned upon any minimum aggregate
principal amount of Old Notes being tendered, and holders of the Old Notes do
not have any appraisal or dissenters' rights under the General Corporation Law
of the State of Delaware or under the Indenture in connection with the Exchange
Offer. The Company shall be deemed to have accepted validly tendered Old Notes
when, as and if the Company has given oral or written notice thereof to the
Exchange Agent. See "-- Exchange Agent." The Exchange Agent will act as agent
for the tendering holders for the purpose of receiving Exchange Notes from the
Company and delivering Exchange Notes to such holders.
If any tendered Old Notes are not accepted for exchange because of an
invalid tender or the occurrence of certain other events set forth herein,
certificates for any such unaccepted Old Notes
25
<PAGE> 31
will be returned, at the Company's cost, to the tendering holder thereof as
promptly as practicable after the Expiration Date.
Holders who tender Old Notes in the Exchange Offer will not be required to
pay brokerage commissions or fees or, subject to the instructions in the Letter
of Transmittal, transfer taxes with respect to the exchange of Old Notes
pursuant to the Exchange Offer. The Company will pay all charges and expenses,
other than certain applicable taxes, in connection with the Exchange Offer.
See"-- Solicitation of Tenders, Fees and Expenses."
NEITHER THE BOARD OF DIRECTORS OF THE COMPANY NOR THE COMPANY MAKES ANY
RECOMMENDATION TO HOLDERS OF OLD NOTES AS TO WHETHER TO TENDER OR REFRAIN FROM
TENDERING ALL OR ANY PORTION OF THEIR OLD NOTES PURSUANT TO THE EXCHANGE OFFER.
MOREOVER, NO ONE HAS BEEN AUTHORIZED TO MAKE ANY SUCH RECOMMENDATION. HOLDERS OF
OLD NOTES MUST MAKE THEIR OWN DECISION WHETHER TO TENDER PURSUANT TO THE
EXCHANGE OFFER AND, IF SO, THE AGGREGATE AMOUNT OF OLD NOTES TO TENDER AFTER
READING THIS PROSPECTUS AND THE LETTER OF TRANSMITTAL AND CONSULTING WITH THEIR
ADVISORS, IF ANY, BASED ON THEIR OWN FINANCIAL POSITION AND REQUIREMENTS.
EXPIRATION DATE; EXTENSIONS; AMENDMENTS
The term "Expiration Date" shall mean 5:00 p.m., New York City time, on
, 1997, unless the Company, in its sole discretion, extends the
Exchange Offer, in which case the term "Expiration Date" shall mean the latest
date to which the Exchange Offer is extended. The Company may extend the
Exchange Offer at any time and from time to time by giving oral or written
notice to the Exchange Agent and by timely public announcement.
The Company expressly reserves the right, in its sole discretion (i) to
delay acceptance of any Old Notes, to extend the Exchange Offer or to terminate
the Exchange Offer and to refuse to accept Old Notes not previously accepted, if
any of the conditions set forth herein under "-- Conditions of the Exchange
Offer" shall have occurred and shall not have been waived by the Company (if
permitted to be waived by the Company), by giving oral or written notice of such
delay, extension or termination to the Exchange Agent and (ii) to amend the
terms of the Exchange Offer in any manner. Any such delay in acceptance,
extension, termination or amendment will be followed as promptly as practicable
by oral or written notice thereof by the Company to the registered holders of
the Old Notes. If the Exchange Offer is amended in a manner determined by the
Company to constitute a material change, the Company will promptly disclose such
amendment in a manner reasonably calculated to inform the holders of such
amendment and the Company will extend the Exchange Offer to the extent required
by law.
Without limiting the manner in which the Company may choose to make public
announcements of any delay in acceptance, extension, termination or amendment of
the Exchange Offer, the Company shall have no obligation to publish, advise, or
otherwise communicate any such public announcement, other than by making a
timely release thereof to the Dow Jones News Service.
INTEREST ON THE EXCHANGE NOTES
The Exchange Notes will bear interest at a rate of 9 1/2% per annum,
payable semi-annually on May 15 and November 15 of each year, commencing
November 15, 1997. Holders of Exchange Notes of record on November 1, 1997, will
receive on November 15, 1997, an interest payment in an amount equal to (x) the
accrued interest on such Exchange notes from the date of issuance thereof to
November 15, 1997, plus (y) the accrued interest on the previously held Old
Notes from the date of issuance of such Old Notes (May 23, 1997) to the date of
exchange thereof. Interest will not be paid on Old Notes that are accepted for
exchange. The Notes mature on May 15, 2007.
26
<PAGE> 32
PROCEDURES FOR TENDERING
Each holder of Old Notes wishing to accept the Exchange Offer must
complete, sign and date the Letter of Transmittal, or a facsimile thereof, in
accordance with the instructions contained herein and therein, and mail or
otherwise deliver such Letter of Transmittal, or such facsimile, together with
the Old Notes to be exchanged and any other required documentation, to The Bank
of New York, as Exchange Agent, at the address set forth herein and therein or
effect a tender of Old Notes pursuant to the procedures for book-entry transfer
as provided for herein and therein. By executing the Letter of Transmittal, each
holder will represent to the Company, that, among other things, the Exchange
Notes acquired pursuant to the Exchange Offer are being acquired in the ordinary
course of business of the person receiving such Exchange Notes, whether or not
such person is the holder, that neither the holder nor any such other person has
any arrangement or understanding with any person to participate in the
distribution of such Exchange Notes and that neither the holder nor any such
other person is an "affiliate," as defined in Rule 405 under the Securities Act,
of the Company.
Any financial institution that is a participant in the Depositary's
Book-entry Transfer Facility system may make book-entry delivery of the Old
Notes by causing the Depositary to transfer such Old Notes into the Exchange
Agent's account in accordance with the Depositary's procedure for such transfer.
Although delivery of Old Notes may be effected through book-entry transfer into
the Exchange Agent's account at the Depositary, the Letter of Transmittal (or
facsimile thereof), with any required signature guarantees and any other
required documents, must, in any case, be transmitted to and received by the
Exchange Agent at its address set forth herein under "-- Exchange Agent" prior
to 5:00 p.m., New York City time, on the Expiration Date. DELIVERY OF DOCUMENTS
TO THE DEPOSITARY IN ACCORDANCE WITH ITS PROCEDURES DOES NOT CONSTITUTE DELIVERY
TO THE EXCHANGE AGENT.
Only a holder may tender its Old Notes in the Exchange Offer. To tender in
the Exchange Offer, a holder must complete, sign and date the Letter of
Transmittal or a facsimile thereof, have the signatures thereof guaranteed if
required by the Letter of Transmittal, and mail or otherwise deliver such Letter
of Transmittal or such facsimile, together with the Old Notes (unless such
tender is being effected pursuant to the procedure for book-entry transfer) and
any other required documents, to the Exchange Agent, prior to 5:00 p.m., New
York City time, on the Expiration Date.
The Tender by a holder will constitute an agreement between such holder,
the Company and the Exchange Agent in accordance with the terms and subject to
the conditions set forth herein and in the Letter of Transmittal. If less than
all of the Old Notes are tendered, a tendering holder should fill in the amount
of Old Notes being tendered in the appropriate box on the Letter of Transmittal.
The entire amount of Old Notes delivered to the Exchange Agent will be deemed to
have been tendered unless otherwise indicated.
THE LETTER OF TRANSMITTAL WILL INCLUDE REPRESENTATIONS TO THE COMPANY THAT,
AMONG OTHER THINGS, (1) THE EXCHANGE NOTES ACQUIRED PURSUANT TO THE EXCHANGE
OFFER ARE BEING ACQUIRED IN THE ORDINARY COURSE OF BUSINESS OF THE PERSON
RECEIVING SUCH EXCHANGE NOTES (WHETHER OR NOT SUCH PERSON IS THE HOLDER), (2)
NEITHER THE HOLDER NOR ANY SUCH OTHER PERSON IS ENGAGED IN, INTENDS TO ENGAGE IN
OR HAS ANY ARRANGEMENT OR UNDERSTANDING WITH ANY PERSON TO PARTICIPATE IN THE
DISTRIBUTION OF SUCH EXCHANGE NOTES, (3) NEITHER THE HOLDER NOR ANY SUCH OTHER
PERSON IS AN "AFFILIATE," AS DEFINED IN RULE 405 UNDER THE SECURITIES ACT, OF
THE COMPANY AND (4) IF THE TENDERING HOLDER IS A BROKER OR DEALER (AS DEFINED IN
THE EXCHANGE ACT) (a) IT ACQUIRED THE OLD NOTES FOR ITS OWN ACCOUNT AS A RESULT
OF MARKET-MAKING ACTIVITIES OR OTHER TRADING ACTIVITIES AND (b) IT HAS NOT
ENTERED INTO ANY ARRANGEMENT OR UNDERSTANDING WITH THE COMPANY OR ANY
"AFFILIATE" THEREOF (WITHIN THE MEANING OF RULE 405 UNDER THE SECURITIES ACT) TO
DISTRIBUTE THE EXCHANGE NOTES TO BE RECEIVED IN THE EXCHANGE OFFER. IN THE CASE
OF A BROKER-DEALER THAT RECEIVES EXCHANGE NOTES FOR ITS OWN ACCOUNT IN EXCHANGE
FOR OLD NOTES WHICH WERE ACQUIRED BY IT AS A RESULT OF MARKET-MAKING OR OTHER
TRADING ACTIVITIES, THE LETTER OF TRANSMITTAL WILL ALSO INCLUDE AN
ACKNOWLEDGMENT THAT THE BROKER-DEALER WILL DELIVER A COPY OF THIS PROSPECTUS IN
CONNECTION WITH
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<PAGE> 33
THE RESALE BY IT OF EXCHANGE NOTES RECEIVED PURSUANT TO THE EXCHANGE OFFER;
HOWEVER, BY SO ACKNOWLEDGING AND BY DELIVERING A PROSPECTUS, SUCH HOLDER WILL
NOT BE DEEMED TO ADMIT THAT IT IS AN "UNDERWRITER" WITHIN THE MEANING OF THE
SECURITIES ACT. SEE "PLAN OF DISTRIBUTION."
THE METHOD OF DELIVERY OF OLD NOTES AND THE LETTER OF TRANSMITTAL AND ALL
OTHER REQUIRED DOCUMENTS TO THE EXCHANGE AGENT IS AT THE ELECTION AND RISK OF
THE HOLDERS. INSTEAD OF DELIVERY BY MAIL, IT IS RECOMMENDED THAT HOLDERS USE AN
OVERNIGHT OR HAND DELIVERY SERVICE. IN ALL CASES, SUFFICIENT TIME SHOULD BE
ALLOWED TO ENSURE DELIVERY TO THE EXCHANGE AGENT PRIOR TO THE EXPIRATION DATE.
NO LETTER OF TRANSMITTAL OR OLD NOTES SHOULD BE SENT TO THE COMPANY. HOLDERS MAY
ALSO REQUEST THAT THEIR RESPECTIVE BROKERS, DEALERS, COMMERCIAL BANKS, TRUST
COMPANIES OR NOMINEES EFFECT SUCH TENDER FOR HOLDERS, IN EACH CASE AS SET FORTH
HEREIN AND IN THE LETTER OF TRANSMITTAL.
Any beneficial owner whose Old Notes are registered in the name of his
broker, dealer, commercial bank, trust company or other nominee and who wishes
to tender should contact such registered holder promptly and instruct such
registered holder to tender on his behalf. If such beneficial owner wishes to
tender on his own behalf, such beneficial owner must, prior to completing and
executing the Letter of Transmittal and delivering his Old Notes, either make
appropriate arrangements to register ownership of the Old Notes in such owner's
name or obtain a properly completed bond power from the registered holder. The
transfer of record ownership may take considerable time.
Signatures on a Letter of Transmittal or a notice of withdrawal, as the
case may be, must be guaranteed by a member firm of a registered national
securities exchange or of the National Association of Securities Dealers, Inc.,
a commercial bank or trust company having an office or correspondent in the
United States or an "eligible guarantor institution" within the meaning of Rule
17Ad-15 under the Exchange Act (each an "Eligible Institution"), unless the Old
Notes tendered pursuant thereto are tendered (i) by a registered holder who has
not completed the box entitled "Special Registration Instructions" or "Special
Delivery Instructions" of the Letter of Transmittal or (ii) for the account of
an Eligible Institution. If the Letter of Transmittal is signed by a person
other than the registered holder listed therein, such Old Notes must be endorsed
or accompanied by appropriate bond powers which authorize such person to tender
the Old Notes on behalf of the registered holder, in either case signed as the
name of the registered holder or holders appears on the Old Notes. If the Letter
of Transmittal or any Old Notes or bond powers are signed or endorsed by
trustees, executors, administrators, guardians, attorneys-in-fact, officers of
corporations or others acting in a fiduciary or representative capacity, such
person should so indicate when signing, and unless waived by the Company,
evidence satisfactory to the Company of their authority to so act must be
submitted with such Letter of Transmittal.
All questions as to the validity, form, eligibility (including time of
receipt), acceptance and withdrawal of the tendered Old Notes will be determined
by the Company in its sole discretion, which determination will be final and
binding. The Company reserves the absolute right to reject any and all Old Notes
not properly tendered or any Old Notes the Company's acceptance of which would,
in the opinion of counsel for the Company, be unlawful. The Company also
reserves the absolute right to waive an irregularities or conditions of tender
as to particular Old Notes. The Company's interpretation of the terms and
conditions of the Exchange Offer (including the instructions in the Letter of
Transmittal) will be final and binding on all parties. Unless waived, any
defects or irregularities in connection with tenders of Old Notes must be cured
within such time as the Company shall determine. Although the Company intends to
notify holders of defects or irregularities with respect to tenders of Old
Notes, neither the Company, the Exchange Agent nor any other person shall be
under any duty to give notification of defects or irregularities with respect to
tenders of Old Notes, nor shall any of them incur any liability for failure to
give such notification. Tenders of Old Notes will not be deemed to have been
made until such irregularities have been cured or waived. Any Old Notes received
by the Exchange Agent that the Company determines are not properly tendered or
28
<PAGE> 34
the tender of which is otherwise rejected by the Company and as to which the
defects or irregularities have not been cured or waived by the Company will be
returned by the Exchange Agent to the tendering holder unless otherwise provided
in the Letter of Transmittal, as soon as practicable following the Expiration
Date.
In addition, the Company reserves the right in its sole discretion (a) to
purchase or make offers for any Old Notes that remain outstanding subsequent to
the Expiration Date, or, as set forth under " -- Conditions of the Exchange
Offer," terminate the Exchange Offer and (b) to the extent permitted by
applicable law, to purchase Old Notes in the open market, in privately
negotiated transactions or otherwise. The terms of any such purchases or offers
may differ from the terms of the Exchange Offer.
BOOK-ENTRY TRANSFER
The Company understands that the Exchange Agent will make a request
promptly after the date of this Prospectus to establish accounts with respect to
the Old Notes at the DTC (the "Book-Entry Transfer Facility") for the purpose of
facilitating the Exchange Offer, and subject to the establishment thereof, any
financial institution that is a participant in the Book-Entry Transfer
Facility's system may make book-entry deliver of Old Notes by causing such
Book-Entry Transfer Facility to transfer such Old Notes into the Exchange
Agent's account with respect to the Old Notes in accordance with the Book-Entry
Transfer Facility's procedures for such transfer. ALTHOUGH DELIVERY OF OLD NOTES
MAY BE EFFECTED THROUGH BOOK-ENTRY TRANSFER INTO THE EXCHANGE AGENT'S ACCOUNT AT
THE BOOK-ENTRY TRANSFER FACILITY, AN APPROPRIATE LETTER OF TRANSMITTAL PROPERLY
COMPLETED AND DULY EXECUTED WITH ANY REQUIRED SIGNATURE GUARANTEE AND ALL OTHER
REQUIRED DOCUMENTS MUST IN EACH CASE BE TRANSMITTED TO AND RECEIVED OR CONFIRMED
BY THE EXCHANGE AGENT AT ITS ADDRESS SET FORTH BELOW ON OR PRIOR TO THE
EXPIRATION DATE, OR, IF THE GUARANTEED DELIVERY PROCEDURES DESCRIBED BELOW ARE
COMPLIED WITH, WITH THE TIME PERIOD PROVIDED UNDER SUCH PROCEDURES. DELIVERY OF
DOCUMENTS TO THE BOOK-ENTRY TRANSFER FACILITY DOES NOT CONSTITUTE DELIVERY TO
THE EXCHANGE AGENT.
GUARANTEED DELIVERY PROCEDURES
Holders who wish to tender their Old Notes and (i) whose Old Notes are not
immediately available, or (ii) who cannot deliver their Old Notes, the Letter of
Transmittal or any other required documents to the Exchange Agent prior to the
Expiration Date, or who cannot complete the procedure for book-entry transfer on
a timely basis, may effect a tender if:
(a) the tender is made through an Eligible Institution;
(b) prior to the Expiration Date, the Exchange Agent receives from
such Eligible Institution a properly completed and duly executed Notice of
Guaranteed Delivery (by facsimile transmittal, mail or hand delivery)
setting forth the name and address of the holder, the certificate number or
numbers of such holder's Old Notes and the principal amount of such Old
Notes tendered, stating that the tender is being made thereby, and
guaranteeing that, within three New York Stock Exchange ("NYSE") trading
days after the Expiration Date, the Letter of Transmittal (or facsimile
thereof), together with the certificate(s) representing the Old Notes to be
tendered in proper form for transfer (or confirmation of a book-entry
transfer into the Exchange Agent's account at the Depositary of Old Notes
delivered electronically) and any other documents required by the Letter of
Transmittal, will be deposited by the Eligible Institution with the
Exchange Agent; and
(c) such properly completed and executed Letter of Transmittal (or
facsimile thereof), together with the certificate(s) representing all
tendered Old Notes in proper form for transfer (or confirmation of a
book-entry transfer into the Exchange Agent's account at the Depositary of
Old Notes delivered electronically) and all other documents required by the
Letter of
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<PAGE> 35
Transmittal are received by the Exchange Agent within three NYSE trading
days after the Expiration Date.
Upon request to the Exchange Agent, a Notice of Guaranteed Delivery will be
sent to holders who wish to tender their Old Notes according to the guaranteed
delivery procedures set forth above.
WITHDRAWAL OF TENDERS
Except as otherwise provided herein, tenders of Old Notes may be withdrawn
at any time prior to 5:00 p.m., New York City time, on the Expiration Date.
For a withdrawal to be effective, a written or facsimile transmission
notice of withdrawal must be received by the Exchange Agent at its address set
forth herein prior to 5:00 p.m., New York City time, on the Expiration Date. Any
such notice of withdrawal must (i) specify the name of the person having
deposited the Old Notes to be withdrawn (the "Depositor"), (ii) identify the Old
Notes to be withdrawn (including the certificate number or numbers and principal
amount of such Old Notes or, in the case of Old Notes transferred by book-entry
transfer, the name and number of the account at the Depositary to be credited),
(iii) be signed by the Depositor in the same manner as the original signature on
the Letter of Transmittal by which such Old Notes were tendered (including any
required signature guarantee) or be accompanied by documents of transfer
sufficient to permit the Trustee with respect to the Old Notes to register the
transfer of such Old Notes into the name of the Depositor withdrawing the tender
and (iv) specify the name in which any such Old Notes are to be registered, if
different from that of the Depositor. All questions as to the validity, form and
eligibility (including time of receipt) of such withdrawal notices will be
determined by the Company, whose determination shall be final and binding on all
parties. Any Old Notes so withdrawn will be deemed not to have been validly
tendered for purposes of the Exchange Offer, and no Exchange Notes will be
issued with respect thereto unless the Old Notes so withdrawn are validly
retendered. Any Old Notes that have been tendered but are not accepted for
exchange will be returned to the holder thereof without cost to such holder as
soon as practicable after withdrawal, rejection of tender or termination of the
Exchange Offer. Properly withdrawn Old Notes may be retendered by following one
of the procedures described above under "-- Procedures for Tendering" at any
time prior to the Expiration Date.
CONDITIONS TO THE EXCHANGE OFFER
Notwithstanding any other term of the Exchange Offer, the Company will not
be required to accept for exchange, or to exchange Exchange Notes for, any Old
Notes, and may terminate or amend the Exchange Offer as provided herein before
the acceptance of such Old Notes if, in the Company's judgment, any of the
following conditions has occurred or exists or has not been satisfied: (i) that
the Exchange Offer, or the making of any exchange by a holder, violates
applicable law or any applicable interpretation of the staff of the SEC, (ii)
that any action or proceeding shall have been instituted or threatened in any
court or by or before any governmental agency or body with respect to the
Exchange Offer, (iii) that there has been adopted or enacted any law, statute,
rule or regulation that can reasonably be expected to impair the ability of the
Company to proceed with the Exchange Offer, (iv) that there has been declared by
United States federal or Texas or New York state authorities a banking
moratorium; or (v) that trading on the New York Stock Exchange or generally in
the United States over-the-counter market has been suspended by order of the SEC
or any other governmental agency, in each of clauses (i) through (iv) which, in
the Company's judgment, would reasonably be expected to impair the ability of
the Company to proceed with the Exchange Offer.
If the Company determines that it may terminate the Exchange Offer for any
of the reasons set forth above, the Company may (i) refuse to accept any Old
Notes and return any Old Notes that have been tendered to the holders thereof,
(ii) extend the Exchange Offer and retain all Old Notes tendered prior to the
Expiration Date of the Exchange Offer, subject to the rights of such holders of
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<PAGE> 36
tendered Old Notes to withdraw their tendered Old Notes or (iii) waive such
termination event with respect to the Exchange Offer and accept all properly
tendered Old Notes that have not been withdrawn. If such waiver constitutes a
material change in the Exchange Offer, the Company will disclose such change by
means of a supplement to this Prospectus that will be distributed to each
registered holder, and the Company will extend the Exchange Offer for a period
of five to ten business days, depending upon the significance of the waiver and
the manner of disclosure to the registered holders, if the Exchange Offer would
otherwise expire during such period.
EXCHANGE AGENT
The Bank of New York, the Trustee under the Indenture, has been appointed
as Exchange Agent for the Exchange Offer. In such capacity, the Exchange Agent
has no fiduciary duties and will be acting solely on the basis of directions of
the Company. Requests for assistance and requests for additional copies of this
Prospectus or of the Letter of Transmittal should be directed to the Exchange
Agent addressed as follows:
<TABLE>
<CAPTION>
The Bank of New York, Exchange Agent
<C> <C>
By Mail or Hand Delivery: By Facsimile Transmission:
The Bank of New York (for Eligible Institutions only):
Reorganization Section (212) 571-3080
101 Barclay Street--7E Attention: Walter Gitlin
New York, New York 10286 Confirm by Telephone:
Attention: Walter Gitlin (212) 815-3687
</TABLE>
DELIVERY OF THE LETTER OF TRANSMITTAL TO AN ADDRESS OTHER THAN AS SET FORTH
ABOVE OR TRANSMISSION OF INSTRUCTIONS VIA FACSIMILE OTHER THAN AS SET FORTH
ABOVE DOES NOT CONSTITUTE A VALID DELIVERY OF SUCH LETTER OF TRANSMITTAL.
Delivery to an address or facsimile number other than those listed above will
not constitute a valid delivery.
SOLICITATION OF TENDERS; FEES AND EXPENSES
The expenses of soliciting tenders pursuant to the Exchange Offer will be
borne by the Company. The principal solicitation pursuant to the Exchange Offer
is being made by mail. Additional solicitations may be made by officers and
regular employees of the Company and its affiliates in person, by telegraph,
telephone or telecopier.
The Company has not retained any dealer-manager in connection with the
Exchange Offer and will not make any payments to brokers, dealers or other
persons soliciting acceptances of the Exchange Offer. The Company will, however,
pay the Exchange Agent reasonable and customary fees for its services and will
reimburse the Exchange Agent for its reasonable out-of-pocket costs and expenses
in connection therewith and will indemnify the Exchange Agent for all losses and
claims incurred by it as a result of the Exchange Offer. The Company may also
pay brokerage houses and other custodians, nominees and fiduciaries the
reasonable out-of-pocket expenses incurred by them in forwarding copies of this
Prospectus, Letters of Transmittal and related documents to the beneficial
owners of the Old Notes and in handling or forwarding tenders for exchange.
The expenses to be incurred in connection with the Exchange Offer,
including fees and expenses of the Exchange Agent and Trustee and accounting and
legal fees and printing costs, will be paid by the Company.
The Company will pay all transfer taxes, if any, applicable to the exchange
of Old Notes pursuant to the Exchange Offer. If, however, certificates
representing Exchange Notes or Old Notes
31
<PAGE> 37
for principal amounts not tendered or accepted for exchange are to be delivered
to, or are to be registered or issued in the name of, any person other than the
registered holder of the Old Notes tendered, or if tendered Old Notes are
registered in the name of any person other than the person signing the Letter of
Transmittal, or if a transfer tax is imposed for any reason other than the
exchange of Old Notes pursuant to the Exchange Offer, then the amount of any
such transfer taxes (whether imposed on the registered holder or any other
persons) will be payable by the tendering holder. If satisfactory evidence of
payment of such taxes or exemption therefrom is not submitted with the Letter of
Transmittal, the amount of such transfer taxes will be billed by the Company
directly to such tendering holder.
ACCOUNTING TREATMENT
The Exchange Notes will be recorded at the same carrying value as the Old
Notes, as reflected in the Company's accounting records on the date of the
exchange. Accordingly, no gain or loss for accounting purposes will be
recognized by the Company as a result of the consummation of the Exchange Offer.
The expenses of the Exchange Offer will be amortized by the Company over the
term of the Exchange Notes.
CONSEQUENCES OF FAILURE TO EXCHANGE
Participation in the Exchange Offer is voluntary. Holders of the Old Notes
are urged to consult their financial and tax advisors in making their own
decisions as to what action to take.
As a result of the making of, and upon acceptance for exchange of all
validly tendered Old Notes pursuant to the terms of, this Exchange Offer, the
Company will have fulfilled a covenant contained in the Registration Rights
Agreement. Holders of the Old Notes who do not tender their Old Notes in the
Exchange Offer will continue to hold such Old Notes and will be entitled to all
the rights, and subject to the limitations applicable thereto, under the
Indenture and the Registration Rights Agreement, except for any such rights
under the Registration Rights Agreement that by their terms terminate or cease
to have further effect as a result of the making of this Exchange Offer. See
"Description of the Notes." All untendered Old Notes will continue to be subject
to the restrictions on transfer set forth in the Indenture. The Old Notes may
not be offered, resold, pledged or otherwise transferred, prior to the date that
is two years after the later of May 23, 1997 and the last date on which the
Company or any "affiliate" (within the meaning of Rule 144 of the Securities
Act) of the Company was the owner of such Old Note except (i) to the Company,
(ii) pursuant to a registration statement which has been declared effective
under the Securities Act, (iii) to Qualified Institutional Buyers in reliance
upon the exemption from the registration requirements of the Securities Act
provided by Rule 144A, (iv) to institutional "accredited investors" (as defined
in Rule 501(a)(1), (2), (3) or (7) under the Securities Act) in transactions
exempt from the registration requirements of the Securities Act, (v) in
transactions complying with the provisions of Regulation S under the Securities
Act or (vi) pursuant to any other available exemption from the registration
requirements under the Securities Act. To the extent that Old Notes are tendered
and accepted in the Exchange Offer, the liquidity of the trading market for
untendered Old Notes could be adversely affected.
The Company may in the future seek to acquire untendered Old Notes in the
open market or through privately negotiated transactions, through subsequent
exchange offers or otherwise. The Company intends to make any such acquisitions
of Old Notes in accordance with the applicable requirements of the Exchange Act
and the rules and regulations of the SEC thereunder, including Rule 14e-1, to
the extent applicable. The Company has no present plan to acquire any Old Notes
that are not tendered in the Exchange Offer or to file a registration statement
to permit resales of any Old Notes that are not tendered in the Exchange Offer.
32
<PAGE> 38
USE OF PROCEEDS
The Company will not receive any cash proceeds from the issuance of the
Exchange Notes offered hereby. In consideration for issuing the Exchange Notes
as contemplated in this Prospectus, the Company will receive in exchange Old
Notes in like principal amount. The form and terms of the Exchange Notes are
identical in all material respects to the form and terms of the Old Notes,
except that (i) the offering of the Exchange Notes has been registered under the
Securities Act, (ii) the Exchange Notes will not be subject to transfer
restrictions and (iii) certain provisions relating to an increase in the stated
interest rate on the Old Notes provided for under certain circumstances will be
eliminated. The Old Notes surrendered in exchange for Exchange Notes will be
retired and canceled and cannot be reissued. Accordingly, issuance of the
Exchange Notes will not result in a change in the indebtedness of the Company.
33
<PAGE> 39
CAPITALIZATION
The following table sets forth as of March 31, 1997, (i) the historical
capitalization of the Company and (ii) the historical capitalization of the
Company as adjusted to give effect to the Offering and the application of the
proceeds therefrom. The information was derived from, and is qualified by
reference to, the consolidated financial statements of the Company, including
the notes thereto, included elsewhere in this Prospectus. This information
should be read in conjunction with such financial statements, including the
notes thereto, and "Management's Discussion and Analysis of Financial Condition
and Results of Operations" included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
AS OF MARCH 31, 1997
-------------------------
HISTORICAL AS ADJUSTED
---------- -----------
(DOLLARS IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents................................... $ 14,331 $ 28,231
======== ========
Short-term debt(1).......................................... $ 26,614 $ 26,614
======== ========
Long-term debt:
Revolving credit facilities:
Existing revolving credit facility..................... $136,648 --
Revolving Credit Facility(2)........................... -- --
7.59% Senior Notes due 2010(3)............................ 60,000 $ 60,000
10.75% Senior Secured Notes due 2005(4)................... 35,000 --
9 1/2% Senior Subordinated Notes due 2007................. -- 200,000
Other..................................................... 160 160
-------- --------
Total long-term debt.............................. 231,808 260,160
-------- --------
Total stockholders' equity(5)............................... 47,905 39,505
-------- --------
Total capitalization.............................. $279,713 $299,665
======== ========
</TABLE>
- ---------------
(1) Consists primarily of unsecured bank lines of credit providing for an
aggregate principal amount of $73.0 million in borrowing capacity. During
the nine months ended March 31, 1997, the maximum outstanding daily balance
was approximately $45.0 million. The weighted average interest rate was
5.97% on the balances outstanding for the nine months ended March 31, 1997.
The Company had no outstanding balance under its short-term bank lines of
credit for a period of 30 days in fiscal 1996. See "Description of Other
Indebtedness."
(2) The borrowing base under the Revolving Credit Facility at June 8, 1997 was
approximately $50.0 million. Borrowings under this facility, if any, will be
used for general corporate purposes. Such amounts do not include
approximately $12.0 million in letters of credit. See "Description of Other
Indebtedness -- Indebtedness of the Company -- Credit Agreement."
(3) The 7.59% Senior Notes due 2010 were issued by Mountaineer, a subsidiary of
the Company. See "Description of Other Indebtedness -- Indebtedness of
Subsidiaries -- Mountaineer."
(4) The 10.75% Senior Secured Notes due 2005 were issued by ESC, a subsidiary of
the Company. Such notes were paid in full with the proceeds from the
Offering.
(5) The decrease in stockholders' equity represents the after-tax write-off of
$2.96 million ($4.3 million on a pre-tax basis) of unamortized financing
costs and approximately $5.4 million of make-whole premium ($7.9 million on
a pre-tax basis) related to the debt which was repaid with the net proceeds
of the Offering.
34
<PAGE> 40
SELECTED CONSOLIDATED FINANCIAL INFORMATION
The following tables present summary historical and pro forma financial
data for the Company. The selected historical financial information as of and
for each year in the two year period ended June 30, 1993 have been derived from
the consolidated financial statements of Eastern American. Effective June 30,
1993, the Company, under common control with the shareholders of Eastern
American, entered into an Exchange Agreement with the shareholders of Eastern
American whereby Eastern American became a wholly-owned subsidiary of the
Company. The selected historical financial information for each year in the
three year period ended June 30, 1996 and for the nine months ended March 31,
1997 and as of the respective period end have been derived from the audited
consolidated financial statements of the Company. The consolidated financial
statements as of March 31, 1997 and June 30, 1996 and for the nine month period
ended March 31, 1997 and the years ended June 30, 1996 and 1995 are included
elsewhere herein together with the report of Deloitte & Touche LLP, independent
auditors. The selected historical data for the nine months ended March 31, 1996
have been derived from the Company's consolidated financial statements which
have not been audited, but reflect, in the opinion of management, all
adjustments which include only normal recurring adjustments necessary to present
fairly the information contained herein. Interim results are not necessarily
indicative of results to be expected for any fiscal year. This information
should be read in conjunction with "Capitalization", "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and the
consolidated financial statements of the Company, including the notes thereto,
included elsewhere in this Prospectus.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED JUNE 30, MARCH 31,
---------------------------------------------------- -------------------
1992 1993 1994 1995 1996 1996 1997
-------- -------- -------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS, EXCEPT RATIOS)
<S> <C> <C> <C> <C> <C> <C> <C>
STATEMENT OF OPERATIONS DATA(1)(2):
Revenues:
Oil and gas sales........................ $ 30,640 $ 28,834 $ 30,545 $ 29,277 $ 31,940 $ 23,861 $ 27,002
Utility gas sales and transportation..... 182,929 157,320 146,965
Gas marketing and pipeline sales......... 37,213 49,222 59,563 103,015 146,398 101,961 120,257
Well operations and service.............. 5,418 4,593 5,134 3,955 14,003 10,562 10,700
Other revenue(3)......................... (716) 623 547 9,247 524 414 229
-------- -------- -------- -------- -------- -------- --------
Total revenues..................... 72,555 83,272 95,789 145,494 375,794 294,118 305,153
-------- -------- -------- -------- -------- -------- --------
Costs and expenses:
Field operating.......................... 6,488 10,213 11,657 11,510 21,796 16,325 15,162
Utility operations and maintenance....... 23,841 17,849 15,480
Utility gas purchased(4)................. 95,157 75,927 85,705
Gas marketing and pipeline costs......... 32,322 42,811 54,978 100,251 138,067 94,320 112,913
Taxes, other than income................. 1,889 1,746 1,250 1,560 16,165 13,706 15,039
General and administrative............... 4,117 4,526 6,271 6,689 23,967 17,380 16,479
Depletion, depreciation, and
amortization........................... 12,597 9,140 8,308 12,041 18,817 15,113 14,980
Interest expense......................... 12,876 9,168 7,501 8,744 23,182 18,164 17,005
Exploration and impairment costs......... 323 2,532 1,681 281 6,756 2,637 3,613
-------- -------- -------- -------- -------- -------- --------
Total costs and expenses........... 70,612 80,136 91,646 141,076 367,748 271,421 296,376
-------- -------- -------- -------- -------- -------- --------
Operating income....................... 1,943 3,136 4,143 4,418 8,046 22,697 8,777
Other (income) and expenses:
Gain on sale of assets(5)................ (270) (9,145) (279) (3,934) (2,499) (8,153)
Other (income) expense(6)................ (1,376) 6,220 3,391 367 693 (421) (604)
Minority interest........................ 107 1,634 435 193 130 339
-------- -------- -------- -------- -------- -------- --------
Income before provision for taxes and
cumulative effect of accounting
change................................. 3,589 5,954 (882) 3,895 11,094 25,487 17,195
Income tax expense....................... 304 381 478 2,710 3,274 7,646 4,960
-------- -------- -------- -------- -------- -------- --------
Income (loss) before cumulative effect of
accounting change...................... 3,285 5,573 (1,360) 1,185 7,820 17,841 12,235
Cumulative effect of change in accounting
for income taxes....................... 3,204
-------- -------- -------- -------- -------- -------- --------
Net income......................... $ 3,285 $ 5,573 $ 1,844 $ 1,185 $ 7,820 $ 17,841 $ 12,235
======== ======== ======== ======== ======== ======== ========
</TABLE>
35
<PAGE> 41
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED JUNE 30, MARCH 31,
---------------------------------------------------- -------------------
1992 1993 1994 1995 1996 1996 1997
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
EBITDA(7).................................. $ 27,739 $ 23,976 $ 21,633 $ 25,484 $ 56,801 $ 58,611 $ 44,375
Adjusted EBITDA(8)......................... $ 27,739 $ 23,976 $ 21,633 $ 25,484 $ 41,432 $ 45,303 $ 32,110
Net cash provided by operating
activities............................... $ 20,064 $ 48,283 $ 7,466 $ 14,020 $ 17,094 $ 8,107 $ 6,699
Net cash provided by/(used in) investing
activities............................... $(23,383) $ 17,076 $(40,878) $ 92,440 $ 22,823 $ 12,154 $ 9,551
Net cash provided by/(used in) financing
activities............................... $ (1,737) $(49,829) $ 21,884 $ 90,631 $ (198) $ (3,664) $ 2,986
Pro forma interest expense(9).............. N/A N/A N/A N/A $ 23,554 N/A $ 17,666
Pro forma adjusted interest
expense(10).............................. N/A N/A N/A N/A $ 19,000 N/A $ 14,250
Capital expenditures(11)................... $ 13,845 $ 27,837 $ 23,679 $ 93,226 $ 39,445 $ 31,576 $ 21,555
Ratios:
EBITDA to interest expense............... 2.15x 2.62x 2.88x 2.91x 2.45x 3.23x 2.61x
EBITDA to pro forma interest expense..... N/A N/A N/A N/A 2.41x N/A 2.51x
Earnings to fixed charges(12)............ 1.26x 1.61x .84x 1.35x 1.44x 2.34x 1.98x
Total long-term debt to EBITDA(13)(14)... 4.90x 3.70x 5.20x 10.50x 4.66x N/A N/A
Adjusted EBITDA to adjusted pro forma
interest expense(8).................... N/A N/A N/A N/A 2.18x N/A 2.25x
BALANCE SHEET DATA (AT END OF
PERIOD)(15)(16):
Cash and cash equivalents................ $ 3,709 $ 19,441 $ 7,913 $ 20,124 $ 14,197 $ 12,412 $ 14,331
Total assets............................. $199,551 $190,594 $222,491 $471,497 $461,504 $506,967 $454,446
Long-term debt(13)....................... $135,917 $ 88,687 $112,430 $267,647 $264,698 $259,391 $231,808
Stockholders' equity..................... $ 32,525 $ 33,068 $ 31,241 $ 31,613 $ 37,550 $ 48,496 $ 47,905
</TABLE>
- ---------------
(1) The fiscal year ended June 30, 1996 includes $8.3 million of revenue, $3.2
million of EBITDA and $0.9 million of net income attributable to the
Company's interest in certain producing properties which were sold in March
1997.
(2) The Company acquired its natural gas distribution operation in June 1995
and, accordingly, the fiscal year ended June 30, 1996 was the first fiscal
year that the operating results of the natural gas distribution operation
were included in the Company's consolidated operations.
(3) For the year ended June 30, 1995, other revenue includes an $8.8 million
contract settlement with Columbia Gas. The settlement relates to damages
paid by Columbia Gas as a result of its rejection in bankruptcy of certain
gas purchase contracts.
(4) For the nine months ended March 31, 1997, utility gas purchased includes a
$6.0 million adjustment for refunds due a subsidiary of the Company from
Columbia Gas related to a settlement approved by the Federal Energy
Regulatory Commission on April 17, 1997. In addition, the Company will
benefit in future periods from the lower rates established in such
settlement.
(5) For the fiscal year ended June 30, 1993, gain on sale of properties
represents the gain realized on the sale of oil and gas properties to the
Royalty Trust.
(6) For the fiscal year ended June 30, 1993, other income and expense includes
a $5 million non-cash expense for the write-off of unamortized deferred
financing costs. The write-off was necessary as new long-term financing was
obtained.
(7) EBITDA represents operating income of the Company and its subsidiaries on a
consolidated basis plus exploration and impairment expense, interest
expense, depletion, depreciation, and amortization expense. Such definition
of EBITDA may not be the same as the definition of EBITDA utilized by
comparable companies. EBITDA is not presented as an indicator of the
Company's operating performance or as a measure of liquidity calculated in
accordance with generally accepted accounting principles.
(8) Adjusted EBITDA represents EBITDA as adjusted to give effect to contractual
restrictions contained in note purchase agreements to which certain
subsidiaries of the Company were parties prior to the Offering that limit
the amount of cash dividends that may be paid by such subsidiaries to the
Company. All such note purchase agreements were terminated after the
Offering except that to which Mountaineer is a party. See "Description of
Other Indebtedness -- Indebtedness of Subsidiaries -- Mountaineer."
(9) Reflects interest expense pro forma for the Offering as if it had occurred
at the beginning of fiscal 1996. It also excludes interest expense
attributable to the interests sold in March 1997.
(10) Reflects interest expense pro forma for the Offering, less annual interest
expense of $4.6 million associated with debt at certain of the Company's
subsidiaries referred to in footnote (8) above.
(11) Capital expenditures for 1995 includes $73.2 million for the acquisition of
the Company's natural gas distribution utility and related properties.
(12) For the purposes of determining the ratio of earnings to fixed charges,
earnings are defined as income before taxes plus fixed charges. Fixed
charges consist of interest expense. Earnings were $1.3 million short of an
earnings to fixed charges ratio of 1.0 to 1.0.
(13) Long-term debt (i) includes current maturities of long-term debt and (ii)
excludes short-term borrowing under lines of credit.
(14) On a pro forma basis after giving effect to the Offering and the
application of the net proceeds therefrom, the ratio of total long-term
debt to EBITDA would have been 4.58x in fiscal 1996.
(15) As of March 31, 1997, after giving pro forma effect to the Offering and the
application of the net proceeds therefrom, the amount of cash and cash
equivalents would have been $28.2 million and the amount of long-term debt
would have been $260.2 million.
(16) The Company acquired its natural gas distribution operation in June 1995
and, accordingly, the balance sheet of the Company at June 30, 1995
includes the assets and liabilities of these companies as of such date.
36
<PAGE> 42
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the Company's
consolidated financial statements and notes thereto (including the segment
information contained therein) and the selected consolidated financial data
included elsewhere herein.
GENERAL
The Company has achieved significant growth in revenues, net income, and
cash flows since 1994 through its acquisition of a natural gas local
distribution company, select acquisitions, development of gas and oil properties
and marketing activities. The Company acquired its natural gas distribution
operation in June 1995. Accordingly, fiscal 1996 was the first year that the
operating results of the natural gas distribution operation were included in the
Company's consolidated operations. The Company has sold certain gas and oil
assets from time to time as its strategy has expanded to include control over
and marketing of gas and oil production. Such dispositions have also enabled the
Company to monetize certain tax credits which it might not otherwise have been
able to use. Proceeds from these dispositions were used to repay outstanding
indebtedness. The following table sets forth selected financial and operating
data as well as the percentage change for each of the years and period
presented:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
YEAR ENDED JUNE 30, MARCH 31,
--------------------------------------------------- ------------------------------
1994 1995 % CHANGE 1996 % CHANGE 1996 1997 % CHANGE
------- -------- -------- -------- -------- -------- -------- --------
(DOLLARS IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FINANCIAL RESULTS:
Revenues....................... $95,789 $145,494 52% $375,794 158% $294,118 $305,153 4%
Cost and expenses.............. 91,646 141,076 54% 367,748 161% 271,421 296,376 9%
Net income..................... 1,844 1,185 (36%) 7,820 560% 17,841 12,235 (31%)
EBITDA......................... 21,633 25,484 18% 56,801 123% 58,611 44,375 (24%)
OPERATING RESULTS:
Proved reserves (Bcfe)......... 212.3 213.9 1% 199.5 (7%) 205.0 172.9 (16%)
Production volumes
(Mmcfe/day).................. 31.6 33.4 6% 35.5 6% 36.1 35.8 (1%)
Marketed volumes (Mmcfe/day)... 98 142 45% 145 2% 141 153 9%
</TABLE>
The Company's revenues are derived from utility gas sales, sales of gas and
oil and gas marketing operations. Utility gas sales are largely seasonal due to
the use of gas as a heating source in residential and commercial buildings.
Historically, a significant portion of the Company's utility gas volumes are
attributable to sales during the six month winter heating season, with highest
sales volumes occurring in December, January and February. In fiscal 1996, gas
sales from October through March accounted for approximately 83% of utility gas
sales for that year. Because a substantial portion of the Company's revenues are
generated by sales of gas used for heating, the Degree Days experienced in the
Company's areas of operations, particularly during the peak heating season, will
have a significant effect on the Company's financial performance.
The revenues, profitability and future rate of growth of the Company's
exploration and production operations are substantially dependent on prevailing
prices for natural gas, oil and condensate. The energy markets have historically
been very volatile and gas and oil prices have been and may continue to be
subject to wide fluctuations. The Company attempts to mitigate the adverse
effects of price volatility by entering into gas sales contacts which are medium
to long term and which provide for fixed and escalating pricing.
37
<PAGE> 43
RESULTS OF OPERATIONS
COMPARISON OF NINE MONTHS ENDED MARCH 31, 1997 TO NINE MONTHS ENDED MARCH 31,
1996
Net Income. The Company's net income decreased from $17.8 million to $12.2
million for the respective nine month periods. The change is primarily
attributable to a $10.3 million decrease in utility sales and a $9.8 million
increase in utility gas purchase costs offset partially by a $2.3 million
decrease in operations and maintenance expense, the inclusion in the current
period of a gain on sale of assets of $8.2 million, and a net positive change in
income tax provision of $2.7 million.
Revenues. Revenues from operations increased 3.7%, from $294.1 million to
$305.2 million during the most recent nine month period. The increase is due to
a 13% increase in oil and gas sales and an 18% increase in gas marketing sales
offset by a 7% decrease in utility sales and transportation.
Utility sales decreased 7% primarily as a result of a 14% decrease in the
weighted average number of Degree Days during the most recent nine month period.
The table below presents for the periods indicated, revenue, volumes and certain
other data related to utility operations:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
MARCH 31,
----------------------
1996 1997
-------- --------
<S> <C> <C>
Gas distribution revenue (in thousands)
Residential.............................................. $107,698 $ 95,136
Commercial............................................... 34,809 33,838
Industrial............................................... 2,819 4,394
Other.................................................... 7,490 5,978
Transportation........................................... 4,504 7,619
-------- --------
$157,320 $146,965
======== ========
Weighted average sales rate (per Mcf)...................... $ 6.31 $ 6.33
Average transportation sales rate (per Mcf)................ $ 0.16 $ 0.27
Miles of distribution pipe................................. 3,871 3,912
Weighted average Degree Days............................... 4,985 4,285
Number of customers........................................ 199,201 199,901
Total throughput volumes................................... 53,112 50,367
</TABLE>
Gas marketing and pipeline revenues increased $18.3 million from $102.0
million to $120.3 million for the respective nine month periods. Gas marketing
and pipeline sales volumes (exclusive of gas gathering and gas processing
volumes) increased 9% from 141.0 Mmcf per day to 153.0 Mmcf per day while the
average price increased 9% from $2.67 per Mcf to $2.92 per Mcf. The Company's
margin on gas gathering and gas processing activities increased 20% from
approximately $0.5 million to $0.6 million.
Oil and gas production volumes remained at 9.7 Bcfe, while the Company
realized an $0.18 per Mcf increase in natural gas sales price and a $2.72 per
Bbl increase in oil prices. Operating margins from oil and gas operations
increased $0.36 per Mcfe during the periods.
38
<PAGE> 44
The table below presents for the periods indicated, data related to the gas
and oil producing activities of the Company:
<TABLE>
<CAPTION>
NINE MONTHS ENDED MARCH 31,
-----------------------------
1996 1997 % CHANGE
------ ------- ---------
<S> <C> <C> <C>
Production volumes
Natural gas (Mmcf).................................... 7,414 7,113 (4%)
Oil (Mbbls)........................................... 387 425 10%
Natural gas equivalents (Mmcfe)....................... 9,739 9,664 (1%)
Natural gas equivalents (Mmcfe/day)................... 36.1 35.8 (1%)
Sale of reserves in place (Mmcfe)....................... -- 34,697 --
</TABLE>
Well operations and other revenues were unchanged.
Costs and Expenses. The Company's costs and expenses increased 9% from
$271.4 million to $296.4 million from period to period, primarily as a result of
utility gas and marketing gas purchase costs which increased 17% during the most
recent nine month period.
Utility gas purchase costs increased $9.8 million or 13% over the prior
period. Approximately $8.0 million of the increase arises from expensing, as
incurred, costs which would have been deferred prior to the rate moratorium. An
additional $1.5 million of the increase is due to higher costs of purchased gas
in the current period, partially offset by a 10% decrease in purchased gas
volumes delivered to residential and commercial customers.
The following table represents for the periods indicated purchased gas
volumes sold to the Company's gas utility customers (in Mmcf):
<TABLE>
<CAPTION>
NINE MONTHS ENDED MARCH 31,
---------------------------
1996 1997 % CHANGE
------ ------ --------
<S> <C> <C> <C>
Residential............................................ 16,600 14,513 (13%)
Commercial............................................. 5,717 5,535 (3%)
Industrial............................................. 609 878 44%
Other.................................................. 1,309 1,074 (18%)
------ ------ ----
Total purchased gas volumes.................. 24,235 22,000 (9%)
====== ====== ====
</TABLE>
Field operating costs decreased 7% from $16.3 million to $15.2 million for
the respective nine month periods as a result of lower per unit well costs.
Operations and maintenance costs were 13% lower than the prior period.
Costs were higher in the prior period due to a one time severance charge of $1.3
million resulting from the relocation of a customer service center operation and
a $0.6 million bad debt allowance.
Exploration and impairment costs increased 37% to $3.6 million due to
increased charges related to geological and geophysical costs and activities for
the most recent period.
Production and other taxes were 10% higher than the prior period due to
generally higher revenue levels.
General and administrative costs were generally comparable between the two
periods.
Depreciation, depletion and amortization expense were comparable between
the two periods. Unit of production depletion rates were unchanged at $0.87 per
Mcfe.
Interest Expense. Interest expense decreased 6% from $18.2 million to $17.0
million in the most recent period. The decrease was primarily related to
generally lower outstanding debt levels.
Other Income and Expense. Other income and expense included a $3.2 million
gain on sale of oil and gas properties in the 1996 period and an $8.2 million
gain on sale of certain oil and gas properties in the most recent period.
39
<PAGE> 45
Income Taxes. Income tax expense decreased $2.7 million as a result of
decreased book pre-tax income levels. The amount of such expense at March 31,
1996 is based on an interperiod allocation of the final tax provision for fiscal
1996. The provision at March 31, 1997 is based on the Company's effective tax
rate on the results of operations for the nine month period.
COMPARISON OF FISCAL YEAR ENDED JUNE 30, 1996 TO FISCAL YEAR ENDED JUNE 30, 1995
Net Income. The Company's net income increased, from $1.2 million in fiscal
1995 to $7.8 million in fiscal 1996. The increase from the Company's fiscal 1995
net income resulted primarily from the inclusion of the consolidated operating
income of the Company's natural gas distribution utility, which utility
generated $28.6 million in earnings before interest charges of $10.9 million and
provision for income tax of $6.4 million.
Revenues. Revenues from operations increased 158%, from $145.5 million in
fiscal 1995 to $375.8 million in fiscal 1996. The increase is primarily
attributable to the addition of $182.9 million in utility gas sales to the
Company's revenue base.
Revenues from utility gas sales and transportation revenues increased 17%
from $156.8 million in fiscal 1995 to $182.9 million in fiscal 1996. The
increased revenues were primarily related to increased volumes of gas sold due
to significantly colder weather conditions (4,651 Degree Days in fiscal 1995
versus 5,535 Degree Days in fiscal 1996). This increase was partially offset by
a $.05 per Mcf reduction in rates which went into effect at November 1, 1995.
The table below represents, for the periods indicated, revenue, volumes and
certain other data related to utility operations:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------
1995 1996
-------- --------
<S> <C> <C>
Gas distribution revenue (in thousands)
Residential.......................................... $113,330 $130,202
Commercial........................................... 31,775 43,462
Industrial........................................... 391 1,670
Other................................................ 272 517
Transportation....................................... 10,986 7,078
-------- --------
Total........................................ $156,754 $182,929
======== ========
Weighted average sales rate (per Mcf).................. $ 6.65 $ 6.40
Average transportation sales rate (per Mcf)............ $ 0.29 $ 0.19
Miles of distribution pipe............................. 3,853 3,887
Weighted average Degree Days........................... 4,651 5,535
Number of customers.................................... 198,293 199,287
Total throughput volumes............................... 59,738 65,194
</TABLE>
Revenues from oil and gas sales increased 9% from $29.3 million in fiscal
1995 to $31.9 million in fiscal 1996. The table below presents, for the years
and periods indicated certain information related to the oil and gas producing
activities of the Company:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
----------------------------
1995 1996 % CHANGE
------ ------ --------
<S> <C> <C> <C>
Production volumes
Natural gas (Mmcf)............................. 8,982 9,816 9%
Oil (Mbbls).................................... 534.7 522.4 (2%)
Natural gas equivalents (Mmcfe)................ 12,190 12,950 6%
Natural gas equivalents (Mmcfe/day)............ 33.4 35.5 6%
</TABLE>
The 6% increase in production volumes was primarily due to reserves
acquired with the natural gas distribution utility as well as the initiation of
production from wells drilled during the previous
40
<PAGE> 46
period, partially offset by the effects of expected production declines and the
disposition of certain properties in the Appalachian Basin. See "Business and
Properties -- Significant Acquisitions and Dispositions." The production
increase was accompanied by average natural gas and oil price increases of 3%
and 7%, respectively, from fiscal 1995 to fiscal 1996. Operating margins from
oil and gas operations increased $0.11 per Mcfe.
Revenues from well operations increased 254% to $14.0 million in fiscal
1996 from $4.0 million in fiscal 1995, largely as a result of the increased
number of operated properties associated with reserves acquired and well
operations assumed as part of the acquisition of the natural gas distribution
utility as well as from well operations performed by the Company on certain
properties which were sold in fiscal 1996.
Gas marketing and pipeline revenues increased $43.4 million from $103.0
million to $146.4 million from fiscal year 1995 to fiscal year 1996. Gas
marketing and pipeline sales volumes (exclusive of gas gathering and gas
processing volumes) increased 2% from 142.0 Mmcf per day to 145.0 Mmcf per day
while the average price increased 39% from $1.98 per Mcf to $2.76 per Mcf. The
Company's margin on gas gathering and gas processing activities increased 50%
from $0.4 million to $0.6 million, primarily as a result of the gas gathering
systems acquired with the Company's gas distribution utility.
Other net revenue decreased 94.6% from $9.2 million in fiscal 1995 to $0.5
million in fiscal 1996. The difference was attributable to $8.8 million in
damages which were paid by Columbia Gas to the Company in fiscal 1995 as a
result of Columbia Gas' rejection in bankruptcy of certain gas purchase
contracts.
Costs and Expenses. The Company's costs and expenses increased 161% from
$141.1 million in fiscal 1995 to $367.7 million in fiscal 1996, primarily as a
result of the addition of $95.2 million of gas purchase costs, operations and
maintenance expense, and general and administrative expenses associated with the
Company's utility gas sales and operations.
Expenses associated with utility gas purchases decreased 1% from $96.0
million in fiscal 1995 to $95.2 million in fiscal 1996, primarily as a result of
a reduction from $4.38 to $3.46 in the cost of gas sold per Mcf. Decreased
utility gas purchases were partially offset by increased purchased gas volumes
required by residential and commercial customers during a winter season with 19%
more Degree Days than in the prior period. The following table represents for
the year indicated purchased gas volumes sold to the Company's gas utility
customers.
<TABLE>
<CAPTION>
1995 % 1996 %
------ --- ------ ---
<S> <C> <C> <C> <C>
Gas distribution volumes (Mmcf)
Residential................................. 16,854 77% 19,898 72%
Commercial.................................. 4,908 22% 7,107 26%
Industrial.................................. 83 -- 374 1%
Other....................................... 66 -- 89 --
------ --- ------ ---
Total purchased gas volumes......... 21,911 100% 27,468 100%
====== === ====== ===
</TABLE>
Production and other taxes increased from $1.6 million in fiscal 1995 to
$16.2 million in fiscal 1996, primarily as a result of the inclusion of utility
based taxes (other than income) of $15.2 million for fiscal 1996 associated with
the Company's natural gas distribution utility. Production taxes on oil and gas
operations and utility based taxes are at fixed statutory rates based on gross
revenue and sales. Production taxes on oil and gas activities declined $0.1
million based on utilization of tax credits and lower production volumes.
Operations and maintenance expense for utility operations increased the
Company's total costs and expenses by $23.8 million. Operations and maintenance
increased by approximately 12.8% from $21.1 million in fiscal 1995 to $23.8
million in fiscal 1996. This increase is primarily due to an
41
<PAGE> 47
increase in bad debt reserves and to costs incurred in connection with the
opening of a new customer service center in fiscal 1996.
Field operating expenses increased from $11.5 million in fiscal 1995 to
$21.8 million in fiscal 1996. The higher costs were related to the larger base
of operated properties resulting from the reserves acquired and the well
operations assumed as part of the acquisition of the natural gas distribution
utility and other costs.
General and administrative expenses increased from $6.7 million in fiscal
1995 to $24.0 million in fiscal 1996 as a result of the inclusion of utility
based expenses during this period. General and administrative expenses
associated with the Company's continuing operations were unchanged.
Depreciation, depletion and amortization increased from $12.0 million in
fiscal 1995 to $18.8 million in fiscal 1996 as a result of the inclusion of $7.5
million of depreciation, depletion and amortization relating to utility
operations of which approximately $1.0 million related to the amortization of a
portion of the natural gas distribution utility purchase price. Depletion
related to oil and gas activities was relatively unchanged from fiscal 1995 to
fiscal 1996 with the effects of higher equivalent production volumes being
partially offset by lower per unit depletion rates.
Exploration and impairment costs increased from $0.3 million in fiscal 1995
to $6.8 million in fiscal 1996. The majority of such increase related to the
abandonment of certain plays in the Appalachian Basin, with the balance
attributable to an unsuccessful exploratory well drilled in New Zealand and
unsuccessful exploration activities in the Rocky Mountains.
Interest Expense. Interest expense increased 166% from $8.7 million in
fiscal 1995 to $23.2 million in fiscal 1996. The increase is primarily due to
additional borrowings associated with the acquisition of the Company's natural
gas distribution utility (including $58.4 million of debt assumed in the
transaction) as well as higher variable borrowing rates on the Company's
revolving and short-term facilities.
Other Income and Expense. Other income and expenses included a gain on sale
of properties for fiscal 1996. The gain resulted from the sale of interests in
certain oil and gas properties to a limited partnership for approximately $17.3
million. The proceeds from this sale were used primarily to reduce outstanding
indebtedness.
Income Taxes. The Company's effective tax rates in 1996 and 1995 were lower
than statutory federal tax rates primarily due to the recognition of
nonconventional fuel tax credits, state income tax credits and investment tax
credits. Changes in income tax expense for the fiscal years resulted from an
increase in pre-tax income.
LIQUIDITY AND CAPITAL RESOURCES
General. The Company's sources of liquidity and capital resources
historically have been net cash provided by operating activities, funds
available under its credit facilities and proceeds from the sales of assets. In
the past, these sources have been sufficient to meet its needs and finance the
growth of the Company's business. The Company believes that the amounts
available to be borrowed under its Revolving Credit Facility described below,
together with the proceeds from the Offering and cash provided by operating
activities will provide it with sufficient funds to explore for and develop new
oil and gas reserves and maintain its gas distribution system for the
foreseeable future. Net cash provided by operating activities is primarily
affected by oil and gas prices, weather, rate regulation, the Company's success
in drilling activities and margins on third-party gas purchased for resale.
Depending on the timing of the Company's future projects, it may be required to
seek additional sources of capital. The Company's ability to secure such capital
is restricted by its credit facilities, although it may request additional
borrowing capacity from the banks, seek waivers from its lenders to permit it to
borrow funds from third-parties, seek replacement credit facilities from other
lenders, sell existing assets or a combination of such alternatives. While the
Company believes that it would be able to secure additional financing, if
required, no assurance can be given
42
<PAGE> 48
that it will be able to do so or as to the terms of any such financing. The
Company believes that cash provided by operating activities will be sufficient
to meet its debt service and capital requirements through fiscal 1998.
Cash Flows. The Company's net cash from operating activities totaled $6.7
million, $17.1 million and $14.0 million for the nine months ended March 31,
1997 and the fiscal years 1996 and 1995 respectively.
Net cash provided by operating activities for the nine months ended March
31, 1997 was $1.4 million less than the comparable prior period. Net cash used
in investing activities at March 31, 1996 totaled $12.2 million, including $9.4
million for utility property expenditures, $4.1 million in exploration related
expenditures and $17.8 million for development related activities, partially
offset by the proceeds from the sale of certain oil and gas properties totaling
$18.7 million. Net cash used in investing activities at March 31, 1997 totaled
$9.6 million, including $7.4 million in expenditures relating to utility
activities, $3.7 million relating to exploration activities and $6.9 million
relating to development activities, partially offset by approximately $12.0
million in proceeds related to the sale of certain oil and gas properties. For
the nine months ended March 31, 1996, cash flows expended in financing
activities totaled $3.7 million and included a $27.3 million net increase in
long-term debt, a $25.7 million net decrease in short-term borrowings under the
Company's credit facilities and $4.4 million in financing costs. For the nine
months ended March 31, 1997, cash flows from financing activities totaled $3.0
million and included a net paydown on the Company's long-term credit facilities
of $13.2 million and a net increase of $18.2 million in short-term borrowings.
Net cash provided by operating activities was $3.1 million greater for the
year ended June 30, 1996 than the prior twelve month period. Net income adjusted
to reconcile net income to net cash was $16.6 million higher in the current
period, offset by a $13.5 million difference in changes in working capital.
Expenditures for plant, property and equipment were $39.4 million offset by
$17.3 million in proceeds from the sale of properties as compared to plant,
property and equipment expenditures for the prior period totaling $20.0 million
and $73.2 million expended for the acquisition of the Company's natural gas
distribution utility. The difference between the $39.4 million in property
expenditures for the current period and the $21.6 million for the prior period
is attributable primarily to inclusion for the first time of utility
expenditures of $13.0 million. Cash flows from financing activities were $90.8
million higher in the prior period as a result of the increased borrowings
related to the acquisition of the utility.
Working Capital. At March 31, 1997 the Company had negative working capital
of $15,600 as compared to negative working capital of $8,000 at June 30, 1996.
The $7,600 decrease in working capital was due to, among other things, increases
in current assets of $12.5 million, which included increases in accounts
receivable of $23 million offset by a decrease in gas-in-storage of $6.0 million
and a decrease in income tax receivable of $3.2 million as well as a decrease in
other assets of $1.3 million. Current liabilities increased $20 million, which
included increases in short-term debt of $18.2 million, increases in current
maturities of long-term debt of $1.9 million and accrued taxes, other than
income, of $4.9 million offset by a decrease in accounts payable of $4.9
million. Approximately $19.3 million of the increase in accounts receivable and
approximately 100% of the decrease in gas-in-storage, as well as the increase in
short-term debt, is related to the seasonal and weather sensitive nature of the
local distribution company business activities, as discussed herein elsewhere.
The income tax receivable of $3.2 million at June 30, 1996 has been
eliminated as a result of payments received therefor.
Allowances for doubtful accounts are primarily related to the activities of
the local distribution company and are not affected by the seasonal increases in
accounts receivable.
Capital Expenditures. The Company requires capital primarily for the
exploration, development and acquisition of oil and gas properties, the
maintenance and extension of its natural gas
43
<PAGE> 49
distribution pipeline system, natural gas marketing activities, repayment of
indebtedness, and general working capital needs.
Utility capital expenditures are estimated to be approximately $10.8
million in fiscal 1997 and remain at such levels in the near term, of which
approximately $5.5 million represents system integrity and reliability
expenditures. In addition, the utility has an option until December 31, 1997, to
purchase certain gas storage assets representing five storage fields with a
seasonal storage capacity of 2.7 Bcf at a net book cost of approximately $7.1
million from an interstate pipeline as part of a contract settlement
arrangement. Additionally, such investment levels may increase as a result of
the acquisition of other local distribution company assets. The utility
anticipates funding both planned, as well as discretionary capital expenditures
through internally generated capital, utilization of its short-term credit
facilities and other outside capital sources as available.
During 1994 the Company determined that an increased level of investment in
exploration, development and production activities was needed in order for both
to diversify on a geographic and commodity basis and to generate certain levels
of market penetration and earnings growth. Accordingly, the Company has begun to
focus on exploration and development opportunities outside the Appalachian Basin
and is currently pursuing projects in the Rocky Mountains and New Zealand. The
Company expects to expend approximately $6.9 million on exploration projects in
fiscal 1998. The Company expects to finance drilling and acquisition activities
(domestic and international) through internally generated capital from all
business segments and the Revolving Credit Facility, as well as developing
financial arrangements with industry partners and specialized financial
institutions. See "Business and Properties -- Gas and Oil Exploration and
Production."
While the Company currently intends to continue to make significant
investments in oil and gas exploration, development and production and may also
make significant investments to acquire business or properties and acquisitions,
the Company's plans will depend significantly on future product prices. Oil and
natural gas prices are volatile, and there are several potentially significant
adverse effects to the Company that can result if product prices decline
materially. First, lower product prices may adversely impact the Company's cash
flows and could cause the Company to (i) curtail its capital program, (ii)
borrow additional amounts under its Revolving Credit Facility or (iii) issue
additional debt or equity securities on terms less favorable than might
otherwise have been available. Second, lower product prices could cause the
borrowing base under the Revolving Credit Facility to be reduced and certain
covenant tests to be adversely affected. Third, if product prices remain low,
decline further and cannot be offset by additional reserves, the Company could
be required to write down its oil and gas properties resulting in a charge
against earnings. The likelihood or magnitude of any or all of these potential
impacts are impossible to predict or quantify at this time. See "Risk Factors"
and "Business and Properties -- Gas and Oil Exploration and Production -- Oil
and Gas Reserves."
The effects of a material decline in product prices can have a beneficial
effect on the results of operations for natural gas distribution, and such
effects are typically opposite the effects that declining prices would have on
the Company's oil and gas producing results of operations. During periods of
declining natural gas prices and to the extent that the natural gas distribution
company is able to acquire lower price gas supplies, operating margins and cash
flow from utility operations are generally improved.
Hedging Activities. Periodically the Company enters into futures, option
and swap contracts to reduce the effects of fluctuations in natural gas and
crude oil prices. The Company currently has interest rate hedging arrangements
in effect with respect to Eastern American's existing credit facility, which
interest rate hedging arrangements were terminated in connection with the
repayment of such indebtedness with the proceeds of the Offering. The Company
has no other material hedging arrangements outstanding. The Company may choose
to enter into hedging arrangements in the future should the Company determine
that such arrangements are advisable.
44
<PAGE> 50
Revolving Credit Facility. The Company received a commitment from General
Electric Capital Corporation to provide the Revolving Credit Facility
concurrently with the consummation of the Offering. The Revolving Credit
Facility provides for a revolving line of credit with the availability of funds
being subject to an annual borrowing base determination. The borrowing base
provides for a maximum availability of $50.0 million (which amount is also
expected to be the initial borrowing base). Borrowings under the Revolving
Credit Facility bear interest, at the Company's option, at a floating rate which
is at or above such financial institution's prime rate or a LIBOR rate,
depending on the percentage of committed funds which have been borrowed. See
"Description of Other Indebtedness -- Indebtedness of the Company." Interest is
payable quarterly. Principal will mature five years following the execution of
definitive loan documents. The Credit Agreement related to the Revolving Credit
Facility requires the Company to pay certain fees to such financial institution,
including a commitment fee based on the unused portion of the commitment. The
Revolving Credit Facility contains customary restrictive covenants (including
restrictions on the payment of dividends and the incurrence of additional
indebtedness) and requires the Company to maintain a current ratio of not less
than 1.0 to 1.0, a ratio of Adjusted EBITDA to Adjusted Interest Expense (in
each case as defined in the Credit Agreement) of not less than 1.5 to 1.0 and a
minimum tangible net worth of $30.0 million. At March 31, 1997, on a pro forma
basis, the Company's current ratio would have been 1.7 to 1.0, the ratio of
Adjusted EBITDA to Adjusted Interest Expense would have been 2.0 to 1.0 and the
Company would have exceeded the tangible net worth test by $9.5 million. The
Company believes it is in compliance with such covenants.
Short-Term Borrowings and Lines of Credit. Certain of the Company's
subsidiaries had unsecured short-term line of credit arrangements with banks
totaling $73.0 million as of March 31, 1997. Borrowings under these lines of
credit are anticipated to be used primarily to finance gas purchases and provide
working capital during peak sales periods. As of March 31, 1997, $26.6 million
was outstanding under these lines of credit. The lines of credit are typically
in effect for a period of one year and are renewed on a year-to-year basis.
Mountaineer's 7.59% Senior Notes due 2010 require Mountaineer to have (i) no
amounts outstanding under its lines of credit for a period of at least 30
consecutive days during each period of 12 consecutive months or (ii) a period of
30 consecutive days during each 12 month period when Mountaineer would be
entitled to incur at least $1 of additional Funded Indebtedness (as defined in
the Indenture) pursuant to which the notes were issued.
Effects of Inflation. Although certain of the Company's costs and expenses
may be affected by inflation, inflationary costs have not had a significant
impact on the Company's results of operations.
45
<PAGE> 51
BUSINESS AND PROPERTIES
Energy Corporation of America is a privately held, integrated energy
company primarily engaged in natural gas distribution in West Virginia and in
the development, production, transportation and marketing of natural gas and oil
in the Appalachian Basin. For the fiscal year ended June 30, 1996, the Company
had total revenues of $375.8 million and EBITDA of $56.8 million. During the
first nine months of fiscal 1997, the Company had revenues of $305.2 million and
EBITDA of $44.4 million.
The Company operates the largest natural gas distribution utility in West
Virginia, supplying natural gas sales and transportation service to
approximately 200,000 customers in 45 of the 55 counties in West Virginia. The
Company distributes approximately 57% of the total natural gas volumes
distributed to end users in West Virginia. In fiscal 1996, the Company owned and
operated approximately 3,900 miles of natural gas distribution pipelines and
sold or transported 65.2 Bcf of gas.
The Company is engaged in the development, production, transportation and
marketing of natural gas and oil in the Appalachian Basin. As of March 31, 1997,
the Company had estimated proved reserves of 172.9 Bcfe (95% natural gas and 90%
developed) with a Present Value (as defined in the Glossary) of $125.8 million.
For the fiscal year ended June 30, 1996, the Company's net gas and oil
production was approximately 13.0 Bcfe. The Company is one of the largest
operators in the Appalachian Basin where it holds interests in 4,755 gross
(2,503 net) wells, substantially all of which it operates. In addition, the
Company has recently commenced an exploration and development program in the
Rocky Mountains and New Zealand, having acquired leasehold interests in
approximately 431,000 gross acres (291,000 net acres) in the Rocky Mountain area
and approximately 5.2 million gross acres (2.6 million net acres) in New
Zealand.
The Company has developed a significant gas marketing and aggregation
business and owns and operates 2,000 miles of gathering and intrastate natural
gas pipelines in West Virginia and Pennsylvania. During fiscal 1996, the Company
aggregated and sold 150.0 Mmcf/day of natural gas, of which 41.1 Mmcf/day
represents gas produced from wells operated by the Company.
The Company has grown significantly since 1988 through acquisitions of oil
and gas companies or properties which have added proved reserves of
approximately 202.0 Bcfe, at an average acquisition cost of approximately $0.70
per Mcfe, and an interest in approximately 4,500 producing wells. In order to
capitalize on opportunities arising from the deregulation of the transportation
and distribution of natural gas, beginning in 1993 the Company broadened its
strategy from its traditional concentration on oil and gas exploration and
production to concentrate on building an integrated energy company focused on
controlling reserves and maximizing upstream and downstream values. As part of
its strategy, the Company acquired its natural gas distribution business in June
1995. During fiscal year 1996, approximately 25% of natural gas sold by the gas
distribution utility operation came from the Company's own production.
BUSINESS STRENGTHS
The Company believes it has certain strengths with respect to its business
activities, including the following:
- LOW COST OPERATIONS. Based on recent filings with the West Virginia
Public Service Commission (the "WVPSC"), the Company's natural gas
distribution utility operations and maintenance expense was $0.55 per
throughput Mcf as compared to $1.53 per throughput Mcf for its largest
competitor. The low cost structure of the Company's utility operation has
enabled it to be the lowest price provider of natural gas to residential
and commercial customers in its service area while realizing a reasonable
rate of return. The Company's residential rate for gas service for 1996,
as reported by the WVPSC, was $6.25 per Mcf of gas compared to an average
of $7.01 per Mcf of gas for its major competitors in West Virginia. The
Company is
46
<PAGE> 52
also a low cost producer of oil and natural gas, with lifting and
operating costs of $0.57 per Mcfe in fiscal 1996.
- DIVERSIFIED CASH FLOW STREAMS. The Company generates cash flow from its
utility operation, gas marketing activities and development and
production activities. The cash flows from these activities tend to be
complimentary. The utility operation generally benefits from lower gas
prices while the development and production activities generally benefit
from higher gas and oil prices. The integration of these activities has
resulted in greater stability in the Company's cash flows.
- LEADING WEST VIRGINIA GAS DISTRIBUTION UTILITY. The Company operates the
largest natural gas distribution utility in West Virginia. The Company is
a leader in achieving innovative rate regulation in West Virginia, having
proposed and received in November 1995 a three year moratorium on rates
charged to its utility customers. The moratorium provides incentives to
the Company to increase efficiencies and pursue ancillary opportunities.
The Company believes that the opportunities afforded by the rate
moratorium will more than offset the additional risk resulting from fixed
utility rates.
- HIGHLY DEVELOPED RESERVE BASE WITH LONG RESERVE LIFE. Approximately 90%
of the Company's reserves are classified as proved developed producing
and have an estimated remaining average reserve life index in excess of
13 years. The Company's Appalachian Basin properties are characterized by
predictable and stable production profiles that decline gradually over
their estimated economic life of approximately 25 years. As a result of
the highly developed and long lived nature of its Appalachian Basin
properties and the relatively low cost to drill development wells on
these properties, the Company believes it has a low reinvestment
requirement to maintain reserve quantities and production levels.
- PREMIUM PRICING. The Company generally benefits from premium pricing for
its Appalachian Basin production due to the geographic proximity of its
reserves to the Northeast markets. In addition, the Company benefits from
a balance of long, intermediate and short term fixed price gas contracts.
- HIGH DEGREE OF OPERATIONAL CONTROL. Over 90% of the Company's proved
reserves at March 31, 1997 are attributable to wells operated by the
Company, giving the Company significant control over the amount and
timing of capital and operating expenditures.
- EXPERIENCED MANAGEMENT. The Company's management has substantial
operational expertise and experience in the gas distribution utility
industry and in the oil and gas industry, particularly with respect to
the Appalachian Basin. This experience provides a significant base upon
which to expand the Company's operations as cash flow and additional
capital become available for investment.
BUSINESS STRATEGY
The Company seeks to maximize shareholder value and increase cash flow by
(i) balancing a portfolio of higher risk, higher reward opportunities with its
traditional moderate risk, moderate reward natural gas distribution utility and
Appalachian Basin oil and gas development and production activities, (ii)
increasing gas throughput volumes while reducing costs in its gas distribution
utility operation, (iii) increasing oil and gas reserves and production through
a managed risk exploration and development program and (iv) increasing gross
profit margin through vertical integration by implementing the following
operating strategies:
- MAINTAIN LOW COST STRUCTURE. The Company's management team is focused on
maintaining a low cost structure to maximize cash flow and earnings. As
part of this focus, the Company's strategy is to participate only in
businesses in which it believes it can be in the lowest quartile of
operating and administrative costs compared to its peers. The Company
believes that it has achieved operating efficiencies through the
economies of scale resulting from its
47
<PAGE> 53
geographic focus in the Appalachian Basin and through the application of
technology to its operating activities. The Company believes that maintaining
its low cost structure makes it less sensitive to market fluctuations in the
sales price of natural gas and oil.
- VERTICAL INTEGRATION. The Company believes that the integration of its
utility operation, its extensive transportation and marketing system and
its stable, long-lived Appalachian Basin production allows it to capture
both downstream and upstream margins and to increase operating
flexibility. The Company expects to allocate its capital spending among
its utility, exploration and production and gas marketing businesses in
order to increase the vertical integration of its business.
- BALANCED DEVELOPMENT AND EXPLORATION PROGRAM. In the Appalachian Basin,
the Company has drilled 444 low risk development wells since 1987,
achieving a success rate of 95%. Recently, the Company began drilling in
Ohio's Rose Run Trend where 18 of 20 wells have been completed
successfully. Outside the Appalachian Basin, the Company seeks
exploration opportunities in which it can (i) add value through technical
expertise, (ii) accumulate large leasehold interests in areas which have
high quality reservoirs, and (iii) limit its initial capital requirements
due to low entry costs and relatively low drilling costs in relation to
reserve potential. After completing its technical evaluation of each
project, the Company seeks to enter into joint development arrangements
with industry partners in order to share initial exploration expenditures
and to limit exposure to dry hole costs. To accelerate its entry into the
Rocky Mountain region, the Company has established a joint venture with
Thomasson Partner Associates, Inc., a geological and geophysical firm
that specializes in generating exploration projects in that region
utilizing advanced technologies, including advanced imaging applications
of 3-D seismic data.
- SELECTIVE ACQUISITIONS. The Company seeks to pursue acquisitions that are
complementary to its existing operations, that are expected to be
immediately additive to cash flow and earnings and that provide long term
growth opportunities. The Company focuses on acquisitions that are
located principally within the Company's operating areas and provide
opportunities to (i) expand its natural gas utility business, (ii) reduce
operating costs, (iii) increase reserves, (iv) enhance margins through
marketing opportunities, and (v) increase operating leverage.
NATURAL GAS DISTRIBUTION
The Company operates the largest natural gas distribution system in West
Virginia and owns approximately 3,900 miles of natural gas distribution
pipelines. The utility provides natural gas sales and transportation service to
approximately 200,000 residential, commercial, industrial and wholesale
customers in 45 of the 55 counties in West Virginia, including the cities of
Charleston, Beckley, Huntington and Wheeling. The Company has a lower cost
structure than any of its natural gas distribution competitors in West Virginia,
and its cost structure is one of the lowest in the United States as compared to
other natural gas distribution companies.
48
<PAGE> 54
CUSTOMERS. The table below sets forth certain information with respect to
the operating revenue and related gas volumes of the utility for the periods
indicated:
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
--------------------------------
1994 1995 1996
-------- -------- --------
<S> <C> <C> <C>
Gas Distribution Revenue:
Residential........................... 69.7% 72.3% 71.2%
Commercial............................ 22.3 20.3 23.8
Transportation........................ 7.1 7.0 3.8
Industrial and other.................. 0.9 0.4 1.2
-------- -------- --------
Total......................... 100.0% 100.0% 100.0%
======== ======== ========
Gas Volumes:
Residential........................... 31.0% 28.2% 30.5%
Commercial............................ 10.2 8.2 10.9
Transportation........................ 58.3 63.3 57.9
Industrial and other.................. 0.5 0.3 0.7
-------- -------- --------
Total throughput volume....... 100.0% 100.0% 100.0%
======== ======== ========
Weighted average sales rate (per Mcf)... $ 5.99 $ 6.65 $ 6.40
Average use per customer (Mcf):
Residential........................... 106 94 110
Commercial............................ 389 308 452
Industrial............................ 28,800 9,222 34,000
Transportation........................ 18,090 16,584 12,076
Average revenue per customer:
Residential........................... $ 640 $ 629 $ 722
Commercial............................ 2,300 1,994 2,765
Industrial............................ 119,900 43,444 151,818
Transportation........................ 5,941 4,816 2,226
Average revenue per Mcf:
Residential........................... $ 6.04 $ 6.69 $ 6.56
Commercial............................ 5.91 6.47 6.12
Industrial............................ 4.16 4.71 4.47
Transportation........................ 0.33 0.29 0.19
Average gas cost per Mcf sold........... $ 3.89 $ 4.38 $ 3.46
Weighted average Degree Days............ 5,212 4,651 5,535
Miles of distribution pipes............. 3,819 3,853 3,887
Number of customers..................... 198,392 198,293 199,287
</TABLE>
More than 95% of the residential and commercial customers of the utility use
natural gas for heating. Revenues, therefore, vary with the weather and
temperature both seasonally and annually. Industrial demand is dependent on
local business conditions, competition from alternate sources of energy and
weather. Demand for natural gas is also affected by Federal and state energy
laws and regulations.
RATE REGULATION. The Company's natural gas distribution utility is
regulated by the WVPSC. See "-- Regulatory Matters." Prior to October 1995, the
Company was subject to traditional regulatory rate making in West Virginia.
Following a proposal by the Company's natural gas distribution utility, the
WVPSC issued an order implementing a three year rate moratorium effective
November 1995. The moratorium provides rate certainty to the Company's natural
gas distribution utility customers by fixing the price of gas for three years.
By entering into the moratorium, the Company assumes the risks and benefits of
fixed utility rates, its gas purchasing activities, ancillary business
activities and achieving operational efficiencies. The Company has sought to
capitalize on the opportunities
49
<PAGE> 55
provided by the rate moratorium by providing billing services for a fee for a
local water company, consolidating multiple customer service centers into one
location and entering into a multi-year gas purchase contract with the Company's
exploration and production subsidiary. The Company believes that the
opportunities afforded by the rate moratorium more than offset the additional
risk accompanying fixed utility rates.
GAS SUPPLY. The Company currently obtains natural gas from a variety of
sources, including gas purchased in the Gulf Coast and Appalachia regions of the
United States. The gas purchased from producer/suppliers in the Gulf Coast
region is transported through the interstate pipeline systems of Columbia Gulf
Transmission Company ("Columbia Gulf"), Columbia Gas Transmission Corporation
("Columbia Gas"), and Tennessee Gas Pipeline Company ("Tennessee Gas") to the
Company's local distribution facilities in West Virginia. Approximately 67% of
the gas purchased in the Appalachia region is transported by Columbia Gas, with
the balance directly delivered into the Company's gas utility distribution
system.
The Company purchases its gas supply pursuant to a balanced portfolio of
intermediate term (one to five years) and short term (less than one year)
contractual arrangements. The following table sets forth the volume of natural
gas purchased and percentage of total volume of natural gas purchases, with
respect to those suppliers accounting for five percent or more of the Company's
purchases for the fiscal year ended June 30, 1996 and for the nine months ended
March 31, 1997, as well as volumes of natural gas subject to natural gas
purchase contracts with significant suppliers for the fiscal year ended June 30,
1998:
<TABLE>
<CAPTION>
NINE MONTHS ENDED YEAR ENDED
YEAR ENDED JUNE 30, 1996 MARCH 31, 1997 JUNE 30, 1998(1)
------------------------- ------------------------- ----------------
SUPPLIER VOLUME (MCF) % OF TOTAL VOLUME (MCF) % OF TOTAL VOLUME (MCF)
-------- ------------ ---------- ------------ ---------- ----------------
<S> <C> <C> <C> <C> <C>
Company Production................. 7,751,070 25% 7,514,364 31% 11,521,539
Equitable Resources................ 4,668,201 15% 2,286,591 10% 1,638,571
Texaco Natural Gas................. 3,159,207 10% 1,452,419 6% --
Penn Union......................... 2,701,039 9% -- -- --
Natural Gas Clearinghouse.......... 1,908,762 6% -- -- --
Cabot Oil and Gas.................. 2,391,652 8% -- -- --
Coastal Gas Marketing.............. -- -- 2,389,955 10% 3,539,700
Noble Gas Marketing................ -- -- 2,639,011 11% --
</TABLE>
- ---------------
(1) Volumes subject to gas purchase contracts in effect as of April 18, 1997.
The following table sets forth certain information relating to the
Company's gas supply purchases for the fiscal years 1994 through 1996.
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30,
------------------------
1994 1995 1996
---- ---- ----
<S> <C> <C> <C>
Interstate suppliers............... 78% 78% 62%
Company production................. 7 8 25
Other Appalachian Basin producers.. 15 14 11
Interstate pipelines and other..... 0 0 2
--- --- ---
Total.................... 100% 100% 100%
=== === ===
</TABLE>
TRANSPORTATION AND STORAGE CAPACITY. To ensure continuous, uninterrupted
service to its customers, the Company has in place long-term transportation and
service agreements with Columbia Gas, Columbia Gulf and Tennessee Gas. These
contracts cover a wide range of transportation services and volumes, ranging
from firm transportation service ("FTS") to no-notice service ("NTS") and
storage with such contracts expiring on various dates ranging from Octo-
50
<PAGE> 56
ber 31, 2000 through October 31, 2004. The aggregate annual reservation fees
associated with such contracts totaled approximately $41.2 million for the
fiscal year ended June 30, 1996. To the extent that the Company may revise its
gas procurement practices so as to procure a greater percentage of its gas
supply from local sources in West Virginia, such firm transportation agreements
and their associated reservation fees may be phased out as such contracts expire
or may be brokered and released for various periods of time.
Gas sales and/or transportation contracts with interruption provisions,
whereby large volume users purchase gas with the understanding that they may be
forced to shut down or switch to alternate sources of energy at times when the
gas is needed for higher priority customers, have been utilized for load
management by the Company and the gas industry as a whole for many years. In
addition, during times of special supply problems, curtailments of deliveries to
customers with firm contracts may be made in accordance with guidelines
established by appropriate federal and state regulatory agencies. There have
been no supply-related curtailments of deliveries to the Company or its
customers with firm contracts during the last seven years.
COMPETITIVE CONDITIONS. The natural gas business competes with oil for
industrial uses and with electricity for drying, cooking, water heating and
space heating. The Company competes with a number of other gas utilities in West
Virginia and it also competes with gas marketers in the sale, but not the
delivery (transportation), of natural gas. Large industrial and commercial end
users also have the option to bypass the Company's distribution system by
constructing pipelines to interconnect directly with the interstate pipeline
which transports all the natural gas consumed in the region. Although no bypass
by customers has occurred to date, the Company generally realizes lower
transportation revenues from large industrial and commercial end users due to
the possibility of such a bypass.
The Company currently has a significant competitive price advantage over
both electricity and fuel oil in its service territory. In a study of
residential energy costs released by the WVPSC in January 1997, fuel oil for
space heating was approximately 13% more expensive than gas, and electricity for
residential space heating was up to 126% more expensive than gas.
The Company has negotiated reduced rates for certain end users to: (1)
provide economic relief to aid the end user in remaining an ongoing concern; (2)
add an incentive to end users to add incremental load; and (3) dissuade the end
user from bypassing the Company's system. There are approximately 60 end users
that have negotiated a reduced rate for service with annual usage levels ranging
from approximately 200 Mcf to approximately 19.9 Bcf. Historically, the WVPSC
has allowed the Company to recover the difference between the tariff rate and
the reduced rate through the base rate filing proceeding.
The Company's demand from commercial and industrial customers is dependent
on local business conditions and competition from alternate sources of energy,
and demand from residential customers likewise is subject to competition from
alternate energy sources. The Company is also subject to competition from
interstate and intrastate pipeline companies, producers and other utilities
which may be able to serve commercial and industrial customers from their
transmission, gathering and/or distribution facilities. In certain markets, gas
has a competitive advantage over alternate fuels, while in other markets it is
not as price competitive.
The Company's natural gas distribution utility began offering gas
transportation service to its industrial customers in 1983. The availability of
both firm and interruptible transportation service, which enables industrial end
users to purchase lower cost gas supplies directly from producers, is an
important factor in maintaining gas usage by those end users during periods of
low residual oil prices. Continued evolution in the natural gas industry,
resulting primarily from FERC Order Nos. 436, 500 and 636, has served to
increase the ability of large gas end users to bypass the Company in obtaining
gas supply and transportation services. While the Company has not lost any
industrial load as a result of bypass, it generally realizes lower
transportation revenues from large industrial and commercial end users due to
the possibility of such bypass. Further, most industrial
51
<PAGE> 57
users that have a choice of alternate fuels have continued to use gas due to
price and other considerations.
GAS AND OIL EXPLORATION AND PRODUCTION
The Company is engaged in the exploration for and production of natural gas
and oil primarily within the Appalachian Basin in the states of West Virginia
and Pennsylvania. The Company also owns interests in the Rocky Mountains and New
Zealand where it is currently evaluating a number of exploration projects. The
Company's proved gas and oil reserves are estimated as of March 31, 1997 at
164.5 net Bcf and 1,391 (net) Mbbls, respectively. For the fiscal year ended
June 30, 1996, the Company's net gas production was approximately 9.8 Bcf and
net oil production was approximately 522 Mbbls, for a total of 13.0 Bcfe. For
the fiscal year ended June 30, 1996, the Company's operating margin was $1.51
per Mcf.
APPALACHIAN BASIN. The Appalachian Basin is a mature producing region with
well known geologic characteristics. Most of the wells in the Appalachian Basin
are relatively shallow, ranging from 2,500 feet to 5,500 feet, and many are
completed to multiple producing zones. In general, these wells are located on
proved producing properties with stable production profiles and generally long-
lived production, often with total projected economic lives in excess of 25
years. Once drilled and completed, ongoing operating and maintenance
requirements are low, and only minimal, if any, capital expenditures are
typically required. The Company holds interests in 4,755 gross (2,503 net) wells
in the Appalachian Basin and serves as operator of substantially all of such
wells in which it has a working interest. The Company's proved gas and oil
reserves attributable to its Appalachian Basin properties are estimated as of
March 31, 1997 at 172.9 Bcfe, of which approximately 95% was gas reserves and 5%
was oil reserves. For the fiscal year ended June 30, 1996, the Company's gas
production from its Appalachian Basin properties was approximately 9.4 Bcf on a
net basis and 23.2 Bcf on a gross basis. In the Appalachian Basin, the Company
has interests in approximately 322,460 gross acres (189,249 net acres) of
producing properties and in an additional 100,059 gross acres (74,905 net acres)
of undeveloped properties located primarily in West Virginia, Pennsylvania and
Ohio.
The Company is currently conducting its drilling activities in Ohio under
two area of mutual interest arrangements with industry partners with respect to
an aggregate of approximately 34,000 gross acres (the "Knox Play"). The
Company's Ohio operations have resulted in the successful completion of 18 wells
out of 20 wells drilled, with an average initial production rate of
approximately 840 Mcfe/day, a rate substantially in excess of the initial
production rates typically associated with the Company's Appalachian Basin
properties located in West Virginia and Pennsylvania. The Company, through its
rights to propose seismic shoots and drilling, is actively involved in the
process of determining the drilling schedule for both joint ventures. The
Company has the right to participate for a 50% working interest on a well by
well basis in 14,000 gross acres in Fairfield County, Ohio and a 25% working
interest in 20,000 gross acres in Licking County, Ohio. The Company makes
drillsite selections after carefully evaluating the seismic and other geological
data, estimates of completion and production costs and its estimates of
recoverable reserves. The Company believes that these joint ventures have
enabled it to limit its initial capital commitments for seismic and acreage and
to spread the risk of this exploratory play with other experienced operators in
Ohio. Independent of its existing strategic alliances, the Company recently
acquired 3,600 gross undeveloped acres in Licking County, Ohio.
ROCKY MOUNTAINS. The Company has recently acquired developed and
undeveloped leasehold interests in approximately 431,000 gross acres (291,000
net acres) located in the Rocky Mountain area. The Company has acquired its
interests in these properties under joint venture arrangements with industry
partners that enabled the Company to make relatively low initial capital
investments and that permit a managed risk approach to subsequent capital
investments related to specific drilling activities. The Company has a
contractual arrangement with Thomasson Partner Associates, Inc., a firm which
specializes in utilizing advanced technologies to identify attractive drilling
52
<PAGE> 58
prospects. The Company, in conjunction with Thomasson and other industry
partners, has identified and is currently focusing on six exploration plays with
respect to these properties which are located in the Blanding Basin, Utah, West
Williston Basin, Montana, East Williston Basin, North Dakota and the Wind River,
West Powder River and East Powder River Basins, Wyoming. The Company plans to
shoot 3-D seismic surveys with respect to 10 of the 20 prospects identified in
these plays. The Company typically operates the projects in which it holds a
majority working interest and determines whether to pursue potential projects
through risk aversion analysis which balances reserve potential, technical risk,
and full-cycle evaluation cost. Where partners are required, the Company targets
companies who can add technical value in addition to financial support. Partners
who take a working interest in the Company's projects reimburse sunk exploration
costs and typically pay an additional premium to cover overhead and management
fees. Subject to further evaluation, the Company expects that it will drill
several exploratory wells in 1997 on prospects that meet its managed risk
criteria of relatively low drilling and completion costs and significant reserve
and production potential.
NEW ZEALAND. The Company's international properties consist of
approximately 5.2 million gross acres (2.6 million net acres) located onshore
and offshore of the North Island of New Zealand. The Company was awarded a
five-year exploration concession with respect to these properties in 1996, and
the Company subsequently entered into a 50-50 joint venture arrangement with
ENERCO New Zealand Limited, a major New Zealand gas utility company, providing
for a sharing of costs and benefits associated with exploration and production
activities on these properties. The Company and its joint venture partners are
currently in the process of reprocessing existing seismic data and shooting 2-D
seismic surveys on a portion of the onshore acreage. The Company also expects
that it will shoot 3-D seismic surveys with respect to portions of the offshore
acreage. Subject to evaluation of the seismic data, the Company expects that it
will commence drilling of one or more exploratory wells in 1998.
OIL AND GAS PROPERTIES. As of March 31, 1997, the Company's properties
included working interests in 4,760 gross (2,505 net) productive oil and gas
wells. The following table sets forth summary information with respect to the
Company's estimated proved oil and gas reserves at March 31, 1997.
<TABLE>
<CAPTION>
PRESENT VALUE NATURAL GAS
---------------- OIL & NGLS NATURAL GAS EQUIVALENT
AMOUNT % (MBBLS) (MMCF) (MMCFE)
-------- ----- ---------- ----------- -----------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Region:
West Virginia......................... $ 83,989 66.7 192.2 121,296 122,449
Pennsylvania.......................... 27,929 22.2 5.9 39,632 39,667
Other................................. 13,925 11.1 1,192.8 3,651 10,808
-------- ----- ------- ------- -------
Total......................... $125,843 100.0 1,390.9 164,579 172,924
======== ===== ======= ======= =======
</TABLE>
OIL AND GAS RESERVES. The following table sets forth summary information
with respect to the Company's estimated proved oil and gas reserves. All
information in this Prospectus as of June 30, 1996, 1995 and 1994 relating to
estimated oil and gas reserves and the estimated future net cash flows
attributable thereto is based upon the Reserve Reports prepared by Ryder Scott
Company and Joseph Mendoza, Inc., both independent petroleum engineers (the
"Independent Engineers"), except for the reserves attributed to properties owned
by a subsidiary of the Company's natural gas distribution utility, which
reserves were estimated by the Company. These properties comprised approximately
6.7% of the Company's estimated total proved reserves at June 30, 1996. All
information in this Prospectus as of March 31, 1997 relating to estimated oil
and gas reserves and estimated future net cash flows attributable thereto is
based on estimates prepared by Ryder Scott Company, except for the reserves
attributed to properties owned by a subsidiary of the Company's natural gas
distribution utility, which reserves were estimated by the Company. These
properties comprised approximately 7.4% of the Company's estimated total proved
reserves at March 31,
53
<PAGE> 59
1997. The estimates of oil and gas reserves and estimated future net cash flows
attributable thereto at March 31, 1997 reflect the sale of the Company's
interest in certain oil and gas properties in California that occurred in March
1997. All calculations of estimated reserves and future net cash flows have been
made in accordance with the rules and regulations of the Commission, and, except
as otherwise indicated, give no effect to federal or state income (including
Section 29 credits) taxes otherwise attributable to estimated future cash flows
from the sale of oil and gas. The Present Value of estimated future net cash
flows has been calculated with constant prices in effect at the time of the
estimates using a discount factor of 10%. For purposes of estimated reserves and
cash flows at March 31, 1997, average product prices of $2.41 per Mcf of gas and
$16.24 per barrel of oil at such date were used.
<TABLE>
<CAPTION>
AS OF
AS OF JUNE 30, MARCH 31,
-------------------------------- ---------
1994 1995 1996 1997
-------- -------- -------- ---------
<S> <C> <C> <C> <C>
Total net proved(1):
Gas (Mmcf)............................ 170,319 171,826 159,446 164,579
Oil (Mbbls)........................... 7,003 7,020 6,668 1,391
Total (Mmcfe)......................... 212,335 213,946 199,453 172,924
Net proved developed:
Gas (Mmcf)............................ 160,980 167,442 153,230 148,362
Oil (Mbbls)........................... 7,003 6,886 6,668 1,146
Total (Mmcfe)......................... 202,998 208,758 193,238 155,238
Estimated future net cash flows before
income taxes (in thousands)(2)........ $400,073 $274,651 $304,237 $333,273
Present Value of estimated future net
cash flows before income taxes (in
thousands)(2)......................... $162,036 $127,886 $130,778 $125,843
</TABLE>
- ---------------
(1) Net proved reserves reflect the sale of approximately 19.7 Bcf of proved
reserves in 1996 and approximately 34.7 Bcfe of proved reserves in 1997.
(2) Estimated future net revenues and discounted estimated future net revenues
are not intended, and should not be interpreted, as representing the fair
market value for the estimated reserves.
There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting future rates of production and the timing of
development expenditures, including many factors beyond the control of the
producer. The reserve data set forth herein represent only estimates. Reserve
engineering is a subjective process of estimating underground accumulations of
oil and gas that cannot be measured in an exact way, and the accuracy of any
reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment and the existence of
development plans. As a result, estimates of reserves made by different
engineers for the same property will often vary. Results of drilling, testing
and production subsequent to the date of an estimate may justify a revision of
such estimates. Accordingly, reserve estimates are generally different from the
quantities of oil and gas that are ultimately produced. Further, the estimated
future net revenues from proved reserves and the present value thereof are based
upon certain assumptions, including geological success, prices, future
production levels and costs that may not prove to be correct. Predictions about
prices and future production levels are subject to great uncertainty, and the
meaningfulness of such estimates depends on the accuracy of the assumptions upon
which they are based. See "Risk Factors -- Uncertainty of Reserves and Future
Net Revenues."
54
<PAGE> 60
PRODUCING WELLS. The following table sets forth certain information
relating to productive wells at March 31, 1997. Wells are classified as oil or
gas according to their predominant production stream.
<TABLE>
<CAPTION>
GROSS WELLS NET WELLS
--------------------- -----------------------
LOCATION OIL GAS TOTAL OIL GAS TOTAL
-------- --- ----- ----- --- ----- -------
<S> <C> <C> <C> <C> <C> <C>
Appalachian Basin.................. 8 4,747 4,755 1.4 2,502 2,503
Other.............................. 5 0 5 2.3 0 2.3
-- ----- ----- --- ----- -------
Total.................... 13 4,747 4,760 3.7 2,502 2,505.3
== ===== ===== === ===== =======
</TABLE>
ACREAGE. The following table sets forth the developed and undeveloped gross
and net acreage held at March 31, 1997.
<TABLE>
<CAPTION>
DEVELOPED ACREAGE UNDEVELOPED ACREAGE
------------------ ----------------------
GROSS NET GROSS NET
------- ------- --------- ---------
<S> <C> <C> <C> <C>
Appalachian Basin.................... 322,460 189,249 100,059 74,905
Rocky Mountains...................... 4,000 3,500 427,000 287,500
New Zealand.......................... 0 0 5,159,152 2,579,576
Other................................ 1,063 836 36,413 35,473
------- ------- --------- ---------
Total...................... 327,523 193,585 5,722,624 2,977,454
======= ======= ========= =========
</TABLE>
PRODUCTION, PRICES AND PRODUCTION COSTS. The following table sets forth
certain production data, the average sales prices and average production
expenses attributable to the Company's properties on an historical basis for
1994, 1995, 1996 and the nine months ending March 31, 1996 and March 31, 1997.
<TABLE>
<CAPTION>
NINE MONTHS
YEAR ENDED JUNE 30, ENDED MARCH 31,
-------------------------- ----------------
1994 1995 1996 1996 1997
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Production Data:
Oil (Mbbls)...................... 459 535 522 387 425
Natural gas (Mmcf)............... 8,775 8,982 9,816 7,414 7,113
Natural gas equivalent (Mmcfe)... 11,527 12,190 12,950(1) 9,739 9,664
Average Sales Price:
Oil ($/Bbl)...................... $12.96 $15.01 $16.02 $15.37 $18.09
Natural gas ($/Mcf).............. $ 2.43 $ 1.95 $ 2.01 $ 2.01 $ 2.19
Lifting and Operating Expense
($/Mcfe)......................... $ 0.54 $ 0.58 $ 0.57 $ 0.56 $ 0.44
</TABLE>
- ---------------
(1) The increase from 1995 production was primarily attributable to the
properties included in the Mountaineer Acquisition.
DRILLING ACTIVITIES. The Company has a large inventory of exploration
drilling opportunities that the Company believes consist of moderate
risk/moderate reward, as well as higher risk/higher reward exploration projects.
In addition, for fiscal year 1998, the Company has identified and expects to
drill 15 gross (8 net) exploration projects in the Rocky Mountain region and 3
gross (1.5 net) exploration projects in New Zealand. In addition, the Company
has identified numerous other exploration drilling opportunities within its
existing properties.
The Company plans to spend approximately 10% of its cash flow for the
foreseeable future to fund higher risk exploration activities and to participate
in a variety of projects with differing characteristics. The Company's existing
inventory of exploration projects varies in risk and reward based on their
depth, location and geology. A significant portion of the existing, as well as
future,
55
<PAGE> 61
exploration projects will be enhanced by use of advanced technology including
3-D seismic and improved completion techniques.
DRILLING RESULTS. The following table summarizes actual drilling activities
for the three years ended June 30, 1996 and for the nine months ended March 31,
1997.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
YEAR ENDED JUNE 30, MARCH 31,
------------------------------------------ -----------
1994 1995 1996 1997
------------ ------------ ------------ -----------
GROSS NET GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ---- ----- ---
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Development:
Productive
Appalachian............ 46 19.0 23 8.8 36 13.6 7 4.4
Other.................. 2 1.6 2 1.6 2 0.8 0 0
-- ---- -- ---- -- ---- -- ---
Total............. 48 20.6 25 10.4 38 14.4 7 4.4
== ==== == ==== == ==== == ===
Nonproductive
Appalachian............ 2 0.8 1 0.4 0 0 1 0.9
Other.................. 0 0 0 0.0 1 0.4 1 0.9
-- ---- -- ---- -- ---- -- ---
Total............. 2 0.8 1 0.4 1 0.4 2 1.8
== ==== == ==== == ==== == ===
Exploratory:
Productive
Appalachian............ 0 0 4 1.2 1 0.4 14 3.9
Other.................. 1 0.4 1 0.4 2 0.9 0 0
-- ---- -- ---- -- ---- -- ---
Total............. 1 0.4 5 1.6 3 1.3 14 3.9
== ==== == ==== == ==== == ===
Nonproductive
Appalachian............ 4 1.5 5 2.3 5 2.1 0 0
Other.................. 1 0.4 12 4.6 12 3.6 9 7.0
-- ---- -- ---- -- ---- -- ---
Total............. 5 1.9 17 6.9 17 5.7 9 7.0
== ==== == ==== == ==== == ===
</TABLE>
COMPETITION. The Company encounters substantial competition in acquiring
properties, marketing oil and gas, securing equipment and personnel and
operating its properties. The competitors in acquisitions, development,
exploration and production include major oil companies, numerous independent oil
and gas companies, gas marketers, individual proprietors and others. Many of
these competitors have financial and other resources which substantially exceed
those of the Company and have been engaged in the energy business for a much
longer time than the Company. Therefore, competitors may be able to pay more for
desirable leases and to evaluate, bid for and purchase a greater number of
properties or prospects than the financial or personnel resources of the Company
will permit.
Natural gas competes with other forms of energy available to customers,
primarily on the basis of rates. These alternate forms of energy include
electricity, coal and fuel oils. Changes in the availability or price of natural
gas or other forms of energy, as well as business conditions, conservation,
legislation, regulations and the ability to convert to alternate fuels and other
forms of energy may affect the demand for natural gas.
Demand from commercial and industrial customers is dependent on local
business conditions and competition from alternate sources of energy. The
natural gas distribution utility's demand from residential customers likewise is
subject to competition from alternate energy sources. The natural gas
distribution utility is also subject to competition from interstate and
intrastate pipeline companies, producers, gas marketers and other utilities
which may be able to serve commercial and industrial customers from their
transmission, gathering and/or distribution facilities. In certain markets, gas
has a competitive advantage over alternate fuels, while in other markets it is
not as price competitive.
56
<PAGE> 62
GAS SALES AND MARKETING
The Company has developed a significant gas aggregation and marketing
operation. The Company aggregates natural gas through production from properties
in the Appalachian Basin in which the Company has an interest, the purchase of
gas delivered through the Company's gathering pipelines located in the
Appalachian Basin, the purchase of gas produced in the Southwestern areas of the
United States pursuant to contractual arrangements and the purchase of gas in
the spot market. The Company sells gas to local gas distribution companies,
industrial end users located on the East Coast, other gas marketing entities and
into the spot market for gas delivered into interstate pipelines. The Company
has historically attempted to balance its gas sales mix with approximately
one-third of its total gas sales being made under premium-priced long term
contracts (contracts with terms of five years or more), one-third being sold
under intermediate term contracts (contracts with terms of one to five years),
and one-third being sold under short term contracts (contracts with terms of
less than one year) or on a spot market basis. See "-- Significant Gas Sales and
Purchase Contracts."
The Company owns and operates approximately 2,000 miles of gathering lines
and intrastate pipelines that are used in connection with its gas aggregation
and marketing activities. In addition, the Company has entered into contracts
with interstate pipeline companies that provide it with rights to transport
specified volumes of natural gas. During the fiscal year ended June 30, 1996,
the Company aggregated and sold an average of 150.0 Mmcf of gas per day, of
which 41.1 Mmcf per day represented sales of gas produced from wells operated by
the Company. The Company believes its ability to satisfy gas supply commitments
from its own reserve base has significantly enhanced its ability to become a
principal marketer of gas produced in the Appalachian Basin.
Approximately 97% of the Company's gas production, on an Mcfe basis, for
fiscal 1996 was attributable to its Appalachian Basin properties. Gas production
from Appalachian Basin properties has historically received a higher price, due
to its proximity to the Northeastern gas markets and the stable deliverability
characteristics of Appalachian Basin production, than gas delivered at Henry
Hub, Louisiana or at delivery points in the Rocky Mountains. In addition, the
Company's ability to aggregate large quantities of natural gas from its own
production and from third parties through the activities of its marketing
operations has contributed to the ability of the Company to receive higher
prices for its gas sales as compared to gas delivered at Henry Hub, Louisiana.
The Company, excluding the natural gas distribution utility, is a party to
fixed price gas sales contracts with third parties having an initial term of
more than one year that obligated the Company to sell approximately 9.0 Bcf of
natural gas in fiscal 1996. In addition, a subsidiary of the Company sold
approximately 9.5 Bcf of natural gas in fiscal 1996 to another subsidiary of the
Company pursuant to a gas sales contract. See "-- Significant Gas Sales and
Purchase Contracts." The Company satisfied its obligations under these contracts
through gas production attributable to its interests in gas and oil properties
(9.8 Bcf in fiscal 1996), through production attributable to the interests of
third parties in gas and oil properties operated by the Company (12.2 Bcf in
fiscal 1996) and from natural gas aggregated by the Company (38.9 Bcf in fiscal
1996) pursuant to its aggregation and marketing activities from third parties.
The Company expects to continue to satisfy its obligations under its existing
gas sales contracts in a similar manner.
SIGNIFICANT GAS SALES AND PURCHASE CONTRACTS
The Company currently has two significant gas sales contracts with third
parties. In addition, Mountaineer has entered into a contract to purchase
natural gas from Eastern American and Eastern Marketing. The following is a
description of these contracts.
Eastern American is a party to a contract with Hope Gas, Inc. ("Hope"), a
subsidiary of Consolidated Natural Gas, that requires Eastern American to sell
up to 5,300 Mmbtu per day through October 31, 1998. The pricing under the
contract is based on a demand and commodity component. The contract requires
Hope to pay Eastern American a demand component of $51,589
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per month and a commodity component that is $2.20 per Mmbtu through October 31,
1996, $2.10 per Mmbtu through October 31, 1997 and $2.00 per Mmbtu through
October 31, 1998. For fiscal year 1996, the gas sold pursuant to this contract
accounted for 1.2% of the Company's consolidated revenues and 8.0% of the total
gas production volume of the Company.
Eastern American is a party to a contract with Seneca Power Partners L.P.,
a limited partnership in which Eastern American and Sithe Energy USA, Inc. are
limited partners, with Seneca Power Corporation as the general partner. This
contract has a 15-year term that commenced on September 1, 1992 and provides for
a fixed price that increases 5% per year until 1999, at which time Eastern
American has the option to renegotiate the price. Such renegotiated price cannot
exceed certain financial ratios set forth in the contract. If, after
negotiation, the parties cannot reach an agreement, the contract provides for
dispute resolution through binding arbitration. Contract volumes are a minimum
of 10,300 Mmbtu per day and a maximum of 12,900 Mmbtu per day. For fiscal year
1996, the gas sold pursuant to this contract accounted for 16.8% of the
Company's total gas production volume and the average sales price was $2.893 per
Mmbtu.
In connection with the sale of a net profits interests in certain oil and
gas properties to the Royalty Trust in March 1993, Eastern Marketing entered
into a gas purchase contract to purchase all gas production attributable to the
Eastern American Natural Gas Trust (the "Royalty Trust") until the termination
of the Royalty Trust in May 2013. See "-- Significant Acquisitions and
Dispositions." The purchase price under the gas purchase contract through
December 1999 will be based in part on a fixed price component, which escalates
each year, and in part on a variable price component, which fluctuates with
certain spot market prices, provided that the purchase price during such period
will not be less than a specified minimum purchase price. The minimum purchase
price was $2.36 per Mcf in 1996 and such minimum purchase price escalates at
approximately 9% per year. The fixed price component was $3.08 in calendar 1996
and escalates five percent each year through December 1999. The variable price
is equal to the future contract prices per Mmbtu for natural gas delivered to
Henry Hub, Louisiana plus $0.30 per Mmbtu, multiplied by 110% to reflect a fixed
adjustment for Btu content. The fixed price component is given a weighting of
66 2/3% and the variable price component is given a weighting of 33 1/3% through
December 1999. Beginning in January 2000, the purchase price under the gas
purchase contract will be determined solely by reference to the variable price
component without regard for any minimum purchase price. Eastern American has
entered into a standby performance agreement with the Royalty Trust to support
the obligations of Eastern Marketing under the gas purchase contract. See "--
Significant Acquisitions and Dispositions."
Eastern American and Eastern Marketing entered into a Gas Purchase Contract
with Mountaineer on September 13, 1995. This contract has a three year term
commencing November 1, 1995 and provides for a gas demand charge of $0.08 per
Mmbtu up to the daily contract demand volume of 28,000 Mmbtu per day. For each
Mmbtu of gas delivered Mountaineer will pay Eastern American a price of $2.20
per Mmbtu for the first contract year, $2.10 per Mmbtu in the second contract
year and $2.00 per Mmbtu in the third contract year. In addition, the parties
have agreed to a sharing arrangement on any revenue generated from Mountaineer
being able to release firm capacity on interstate transportation systems. Since
Mountaineer is a public utility and an affiliate of Eastern American and Eastern
Marketing, this contract required the approval of the WVPSC, which approval has
been obtained.
SIGNIFICANT ACQUISITIONS AND DISPOSITIONS
The Company has grown significantly since 1988 through acquisitions. Set
forth below is a summary of the most significant acquisitions and dispositions
over the past eight years.
BREITBURN DISPOSITION. In March 1997, the Company sold approximately 34.7
Bcfe of proved reserves in California for total consideration of approximately
$23.8 million. The total consideration included $11.3 million of cash and a
promissory note in the principal amount of $1.5 million. In
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addition to the cash and promissory note, the Company received an assignment of
a 20% working interest in certain undeveloped properties located in California,
a 50% interest in certain surface real estate located in California and retained
a 30% ownership interest in the successor entity.
SECTION 29 MONETIZATION. In November 1995, the Company transferred
approximately 19.7 Bcf of proved reserves located in the Appalachian Basin to a
limited partnership as to which a subsidiary of the Company acts as general
partner. The limited partner contributed approximately $17.3 million to the
partnership, which amount was subsequently distributed to the Company. In
connection with such transaction, the Company agreed to purchase all of the gas
produced from certain wells transferred to the partnership until September 2015
unless earlier terminated by either party upon 30 days written notice. This
transaction enabled the Company to transfer properties which were eligible for
Section 29 tax credits.
ALLEGHENY & WESTERN ACQUISITION. In June 1995, the Company acquired all of
the outstanding stock of Allegheny & Western Energy Corporation, a company whose
stock had traded on the New York Stock Exchange prior to the acquisition, for
approximately $95.3 million. As a result of this transaction, the Company
acquired all of the stock of Mountaineer and interests in 886 producing gas and
oil wells with approximately 28.5 Bcf of proved producing reserves located
primarily in West Virginia.
BREITBURN ACQUISITION. The Company acquired a limited partnership interest
in certain oil and gas properties located in Los Angeles County, California from
Occidental Petroleum Corporation and Oxy USA, Inc. which added approximately 31
Bcfe to the Company's proved producing reserves for a purchase price of
approximately $12 million.
ROYALTY TRUST. In March 1993, the Company conveyed to the Eastern American
Natural Gas Trust (the "Royalty Trust"), a trust whose units are traded on the
New York Stock Exchange, certain net profits interests derived from the
Company's working interest in certain natural gas properties located in the
Appalachian Basin whose production is eligible for tax credits under Section 29
of the Internal Revenue Code. Proved net developed and undeveloped reserves
attributable to these interests were approximately 66.5 Bcfe. The Company
received approximately $93 million from the proceeds of the initial public
offering of the Royalty Trust.
EDISTO RESOURCES ACQUISITION. In January 1991, the Company acquired from
Edisto Resources Corporation and NRM Operating Company, L.P. interests in 807
producing natural gas wells located principally in West Virginia and
Pennsylvania. These wells produced 16,250 Mmcf per day gross and 11,000 Mmcf per
day net in 1991, with natural gas reserves estimated to total approximately 45.0
Bcf. These wells are located on 127,855 gross (110,714 net) developed acres and
8,300 gross (7,850 net) undeveloped acres. The purchase price of these assets
totaled approximately $31.0 million.
J&J ACQUISITION. In November 1988, Eastern American acquired 100% of the
outstanding common stock of J&J Enterprises, Inc., a closely held Pennsylvania
based corporation, for total consideration consisting of shares of the common
stock of Eastern American (which were subsequently repurchased by Eastern
American), the assumption of $59.1 million of bank debt and certain other
obligations. The properties acquired in this transaction included 1,370 gross
(797 net) producing gas wells in Pennsylvania and 920 gross (540 net) producing
gas wells in West Virginia and approximately 81,347 gross developed acres and
24,000 gross undeveloped acres. The acquisition added approximately 99.0 Bcfe to
the Company's Appalachian Basin proved producing gas reserves.
The Company believes that each of these acquisitions and dispositions is
consistent with its focus on pursuing vertical integration to capture downstream
margins, maintaining low cost operations, establishing a balanced development
and exploration program and achieving diversified cash flows which are less
sensitive to commodity pricing risks.
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REGULATORY MATTERS
GENERAL. The Company's operations are affected by extensive regulation
pursuant to various federal, state and local laws and regulations relating to
the prices the Company may charge for distribution and transportation of natural
gas, exploration for and development, production, gathering, marketing,
transportation and storage of oil and gas. These regulations, among other
things, may affect the rate of oil and gas production. The Company's operations
are subject to numerous laws and regulations governing plugging and abandonment,
the discharge of materials into the environment or otherwise relating to
environmental protection. These laws and regulations require the acquisition of
a permit before drilling commences, restrict the types, quantities and
concentration of various substances that can be released into the environment in
connection with drilling and production activities, limit or prohibit drilling
activities on certain lands lying within wilderness, wetlands and other
protected areas, and impose substantial liabilities for pollution which might
result from the Company's operations. See "Risk Factors -- Regulations Affecting
Operations."
WEST VIRGINIA PUBLIC SERVICE REGULATION. The Company operates a natural gas
distribution utility that is regulated by the WVPSC. Under traditional rate
making in West Virginia, the natural gas distribution utility is prohibited from
increasing its base rate unless it obtains the approval of the WVPSC. In
general, the WVPSC would review any base rate increase based upon an analysis of
the cost of service, as adjusted for known and measurable changes in expenses
and revenues, and would also include a reasonable return on equity. In
determining the overall rate of return on equity allowed in the rate proceeding,
the WVPSC employs a methodology which computes both the natural gas distribution
utility's cost of debt capital as well as a cost of equity capital. The
allowable return on equity is designed to compensate the equity owner at rates
commensurate with the rate of return on investments at comparable risks. In
order to determine the allowable return on equity, the WVPSC utilizes two market
oriented methodologies, the discounted cash flow and the capital asset pricing
model. A further review utilized by the WVPSC to check the reasonableness of the
allowable return on equity involves an analysis of the overall return required
to provide reasonable interest coverage, dividend pay-out ratios and internally
generated cash flow. The cost of debt capital is determined by utilizing the
utility's actual interest rates as set forth in its loan documents, provided the
rate is determined to be reasonable. While the cost of debt capital is normally
based upon long-term debt, if the utility uses short-term debt on a regular
basis the WVPSC may determine that such debt should be treated as a component of
the utility's debt capital. Finally, the WVPSC utilizes a sample group of
approximately ten to twelve gas distribution utilities located within and
outside of West Virginia for comparison purposes with respect to its discounted
cash flow calculation and the capital asset pricing model. Because the rate
regulatory process has certain inherent time delays, rate orders may not reflect
the operating costs at the time new rates are put into effect.
Any change to the rate the natural gas distribution utility charges its
customers for natural gas costs must be approved by the WVPSC. In order to
obtain approval of changes to gas purchase costs, the Company makes purchase gas
adjustment filings with the WVPSC on an annual basis which include a forecast
for the upcoming twelve month period of gas costs and a true-up mechanism for
the previous period for any over or under-recovery balances. The WVPSC reviews
the Company's gas purchasing activities during the previous year to determine
the prudence of gas purchase expenditures and to determine that dependable
lower-priced supplies of natural gas are not readily available from other
sources. The forecast of gas costs submitted by the natural gas distribution
utility in its annual filings incorporates known and measurable pipeline fees
during the upcoming period and an estimate of gas cost based on several natural
gas futures indices. The WVPSC also reviews the Company's forecast of gas costs
in such filings for reasonableness.
All of the requests of natural gas distribution utilities in West Virginia
for rate changes are reviewed by the staff of the WVPSC as well as the Consumer
Advocate Division of the WVPSC. The Consumer Advocate Division is charged with
representing and protecting the interests of residential customers in regulating
the utility.
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On October 19, 1995, the WVPSC entered an order that established a three
year moratorium on the rates that the Company may charge its natural gas
distribution system customers. As a consequence of the rate moratorium, the
Company is subject to the risk and benefits of changes in costs, including
changes in costs for natural gas purchased by the Company and changes in
interstate pipeline transportation rates, during the three year term of the
moratorium without the ability to increase rates charged to its customers to
absorb any increases in such costs during this period. In the event that the
Company purchases gas during the moratorium period at prices per Mcf that are in
excess of amounts being recovered in approved rates, the inability of the
Company to increase the rates it charges its customers could have a material
averse effect on the Company's financial condition, results of operations and
cash flows. The Company has taken certain steps to mitigate its exposure to
price increases per Mcf that exceed the level being recovered in rates during
the rate moratorium. These steps include entering into fixed price contracts and
contracts to purchase volumes in future months based on current prices and
purchasing options to purchase gas in the future at prices below current market
levels. The WVPSC order provides for certain exceptions if unforeseen
extraordinary circumstances, including natural disaster, sabotage or force
majeure, significantly impair the Company's financial integrity or service
reliability. Also, new or increased taxes imposed by legislation or regulation
may be recovered through a rate surcharge if such increase exceeds $250,000
annually. In its order, the WVPSC indicated that the moratorium was an
experiment in incentive regulation for the Company and its belief that the
moratorium created appropriate incentives for the Company to operate prudently
and efficiently. The Company expects that its natural gas distribution utility
operations will continue to be regulated following the moratorium period in a
manner which will allow the Company to recover its costs of operations and earn
a reasonable return on its equity.
The monthly customer bill contains a fixed service charge and a charge for
the amount of natural gas used. While the monthly fixed charge provides an even
revenue stream, the usage charge increases the Company's annual revenue and
earnings in the traditional higher load winter months when usage of natural gas
increases. The monthly service charge is determined in the Company's base rate
filing while the usage charge is determined in both the Company's base rate
filing and purchased gas costs filing.
Transactions between a public utility regulated by the WVPSC and the
affiliates of such utility are required to be approved by the WVPSC. Mountaineer
and Eastern American are parties to an agreement providing for the sale of
natural gas from Eastern American to Mountaineer. See "--Significant Gas Sales
and Purchase Agreements." This agreement has been approved by the WVPSC. Under
West Virginia law, if a West Virginia gas distribution company purchases more
than 50% of its natural gas requirements from its affiliates, then the purchase
gas adjustment which such gas distribution company is permitted to charge by the
WVPSC is based upon the affiliates' actual costs rather than the prices charged
by the affiliates. In addition, the WVPSC may restrict Mountaineer from
guaranteeing indebtedness of the Company or any other subsidiary of the Company
pursuant to its authority to regulate rates that Mountaineer may charge its
customers for natural gas.
NATURAL GAS AND OIL MARKETING AND TRANSPORTATION. Historically, the
transportation and sale for resale of natural gas in interstate commerce have
been regulated pursuant to the Natural Gas Act of 1938, the Natural Gas Policy
Act of 1978 (the "NGPA"), and the regulations promulgated thereunder by the
FERC. In the past, the federal government has regulated the wellhead price of
natural gas. While sales by producers of natural gas, and all sales of crude
oil, condensate and natural gas liquids, can currently be made at uncontrolled
market prices, Congress could reenact price controls in the future. Deregulation
of wellhead sales in the natural gas industry began with the enactment of the
NGPA. In 1989, the Natural Gas Wellhead Decontrol Act was enacted.
Several major regulatory changes have been implemented by the FERC from
1985 to the present that affect the economics of natural gas production,
transportation and sales. In addition, the FERC continues to promulgate
revisions to various aspects of the rules and regulations affecting
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those segments of the natural gas industry, most notably interstate natural gas
transmission companies, which remain subject to the FERC's jurisdiction. These
initiatives may also affect the intrastate transportation of gas under certain
circumstances. The stated purposes of many of these regulatory changes is to
promote competition among the various sectors of the gas industry. The ultimate
impact of these complex and overlapping rules and regulations, many of which are
repeatedly subjected to judicial challenge and interpretation, cannot be
predicted.
Commencing in April 1992, the FERC issued Order Nos. 636, 636-A and 636-B
(collectively, "Order No. 636"), which, among other things, require interstate
pipelines to "restructure" to provide transportation separate or "unbundled"
from the pipelines' sales of gas. Also, Order No. 636 requires pipelines to
provide open-access transportation on a basis that is equal for all gas
supplies. Order No. 636 has been implemented through negotiated settlements in
individual pipeline service restructuring proceedings. In many instances, the
result of the Order No. 636 and related initiatives have been to substantially
reduce or bring to an end the interstate pipelines' traditional roles as
wholesalers of natural gas in favor of providing only storage and transportation
services.
Although Order No. 636 does not directly regulate natural gas producers
such as the Company, Order No. 636 has fostered increased competition within all
phases of the natural gas industry. Although Order No. 636 provides the Company
with additional market access and more fairly applied transportation service
rates, terms and conditions, it also subjects the Company to more restrictive
pipeline imbalance tolerances and greater penalties for violations of these
tolerances. The Company does not believe, however, that it will be affected by
any action taken under or with respect to Order No. 636 materially differently
from other natural gas producers and marketers with which it competes.
The FERC has announced its intention to reexamine certain of its
transportation-related policies, including the use of market-based rates for
interstate gas transmission. While any resulting FERC action would affect the
Company only indirectly, the FERC's current rules and policies may have the
effect of enhancing competition in natural gas markets by, among other things,
encouraging non-producer natural gas marketers to engage in certain purchase and
sale transactions. The Company cannot predict what action the FERC will take on
these matters, nor can it accurately predict whether the FERC's actions will
achieve the goal of increasing competition in markets in which the Company's
natural gas is sold. However, the Company does not believe that it will be
affected by any action taken materially differently than other natural gas
producers and marketers with which it competes.
Additional proposals and proceedings that might affect the oil and gas
industry are pending before the FERC and the courts. The Company cannot predict
when or whether any such proposals may become effective. In the past, the
natural gas industry has been heavily regulated. There is no assurance that the
regulatory approach currently pursued by the FERC will continue indefinitely.
Notwithstanding the foregoing, the Company does not anticipate that compliance
with existing federal, state, and local laws, rules, and regulations will have a
material or significantly adverse effect upon the capital expenditures,
earnings, or competitive position of the Company.
On November 22, 1996, the Company entered into a settlement agreement with
Columbia Gas and other Columbia Gas customers in a rate proceeding initiated by
Columbia Gas in 1995. Among the material provisions of the settlement affecting
the Company include (i) the receipt by the Company of approximately $7.1 million
annually, through 2004, in demand charge credits, and (ii) a rate moratorium on
Columbia Gas until the year 2000. On April 17, 1997, the FERC approved the
settlement agreement. As of March 31, 1997, the Company is due refunds under the
settlement agreement of approximately $6 million including zone credits earned
and transportation charges paid in excess of settled rates. As a result of the
FERC order, the Company recorded a receivable and associated reduction in gas
costs of $6 million for the nine months ended March 31, 1997.
OIL AND GAS EXPLORATION AND PRODUCTION. Certain operations the Company
conducts are on Federal oil and gas leases, which the Minerals Management
Services ("MMS") administers. The MMS issues such leases through competitive
bidding. These leases contain relatively standardized
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terms and require compliance with detailed MMS regulations and orders. In
addition to permits required from other agencies (such as the Environmental
Protection Agency), lessees must obtain a permit from the MMS prior to the
commencement of drilling. The MMS has promulgated regulations implementing
restrictions on various production-related activities, including restricting the
flaring or venting of natural gas. In addition, the MMS has proposed to amend
its regulations to prohibit the flaring of liquid hydrocarbons and oil without
prior authorization. Finally, the MMS is conducting an inquiry into certain
contract agreements from which producers on MMS leases have received settlement
proceeds that are royalty bearing and the extent to which producers have paid
the appropriate royalties on those proceeds. The Company believes that this
inquiry will not have a material impact on its financial condition, liquidity or
results of operations.
Drilling and production of natural gas are heavily regulated in
Pennsylvania and West Virginia, as in most states. A well cannot be drilled
without a permit, and operations must be conducted in compliance with
environmental, safety and conservation laws and regulations. In contrast to many
other states which have substantial oil and gas production activity, the spacing
of shallow wells (which constitute a significant portion of the Company's
Appalachian wells) is not regulated by any state statute or regulatory agency in
either West Virginia or Pennsylvania. Without spacing requirements specified by
state statute or regulation, drainage of reserves from a property may occur from
wells located in close proximity to such property. Due to the cost of drilling
and completing wells and the typical production characteristics of natural gas
wells in these states, however, the Company believes that it is not generally
economic to drill gas wells in close proximity with an existing well since the
new well would not generally produce sufficient volumes of gas to provide a
sufficient rate of return after taking into account drilling costs, completion
costs and ongoing operating and marketing costs of such new well. As a result,
the Company historically has not drilled development wells closer than 1,000
feet from an existing well, although in some cases parties that have interests
in adjacent properties may drill wells closer than 1,000 feet from an existing
well which may otherwise be produced by the Company. In addition, these states
do not regulate wellhead prices or engage in other similar direct economic
regulation, but there can be no assurance that they will not do so in the
future. At the time a well reaches the end of its economic life, the Company is
required to plug and abandon the well in compliance with various state laws and
regulations.
ENVIRONMENTAL REGULATION. Activities on the Company's oil and gas producing
properties are subject to existing Federal, state and locals laws and
regulations governing health, safety, environmental quality and pollution
control. Failure to comply with environmental laws can result in substantial
civil or criminal penalties, as well as the revocation of necessary
environmental permits. Pursuant to these laws and regulations, the Company may
be subject to substantial clean-up costs for any toxic or hazardous substance
that may exist on or under any of its properties. The Company cannot predict
what effect additional regulation or legislation, enforcement policies
thereunder, and claims for damages to property, employees, other persons and the
environment resulting from operations on its properties could have on its
financial condition or results of operations. The Company could incur
substantial costs to comply with environmental laws and regulations.
The Comprehensive Environmental Response, Compensation and Liability Act
("CERCLA"), also known as the "superfund" law, imposes liability, regardless of
fault or the legality of the original conduct, on certain classes of persons
that contributed to the release of a "hazardous substance" into the environment.
These persons include the current or previous owner and operator of a site and
companies that disposed or arranged for the disposal of, the hazardous substance
found at a site. CERCLA also authorizes the EPA and, in some cases, private
parties to take actions in response to threats to the public health or the
environment and to seek recovery from such responsible classes of persons of the
costs of such action. In the course of their operations, the operators of the
Company's properties have generated and will generate wastes that may fall
within CERCLA's definition of "hazardous substances." The Company or the
operator of the properties
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may be responsible under CERCLA for all or part of the costs to clean up sites
at which such substances have been disposed.
The operations of the Company's properties are subject to Federal, state
and local regulations concerning the control of emissions from sources of air
contaminants. The Company's cost of air quality compliance is consistent with
industry experience.
The operations of the Underlying Properties are subject to the requirements
of the Federal Occupational Safety and Health Act ("OSHA") and comparable state
statutes. The OSHA hazard communication standard, the EPA community
right-to-know regulations under Title III of the Federal Superfund Amendment and
Reauthorization Act and similar state statutes require that information be
organized and maintained about hazardous materials used or produced in the
operations. Certain of this information must be provided to employees, state and
local government authorities and citizens.
TITLE TO PROPERTIES
The Company believes that its working interests with respect to its oil and
gas properties are good and defensible in accordance with standards generally
accepted in the oil and gas industry, subject to such exceptions which, in the
opinion of the Company are not so material as to detract substantially from the
use or value of its interests with respect to such properties. As is customary
in the oil and gas industry, only a perfunctory title examination is performed
when a lease is acquired, except leases covering proved reserves. Generally,
prior to drilling a well, a more thorough title examination of the drill site
tract is conducted and curative work is performed with respect to significant
title defects, if any, before proceeding with operations. The Company's oil and
gas properties are typically subject, in one degree or another, to one or more
of the following: (i) royalty interests and other burdens and obligations,
expressed and implied, under gas leases; (ii) overriding royalty interests,
production payments and similar interests and other burdens created by the
Company or its predecessors in title; (iii) a variety of contractual obligations
arising under operating agreements, farmout agreements, production sales
contracts and other agreements that may affect the properties or their titles;
(iv) liens that arise in the normal course of operations, such as those for
unpaid taxes, statutory liens securing unpaid suppliers and contractors and
contractual liens under operating agreements that are not yet delinquent or, if
delinquent, are being contested in good faith by appropriate proceedings; (v)
pooling, unitization and communitization agreements, declarations and orders;
(vi) easements, restrictions, rights-of-way and other matters that commonly
affect property; (vii) conventional rights of reassignment that obligate the
Company to reassign all or part of a property to a third party if the Company
intends to release or abandon such property; and (viii) rights reserved to or
vested in the appropriate governmental agency or authority to control or
regulate the properties. The Company believes that the burdens and obligations
affecting its oil and gas properties are conventional in the industry for
similar properties and do not, in the aggregate, materially interfere with the
use of such properties.
EMPLOYEES
As of March 31, 1997, the Company had approximately 700 full-time
employees, including four geologists, one geophysicist, seven petroleum
engineers, six landmen and 14 members of the marketing department. Approximately
278 employees are covered by six separate collective bargaining agreements.
These agreements expire on various dates in 1997 and early 1998 and the Company
anticipates renewing each of them. Management believes that its relationship
with its employees is good.
LEGAL PROCEEDINGS
The Company is involved in various legal actions and claims arising in the
ordinary course of business. In addition, Columbia Gas filed a suit in the U.S.
District Court for the Southern District of West Virginia -- Charleston Division
in March 1997 against Eastern American alleging that Eastern
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American's wells are producing storage gas from a Columbia Gas storage field in
West Virginia. Columbia Gas estimates its alleged damages to be in excess of $5
million. Eastern American purchased the wells in question from Great Western
Onshore Inc. and Great Western Drilling Inc. (collectively "Great Western")
pursuant to an Asset Purchase and Sale Agreement dated January 28, 1992.
Pursuant to the terms of the Asset Purchase and Sale Agreement, Eastern American
believes that it is entitled to indemnification from Forcenergy, Inc., successor
in interest to Great Western, as a result of Forcenergy's breach of certain
representations and warranties contained therein. While the outcome of this
lawsuit and other proceedings against the Company cannot be predicted with
certainty, management does not expect these matters to have a material adverse
effect on the Company's financial position.
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MANAGEMENT
The current executive officers and Directors of the Company and the current
executive officers of its subsidiaries are listed below, together with a
description of their experience and certain other information. Each of the
Directors was re-elected for a one year term at the Company's December annual
meeting of stockholders. Executive officers are appointed by the Board of
Directors.
<TABLE>
<CAPTION>
NAME AGE POSITION WITH COMPANY
---- --- ---------------------
<S> <C> <C>
Kenneth W. Brill........................ 89 Chairman of the Board of the Company; Director
John Mork............................... 49 President and Chief Executive Officer of the Company;
Director
Joseph E. Casabona...................... 53 Executive Vice President of the Company; Director
J. Michael Forbes....................... 36 Vice President and Treasurer of the Company
Richard E. Heffelfinger................. 38 President of Eastern American; Director
Donald C. Supcoe........................ 40 Vice President, General Counsel and Secretary of Eastern
American
F. H. McCullough, III................... 49 President of Eastern Marketing Corporation; Director
Richard L. Grant........................ 42 President of Mountaineer
Michael S. Fletcher..................... 48 Senior Vice President and Chief Financial Officer of
Mountaineer
Peter H. Coors.......................... 50 Director
L. B. Curtis............................ 72 Director
John J. Dorgan.......................... 73 Director
Arthur C. Nielsen, Jr................... 78 Director
Julie Mork.............................. 46 Director
</TABLE>
Kenneth W. Brill has been the Chairman of the Board of the Company since
its formation. He served as Chairman of Eastern American from 1974 until it
became a wholly owned subsidiary of the Company in 1993. He was employed by
Conoco, Inc. from 1930 to 1973, and served as Vice President and Regional
General Manager of the Rocky Mountain Division for thirteen years.
John Mork has been President and Chief Executive Officer of the Company and
a Director of the Company since its formation. Mr. Mork served in various
capacities at Santa Fe International and Union Oil Company until 1972 when he
joined Pacific States Gas and Oil, Inc. and subsequently founded Eastern
American. Mr. Mork was President and a Director of Eastern American Energy
Corporation from 1973 until 1993. Mr. Mork is a past Director of the Independent
Petroleum Association of America, and the Independent Oil and Gas Association of
West Virginia. He was chapter chairman of the Young Presidents' Organization,
Inc., Rocky Mountain Chapter in 1994-1995. Mr. Mork also founded the Mountain
States Chapter of the Young Presidents' Organization located in Charleston, West
Virginia. He is the husband of Julie Mork. Mr. Mork holds a Bachelor of Science
Degree in Petroleum Engineering from the University of Southern California and
he is a graduate of the Stanford Business School Program for Chief Executive
Officers.
Joseph E. Casabona is Executive Vice President of the Company and has been
a Director since its formation. Mr. Casabona joined Eastern American in 1985 and
was Executive Vice President of Eastern American and a Director from 1987 until
1993. Mr. Casabona was employed in various audit staff capacities from 1967 to
1984 with K. M. G. Main Hurdman ("KPMG, Peat Marwick") and from 1979 to 1984,
Mr. Casabona was an Audit Partner and a Director for Accounting and Auditing at
Main Hurdman's Pittsburgh, Pennsylvania office. Mr. Casabona graduated from the
University of Pittsburgh with a B.S. in Accounting and from the Colorado School
of Mines with an M.S. in mineral economics. Mr. Casabona has been a Certified
Public Accountant since 1967.
66
<PAGE> 72
J. Michael Forbes has been Vice President and Treasurer of the Company
since 1995. Mr. Forbes joined Eastern American in 1982 and was the Vice
President of Accounting, Treasurer and Chief Financial Officer of Eastern
American. Mr. Forbes graduated with a B. A. in accounting and finance from
Glenville State College and is a Certified Public Accountant. He also holds a
M.B.A. from Marshall University and is a graduate of Stanford University's
Program for Chief Financial Officers.
Richard E. Heffelfinger is President of Eastern American and has been a
Director of the Company since 1993. Mr. Heffelfinger joined Eastern American in
1980. Mr. Heffelfinger currently serves on the Board of Directors of Capital
State Bank of West Virginia as well as the West Virginia Oil and Natural Gas
Association. He is a member of the Young Presidents' Organization, Mountain
States Chapter, and a past Board Member and President of the Independent Oil and
Gas Association of West Virginia. Mr. Heffelfinger is a graduate of Glenville
State College.
Donald C. Supcoe is Vice President, General Counsel and Secretary of
Eastern American. He has been employed by Eastern American since 1981. Mr.
Supcoe is currently the President of the Independent Oil and Gas Association of
West Virginia and a past Vice President of the Independent Petroleum Association
of America. Mr. Supcoe graduated from West Virginia University with a B.S. in
Business Administration. Mr. Supcoe received a Doctor of Jurisprudence Degree
from West Virginia University College of Law.
F. H. McCullough, III has been a Director of the Company since 1993. Mr.
McCullough joined Eastern American in 1977. Mr. McCullough currently serves as
President of Eastern Marketing Corporation, a wholly-owned subsidiary of Eastern
American. Mr. McCullough was a Director of Eastern American from 1978 until
1993. Mr. McCullough is a graduate of the University of Southern California with
a Bachelor of Arts Degree in International Economics and two Masters Degrees in
Business Administration and Financial Systems Management. He is a graduate of
the Stanford University Graduate Business School Executive Program and a
graduate of the Northwestern University Kellogg Graduate School of Management
Executive Marketing Program.
Richard L. Grant has been President of Mountaineer Gas Company since 1988.
Prior to his service with Mountaineer Gas Company, Mr. Grant served as legal
counsel with the Cincinnati Gas and Electric Company. Mr. Grant is both a
licensed professional engineer and attorney having graduated from Rose Hulman
Institute of Technology and Northern Kentucky University.
Michael S. Fletcher has been Senior Vice President and Chief Financial
Officer of Mountaineer Gas Company since 1987. Prior to that time, Mr. Fletcher
was a partner of Arthur Andersen and Company and was employed by that firm for
15 years. Mr. Fletcher is also a Certified Public Accountant. Mr. Fletcher
graduated from Utah State University with a Bachelors Degree in Accounting.
Peter H. Coors has been a director of the Company since 1996. Mr. Coors is
Vice Chairman of the Board and Chief Executive Officer of Coors Brewing Company
and Vice President of Adolph Coors Company. He received his Bachelors Degree in
Industrial Engineering from Cornell University in 1969, and he earned his
Masters Degree in Business Administration from the University of Denver in 1970.
Mr. Coors also serves on the Board of Directors of First Bank Systems.
L. B. Curtis has been a director of the Company since 1993. Mr. Curtis was
a Director of Eastern American Energy Corporation from 1988 until 1993. Mr.
Curtis is retired from a career at Conoco, Inc. where he held the position of
Vice President of Production Engineering with Conoco Worldwide. Mr. Curtis
graduated from The Colorado School of Mines with an Engineer of Petroleum
Professional degree.
John J. Dorgan has been a Director of the Company since 1993. He served as
a Director for Eastern American Energy Corporation in 1992. He is a former
Executive Vice President and now a consultant to Occidental Petroleum
Corporation where he has worked in various capacities since 1972.
67
<PAGE> 73
Arthur C. Nielsen, Jr. has been a Director of the Company since 1993. He
was a Director of Eastern American Energy Corporation from 1985 until 1993. He
is Chairman, Emeritus of A. C. Nielsen Company and serves on the Boards of
Directors of Cafim, Italia', Dataquest, Inc. and General Binding Corporation. He
also serves as senior advisor to the Toshiba Corporation.
Julie M. Mork has been a Director of the Company since 1993. She was a
Director of Eastern American from 1974 until 1993. Mrs. Mork served as a founder
and Secretary/Treasurer of Pacific States Gas and Oil, Inc. and Eastern
American. Mrs. Mork received a B.A. in history from the University of California
in Los Angeles. She is the wife of John Mork.
The Company's Articles of Incorporation provide indemnification for each of
the Company's officers and directors for actions taken in such capacities.
DIRECTORS COMPENSATION
Each director of the Company receives a fee of $2,000 for attendance at
each Board of Directors meeting. Directors of the Company are reimbursed for
out-of-pocket expenses incurred in attending meetings of the Board of Directors
or committees thereof, and for other expenses incurred in their capacity as
directors of the Company.
EXECUTIVE COMPENSATION
The following table sets forth for fiscal year 1996 the total value of
compensation of (i) the Company's Chief Executive Officer and (ii) each other
executive officer of the Company.
<TABLE>
<CAPTION>
ALL OTHER
YEAR SALARY BONUS COMPENSATION(1)
---- -------- -------- ---------------
<S> <C> <C> <C> <C>
John Mork.................................. 1996 $224,000 $197,872 $5,122(5)
President and Chief Executive Officer
Joseph E. Casabona......................... 1996 177,904 213,124(2) 4,624(6)
Executive Vice President
J. Michael Forbes.......................... 1996 115,562 89,986(3) 2,591
Vice President and Treasurer
Richard L. Grant........................... 1996 250,785 25,000 -0-
President of Mountaineer Gas Company
Richard E. Heffelfinger.................... 1996 161,019 123,410(4) 3,714
President of Eastern American Energy
Corporation
</TABLE>
- ---------------
(1) Each of the amounts in this column reflects contributions by the Company to
its 401(k) Plan for the executive officer.
(2) Includes loan forgiveness of $75,000 in lieu of a cash bonus for fiscal
1996.
(3) Includes loan forgiveness of $32,000 in lieu of a cash bonus for fiscal
1996.
(4) Includes loan forgiveness of $64,000 in lieu of a cash bonus for fiscal
1996.
(5) Includes $1,740 in insurance premiums paid on a term life insurance policy
for the benefit of John Mork.
(6) Includes $1,440 in insurance premiums paid on a term life insurance policy
for the benefit of Joseph Casabona.
401(K) PLAN
For certain subsidiaries, the Company sponsors a qualified profit-sharing
plan and salary deferral program (the "401(k) Plan"). Full-time employees of
these subsidiaries are eligible to participate in the 401(k) Plan following
commencement of employment. Participants may defer up to 15% of their total
salary (including bonuses and commissions) each pay period. The Company
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<PAGE> 74
may make profit-sharing contributions to the 401(k) Plan to eligible
participants on a pro rata basis (or equally among all eligible participants)
which vest ratably over a four-year period. For calendar year 1996, the Company
undertook to match 33 1/3% of an employee's contribution and such policy may or
may not be extended by the Board of Directors in subsequent years. All
contributions are credited to separate accounts maintained in trust for each
participant and are invested, at the participant's direction, in one or more of
the investment funds available under the 401(k) Plan. All account balances are
adjusted at least annually to reflect the investment earnings and losses of the
funds. Each participant is fully vested in his or her deferred salary
contributions. Distributions may be made from a participant's account upon
termination of employment, retirement, disability or death. Participants may
also obtain loans from the 401(k) Plan secured by their account balances and may
request withdrawals in the event of certain financial hardship.
The federal tax laws limit the amount which may be added to a participant's
accounts for any one year under a qualified plan, such as the 401(k) Plan, to
the lesser of (i) $30,000 or (ii) 25% of the participant's compensation (net of
deferred salary contributions) for the year. In addition, not more than $9,500
of compensation (subject to periodic cost-of-living adjustments) may be deferred
by a participant through deferred salary contributions in any one calendar year.
MOUNTAINEER RETIREMENT INCOME PLAN
Mountaineer sponsors a non-contributory retirement Income Plan (the
"Pension Plan") which covers substantially all qualified Mountaineer employees
21 years of age and over. Employees became fully vested upon completion of five
years of credited service, as defined in the Pension Plan. Retirement income is
based on credited years of service and the employees' level of compensation, as
defined in the Pension Plan. The Pension Plan is subject to the provisions of
the Employee Retirement Income Security Act of 1974 ("ERISA"). The determination
of contributions is made in consultation with the Pension Plans' actuary and is
based upon anticipated earnings of the Pension Plan, mortality and turnover
experience, the funded status of the Pension Plan and anticipated future
compensation levels. Mountaineer's funding policy is to be in compliance with
ERISA guidelines and to make annual contributions to the Pension Plan to assure
that all employees' benefits will be fully provided for by the time they retire.
The following table reflects the estimated annual pension benefits payable
(assuming the Retirement Income Plan will continue in its present form) upon
retirement at age 65 to covered employees under the Retirement Income Plan based
upon various levels of compensation and years of service.
PENSION PLAN TABLE
<TABLE>
<CAPTION>
YEARS OF CREDITED SERVICE
FINAL AVERAGE ---------------------------------------------------
COMPENSATION 15 20 25 30 35
- ------------- ------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
$300,000....................... $32,900 $42,600 $52,500 $62,300 $65,500
250,000....................... 32,900 42,600 52,500 62,300 65,500
200,000....................... 32,900 42,600 52,500 62,300 65,500
175,000....................... 32,900 42,600 52,500 62,300 65,500
150,000....................... 32,900 42,600 52,500 62,300 65,500
125,000....................... 27,100 34,800 42,800 50,700 53,200
100,000....................... 21,300 27,100 33,100 39,100 41,000
</TABLE>
The remuneration amounts listed above are within 10% of the covered
compensation of the executive officer of Mountaineer named in the Summary
Compensation Table. Benefits reflected above are computed based upon a
straight-life annuity and are subject to Social Security deductions.
69
<PAGE> 75
PROFIT SHARING AND INCENTIVE STOCK PLANS
EASTERN AMERICAN PROFIT SHARING PLAN. Eastern American implemented its
Profit Sharing Plan (the "EAEC Plan") in 1987 to assist Eastern American in
attracting and retaining key personnel and executive employees. The EAEC Plan is
administered by a Profit Sharing Committee whose members are selected and
appointed by the Board of Directors. The EAEC Plan requires that a three-member
Committee be in place at all times to oversee the operations of the plan and to
make recommendations to the Board of Directors as to which employees should be
entitled to participate in the plan.
Eligible employees under the EAEC Plan include the following: (i) all
current employees with two or more years of service; (ii) new employees with
more than one year's service in jobs which affect Eastern American's
profitability; and (iii) any employee which the Committee deems as eligible due
to that employee's extraordinary service or contribution.
Profit sharing distributions under the EAEC Plan are calculated as a
portion of Eastern American's base pool, defined as that percentage of cash
operating profit which the Board determines on an annual basis. Cash operating
profit is defined under the EAEC Plan as operating profit or loss plus
depreciation, depletion and impairment allowances less federal income tax
expense and principal reductions on long-term debt. The EAEC Plan calls for the
monies in the base pool to be allocated, one-third of which is placed into an
award pool. The award pool under the EAEC Plan is then divided among six
employee groups with each group receiving a fixed percentage of the award pool
so designated by the Board.
The EAEC Plan requires that the monies in the award pool be distributed
over a two-year period. During the first year, one-half of the award pool must
be distributed to plan participants within 120 days of Eastern American's fiscal
year end. Those eligible employees within each of the six employee groups who
are not executive officers are entitled to mandatory awards equal to an amount
calculated as one-half of the employee's annual base salary divided by the
aggregate base salaries of all eligible employees within the same employee
group. After mandatory awards are disbursed, the remaining funds are to be
distributed among those employees within the six employee groups that have been
chosen by their supervisors as outstanding employees. Payment of one-half of the
monies from the award pool is deferred and added to the award pool for
distribution in the following fiscal year so as to avoid large variances in the
annual distributions. The EAEC Plan allows an employee to earn one-twelfth of
the deferred portion of his or her profit sharing per month for each month of
employment during the second year.
The EAEC Plan may be amended or terminated within the sole discretion of
Eastern American's Board of Directors.
EASTERN AMERICAN INCENTIVE STOCK PLAN. Eastern American currently has an
Incentive Stock Plan (the "Stock Plan") in place which provides certain
employees with the opportunity to use their profit sharing distributions under
the EAEC Plan to purchase incentive stock.
The Stock Plan is administered by the same three-member Committee appointed
by Eastern American's Board to oversee the EAEC Plan. The Stock Plan authorizes
either the Committee or the Board to determine the eligibility of employees
under the Stock Plan. Eligible employees are defined under the Stock Plan as
either (i) members of the upper three employee groups under the EAEC Plan or
(ii) employees who have received discretionary profit sharing awards under the
EAEC Plan based upon their extraordinary service or contribution. No other
employees are eligible to convert their profit sharing distributions under the
EAEC Plan into incentive stock.
Under the Stock Plan, Eastern American is authorized to issue incentive
stock equal to the lesser of 100,000 shares or 5% of Eastern American's total
outstanding stock. Participants in the Stock Plan are entitled to share in the
dividends of Eastern American by an amount equal to the percent by which
incentive stock comprises Eastern American's total shares outstanding, limited,
however, to no more than 10% of the total dividends declared in any one year.
70
<PAGE> 76
Participants under the Stock Plan may purchase their incentive shares at a
price equal to six times Eastern American's three-year average net earnings per
share.
MOUNTAINEER PROFIT SHARING PLAN. Mountaineer established its Annual Cash
Profit Sharing Plan (the "Mountaineer Plan") in 1996 to encourage employees and
management to expand and improve the profits and prosperity of Mountaineer while
assisting Mountaineer in attracting and retaining key executive employees and
other personnel. The Mountaineer Plan is administered by a Profit Sharing
Committee whose members are selected and appointed by the Board of Directors.
The Mountaineer Plan entitles the Board to select the number of Committee
members on an annual basis. The Committee is charged with determining which
employees meet the minimum eligibility requirements under the Mountaineer Plan.
Eligible employees under the Mountaineer Plan include the following: (i)
all current full-time employees with two or more years of service; (ii) new
full-time permanent employees with more than one year's service in jobs which
affect Mountaineer's profitability; (iii) any part-time permanent employee in a
job which affects Mountaineer's profitability; and (iv) any employee which the
Committee deems as eligible due to that employee's extraordinary service or
contribution. An employee must be employed by Mountaineer as of the last day of
the fiscal year in order to participate.
Profit sharing distributions under the Mountaineer Plan are calculated as a
portion of Mountaineer's base pool, defined as the amount remaining after the
Board deducts certain expenses from Mountaineer's cash operating profit. Cash
operating profit under the Mountaineer Plan is defined as net income less
principal reductions on long-term debt plus or minus other noncash items which
the Board determines to have impacted net income. One-third of the monies
included in the base pool under the Mountaineer Plan is allocated to an award
pool, a portion of which will ultimately be paid to plan participants in the
form of distributions.
The award pool under the Mountaineer Plan is allocated in the following
manner: First, the Board establishes a fixed percentage of base salaries for the
applicable fiscal year. Amounts in the award pool not exceeding the fixed
percentage, together with 25% of the amount exceeding the fixed percentage,
remain in the award pool. 75% of the amount exceeding the fixed percentage is
allocated to ESC to be used for any purpose determined by ESC's Board of
Directors.
The monies allocated to the award pool are distributed under the
Mountaineer Plan over a two-year period. During the first year, one-half of the
monies from the tiers are distributed to plan participants within 180 days of
Mountaineer's fiscal year end. Eligible employees are divided among seven
different award groups, with each employee being entitled to a mandatory award
equal to an amount calculated as one-half of the employee's annual base salary
divided by the aggregate base salaries of all eligible employees within the same
award group. After each employee receives his or her mandatory award, the
remaining funds are distributed among those employees within the seven award
groups that have been chosen by their supervisors as outstanding employees.
Payment of one-half of the remaining monies in the award pool is deferred and
added to the award pool for the following fiscal year so as to avoid large
variances in distributions from year to year.
The Mountaineer Plan allows for proportionate distributions to be made to
employees in the event of death, retirement, long-term disability or authorized
leave of absence. Under the Mountaineer Plan, the employee or his beneficiary is
entitled to receive a proportionate distribution based upon the actual number of
days worked during the fiscal year, with the remainder reverting to
Mountaineer's award pool for distribution in the following year.
The Mountaineer Plan may be amended or terminated within the sole
discretion of Mountaineer's Board of Directors.
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<PAGE> 77
INCENTIVE STOCK OPTION AGREEMENTS
The Company has granted incentive stock options to Richard E. Heffelfinger,
Donald C. Supcoe and J. Michael Forbes. The incentive stock options were granted
in December 1994 and give each of the employees the option to purchase specified
numbers of shares of the Company's Common Stock at a price of $40.00 per share
over a four year period commencing January 1, 1994 and extending through
December 31, 1997. Messrs. Heffelfinger, Forbes and Supcoe have the option to
purchase 6,400, 3,200 and 3,200 shares of the Company's Common Stock,
respectively. Any Common Stock purchased with respect to these options will be
subject to certain restrictions and limitations upon transfer.
72
<PAGE> 78
PRINCIPAL STOCKHOLDERS AND SHARE OWNERSHIP OF MANAGEMENT
The following table sets forth certain information regarding (i) the share
ownership of the Company by each person known to the Company to be the
beneficial owner of more than 5% of the outstanding shares of Common Stock, (ii)
the share ownership of the Company by each Director, (iii) the share ownership
of the Company by certain executive officers and (iv) the share ownership of the
Company by all Directors and executive officers as a group, in each case as of
April 25, 1997. The business address of each officer and Director listed below
is: c/o Energy Corporation of America, 4643 S. Ulster, Suite 1100, Denver,
Colorado 80237.
<TABLE>
<CAPTION>
BENEFICIAL OWNERSHIP
----------------------
NUMBER OF
SHARES PERCENT
--------- -------
<S> <C> <C>
Kenneth W. Brill(1)......................................... 62,600 9.3%
John Mork(2)................................................ 399,283 59.5
Joseph E. Casabona.......................................... 18,337 2.7
Richard E. Heffelfinger(3).................................. 6,400 *
J. Michael Forbes(4)........................................ 3,200 *
Donald C. Supcoe(4)......................................... 3,200 *
Peter H. Coors.............................................. 150 *
L. B. Curtis................................................ 10,000 1.5
John J. Dorgan.............................................. 650 *
Arthur C. Nielsen, Jr....................................... 36,000 5.4
F. H. McCullough, III(5).................................... 101,925 15.2
Julie Mork(2)............................................... 399,283 59.5
All officers and directors as a group (12 persons).......... 641,745 95.6
</TABLE>
- ---------------
* Less than one percent
(1) Pursuant to agreements dated June 30, 1993 and July 8, 1996, Kenneth W.
Brill granted the Company options to purchase 15,400 and 64,000 shares,
respectively, of the Company's Common Stock owned by him.
(2) Includes 391,200 shares held by John and Julie Mork as joint tenants, 2,183
shares held by Julie Mork individually, and 2,950 shares held by each of the
Alison Mork Trust and the Kyle Mork Trust.
(3) Includes options to purchase 1,600 shares which are exercisable at a price
of $40.00 per share.
(4) Includes options to purchase 800 shares which are exercisable at a price of
$40.00 per share.
(5) Pursuant to an agreement dated May 20, 1997, F. H. McCullough, III and his
wife, Kathy L. McCullough, jointly granted the Company an option to purchase
11,920 shares of the Company's Common Stock owned by them.
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<PAGE> 79
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Certain officers, directors and key employees of the Company and members of
their families regularly participate in the wells drilled by the Company on an
actual costs basis and share in the costs and revenues on the same basis as the
Company. The Company has the right to select the wells drilled and each officer,
director and key employee participates in all wells included within a Company
drilling program (the "Drilling Program") and cannot selectively choose the
wells in which to participate. The Company typically has a development drilling
component and an exploration drilling component within each years' Drilling
Program. The officers, directors, key employees and their family members may
participate in either or both of the components. The following table identifies
the officers', directors', key employees' and family members' aggregate
investment in the calendar years shown:
<TABLE>
<CAPTION>
1995 1996 1997(1)
---------- -------- --------
<S> <C> <C> <C>
K.W. Brill................................ $ 160,731 $ 32,223 $ 35,000
John Mork(2).............................. 482,510 224,346 175,000
Joseph E. Casabona........................ 31,440 20,858 35,000
J. Michael Forbes......................... 14,252 8,276 15,000
Donald C. Supcoe.......................... 16,480 2,751 0
Richard L. Grant.......................... 0 2,751 25,000
L.B. Curtis............................... 91,665 30,932 35,000
John J. Dorgan............................ 31,351 22,232 35,000
Arthur C. Nielsen, Jr..................... 32,210 24,981 25,000
F. H. McCullough, III..................... 219,663 0 100,000
Lesley McCullough(3)...................... 9,734 3,300 0
Kristen McCullough(3)..................... 9,734 3,300 0
Meredith McCullough(3).................... 9,734 3,300 0
Katherine McCullough(3)................... 9,734 3,300 0
Alison Mork Trust(4)...................... 23,804 11,103 25,000
Kyle Mork Trust(4)........................ 23,804 11,103 25,000
Gary A. Brill(5).......................... 120,076 20,858 0
E.J. Davies............................... 9,086 20,858 35,000
---------- -------- --------
Total:.......................... $1,296,008 $446,472 $565,000
========== ======== ========
</TABLE>
- ---------------
(1) This amount represents only the amount committed to the exploration
component of the 1997 Drilling Program and the actual investment may vary.
(2) Interest of John Mork and Julie Mork held as joint tenants.
(3) Minor children of F. H. McCullough, III and Kathy L. McCullough.
(4) Alison Mork and Kyle Mork are the minor children of John Mork and Julie
Mork.
(5) Gary A. Brill is the son of K.W. Brill.
74
<PAGE> 80
Certain officers, directors and key employees of the Company have notes
payable to the Company or its subsidiaries which are secured by such
individual's interests in certain of the Company's drilling programs. Each of
these notes bear interest at 8% per annum. The balance owed by the individuals
as of March 31, 1997 was approximately $1 million. The amounts owed by the named
officers, directors and key employees, as of March 31, 1997, are as follows:
<TABLE>
<S> <C>
K.W. Brill.................................................. $303,158
John Mork................................................... 326,224
Joseph E. Casabona.......................................... 44,485
J. Michael Forbes........................................... 7,250
Richard E. Heffelfinger..................................... 4,943
L.B. Curtis................................................. 18,453
Arthur C. Neilsen, Jr....................................... 42,838
F. H. McCullough, III....................................... 168,055
--------
Total............................................. $915,406
========
</TABLE>
In addition to the foregoing notes, various officers and directors of the
Company have borrowed money from the Company and have executed promissory notes
therefor. These promissory notes are generally secured by a pledge of the stock
of the Company or the stock of one of its subsidiaries. The notes issued by
Messrs. Forbes, Supcoe and Heffelfinger bear interest at the rate charged by
Eastern American's largest lender, plus one-half percent. The balance of these
notes bear interest at 8% per annum. As of March 31, 1997, the following were
indebted to the Company in amounts in excess of $60,000:
<TABLE>
<S> <C>
Joseph E. Casabona.......................................... $314,822
F. H. McCullough, III....................................... 190,000
J. Michael Forbes........................................... 64,000
Donald C. Supcoe............................................ 64,000
Richard E. Heffelfinger..................................... 128,000
--------
Total............................................. $760,822
========
</TABLE>
Eastern American entered into an agreement in July 1991 to rent 11,260
square feet of office space in Charleston, West Virginia from a corporation
owned 33.33% by John Mork, 16.667% by each of Kenneth W. Brill, F. H.
McCullough, III and Joseph E. Casabona and 5.57% by each of Donald C. Supcoe,
Richard E. Heffelfinger and J. Michael Forbes. The agreement was amended in
April 1994 to provide for the lease of an aggregate of 19,069 square feet of
office space. The aggregate amount paid by such subsidiary for rent to such
corporation was $337,291 for fiscal year 1996. The Company believes that such
rental terms are no less favorable than could have been obtained from an
unaffiliated party.
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<PAGE> 81
DESCRIPTION OF THE NOTES
The Exchange Notes will be issued, and the Old Notes were issued, pursuant
to the Indenture (the "Indenture") between the Company and The Bank of New York,
as trustee (the "Trustee"). The following is a summary of material provisions of
the Indenture. Certain terms used herein are defined below under "-- Certain
Definitions." Copies of the proposed form of Indenture and Registration Rights
Agreement are available as set forth under "Other Information."
GENERAL
The Exchange Notes will be issued solely in exchange for an equal principal
amount of Old Notes pursuant to the Exchange Offer. The form and terms of the
Exchange Notes will be identical in all material respects to the form and terms
of the Old Notes except that the offering of the Exchange Notes has been
registered under the Securities Act, and the Exchange Notes will therefore not
be subject to transfer restrictions, registration rights and certain provisions
relating to an increase in the stated interest rate on the Old Notes under
certain circumstances. See "-- Registered Exchange Offer; Registration Rights."
The Notes are subject to the terms stated in the Indenture, a copy of which has
been filed as an exhibit to the Registration Statement, and holders of the Notes
are referred thereto for a statement of those terms. The statements and
definitions of terms under this caption relating to the Notes and the Indenture
described below are summaries. Such summaries make use of certain terms defined
in the Indenture which are not separately defined herein. Certain terms used
herein are defined below under "-- Certain Definitions."
The Old Notes and the Exchange Notes will constitute a single series of
debt securities under the Indenture. If the Exchange Offer is consummated,
holders of Old Notes who do not exchange their Old Notes for Exchange Notes will
vote together with holders of the Exchange Notes for all relevant purposes under
the Indenture. In that regard, the Indenture requires that certain actions by
the holders thereunder (including acceleration following an Event of Default)
must be taken, and certain rights must be exercised, by specified minimum
percentages of the aggregate principal amount of the outstanding securities
issued under the Indenture. In determining whether holders of the requisite
percentage in principal amount have given any notice, consent or waiver or taken
any other action permitted under the Indenture, any Old Notes that remain
outstanding after the Exchange Offer will be aggregated with the Exchange Notes,
and the holders of such Old Notes and the Exchange Notes will vote together as a
single series for all such purposes. Accordingly, all references herein to
specified percentages in aggregate principal amount of the outstanding Notes
shall be deemed to mean, at any time after the Exchange Offer is consummated,
such percentages in aggregate principal amount of the Old Notes and the Exchange
Notes then outstanding.
The Notes are general unsecured obligations of the Company and are
subordinated in right of payment to Senior Debt. See "-- Ranking and
Subordination." For purposes of this section, the term "Company" means Energy
Corporation of America. As of the date of the Indenture, all of the Company's
Subsidiaries were Restricted Subsidiaries. Under certain circumstances, however,
the Company will be able to designate current and future Subsidiaries as
Unrestricted Subsidiaries. Unrestricted Subsidiaries will not be subject to any
of the restrictive covenants set forth in the Indenture. See "-- Certain
Covenants."
TERMS OF THE NOTES
The Notes are limited in aggregate principal amount to $200.0 million and
mature on May 15, 2007. Interest on the Notes accrues at the rate of 9 1/2% per
annum and is payable semi-annually in arrears on May 15 and November 15 of each
year, commencing November 15, 1997, to holders of the Notes of record on the
immediately preceding May 1 and November 1. Interest on the Notes accrues from
the most recent date on which interest has been paid or, if no interest has been
paid, from the date of original issuance. The Old Notes provide that if, by
November 5, 1997, (i) the Exchange Offer has not been consummated, or (ii) a
shelf registration statement relating to the sale
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of the Old Notes has not been declared effective, the Company will pay
liquidated damages in an amount equal to $0.192 per week per $1,000 principal
amount of the Old Notes outstanding from and including November 5, 1997 until
but excluding the date of the consummation of the Exchange Offer or the date
such shelf registration statement is declared effective, as the case may be.
These liquidated damages provisions do not apply to the Exchange Notes.
Interest will be computed on the basis of a 360-day year comprised of
twelve 30-day months. Principal, premium, if any, and interest on the Notes is
payable at the office or agency of the Company maintained for such purpose
within the City and State of New York or, at the option of the Company, payment
of interest may be made by check mailed to the holders of the Notes at their
respective addresses set forth in the applicable register of holders of the
Notes. Until otherwise designated by the Company, the Company's office or agency
in New York is the office of the Trustee maintained for such purpose. The Notes
are fully registered as to principal and interest in minimum denominations of
$1,000 and integral multiples of $1,000 in excess thereof.
OPTIONAL REDEMPTION
Except as otherwise described below, the Notes are not be redeemable at the
Company's option prior to May 15, 2002. Thereafter, the Notes are subject to
redemption at the option of the Company, in whole or in part, upon not less than
30 nor more than 60 days' notice, at the redemption prices (expressed as
percentages of principal amount) set forth below plus accrued and unpaid
interest thereon to the applicable redemption date, if redeemed during the
twelve-month period beginning on May 15 of the years indicated below:
<TABLE>
<CAPTION>
YEAR PERCENTAGE
---- ----------
<S> <C>
2002........................................................ 104.750%
2003........................................................ 103.167%
2004........................................................ 101.583%
2005 and thereafter......................................... 100.000%
</TABLE>
Prior to May 15, 2000, the Company may, at its option, on any one or more
occasions, redeem up to 33 1/3% of the original aggregate principal amount of
the Notes at a redemption price equal to 109.50% of the principal amount
thereof, plus accrued and unpaid interest, if any, thereon to the redemption
date, with all or a portion of the net proceeds of public sales of Common Stock
of the Company; provided that at least 66 2/3% of the original aggregate
principal amount of the Notes remains outstanding immediately after the
occurrence of such redemption; and provided, further, that such redemption shall
occur within 60 days of the date of the closing of the related sale of Common
Stock of the Company.
SELECTION AND NOTICE
In the case of any partial redemption, selection of the Notes for
redemption will be made by the Trustee in compliance with the requirements of
the principal national securities exchange, if any, on which the Notes are
listed, or, if such Notes are not so listed, on a pro rata basis, by lot or by
such method as such Trustee shall deem fair and appropriate; provided that no
Note of $1,000 or less shall be redeemed in part. Notices of redemption shall be
mailed by first class mail at least 30 but not more than 60 days before the
redemption date to each holder of the Notes to be redeemed at its registered
address. If any Note is to be redeemed in part only, the notice of redemption
that relates to such Note shall state the portion of the principal amount
thereof to be redeemed. A new Note in principal amount equal to the unredeemed
portion thereof will be issued in the name of the holder thereof upon
cancellation of the original Note. On and after the redemption date, interest
will cease to accrue on the Notes or portions of them called for redemption.
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<PAGE> 83
REGISTERED EXCHANGE OFFER; REGISTRATION RIGHTS
Pursuant to the Registration Rights Agreement, the Company has agreed that
it will, at its cost, (i) within 45 days after the date of original issue of the
Old Notes, file the Registration Statement with the SEC with respect to the
Exchange Offer to exchange the Old Notes for Exchange Notes of the Company,
which will have terms substantially identical in all material respects to the
Old Notes (except that the Exchange Notes will not contain terms with respect to
transfer restrictions) and (ii) use its best efforts to cause the Registration
Statement to be declared effective under the Securities Act within 150 days
after the date of original issue of the Old Notes. Upon the effectiveness of the
Registration Statement, the Company will offer the Exchange Notes in exchange
for surrender of the Old Notes. The Company will keep the Exchange Offer open
for not less than 30 days (or longer if required by applicable law) after the
date notice of the Exchange Offer is mailed to the holders of the Old Notes. For
each Old Note surrendered to the Company pursuant to the Exchange Offer, the
holder of such Old Note will receive an Exchange Note having a principal amount
equal to that of the surrendered Old Note. Interest on each Exchange Note will
accrue from the last interest payment date on which interest was paid on the Old
Note surrendered in exchange thereof or, if no interest has been paid on such
Old Note, from the date of its original issue. Under existing SEC
interpretations, the Company believes that the Exchange Notes would be freely
transferable by holders other than affiliates of the Company after the Exchange
Offer without further registration under the Securities Act if the holder of the
Exchange Notes represents that it is acquiring the Exchange Notes in the
ordinary course of its business, that it has no arrangement or understanding
with any person to participate in the distribution of the Exchange Notes and
that it is not an affiliate of the Company, as such terms are interpreted by the
SEC; provided, however, that broker-dealers ("Participating Broker-Dealers")
receiving Exchange Notes in the Exchange Offer will have a prospectus delivery
requirement with respect to resales of such Exchange Notes. The SEC has taken
the position that Participating Broker-Dealers may fulfill their prospectus
delivery requirements with respect to Exchange Notes (other than a resale of an
unsold allotment from the original sale of the Old Notes) with this Prospectus.
Under the Registration Rights Agreement, the Company is required to allow
Participating Broker-Dealers and other persons, if any, with similar prospectus
and delivery requirements to use this Prospectus in connection with the resale
of such Exchange Notes.
A holder of Old Notes (other than certain specified holders) who wishes to
exchange such Old Notes for Exchange Notes in the Exchange Offer will be
required to represent that any Exchange Notes to be received by it will be
acquired in the ordinary course of its business and that at the time of the
commencement of the Exchange Offer it has no arrangement or understanding with
any person to participate in the distribution (within the meaning of the
Securities Act) of the Exchange Notes and that it is not an "affiliate" of the
Company, as defined in Rule 405 of the Securities Act, or if it is an affiliate,
it will comply with the registration and prospectus delivery requirements of the
Securities Act to the extent applicable.
In the event that applicable interpretations of the staff of the SEC do not
permit the Company to effect the Exchange Offer, or if for any other person, the
Exchange Offer is not consummated within 165 days of the date of original issue
of the Old Notes, or if the Initial Purchasers so request with respect to Old
Notes not eligible to be exchanged for Exchange Notes in the Exchange Offer, or
if any holder of Old Notes is not eligible to participate in the Exchange Offer
or does not receive freely tradeable Exchange Notes in the Exchange Offer, the
Company will, at its cost, (a) as promptly as practicable, file a shelf
registration statement (the "Shelf Registration Statement") with the SEC
covering resales of the Old Notes or the Exchange Notes, as the case may be, (b)
use its best efforts to cause the Shelf Registration Statement to be declared
effective under the Securities Act and (c) keep the Shelf Registration Statement
effective until the earlier of (i) the time when the Notes covered by the Shelf
Registration Statement can be sold pursuant to Rule 144 without any limitations
under clauses (c), (e), (f) and (h) of Rule 144 and (ii) three years from the
Issue Date. The Company will, in the event a Shelf Registration Statement is
filed, among other things, provide
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to each holder for whom such Shelf Registration Statement was filed copies of
the prospectus which is part of the Shelf Registration Statement, notify each
such holder when the Shelf Registration Statement has become effective and take
certain other actions as are required to permit unrestricted resales of the Old
Notes or the Exchange Notes, as the case may be. A Holder selling such Old Notes
or Exchange Notes pursuant to the Shelf Registration Statement generally would
be required to be named as a selling security holder in the related prospectus
and to delivery a prospectus to purchasers, will be subject to certain of the
civil liability provisions under the Securities Act in connection with such
sales and will be bound by the provisions of the Registration Rights Agreement
which are applicable to such holder (including certain indemnification
obligations).
If (i) the Registration Statement or the Shelf Registration Statement, as
the case may be, is not filed with the Commission on or prior to 45 days after
the Issue Date, (ii) the Registration Statement or the Shelf Registration
Statement, as the case may be, is not declared effective within 150 days after
the Issue Date (or in the case of a Shelf Registration Statement required to be
filed in response to a change in law or the applicable interpretations of
Commissions' staff, if later, within 45 days after publication of the change in
law or interpretation), (iii) the Exchange Offer is not consummated on or prior
to 165 days after the Issue Date, or (iv) the Shelf Registration Statement is
filed and declared effective within 150 days after the Issue Date (or in the
case of a Shelf Registration Statement required to be filed in response to a
change in law or the applicable interpretations of Commission's staff, if later,
within 45 days after publication of the change in law or interpretation) but
shall thereafter cease to be effective (each such event referred to in clauses
(i) through (iv), a "Registration Default"), the Company will pay liquidated
damages to each holder of Transfer Restricted Securities (as defined in the
Indenture), during the period of Registration Default, in an amount equal to
$0.192 per week per $1,000 principal amount of the Notes constituting Transfer
Restricted Securities held by such holder until the applicable Registration
Statement is filed or declared effective, the Exchange Offer is consummated or
the Shelf Registration Statement again becomes effective, as the case may be.
Pursuant to the Registration Rights Agreement, if the Company effects the
Exchange Offer, it will be entitled to close the Exchange Offer 30 days after
the commencement thereof provided that it has accepted all Old Notes theretofore
validly tendered in accordance with the terms of the Exchange Offer.
The summary herein of certain provisions of the Registration Rights
Agreement does not purport to be complete and is subject to, and is qualified in
its entirety by reference to, all the provisions of the Registration Right
Agreement, a copy of which is filed as an exhibit to the Registration Statement.
RANKING AND SUBORDINATION
The Notes are unsecured obligations of the Company and the payment of
principal, premium, if any, and interest on the Notes and any other payment
obligations of the Company in respect of the Notes (including any obligation to
repurchase the Notes) are subordinated in certain circumstances in right of
payment, as set forth in the Indenture, to the prior payment in full in cash of
all Senior Debt, whether outstanding on the date of the Indenture or thereafter
incurred, which includes borrowings under the Credit Agreement. The Notes rank
pari passu in right of payment with all other existing and future Pari Passu
Debt (as defined in "-- Certain Definitions") of the Company, and with any other
indebtedness or liability of the Company which does not expressly provide that
it is subordinated in right of payment to the Notes. The Notes are senior to
other indebtedness of the Company that expressly provides that it is
subordinated in right of payment of the Notes. The Notes are effectively
subordinated in right of payment to the liabilities of the subsidiaries of the
Company (including claims of trade creditors and tort claimants). In the event
of bankruptcy, liquidation or reorganization of the Company, the assets of the
Company will be available to pay obligations on the Notes only after all Senior
Debt has been paid in full, and there may not be sufficient assets remaining to
pay amounts due on any or all of the Notes outstanding. As of March 31, 1997, on
a pro
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<PAGE> 85
forma basis giving effect to the Offering and the application of the net
proceeds therefrom, the Company would not have had any Senior Debt outstanding,
the Company would not have had any Pari Passu Debt outstanding, the aggregate
principal amount of indebtedness outstanding of the subsidiaries of the Company
would have been $86.6 million and such subsidiaries would have had $46.4 million
of additional borrowing availability under existing revolving lines of credit.
The Indenture will limit, subject to certain financial tests, the amount of
additional Indebtedness, that the Company and its Restricted Subsidiaries may
incur. See "-- Certain Covenants -- Incurrence of Indebtedness and Issuance of
Disqualified Stock." In addition to being subordinated to all existing and
future Senior Indebtedness of the Company, the Notes will be effectively
subordinated to all secured debt of the Company and its subsidiaries. The
Company's obligations under the Credit Agreement will be secured by a mortgage
on substantially all of the gas and oil properties of Eastern American, the
subsidiary of the Company that owns and operates substantially all of the
Company's gas and oil properties in the Appalachian Basin. See "Description of
Other Indebtedness -- Indebtedness of the Company -- Credit Agreement."
The Company conducts all of its operations through subsidiaries.
Accordingly, the Company relies on dividends and cash advances from its
subsidiaries to provide funds necessary to meet its obligations, including the
payment of principal and interest on the Notes. The ability of any such
subsidiary to pay dividends or make cash advances is subject to applicable laws
and contractual restrictions, including restrictions under credit agreements
between such subsidiary and third party lenders, as well as the financial
condition and operating requirements of such subsidiary. See "-- Certain
Covenants -- Incurrence of Indebtedness and Issuance of Disqualified Stock,"
"-- Certain Covenants -- Dividend and Other Payment Restrictions Affecting
Restricted Subsidiaries" and "Description of Other Indebtedness -- Indebtedness
of Subsidiaries."
Upon any payment or distribution of property or securities to creditors of
the Company in a liquidation or dissolution of the Company or in a bankruptcy,
reorganization, insolvency, receivership or similar proceeding relating to the
Company or its property, or in an assignment for the benefit of creditors or any
marshalling of the Company's assets and liabilities, the holders of Senior Debt
will be entitled to receive payment in full of all Obligations due in respect of
such Senior Debt (including interest after the commencement of any such
proceeding at the rate specified in the applicable Senior Debt, whether or not a
claim for such interest would be allowed in a proceeding) before the holders of
the Notes will be entitled to receive any payment with respect to the Notes, and
until all Obligations with respect to Senior Debt are paid in full, any
distribution to which the holders of the Notes would be entitled shall be made
to the holders of Senior Debt (except that holders of the Notes may receive (i)
Equity Interests and securities that are subordinated at least to the same
extent as the Notes are subordinated to Senior Debt and (ii) payments made from
the trust described under "-- Legal Defeasance and Covenant Defeasance").
The Company also may not make any payment (whether by redemption, purchase,
retirement defeasance or otherwise) upon or in respect of the Notes (except (i)
payment of Equity Interests and securities that are subordinated at least to the
same extent as the Notes are subordinated to Senior Debt and (ii) payments made
from the trust described under "-- Legal Defeasance and Covenant Defeasance") if
(i) a default in the payment of the principal of, premium, if any, or interest
on Designated Senior Debt occurs ("payment default") or (ii) any other default
occurs and is continuing with respect to Designated Senior Debt that permits, or
with the giving of notice or passage of time or both (unless cured or waived)
will permit, holders of the Designated Senior Debt as to which such default
relates to accelerate its maturity ("non-payment default") and the Trustee
receives a notice of such default (a "Payment Blockage Notice") from the Company
or the holders of any Designated Senior Debt. Cash payments on the Notes shall
be resumed (a) in the case of a payment default, upon the date on which such
default is cured or waived and (b) in case of a nonpayment default, the earlier
of the date on which such nonpayment default is cured or waived or 179 days
after the date on which the applicable Payment Blockage Notice is received,
unless the maturity of any Designated Senior Debt has been accelerated or a
default of the type described in
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<PAGE> 86
clause (ix) under the caption "Events of Default" has occurred and is
continuing. No new period of payment blockage may be commenced unless and until
360 days have elapsed since the date of commencement of the payment blockage
period resulting from the immediately prior Payment Blockage Notice. No
nonpayment default in respect of Designated Senior Debt that existed or was
continuing on the date of delivery of any Payment Blockage Notice to the Trustee
shall be, or be made, the basis for a subsequent Payment Blockage Notice unless
such default shall have been cured or waived for a period of no less than 90
days.
The Indenture further requires that the Company promptly notify holders of
Senior Debt if payment of the Notes is accelerated because of an Event of
Default.
As a result of the subordination provisions described above, in the event
of a liquidation or insolvency of the Company, holders of the Notes may recover
less ratably than creditors of the Company who are holders of Senior Debt.
MANDATORY REDEMPTION
Except as set forth below under "-- Repurchase at the Option of holders,"
the Company is not required to make mandatory redemption or sinking fund
payments with respect to the Notes.
REPURCHASE AT THE OPTION OF HOLDERS
Change of Control
Upon the occurrence of a Change of Control, each holder of the Notes will
have the right to require the Company to repurchase all or any part (equal to
$1,000 or an integral multiple thereof) of such holder's Notes pursuant to the
offer described below (the "Change of Control Offer") at an offer price in cash
equal to 101% of the aggregate principal amount of the Notes plus accrued and
unpaid interest, if any, thereon to the date of purchase (the "Change of Control
Payment"). Within 30 days following any Change of Control, the Company will (i)
mail a notice to each holder describing the transaction or transactions that
constitute the Change of Control and (ii) offer to repurchase the Notes pursuant
to the procedures required by the Indenture and described in such notice on a
date no earlier than 30 days nor later than 60 days from the date such notice is
mailed (the "Change of Control Payment Date"). The Company will comply with the
requirements of Rule 14e-1 under the Exchange Act and any other securities laws
and regulations thereunder to the extent such laws and regulations are
applicable in connection with the repurchase of the Notes as a result of a
Change of Control. To the extent that the provisions of any securities laws or
regulations conflict with the provisions of the covenant described hereunder,
the Company shall comply with the applicable securities laws and regulations and
shall not be deemed to have breached its obligations under the covenant
described hereunder by virtue thereof.
On the Change of Control Payment Date, the Company will, to the extent
lawful, (i) accept for payment all Notes or portions thereof properly tendered
pursuant to the Change of Control Offer, (ii) deposit with the Paying Agent an
amount equal to the Change of Control Payment in respect of all the Notes or
portions thereof so tendered and (iii) deliver or cause to be delivered to the
Trustee the relevant Notes so accepted together with an Officers' Certificate
stating the aggregate principal amount of such Notes or portions thereof being
purchased by the Company. The Paying Agent will promptly mail to each holder of
the Notes so tendered the Change of Control Payment for such Notes, and the
Trustee will promptly authenticate and mail (or cause to be transferred by book
entry) to each tendering holder a new Note equal in principal amount to any
unpurchased portion of the Notes surrendered, if any; provided that each such
new Note will be in a principal amount of $1,000 or an integral multiple
thereof. The Indenture provides that, prior to complying with the provisions of
this covenant, but in any event within 30 days following a Change of Control,
the Company will either repay all outstanding Senior Debt or obtain the
requisite consents, if any, under all agreements governing outstanding Senior
Debt to permit the repurchase of the Notes required by
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<PAGE> 87
this covenant. The Company will publicly announce the results of the Change of
Control Offer on or as soon as practicable after the Change of Control Payment
Date.
Except as described above with respect to a Change of Control, the
Indenture does not contain provisions that permit the holders of the Notes to
require that the Company repurchase or redeem the Notes in the event of a
takeover, recapitalization, restructuring or similar transaction. Although the
existence of a holder's right to require the Company to repurchase the Notes in
respect of a Change of Control may deter a third party from acquiring the
Company in a transaction that constitutes a Change of Control, the provisions of
the Indenture relating to a Change of Control in and of themselves may not
afford holders of the Notes protection in the event of a highly leveraged
transaction, reorganization, recapitalization, restructuring, merger or similar
transaction involving the Company that may adversely affect holders, if such
transaction is not the type of transaction included within the definition of a
Change of Control.
The Company will not be required to make a Change of Control Offer if a
third party makes the Change of Control Offer in the manner, at the times and
otherwise in compliance with the requirements set forth in the Indenture
applicable to a Change of Control Offer made by the Company and purchases all
Notes validly tendered and not withdrawn under such Change of Control Offer.
A holder's right to require the Company to repurchase its Notes upon a
Change of Control pursuant to the terms of the Indenture may not be waived by
the Company or the Trustee.
The definition of Change of Control includes a phrase relating to the sale,
lease, transfer, conveyance or other disposition of "all or substantially all"
of the assets of the Company and its Subsidiaries taken as a whole. Although
there is a developing body of case law interpreting the phrase "substantially
all," there is no precise established definition of the phrase under applicable
law. Accordingly, the ability of a holder of the Notes to require the Company to
repurchase such Notes as a result of a sale, lease, transfer, conveyance or
other disposition of less than all of the assets of the Company and its
Subsidiaries taken as a whole to another Person or group may be uncertain.
The Credit Agreement provides that certain Change of Control events with
respect to the Company would constitute a default thereunder. Any future credit
agreements or other agreements relating to Senior Debt to which the Company
becomes a party may contain similar restrictions and provisions. Moreover, the
exercise by the holders of their rights to require the Company to repurchase the
Notes could cause a default under such indebtedness, even if the Change of
Control itself does not, due to the financial effect of such repurchase on the
Company. In the event a Change of Control occurs at a time when the Company is
prohibited from purchasing Notes by the Credit Agreement or other agreements
relating to Senior Debt, the Company could seek the consent of its lenders to
the purchase of Notes or could attempt to refinance the borrowings that contain
such prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company will be prohibited from purchasing Notes. In such case,
the Company's failure to purchase tendered Notes would constitute an Event of
Default under the Indenture which would, in turn, constitute a default under the
Credit Agreement. In such circumstances, the subordination provisions in the
Indenture would likely restrict payments to the holders of Notes. Finally, the
Company's ability to pay cash to the holders of Notes following the occurrence
of a Change of Control may be limited by the Company's then existing financial
resources. There can be no assurance that sufficient funds will be available
when necessary to make any required repurchases. The provisions under the
Indenture relating to the Company's obligation to make an offer to repurchase
the Notes as a result of a Change of Control may be waived or modified with the
prior written consent of the holders of a majority in principal amount of the
Notes.
Restrictions in the Indenture described herein on the ability of the
Company and its Subsidiaries to incur additional Indebtedness, to grant Liens on
its or their property, to make Restricted Payments and to make Asset Sales may
also make difficult or discourage a takeover of the
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Company, whether favored or opposed by the management of the Company.
Consummation of any such transaction in certain circumstances may require
redemption or repurchase of the Notes, and there can be no assurance that the
Company or the acquiring party will have sufficient financial resources to
effect such redemption or repurchase. In certain circumstances, such
restrictions and the restrictions on transactions with Affiliates may make more
difficult or discourage any leveraged buyout of the Company or any of its
Subsidiaries. While such restrictions cover a variety of arrangements which have
traditionally been used to effect highly leveraged transactions, the Indenture
may not afford the holders of Notes protection in all circumstances from the
adverse aspects of a highly leveraged transaction, reorganization,
restructuring, merger or similar transaction.
Asset Sales
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, engage in an Asset Sale unless (i) the
Company or such Restricted Subsidiary, as the case may be, receives
consideration at the time of such Asset Sale at least equal to the fair market
value (as determined in good faith by a resolution of the Board of Directors set
forth in an Officers' Certificate delivered to the Trustee, which determination
shall be conclusive evidence of compliance with this provision) of the assets or
Equity Interests issued or sold or otherwise disposed of and (ii) the
consideration therefor received by the Company or such Restricted Subsidiary is
in the form of cash, Cash Equivalents or assets that are useful in the Energy
Business ("Energy Business Assets"); provided that (A) the amount of (x) any
liabilities (as shown on the Company's or such Restricted Subsidiary's most
recent balance sheet), of the Company or any Restricted Subsidiary (other than
contingent liabilities and liabilities that are by their terms subordinated to
the Notes or any guarantee thereof) that are assumed by the transferee of any
such assets pursuant to a customary novation agreement that releases the Company
or such Restricted Subsidiary from further liability and (y) any non-cash
consideration received by the Company or any such Restricted Subsidiary from
such transferee that are converted by the Company or such Restricted Subsidiary
into cash within 180 days of closing such Asset Sale, shall be deemed to be cash
for purposes of this provision (to the extent of the cash received) and (B) the
Company or such Restricted Subsidiary may accept consideration (including
consideration in the form of assumption of liabilities) from such Asset Sale in
other than cash, Cash Equivalents and Energy Business Assets if the aggregate
fair market value (as determined in good faith by the Company's Board of
Directors and evidenced by a resolution of such Board) of all consideration from
all Asset Sales since the date of the Indenture that is other than cash, Cash
Equivalents and Energy Business Assets ("Other Consideration") at the time of
such Asset Sale, less the sum of the amount of any cash and Cash Equivalents and
the fair market value (as determined in good faith by the Company's Board of
Directors and evidenced by a resolution of such Board) of any Energy Business
Assets realized from, or received in exchange for, any Other Consideration prior
to the time of such Asset Sale, does not exceed 5% of Total Assets at the time
of such Asset Sale.
Within 360 days after the receipt of any Net Proceeds from an Asset Sale,
the Company may apply such Net Proceeds, at its option, (a) to reduce Senior
Debt, Guarantor Senior Indebtedness or Pari Passu Debt (provided that, in
connection with a reduction of Pari Passu Debt, the Company or such Restricted
Subsidiary redeems a pro rata portion of the Notes), (b) to acquire a
controlling interest in another Energy Business if, as a result of such
acquisition, such other Energy Business became a Restricted Subsidiary, (c) to
make capital expenditures in respect of the Company's or its Restricted
Subsidiaries' Energy Business, (d) to purchase long-term assets that are used or
useful in the Energy Business or (e) to repurchase any Notes. Pending the final
application of any such Net Proceeds, the Company may temporarily reduce Senior
Debt that is revolving debt or otherwise invest such Net Proceeds in any manner
that is not prohibited by the Indenture. Any Net Proceeds from Asset Sales that
are not applied as provided in the first sentence of this paragraph will (after
the expiration of the 360 day period specified in the first sentence of this
paragraph) be deemed to constitute "Excess Proceeds."
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When the aggregate amount of Excess Proceeds from one or more Asset Sales
exceeds $10 million, the Company will be required to make an offer to all
holders of the Notes and, to the extent required by the terms of Pari Passu
Debt, to all holders or lenders thereof (an "Asset Sale Offer") to purchase the
maximum principal amount of the Notes and any such Pari Passu Debt to which the
Asset Sale Offer applies that may be purchased out of the Excess Proceeds, at an
offer price in cash equal to 100% of the principal amount thereof plus accrued
and unpaid interest thereon to the date of purchase and, with respect to Pari
Passu Debt, any applicable premium specified in the agreements relating thereto,
in accordance with the procedures set forth in the Indenture or the agreements
governing the Pari Passu Debt, as applicable. To the extent that the aggregate
principal amount of the Notes and Pari Passu Debt tendered pursuant to an Asset
Sale Offer, plus accrued and unpaid interest thereon to the date of purchase
and, if applicable, premium on Pari Passu Debt, is less than the Excess
Proceeds, the Company or any Restricted Subsidiary may use any remaining Excess
Proceeds for general corporate purposes. If the aggregate principal amount of
the Notes surrendered by holders thereof and other Pari Passu Debt surrendered
by holders or lenders thereof, collectively, plus accrued and unpaid interest
thereon to the date of purchase and, if applicable, premium on Pari Passu Debt,
exceeds the amount of Excess Proceeds, the Trustee shall select the Notes and
Pari Passu Debt to be purchased on a pro rata basis, based on the aggregate
principal amount thereof surrendered in such Asset Sale Offer. Upon completion
of such Asset Sale Offer, the amount of Excess Proceeds shall be reset at zero.
The Credit Agreement may prohibit the Company from purchasing any Notes
with Excess Proceeds. Any future credit agreements or other agreements relating
to Senior Debt to which the Company becomes a party may contain similar
prohibitions and restrictions. In the event the Company is required to make an
Asset Sale Offer at a time when the Company is prohibited from purchasing the
Notes by the Credit Agreement or other agreements relating to Senior Debt, the
Company could seek the consent of its lenders to the purchase of Notes pursuant
to an Asset Sale Offer or could attempt to refinance the borrowings that contain
such prohibition. If the Company does not obtain such a consent or repay such
borrowings, the Company may remain prohibited from purchasing the Notes. In such
case, the Company's failure to purchase tendered Notes would constitute an Event
of Default under the Indenture which would, in turn, constitute a default under
the Credit Agreement. In such circumstances, the subordination provisions in the
Indenture would likely restrict payments to the holders of the Notes.
CERTAIN COVENANTS
Restricted Payments
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly: (i) declare or pay
any dividend or make any other payment or distribution on account of the Equity
Interests of the Company or any Restricted Subsidiary (including, without
limitation, any payment in connection with any merger or consolidation involving
the Company) to the direct or indirect holders of the Company's Equity Interests
in their capacity as such (other than dividends or distributions payable in
Equity Interests (other than Disqualified Stock) of the Company or a Restricted
Subsidiary and other than dividends or distributions payable to the Company or a
Restricted Subsidiary so long as, in the case of any dividend or distribution
payable on or in respect of any class or series of securities issued by a
Subsidiary other than a Wholly Owned Restricted Subsidiary, the Company or a
Restricted Subsidiary receives at least its pro rata share of such dividend or
distribution in accordance with its Equity Interests in such class or series of
securities); (ii) purchase, redeem or otherwise acquire or retire for value any
Equity Interests of the Company or any direct or indirect parent or other
Affiliate of the Company that is not a Restricted Subsidiary of the Company;
(iii) make any principal payment on, or purchase, redeem, defease or otherwise
acquire or retire for value any Indebtedness that is subordinated to the Notes,
except at final maturity; or (iv) make any Restricted Investment (all such
payments and other
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actions set forth in clauses (i) through (iv) above being collectively referred
to as "Restricted Payments"), unless, at the time of and after giving effect to
such Restricted Payment:
(a) no Default or Event of Default shall have occurred and be
continuing or would occur as a consequence thereof; and
(b) the Company would, at the time of such Restricted Payment and
after giving pro forma effect thereto as if such Restricted Payment had
been made at the beginning of the applicable four-quarter period, have been
permitted to incur at least $1.00 of additional Indebtedness pursuant to
the Fixed Charge Coverage Ratio test set forth in the first paragraph of
the covenant described below under the caption "-- Incurrence of
Indebtedness and Issuance of Disqualified Stock"; and
(c) such Restricted Payment, together with the aggregate of all other
Restricted Payments made by the Company and its Restricted Subsidiaries
after the date of the Indenture (excluding Restricted Payments permitted by
clauses (2), (3) and (5) of the next succeeding paragraph), is less than
the sum of (i) 50% of the Consolidated Net Income of the Company for the
period (taken as one accounting period) from the beginning of the first
fiscal quarter commencing after the date of the Indenture to the end of the
Company's most recently ended fiscal quarter for which internal financial
statements are available at the time of such Restricted Payment (or, if
such Consolidated Net Income for such period is a deficit, less 100% of
such deficit), plus (ii) 100% of the aggregate net cash proceeds received
by the Company from the issue or sale since the date of the Indenture of
Equity Interests of the Company or of debt securities of the Company that
have been converted into or exchanged for such Equity Interests (other than
Equity Interests (or convertible debt securities) sold to a Subsidiary of
the Company and other than Disqualified Stock or debt securities that have
been converted into Disqualified Stock), plus (iii) to the extent that any
Restricted Investment that was made after the date of the Indenture is sold
for cash or otherwise liquidated or repaid for cash, the lesser of (A) the
net proceeds of such sale, liquidation or repayment and (B) the amount of
such Restricted Investment.
The foregoing provisions will not prohibit (1) the payment of any dividend
within 60 days after the date of declaration thereof, if at said date of
declaration such payment would have complied with the provisions of the
Indenture; (2) the redemption, repurchase, retirement or other acquisition of
any Equity Interests of the Company in exchange for, or out of the proceeds of,
the substantially concurrent sale (other than to a Subsidiary of the Company) of
other Equity Interests of the Company (other than any Disqualified Stock);
provided that the amount of any such net cash proceeds that are utilized for any
such redemption, repurchase, retirement or other acquisition shall be excluded
from clause (c)(ii) of the preceding paragraph; (3) the defeasance, redemption
or repurchase of subordinated Indebtedness with the net cash proceeds from an
incurrence of subordinated Permitted Refinancing Debt or the substantially
concurrent sale (other than to a Subsidiary of the Company) of Equity Interests
of the Company (other than Disqualified Stock); provided that the amount of any
such net cash proceeds that are utilized for any such redemption, repurchase,
retirement or other acquisition shall be excluded from clause (c)(ii) of the
preceding paragraph; (4) the repurchase, redemption or other acquisition or
retirement for value of any Equity Interests of the Company or any Subsidiary of
the Company held by any of the Company's (or any of its Subsidiaries') employees
pursuant to any stock repurchase agreement, management equity subscription
agreement or stock option agreement in effect as of the date of the Indenture;
provided that the aggregate price paid for all such repurchased, redeemed,
acquired or retired Equity Interests shall not exceed $2 million in any
twelve-month period; and provided further that no Default or Event of Default
shall have occurred and be continuing immediately after such transaction; (5)
repurchases of Equity Interests deemed to occur upon exercise of stock options
if such Equity Interests represent a portion of the exercise price of such
options ; (6) the payment of the redemption price of rights issued pursuant to
any shareholders' rights plan not in excess of $0.05 per right and not in excess
of $1,000,000 in the aggregate; (7) payments made by the Company to
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any Subsidiary or by any Subsidiary to the Company or another Subsidiary
pursuant to any tax sharing agreement; (8) the payment of dividends with respect
to shares of Capital Stock of any Subsidiary of the Company to holders thereof
who are employees or directors of such Subsidiary in an aggregate amount not to
exceed $350,000 in any 12-month period for all such shares of Capital Stock of
Subsidiaries of the Company; and (10) Restricted Payments in an aggregate amount
since the date of the Indenture not to exceed $10,000,000.
The amount of all Restricted Payments (other than cash) shall be the fair
market value (as determined in good faith by a resolution of the Board of
Directors set forth in an Officers' Certificate delivered to the Trustee, which
determination shall be conclusive evidence of compliance with this provision) on
the date of the Restricted Payment of the asset(s) proposed to be transferred by
the Company or the applicable Restricted Subsidiary, as the case may be,
pursuant to the Restricted Payment. Not later than five days after the date of
making any Restricted Payment, the Company shall deliver to the Trustee an
Officers' Certificate stating that such Restricted Payment is permitted and
setting forth the basis upon which the calculations required by the covenant
"Restricted Payments" were computed.
Incurrence of Indebtedness and Issuance of Disqualified Stock
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue,
assume, guarantee or otherwise become directly or indirectly liable,
contingently or otherwise, with respect to (collectively, "incur") any
Indebtedness (including Acquired Debt) and that the Company and any Subsidiary
Guarantors will not issue any Disqualified Stock and will not permit any of its
Restricted Subsidiaries to issue any shares of preferred stock; provided,
however, that the Company may incur Indebtedness (including Acquired Debt) or
issue shares of Disqualified Stock if:
(i) the Fixed Charge Coverage Ratio for the Company's most recently
ended four full fiscal quarters for which internal financial statements are
available immediately preceding the date on which such additional
Indebtedness is incurred or such Disqualified Stock is issued would have
been at least 2.5 to 1, determined on a pro forma basis as set forth in the
definition of Fixed Charge Coverage Ratio; and
(ii) no Default or Event of Default shall have occurred and be
continuing at the time such additional Indebtedness is incurred or such
Disqualified Stock is issued or would occur as a consequence of the
incurrence of the additional Indebtedness or the issuance of the
Disqualified Stock.
Notwithstanding the foregoing, the Indenture will not prohibit any of the
following (collectively, "Permitted Indebtedness"): (a) the Indebtedness
evidenced by the Notes; (b) the incurrence by the Company and any Subsidiary
Guarantor, if any, of Indebtedness pursuant to Credit Facilities, so long as the
aggregate principal amount of all Indebtedness outstanding under all Credit
Facilities does not, at any one time, exceed the greater of (i) $50 million or
(ii) 10% of Total Assets determined as of the incurrence of the Indebtedness;
(c) the guarantee by any Restricted Subsidiary of any Indebtedness that is
permitted by the Indenture to be incurred by the Company, provided that the
covenant under the caption entitled "-- Certain Covenants -- Limitation on
Guarantees of Indebtedness by Restricted Subsidiaries" is satisfied in
connection with the issuance of such guarantee; (d) all Indebtedness,
Disqualified Stock and preferred stock of the Company and its Restricted
Subsidiaries in existence as of the date of the Indenture or permitted to be
incurred under any agreement to which any Restricted Subsidiary of the Company
is a party in existence on the date of the Indenture; (e) intercompany
Indebtedness between or among the Company and any of its Wholly Owned Restricted
Subsidiaries, or between or among Wholly Owned Restricted Subsidiaries;
provided, however, that (i) if the Company is the obligor on such Indebtedness,
such Indebtedness is expressly subordinate to the payment in full of all
Obligations with respect to the Notes and (ii)(A) any subsequent issuance or
transfer of Equity Interests that
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results in any such Indebtedness being held by a Person other than the Company
or a Wholly Owned Subsidiary and (B) any sale or other transfer of any such
Indebtedness to a Person that is not either the Company or a Wholly Owned
Subsidiary shall be deemed, in each case, to constitute an incurrence of such
Indebtedness by the Company or such Subsidiary, as the case may be; (f)
Indebtedness in connection with one or more standby letters of credit,
guarantees, performance bonds or other reimbursement obligations, in each case,
issued in the ordinary course of business and not in connection with the
borrowing of money or the obtaining of advances or credit (other than advances
or credit on open account, includible in current liabilities, for goods and
services in the ordinary course of business and on terms and conditions which
are customary in the Energy Business, and other than the extension of credit
represented by such letter of credit, guarantee or performance bond itself), not
to exceed, in the aggregate at any given time, 5% of Total Assets; (g)
Indebtedness under Interest Rate Hedging Agreements entered into for the purpose
of limiting interest rate risks, provided that the obligations under such
agreements are related to payment obligations on Indebtedness otherwise
permitted by the terms of this covenant and that the aggregate notional
principal amount of such agreements does not exceed the principal amount of the
Indebtedness to which such agreements relate; (h) Indebtedness under Oil and Gas
Hedging Contracts, provided that such contracts were entered into in the
ordinary course of business for the purpose of limiting risks that arise in the
ordinary course of business of the Company and its Restricted Subsidiaries; (i)
the incurrence by the Company or any of its Restricted Subsidiaries of
Indebtedness not otherwise permitted to be incurred pursuant to this paragraph,
provided that the aggregate principal amount of all Indebtedness incurred
pursuant to this clause (i), together with all Permitted Refinancing Debt
incurred pursuant to clause (j) of this paragraph in respect of Indebtedness
previously incurred pursuant to this clause (i), does not exceed, at any one
time outstanding, 5% of Total Assets; (j) Permitted Refinancing Debt incurred in
exchange for, or the net proceeds of which are used to refinance, extend, renew,
replace, defease or refund, Indebtedness that was permitted by the Indenture to
be incurred (including Indebtedness previously incurred pursuant to this clause
(j), but excluding Indebtedness under clauses (c), (e), (f), (g), (h), (k), (l)
and (m)); (k) accounts payable or other obligations of the Company or any
Restricted Subsidiary to trade creditors created or assumed by the Company or
such Restricted Subsidiary in the ordinary course of business in connection with
the obtaining of goods or services; (l) Indebtedness consisting of obligations
in respect of purchase price adjustments, guarantees or indemnities in
connection with the acquisition or disposition of assets; (m) production
imbalances that do not, at any one time outstanding, exceed 2% of the Total
Assets of the Company; (n) Indebtedness of a Subsidiary Guarantor, if any, in
respect of the Subsidiary Guarantee of such Subsidiary Guarantor; and (o) the
incurrence of Indebtedness or the issuance of Disqualified Stock by Mountaineer
so long as (i) the Debt to Cash Flow Ratio for Mountaineer's most recently ended
four full fiscal quarters immediately preceding the date on which such
additional Indebtedness is incurred or such Disqualified Stock is issued would
have been no more than 3 to 1, determined on a pro forma basis as set forth in
the definition of Debt to Cash Flow Ratio and (ii) no Default or Event of
Default shall have occurred and be continuing at the time such additional
Indebtedness is incurred or would occur as a consequence of the incurrence of
the additional Indebtedness. ESC may not incur any additional indebtedness.
No Layering
The Indenture provides that the Company will not incur, create, issue,
assume, guarantee or otherwise become liable for any Indebtedness that is
subordinate or junior in right of payment to any Senior Debt and senior in any
respect in right of payment to the Notes, provided, however, that the foregoing
limitations will not apply to distinctions between categories of Indebtedness
that exist by reason of any Liens arising or created in accordance with the
provisions of the Indenture in respect of some but not all such Indebtedness.
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Liens
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or
suffer to exist or become effective any Lien securing Indebtedness of any kind
(other than Permitted Liens) upon any of its property or assets, now owned or
hereafter acquired, unless contemporaneously therewith all payments under the
Notes are secured on an equal and ratable basis with the obligations so secured
until such time as such obligations are no longer secured by a Lien.
The Indenture provides that no Subsidiary Guarantor will directly or
indirectly create, incur, assume or suffer to exist any Lien that secures
obligations under any Pari Passu Debt or under any subordinated Indebtedness of
such Subsidiary Guarantor on any asset or property of such Subsidiary Guarantor
or any income or profits therefrom, or assign or convey any right to receive
income therefrom, unless the Subsidiary Guarantee of such Subsidiary Guarantor
is equally and ratably secured with the obligations so secured or until such
time as such obligations are no longer secured by a Lien.
Sale and Leaseback Transactions
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, enter into any sale and leaseback
transaction; provided that the Company or its Restricted Subsidiaries may enter
into a sale and leaseback transaction if (i) the Company could have incurred
Indebtedness in an amount equal to the Attributable Debt relating to such sale
and leaseback transaction pursuant to the test set forth in the first paragraph
of the covenant described above under the caption "Incurrence of Indebtedness
and Issuance of Disqualified Stock" or (ii) the gross cash proceeds of such sale
and leaseback transaction are at least equal to the fair market value (as
determined in good faith by a resolution the Board of Directors set forth in an
Officers' Certificate delivered to the Trustee, which determination shall be
conclusive evidence of compliance with this provision) of the property that is
the subject of such sale and leaseback transaction and the transfer of assets in
such sale and leaseback transaction is permitted by, and the Company applies the
net proceeds of such transaction in compliance with, the covenant described
above under the caption "Repurchase at the Option of Holders -- Asset Sales."
Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries
The Indenture provides that the Company will not, and will not permit any
of its Restricted Subsidiaries to, directly or indirectly, create or otherwise
cause or suffer to exist or become effective any encumbrance or restriction on
the ability of any Restricted Subsidiary to (i)(x) pay dividends or make any
other distributions to the Company or any of the Restricted Subsidiaries of the
Company on its Capital Stock or (y) pay any indebtedness owed to the Company or
any Restricted Subsidiaries of the Company, (ii) make loans or advances to the
Company or any Restricted Subsidiary of the Company or (iii) transfer any of its
properties or assets to the Company or any Restricted Subsidiary of the Company,
except for such encumbrances or restrictions existing under or by reason of (a)
the Credit Agreement as in effect as of the date of the Indenture, and any
amendments, modifications, restatements, renewals, increases, supplements,
refundings, replacements or refinancings thereof or any other Credit Facility,
provided that such amendments, modifications, restatements, renewals, increases,
supplements, refundings, replacements, refinancings or other Credit Facilities
are no more restrictive with respect to such dividend and other payment
restrictions than those contained in the Credit Facilities as in effect on the
date of the Indenture, (b) the Indenture and the Notes, (c) applicable law or
regulations or any order, ruling or other determination by a governmental
regulatory authority, (d) any instrument governing Indebtedness or Capital Stock
of a Person acquired by the Company or any of its Restricted Subsidiaries
(through the acquisition of Capital Stock or through a merger or consolidation)
as in effect at the time of such acquisition (except, in the case of
Indebtedness, to the extent such Indebtedness was incurred in connection with or
in contemplation of such acquisition), which encumbrance or
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restriction is not applicable to any Person, or the properties or assets of any
Person, other than the Person and its Subsidiaries, or the property or assets of
the Person and its Subsidiaries, so acquired, provided that, in the case of
Indebtedness, such Indebtedness or Disqualified Stock was permitted by the terms
of the Indenture to be incurred, (e) by reason of customary non-assignment
provisions in leases entered into in the ordinary course of business and
consistent with past practices, (f) purchase money obligations for property
acquired in the ordinary course of business that impose restrictions of the
nature described in clause (iii) above on the property so acquired, (g)
Permitted Refinancing Debt, provided that the restrictions contained in the
agreements governing such Permitted Refinancing Debt are no more restrictive
than those contained in the agreements governing the Indebtedness being
refinanced or (h) any instrument governing Indebtedness or preferred stock of a
Restricted Subsidiary in existence on the date of the Indenture.
Limitation on Guarantees of Indebtedness by Restricted Subsidiaries
(a) The Indenture provides that the Company will not permit any Restricted
Subsidiary to guarantee the payment of any Indebtedness of the Company or any
Indebtedness of any other Restricted Subsidiary (in each case, the "Guaranteed
Debt") unless (i) if such Restricted Subsidiary is not a Subsidiary Guarantor,
such Restricted Subsidiary simultaneously executes and delivers a supplemental
indenture to the Indenture providing for a Subsidiary Guarantee of payment of
the Notes by such Restricted Subsidiary, (ii) if the Notes or the Subsidiary
Guarantee (if any) of such Restricted Subsidiary are subordinated in right of
payment to the Guaranteed Debt, the Subsidiary Guarantee under the supplemental
indenture shall be subordinated to such Restricted Subsidiary's guarantee with
respect to the Guaranteed Debt substantially to the same extent as the Notes or
the Subsidiary Guarantee are subordinated to the Guaranteed Debt under the
Indenture, (iii) if the Guaranteed Debt is by its express terms subordinated in
right of payment to the Notes or the Subsidiary Guarantee (if any) of such
Restricted Subsidiary, any such guarantee of such Restricted Subsidiary with
respect to the Guaranteed Debt shall be subordinated in right of payment to such
Restricted Subsidiary's Subsidiary Guarantee with respect to the Notes
substantially to the same extent as the Guaranteed Debt is subordinated to the
Notes or the Subsidiary Guarantee (if any) of such Restricted Subsidiary, (iv)
such Restricted Subsidiary waives and will not in any manner whatsoever claim or
take the benefit or advantage of, any rights of reimbursement, indemnity or
subrogation or any other rights against the Company or any other Restricted
Subsidiary as a result of any payment by such Restricted Subsidiary under its
Subsidiary Guarantee; and (v) such Restricted Subsidiary shall deliver to the
Trustee an opinion of counsel to the effect that (A) such Subsidiary Guarantee
of the Notes has been duly executed and authorized and (B) such Subsidiary
Guarantee of the Notes constitutes a valid, binding and enforceable obligation
of such Restricted Subsidiary, except insofar as enforcement thereof may be
limited by bankruptcy, insolvency or similar laws (including, without
limitation, all laws relating to fraudulent transfers) and except insofar as
enforcement thereof is subject to general principles of equity; provided that
this paragraph (a) shall not be applicable to any guarantee of any Restricted
Subsidiary that (A) existed at the time such Person became a Restricted
Subsidiary of the Company and (B) was not incurred in connection with, or in
contemplation of, such Person becoming a Restricted Subsidiary of the Company.
(b) Notwithstanding the foregoing and the other provisions of the
Indenture, any Subsidiary Guarantee by a Restricted Subsidiary of the Notes
shall provide by its terms that it shall be automatically and unconditionally
released and discharged upon (i) any sale, exchange or transfer, to any Person
not an Affiliate of the Company, of all of the Company's Capital Stock in, or
all or substantially all the assets of, such Restricted Subsidiary (which sale,
exchange or transfer is not prohibited by the Indenture) or (ii) in the case of
a guarantee incurred pursuant to clause (a) of this covenant, the release or
discharge of the guarantee which resulted in the creation of such Subsidiary
Guarantee, except a discharge or release by or as a result of payment under such
guarantee.
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Limitation on the Sale or Issuance of Capital Stock of Restricted Subsidiaries
The Indenture provides that the Company will not sell or otherwise dispose
of any shares of Capital Stock of a Restricted Subsidiary, and shall not permit
any Restricted Subsidiary, directly or indirectly, to issue or sell or otherwise
dispose of any shares of its Capital Stock except (i) to the Company or a Wholly
Owned Restricted Subsidiary, (ii) if, immediately after giving effect to such
issuance, sale or other disposition, such Restricted Subsidiary remains a
Restricted Subsidiary, (iii) shares of nonvoting Capital Stock of Restricted
Subsidiaries may be issued or sold to employees or directors of the Company or
any Subsidiary or (iv) if all shares of Capital Stock of such Restricted
Subsidiary are sold or otherwise disposed of; provided, however, that in
connection with any sale pursuant to this clause (iv), the Company may retain no
more than 10% of the outstanding Capital Stock of the Restricted Subsidiary
being sold as security for the payment of the purchase price in connection with
such sale or as security for the payment or performance of any other obligation
or liability of the purchaser in connection therewith. In connection with any
such sale or disposition of Capital Stock, the Company will be required to
comply with the covenant described under the caption "-- Asset Sales" above.
Merger, Consolidation, or Sale of Assets
The Indenture provides that the Company may not consolidate or merge with
or into (whether or not the Company is the surviving corporation), or sell,
assign, transfer, lease, convey or otherwise dispose of all or substantially all
of its properties or assets, in one or more related transactions, to another
Person, and the Company may not permit any of its Restricted Subsidiaries to
enter into any such transaction or series of transactions if such transaction or
series of transactions would, in the aggregate, result in a sale, assignment,
transfer, lease, conveyance, or other disposition of all or substantially all of
the properties or assets of the Company to another Person unless (i) the Company
is the surviving corporation or the Person formed by or surviving any such
consolidation or merger (if other than the Company) or to which such sale,
assignment, transfer, lease, conveyance or other disposition shall have been
made (the "Surviving Entity") is a corporation organized or existing under the
laws of the United States, any state thereof or the District of Columbia; (ii)
the Surviving Entity (if the Company is not the continuing obligor under the
Indenture) assumes all the obligations of the Company under the Notes and the
Indenture pursuant to a supplemental indenture in a form reasonably satisfactory
to the Trustee; (iii) immediately before and after giving effect to such
transaction or series of transactions no Default or Event of Default exists;
(iv) immediately after giving effect to such transaction or series of
transactions on a pro forma basis (and treating any Indebtedness not previously
an obligation of the Company and its Subsidiaries which becomes the obligation
of the Company or any of its Subsidiaries as a result of such transaction as
having been incurred at the time of such transaction or series of transactions),
the Consolidated Net Worth of the Company and its Subsidiaries or the Surviving
Entity (if the Company is not the continuing obligor under the Indenture) is
equal to or greater than the Consolidated Net Worth of the Company and its
Subsidiaries immediately prior to such transaction or series of transactions;
(v) each Subsidiary Guarantor, if any, unless it is the other party to the
transactions described above, shall have by supplemental indenture confirmed
that its Subsidiary Guarantee shall apply to such Person's obligations under the
Indenture and the Notes; and (vi) the Company or the Surviving Entity (if the
Company is not the continuing obligor under the Indenture) will, at the time of
such transaction or series of transactions and after giving pro forma effect
thereto as if such transaction or series of transactions had occurred at the
beginning of the applicable four-quarter period, be permitted to incur at least
$1.00 of additional Indebtedness pursuant to the test set forth in the first
paragraph of the covenant described above under the caption "-- Incurrence of
Indebtedness and Issuance of Disqualified Stock"; provided, however, that the
requirements of clause (vi) above shall not apply with respect to a merger of
the Company with and into a Wholly Owned Restricted Subsidiary, a merger of a
Wholly Owned Restricted Subsidiary with and into the Company or a merger of a
Wholly Owned Restricted Subsidiary with and into another Wholly Owned Restricted
Subsidiary.
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Transactions with Affiliates
The Indenture provides that the Company will not, and will not permit any
of its Subsidiaries to, make any payment to, or sell, lease, transfer or
otherwise dispose of any of its properties or assets to, or purchase any
property or assets from, or enter into or make or amend any contract, agreement,
understanding, loan, advance or guarantee with, or for the benefit of, any of
its Affiliates (each of the foregoing, an "Affiliate Transaction"), unless (i)
such Affiliate Transaction is on terms that are no less favorable to the Company
or the relevant Subsidiary than those that would have been obtained in a
comparable transaction by the Company or such Subsidiary with an unrelated
Person and (ii) the Company delivers to the Trustee (a) with respect to any
Affiliate Transaction or series of related Affiliate Transactions involving
aggregate consideration in excess of $2.0 million but less than or equal to $5
million, an Officers' Certificate certifying that such Affiliate Transaction
complies with clause (i) above, (b) with respect to any Affiliate Transaction or
series of related Affiliate Transactions involving aggregate consideration in
excess of $5 million but less than or equal to $10 million, a resolution of the
Board of Directors set forth in an Officers' Certificate certifying that such
Affiliate Transaction complies with clause (i) above and that such Affiliate
Transaction has been approved in good faith by a majority of the members of the
Board of Directors who are disinterested with respect to such Affiliate
Transaction, which resolution shall be conclusive evidence of compliance with
this provision, and (c) with respect to any Affiliate Transaction or series of
related Affiliate Transactions involving aggregate consideration in excess of
$10 million, an opinion as to the fairness to the holders of such Affiliate
Transaction from a financial point of view issued by an accounting, appraisal,
engineering or investment banking firm of national standing; provided that the
following shall not be deemed Affiliate Transactions: (1) transactions
contemplated by any employment agreement or other compensation plan or
arrangement entered into by the Company or any of its Subsidiaries in the
ordinary course of business and consistent with the past practice of the Company
or such Subsidiary, (2) transactions between or among the Company and/or its
Subsidiaries, (3) Restricted Payments and Permitted Investments that are
permitted by the provisions of the Indenture described above under the caption
"-- Restricted Payments" and (4) the following agreements in effect on the date
of the Indenture: (i) that certain Lease Agreement dated May 11, 1987 between
Texas International Petroleum Corporation, predecessor to Energy Centre, Inc.,
and Eastern American, including all amendments thereto; (ii) that certain
Agreement dated June 30, 1993 between Kenneth W. Brill and the Company granting
the Company an option to purchase 15,400 shares of the Company's Common Stock
owned by Mr. Brill; (iii) that certain Buy-Sell Stock Option Agreement dated
July 8, 1996 between Kenneth W. Brill and the Company granting the Company an
option to purchase 64,000 shares of the Company's Common Stock owned by Mr.
Brill; (iv) that certain Buy-Sell Stock Option Agreement dated May 20, 1997
between F. H. McCullough, III, Kathy L. McCullough and the Company granting the
Company an option to purchase 11,920 shares of the Company's Common Stock owned
jointly by F. H. McCullough, III and Kathy L. McCullough; (v) the Eastern
American Incentive Stock Plan implemented by the Company in 1987; (vi) those
certain Incentive Stock Option Agreements dated December 1994 between the
Company and J. Michael Forbes, Donald C. Supcoe and Richard E. Heffelfinger,
granting the individuals the option to purchase 3,200, 3,200 and 6,400 shares of
the Company's Common Stock, respectively; and (vii) Drilling Programs between
the Company and its officers and directors.
Business Activities
The Company will not, and will not permit any Restricted Subsidiary to,
engage in any material respect in any business other than the Energy Business.
Commission Reports
Notwithstanding that the Company may not be required to remain subject to
the reporting requirements of Section 13 or 15(d) of the Exchange Act, to the
extent permitted by the Exchange
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Act the Company will file with the Commission and provide, within 15 days after
such filing, the Trustee and holders and prospective holders (upon request) with
the annual reports and the information, documents and other reports which are
specified in Sections 13 and 15(d) of the Exchange Act. In the event that the
Company is not permitted to file such reports, documents and information with
the Commission, the Company will provide substantially similar information to
the Trustee, the holders, and prospective holders (upon request) as if the
Company were subject to the reporting requirements of Section 13 or 15(d) of the
Exchange Act. The Company also will comply with the other provisions of Section
314(a) of the Trust Indenture Act.
EVENTS OF DEFAULT AND REMEDIES
The Indenture provides that each of the following constitutes an Event of
Default: (i) a default for 30 days in the payment when due of interest on the
Notes (whether or not prohibited by the subordination provisions of the
Indenture); (ii) a default in payment when due of the principal of or premium,
if any, on the Notes (whether or not prohibited by the subordination provisions
of the Indenture); (iii) the failure by the Company to comply with its
obligations under "-- Certain Covenants -- Merger, Consolidation or Sale of
Assets" above; (iv) the failure by the Company for 30 days after notice from the
Trustee or the holders of at least 25% in aggregate principal amount of the
Notes then outstanding to comply with the provisions described under the
captions "-- Repurchase at the Option of Holders" and "-- Certain Covenants"
other than the provisions described under "-- Merger, Consolidation or Sale of
Assets"; (v) failure by the Company for 60 days after notice from the Trustee or
the holders of at least 25% in aggregate principal amount of the Notes then
outstanding to comply with any of its other agreements in the Indenture or the
Notes; (vi) except as permitted by the Indenture, any Subsidiary Guarantee shall
be held in any judicial proceeding to be unenforceable or invalid or shall cease
for any reason to be in full force and effect or a Subsidiary Guarantor, or any
Person acting on behalf of such Subsidiary Guarantor, shall deny or disaffirm
its obligations under its Subsidiary Guarantee; (vii) a default under any
mortgage, indenture or instrument under which there may be issued or by which
there may be secured or evidenced any Indebtedness for money borrowed by the
Company or any of its Restricted Subsidiaries (or the payment of which is
guaranteed by the Company or any of its Restricted Subsidiaries) whether such
Indebtedness or guarantee now exists, or is created after the date of the
Indenture, which default (a) is caused by a failure to pay principal of or
premium, if any, or interest on such Indebtedness prior to the expiration of the
grace period provided in such Indebtedness on the date of such default (a
"Payment Default") or (b) results in the acceleration of such Indebtedness prior
to its express maturity and, in each case, the principal amount of any such
Indebtedness, together with the principal amount of any other such Indebtedness
under which there is then existing a Payment Default or, the maturity of which
has been so accelerated, aggregates $10.0 million (or its equivalent in any
other currency) or more; (viii) the failure by the Company or any of its
Restricted Subsidiaries to pay final, non-appealable judgments by courts of
competent jurisdiction aggregating in excess of $10.0 million, which judgments
remain unpaid or discharged for a period of 90 days (net of applicable insurance
coverage which is acknowledged in writing by the insurer or which has been
determined to be applicable by a final, nonappealable determination by a court
of competent jurisdiction); and (ix) certain events of bankruptcy or insolvency
with respect to the Company or any of its Restricted Subsidiaries.
If any Event of Default occurs and is continuing, the Trustee or the
holders of at least 25% in principal amount of the Notes then outstanding may
declare the principal of and accrued but unpaid interest on such Notes to be due
and payable immediately. Notwithstanding the foregoing, in the case of an Event
of Default arising from certain events of bankruptcy or insolvency, with respect
to the Company or any Subsidiary, all outstanding Notes will become due and
payable without further action or notice. Holders of the Notes may not enforce
the Indenture or the Notes except as provided in the Indenture. Subject to
certain limitations, holders of a majority in principal amount of the Notes then
outstanding may direct the Trustee in its exercise of any trust or power. The
Trustee may withhold from holders of the Notes notice of any continuing Default
or Event of Default (except
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a Default or Event of Default relating to the payment of principal or interest)
if it determines that withholding notice is in their interest.
The holders of a majority in aggregate principal amount of the Notes then
outstanding by notice to the Trustee may on behalf of the holders of all of the
Notes waive any existing Default or Event of Default and its consequences under
the Indenture except a continuing Default or Event of Default in the payment of
interest or premium on, or the principal of, the Notes.
The Company is required to deliver to the Trustee annually a statement
regarding compliance with the Indenture, and the Company or any Subsidiary
Guarantor is required, within five business days of becoming aware of any
Default or Event of Default, to deliver to the Trustee a statement specifying
such Default or Event of Default.
LEGAL DEFEASANCE AND COVENANT DEFEASANCE
The Company may, at its option and at any time, elect to have all of its
obligations discharged with respect to the outstanding Notes and have each
Subsidiary Guarantor's, if any, obligation discharged with respect to its
Subsidiary Guarantee ("Legal Defeasance") except for (i) the rights of holders
of such outstanding Notes to receive payments in respect of the principal of,
premium, if any, and interest on such Notes when such payments are due from the
trust referred to below, (ii) the Company's obligations with respect to such
Notes concerning issuing temporary Notes, registration of such Notes, mutilated,
destroyed, lost or stolen Notes and the maintenance of an office or agency for
payment and money for security payments held in trust, (iii) the rights, powers,
trusts, duties and immunities of the Trustee, and the Company's obligations in
connection therewith and (iv) the Legal Defeasance provisions of the Indenture.
In addition, the Company may, at its option and at any time, elect to have the
obligations of the Company and have each Subsidiary Guarantor's, if any,
obligation discharged with respect to its Subsidiary Guarantee released with
respect to certain covenants that are described in the Indenture ("Covenant
Defeasance") and thereafter any omission to comply with such obligations shall
not constitute a Default or Event of Default. In the event Covenant Defeasance
occurs, certain events (not including non-payment, bankruptcy, receivership,
rehabilitation and insolvency events) described under "Events of Default and
Remedies" will no longer constitute an Event of Default.
In order to exercise either Legal Defeasance or Covenant Defeasance, (i)
the Company must irrevocably deposit with the Trustee, in trust, for the benefit
of the holders of the Notes, cash in U.S. dollars, non-callable Government
Securities, or a combination thereof, in such amounts as will be sufficient, in
the opinion of a nationally recognized firm of independent public accountants,
to pay the principal of, premium, if any, and interest on the outstanding Notes
on the stated maturity or on the applicable redemption date, as the case may be,
and the Company must specify whether the Notes are being defeased to maturity or
to a particular redemption date; (ii) in the case of Legal Defeasance, the
Company shall have delivered to the Trustee an opinion of counsel in the United
States reasonably acceptable to such Trustee confirming that (A) the Company has
received from, or there has been published by, the Internal Revenue Service a
ruling or (B) since the date of the Indenture, there has been a change in the
applicable federal income tax law, in either case to the effect that, and based
thereon such opinion of counsel shall confirm that, the holders of the
outstanding Notes will not recognize income, gain or loss for federal income tax
purposes as a result of such Legal Defeasance and will be subject to federal
income tax on the same amounts, in the same manner and at the same times as
would have been the case if such Legal Defeasance had not occurred; (iii) in the
case of Covenant Defeasance, the Company shall have delivered to the Trustee an
opinion of counsel in the United States reasonably acceptable to such Trustee
confirming that the holders of the outstanding Notes will not recognize income,
gain or loss for federal income tax purposes as a result of such Covenant
Defeasance and will be subject to federal income tax on the same amounts, in the
same manner and at the same times as would have been the case if such Covenant
Defeasance had not occurred; (iv) no Default or Event of Default shall have
occurred and be continuing on the date of such deposit (other than a Default or
Event of
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Default resulting from the borrowing of funds to be applied to such deposit) or
insofar as Events of Default from bankruptcy or insolvency events are concerned,
at any time in the period ending on the 91st day after the date of deposit: (v)
such Legal Defeasance or Covenant Defeasance will not result in a breach or
violation of, or constitute a default under any material agreement or instrument
(other than the Indenture) to which the Company or any of its Restricted
Subsidiaries is a party or by which the Company or any of its Restricted
Subsidiaries is bound; (vi) the Company must have delivered to the Trustee an
opinion of counsel to the effect that after the 91st day following the deposit,
the trust funds will not be subject to the effect of any applicable bankruptcy,
insolvency, reorganization or similar laws affecting creditors' rights
generally; (vii) the Company must deliver to the Trustee an Officers'
Certificate stating that the deposit was not made by the Company with the intent
of preferring the holders of the Notes over the other creditors of the Company,
or with the intent of defeating, hindering, delaying or defrauding creditors of
the Company or others; and (viii) the Company must deliver to the Trustee an
Officers' Certificate and an opinion of counsel, each stating that all
conditions precedent provided for relating to the Legal Defeasance or the
Covenant Defeasance have been complied with.
TRANSFER AND EXCHANGE
A holder may transfer or exchange Notes in accordance with the Indenture.
The Registrar and the Trustee may require a holder, among other things, to
furnish appropriate endorsements and transfer documents and the Company may
require a holder to pay any taxes and fees required by law or permitted by the
Indenture. The Company is not required to transfer or exchange any Note selected
for redemption. Also, the Company is not required to transfer or exchange any
Note for a period of 15 days before a selection of the Notes to be redeemed.
The registered holder of a Note will be treated as the owner of it for all
purposes.
AMENDMENT, SUPPLEMENT AND WAIVER
Except as provided in the next two succeeding paragraphs, the Indenture or
the Notes and the Subsidiary Guarantees, if any, may be amended or supplemented
with the consent of the holders of at least a majority in principal amount of
the Notes then outstanding (including, without limitation, consents obtained in
connection with a purchase of, or tender offer or exchange offer for, the
Notes), and any existing default or compliance with any provision of the
Indenture or the Notes may be waived with the consent of the holders of a
majority in principal amount of the then outstanding Notes (including consents
obtained in connection with a tender offer or exchange offer for the Notes).
Without the consent of each holder affected, an amendment or waiver may not
(with respect to any Notes held by a non-consenting holder): (i) reduce the
principal amount of the Notes whose holders must consent to an amendment,
supplement or waiver, (ii) reduce the principal of or change the fixed maturity
of any Note, (iii) reduce the rate of or change the time for payment of interest
on any Note, (iv) waive a Default or Event of Default in the payment of
principal of or premium, if any, or interest on the Notes (except a rescission
of acceleration of the Notes by the holders of at least a majority in principal
amount of such Notes and a waiver of the payment default that resulted from such
acceleration), (v) make any Note payable in money other than that stated in the
Notes, (vi) make any change in the provisions of the Indenture relating to
waivers of past Defaults or the rights of holders of the Notes to receive
payments of principal of or premium, if any, or interest on the Notes, (vii)
make any change in the foregoing amendment and waiver provisions or (viii)
except as provided under "Legal Defeasance and Covenant Defeasance", release a
Subsidiary Guarantor, if any, from its obligations under its Subsidiary
Guarantee, if any, or make any change in a Subsidiary Guarantee, if any, that
would adversely affect the holders. In addition, any amendment to the provisions
of the Indenture which relate to subordination will require the consent of the
holders of at least 66 2/3% in principal amount of the Notes then outstanding if
such amendment would adversely affect the rights of holders of such Notes.
However, no amendment may be made
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to the subordination provisions of the Indenture that adversely affects the
rights of any holder of Senior Debt then outstanding unless the holders of such
Senior Debt (or any group or representative thereof authorized to give a
consent) consents to such change.
Notwithstanding the foregoing, without the consent of any holder of the
Notes the Company, a Subsidiary Guarantor, if any (with respect to a Subsidiary
Guarantee, if any, or the Indenture to which it is a party) and the Trustee may
amend or supplement the Indenture, any Subsidiary Guarantee or the Notes to cure
any ambiguity, defect or inconsistency, to provide for uncertificated Notes in
addition to or in place of certificated Notes, to provide for the assumption of
the Company's obligations or any Subsidiary Guarantor's obligations in the case
of a merger or consolidation, to make any change that would provide any
additional rights or benefits to the holders of the Notes or that does not
adversely affect the legal rights under the Indenture of any such holder, or to
comply with requirements of the Commission in order to effect or maintain the
qualification of the Indenture under the Trust Indenture Act.
CONCERNING THE TRUSTEE
The Indenture contains certain limitations on the rights of the Trustee,
should it become a creditor of the Company, to obtain payment of claims in
certain cases, or to realize on certain property received in respect of any such
claim as security or otherwise. The Trustee will be permitted to engage in other
transactions; however, if it acquires any conflicting interest, it must
eliminate such conflict within 90 days, apply to the Commission for permission
to continue or resign.
The holders of a majority in principal amount of the then outstanding Notes
will have the right to direct the time, method and place of conducting any
proceeding for exercising any remedy available to the Trustee, subject to
certain exceptions. The Indenture provides that in case an Event of Default
shall occur (which shall not be cured), the Trustee will be required, in the
exercise of its power, to use the degree of care of a prudent person in the
conduct of his own affairs. Subject to such provisions, the Trustee will be
under no obligation to exercise any of its rights or powers under the Indenture
at the request of any holder of the Notes, unless such holder shall have offered
to such Trustee security and indemnity satisfactory to it against any loss,
liability or expense.
GOVERNING LAW
The Indenture, the Notes and the Subsidiary Guarantees, if any, will
provide that they will be governed by the laws of the State of New York.
CERTAIN DEFINITIONS
Set forth below are certain defined terms used in the Indenture. Reference
is made to the Indenture for a full definition of all such terms, as well as any
other capitalized terms used herein for which no definition is provided.
"Acquired Debt" means, with respect to any specified Person, (i)
Indebtedness of any other Person existing at the time such other Person is
merged with or into or became a Subsidiary of such specified Person, including,
without limitation, Indebtedness incurred in connection with, or in
contemplation of, such other Person merging with or into or becoming a
Subsidiary of such specified Person, and (ii) Indebtedness secured by a Lien
encumbering any asset acquired by such specified Person.
"Affiliate" of any specified Person means any other Person directly or
indirectly controlling or controlled by or under direct or indirect common
control with such specified Person. For purposes of this definition, "control"
(including, with correlative meanings, the terms "controlling," "controlled by"
and "under common control with"), as used with respect to any Person, shall mean
the possession, directly or indirectly, of the power to direct or cause the
direction of the management or policies of such Person, whether through the
ownership of voting securities, by agreement or
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otherwise; provided that beneficial ownership of 10% or more of the voting
securities of a Person shall be deemed to be control.
"Asset Sale" by a Person means (i) the sale, lease, conveyance or other
disposition (but excluding the creation of a Lien) of any assets including,
without limitation, by way of a sale and leaseback (provided that the sale,
lease, conveyance or other disposition of all or substantially all of the assets
of the Company and its Restricted Subsidiaries taken as a whole will be governed
by the provisions of the Indenture described above under the caption
"-- Repurchase at the Option of Holders -- Change of Control" and/or the
provisions described above under the caption "-- Certain Covenants -- Merger,
Consolidation, or Sale of Assets" and not by the provisions described above
under "-- Repurchase at the Option of Holders -- Asset Sales"), and (ii) the
issue or sale by such Person or any of its Restricted Subsidiaries of Equity
Interests of any of such Person's Subsidiaries (including the sale by the
Company or a Restricted Subsidiary of Equity Interests in an Unrestricted
Subsidiary), in the case of either clause (i) or (ii), whether in a single
transaction or a series of related transactions (a) that have a fair market
value in excess of the greater of $5 million or 1% of Total Assets at the time
of such transaction or (b) for net proceeds in excess of the greater of $5
million or 1% of Total Assets at the time of such transaction. Notwithstanding
the foregoing, the following shall not be deemed to be Asset Sales: (i) a
transfer of assets by such Person to a Wholly Owned Restricted Subsidiary of
such Person or by a Wholly Owned Restricted Subsidiary of such Person to such
Person or to another Wholly Owned Restricted Subsidiary of such Person, (ii) an
issuance of Equity Interests by a Restricted Subsidiary of such Person to such
Person or to another Wholly Owned Restricted Subsidiary of such Person, (iii)
the making of a Restricted Payment or Permitted Investment that is permitted by
the covenant described above under the caption "-- Certain
Covenants -- Restricted Payments," (iv) the abandonment, farm-out, lease or
sublease of undeveloped oil and gas properties in the ordinary course of
business, (v) the trade or exchange by such Person or any Restricted Subsidiary
of such Person of any oil and gas property or properties owned or held by such
Person or such Restricted Subsidiary for any oil and gas property or properties
owned or held by another Person, which the Board of Directors of the Company
determines in good faith to be of approximately equivalent value, (vi) the sale
or transfer of oil, natural gas, natural gas liquids or hydrocarbons or mineral
products or surplus or obsolete equipment in the ordinary course of business,
(vii) the sale or lease of equipment, inventory, accounts receivable or obsolete
or surplus equipment or assets in the ordinary course of business consistent
with past practice and (viii) the trade or exchange by the Company or any
Restricted Subsidiary of the Company of any oil and gas property or properties
owned or held by the Company or such Restricted Subsidiary for any oil and gas
property or properties owned or held by another Person provided that the fair
market value of the properties traded or exchanged by the Company or such
Restricted Subsidiary (including any cash or Cash Equivalents to be delivered by
the Company or such Restricted Subsidiary) is reasonably equivalent to the fair
market value of the properties (together with any cash or Cash Equivalents) to
be received by the Company or such Restricted Subsidiary as determined in good
faith by (i) any officer of the Company if such fair market value is less than
$5 million and (ii) the Board of Directors of the Company as certified by a
resolution delivered to the Trustee if such fair market value is equal to or in
excess of $5 million.
"Attributable Debt" in respect of a sale and leaseback transaction means,
at the time of determination, the present value (discounted at the rate of
interest implicit in such transaction, determined in accordance with GAAP) of
the obligation of the lessee for net rental payments during the remaining term
of the lease included in such sale and leaseback transaction (including any
period for which such lease has been extended or may, at the option of the
lessor, be extended). As used in the preceding sentence, the "net rental
payment" under any lease for any such period shall mean the sum of rental and
other payments required to be paid with respect to such period by the lessee
thereunder, excluding any amounts required to be paid by such lessee on account
of maintenance and repairs, insurance, taxes, assessments, water rates or
similar charges.
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"Capital Lease Obligation" means, at the time any determination thereof is
to be made, the amount of the liability in respect of a capital lease that would
at such time be required to be capitalized on a balance sheet in accordance with
GAAP.
"Capital Stock" means (i) in the case of a corporation, corporate stock,
(ii) in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however designated) of
corporate stock, (iii) in the case of a partnership, partnership interests
(whether general or limited) and (iv) any other interest or participation that
confers on a Person the right to receive a share of the profits and losses of,
or distributions of assets of, the issuing Person.
"Cash Equivalents" means (i) United States dollars, (ii) securities issued
or directly and fully guaranteed or insured by the United States government or
any agency or instrumentality thereof having maturities of not more than one
year from the date of acquisition, (iii) demand or time deposits, certificates
of deposit and eurodollar time deposits with maturities of one year or less from
the date of acquisition, bankers' acceptances with maturities not exceeding one
year and overnight bank deposits, in each case with any lender party to the
Credit Agreement or with any domestic commercial bank having capital and surplus
in excess of $500 million and a Thompson Bank Watch Rating of "B" or better,
(iv) repurchase obligations with a term of not more than seven days for
underlying securities of the types described in clauses (ii) and (iii) above
entered into with any financial institution meeting the qualifications specified
in clause (iii) above, (v) commercial paper having a rating of at least P1 from
Moody's Investors Service, Inc. (or its successor) and a rating of at least A1
from Standard & Poor's Ratings Services (or its successor) and (vi) investments
in money market or other mutual funds substantially all of whose assets comprise
securities described in clause (ii) through (v) above.
"Change of Control" means the occurrence of any of the following: (i) the
sale, lease, transfer, conveyance or other disposition (other than by way of
merger or consolidation), in one or a series of related transactions, of all or
substantially all of the assets of the Company and its Subsidiaries taken as a
whole to any "person" or group of related "persons" (a "Group") (as such terms
are used in Section 13(d)(3) of the Exchange Act), (ii) the adoption of a plan
relating to the liquidation or dissolution of the Company, (iii) the
consummation of any transaction (including, without limitation, any purchase,
sale, acquisition, disposition, merger or consolidation) the result of which is
that any "person" (as defined above) or Group becomes the "beneficial owner" (as
such term is defined in Rule 13d-3 and Rule 13d-5 under the Exchange Act) of
more than 35% of the outstanding Voting Stock of the Company having the right to
elect directors under ordinary circumstances other than any such transaction
where (A) the outstanding Voting Stock of the Company is changed into or
exchanged for Voting Stock of the surviving corporation which is not
Disqualified Stock or (B) John Mork and Julie Mork continue to own, directly or
indirectly, not less than a majority of the Voting Stock of the surviving
corporation immediately after such transaction or (iv) the first day on which a
majority of the members of the Board of Directors of the Company are not
Continuing Directors.
"Commission" means the Securities and Exchange Commission.
"Consolidated Cash Flow" means, with respect to any Person for any period,
the Consolidated Net Income of such Person for such period plus (i) an amount
equal to any extraordinary loss, plus any net loss realized in connection with
an Asset Sale (together with any related provision for taxes), to the extent
such losses were included in computing such Consolidated Net Income, plus (ii)
an amount equal to the provision for taxes based on income or profits of such
Person and its Restricted Subsidiaries for such period (including state
franchise taxes), to the extent that such provision for taxes was deducted in
computing such Consolidated Net Income, plus (iii) consolidated interest expense
of such Person and its Restricted Subsidiaries for such period, whether paid or
accrued (including, without limitation, amortization of original issue discount
and capitalized debt issuance costs, non-cash interest payments, the interest
component of any
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deferred payment obligations, the interest component of all payments associated
with Capital Lease Obligations, imputed interest with respect to Attributable
Debt, commissions, discounts and other fees and charges incurred in respect of
letters of credit or bankers' acceptance financings, and net payments (if any)
pursuant to Interest Rate Hedging Agreements), to the extent that any such
expense was deducted in computing such Consolidated Net Income, plus (iv)
depreciation, depletion and amortization expenses (including amortization of
goodwill and other intangibles) for such Person and its Restricted Subsidiaries
for such period to the extent that such depreciation, depletion and amortization
expenses were deducted in computing such Consolidated Net Income, plus (v)
exploration and impairment expenses for such Person and its Restricted
Subsidiaries for such period to the extent such expenses were deducted in
computing such Consolidated Net Income, plus (vi) other non-cash charges
(excluding any such non-cash charge to the extent that it represents an accrual
of or reserve for cash charges in any future period or amortization of a prepaid
cash expense that was paid in a prior period) of such Person and its Restricted
Subsidiaries for such period to the extent that such other non-cash charges were
deducted in computing such Consolidated Net Income, in each case, on a
consolidated basis and determined in accordance with GAAP. Notwithstanding the
foregoing, the provision for taxes on the income or profits of, and the
depreciation, depletion and amortization and other non-cash charges and expenses
of, a Restricted Subsidiary of the relevant Person shall be added to
Consolidated Net Income to compute Consolidated Cash Flow only to the extent
(and in the same proportion) that the Net Income of such Restricted Subsidiary
was included in calculating the Consolidated Net Income of such Person and only
if a corresponding amount would be permitted at the date of determination to be
dividended to such Person by such Restricted Subsidiary without prior
governmental approval (that has not been obtained), and without direct or
indirect restriction pursuant to the terms of its charter and all agreements,
instruments, judgments, decrees, orders, statutes, rules and governmental
regulations applicable to that Restricted Subsidiary or its stockholders.
"Consolidated Net Income" means, with respect to any Person for any period,
the aggregate of the Net Income of such Person and its Subsidiaries for such
period, on a consolidated basis, determined in accordance with GAAP; provided
that (i) the Net Income (but not loss) of any Person that is not a Restricted
Subsidiary or that is accounted for by the equity method of accounting shall be
included only to the extent of the amount of dividends or distributions paid in
cash to the referent Person or a Wholly Owned Restricted Subsidiary thereof
during such period, (ii) the Net Income of any Restricted Subsidiary shall be
included (x) to the extent that the declaration or payment of dividends or
similar distributions by that Restricted Subsidiary of that Net Income is at the
date of determination permitted without any prior governmental approval (that
has not been obtained) or, directly or indirectly, by operation of the terms of
its charter or any agreement, instrument, judgment, decree, order, statute, rule
or governmental regulation applicable to that Restricted Subsidiary or its
stockholders and (y), with respect to a Restricted Subsidiary that is not a
Wholly Owned Restricted Subsidiary, in an amount equal to the pro rata share of
such dividend or distribution (in accordance with the Equity Interests thereof
held by the Company and its Restricted Subsidiaries), (iii) the Net Income of
any Person acquired in a pooling of interests transaction for any period prior
to the date of such acquisition shall be excluded and (iv) the cumulative effect
of a change in accounting principles shall be excluded.
"Consolidated Net Worth" means the total of the amounts shown on the
balance sheet of the Company and its consolidated Restricted Subsidiaries,
determined on a consolidated basis in accordance with GAAP, as of the end of the
most recent fiscal quarter of the Company ending prior to the taking of any
action for the purpose of which the determination is being made and for which
financial statements are available (but in no event ending more than 135 days
prior to the taking of such action), as (i) the par or stated value of all
outstanding Capital Stock of the Company, plus (ii) paid-in capital or capital
surplus relating to such Capital Stock plus (iii) any retained earnings or
earned surplus less (A) any accumulated deficit (in each case excluding any
minority interest) and (B) any amounts attributable to Disqualified Stock.
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"Continuing Directors" means, as of any date of determination, any member
of the Board of Directors of the Company who (i) was a member of such Board of
Directors on the date of original issuance of the Notes or (ii) was nominated
for election or elected to such Board of Directors with the approval of (x)
two-thirds of the Continuing Directors who were members of such Board at the
time of such nomination or election or (y) two-thirds of those Directors who
were previously approved by Continuing Directors.
"Credit Agreement" means that certain Credit Agreement, dated as of May 20,
1997, among the Company and General Electric Capital Corporation and certain
other financial institutions, as lenders, providing for up to $50 million of
Indebtedness, including any related notes, guarantees, collateral documents,
instruments and agreements executed in connection therewith, and in each case as
amended, restated, modified, renewed, refunded, replaced or refinanced, in whole
or in part, from time to time, whether or not with the same lenders or agents.
"Credit Facilities" means, with respect to the Company, one or more debt
facilities (including, without limitation, the Credit Agreement) or commercial
paper facilities with banks or other institutional lenders providing for
revolving credit loans, term loans, Production Payments, receivables financing
(including through the sale of receivables to such lenders or to special purpose
entities formed to borrow from such lenders against such receivables) or letters
of credit, in each case, as amended, restated, modified, renewed, refunded,
replaced or refinanced in whole or in part from time to time. Indebtedness under
Credit Facilities outstanding on the date on which the Notes are first issued
and authenticated under the Indenture (after giving effect to the use of
proceeds thereof) shall be deemed to have been incurred on such date in reliance
on the exception provided by clause (b) of the definition of Permitted
Indebtedness.
"Debt to Cash Flow Ratio" means with respect to any Person for any period,
the ratio of the Indebtedness of such Person for such period to the Consolidated
Cash Flow of such Person for such period; provided, that, for purposes of the
foregoing, Indebtedness shall not include Indebtedness of such Person that is
required to be repaid within 12 months after the incurrence thereof except to
the extent that the aggregate principal amount of any such Indebtedness
outstanding at any time exceeds the amount permitted to be outstanding by any
credit agreement to which such Person is a party. In the event that such Person
or any of its Subsidiaries incurs, assumes, guarantees or redeems any
Indebtedness (other than revolving credit borrowings) subsequent to the
commencement of the period for which the Debt Coverage Ratio is being calculated
but prior to the date on which the calculation of the Debt Coverage Ratio is
made (the "Debt to Cash Flow Calculation Date"), then the Debt Coverage Ratio
shall be calculated giving pro forma effect to such incurrence, assumption,
guarantee or redemption of Indebtedness, as if the same had occurred at the
beginning of the applicable four-quarter reference period. In addition, for
purposes of making the computation referred to above, (i) acquisitions that have
been made by such Person or any of its Subsidiaries, including through mergers
or consolidations and including any related financing transactions, during the
four-quarter reference period or subsequent to such reference period and on or
prior to the Debt to Cash Flow Calculation Date (including, without limitation,
any acquisition to occur on the Debt to Cash Flow Calculation Date) shall be
deemed to have occurred on the first day of the four-quarter reference period
and Consolidated Cash Flow for such reference period shall be calculated without
giving effect to clause (iii) of the proviso set forth in the definition of
Consolidated Net Income, (ii) the net proceeds of Indebtedness incurred or
Disqualified Stock issued by such Person pursuant to "-- Certain
Covenants -- Incurrence of Indebtedness and Issuance of Disqualified Stock"
during the four-quarter reference period and on or prior to the Debt to Cash
Flow Calculation Date shall be deemed to have been received by such Person or
any of its Subsidiaries on the first day of the four-quarter reference period
and applied to its intended use on such date and (iii) the Consolidated Cash
Flow attributable to discontinued operations, as determined in accordance with
GAAP, and operations or businesses disposed of prior to the Debt to Cash Flow
Calculation Date, shall be excluded.
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"Default" means any event that is or with the passage of time or the giving
of notice or both would be an Event of Default.
"Designated Senior Debt" means (i) the Credit Agreement and (ii) any other
Senior Debt permitted under the Indenture the principal amount of which is $25
million or more and that has been designated by the Company as "Designated
Senior Debt."
"Disqualified Stock" means any Capital Stock that, by its terms (or by the
terms of any security into which it is convertible or for which it is
exchangeable), or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, is convertible
or exchangeable for Indebtedness or Disqualified Stock or redeemable at the
option of the holder thereof, in whole or in part, on or prior to the date that
is 91 days after the date on which the Notes mature.
"Dollar-Denominated Production Payments" means production payment
obligations recorded as liabilities in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Energy Business" means (i) the operation of one or more natural gas
distribution businesses, (ii) the acquisition, exploration, development,
operation and disposition of interests in oil, gas and other hydrocarbon
properties, (iii) the gathering, purchasing, marketing, treating, processing,
storage, selling and transporting of any natural oil, gas and other minerals or
hydrocarbon products, (iv) any business related to any business or activity
described in clause (i) or clause (iii) of this definition, including, without
limitation, (a) the production of electricity or other sources of power
utilizing oil, gas or other hydrocarbon products and (b) providing services in
support of or incidental to any business or activity described in clause (i) or
clause (ii) of this definition and (v) any activity that is ancillary to or
necessary or appropriate for the activities described in clauses (i) through
(iv) of this definition.
"Equity Interests" means Capital Stock and all warrants, options or other
rights to acquire Capital Stock (but excluding any debt security that is
convertible into, or exchangeable for, Capital Stock).
"Fixed Charge Coverage Ratio" means with respect to any Person for any
period, the ratio of the Consolidated Cash Flow of such Person for such period
to the Fixed Charges of such Person for such period. In the event that such
Person or any of its Restricted Subsidiaries incurs, assumes, guarantees or
redeems any Indebtedness (other than revolving credit borrowings) or issues or
redeems preferred stock subsequent to the commencement of the period for which
the Fixed Charge Coverage Ratio is being calculated but prior to the date on
which the calculation of the Fixed Charge Coverage Ratio is made (the
"Calculation Date"), then the Fixed Charge Coverage Ratio shall be calculated
giving pro forma effect to such incurrence, assumption, guarantee or redemption
of Indebtedness, or such issuance or redemption of preferred stock, as if the
same had occurred at the beginning of the applicable four-quarter reference
period. In addition, for purposes of making the computation referred to above,
Consolidated Cash Flow and Fixed Charges shall be calculated on a pro forma
basis, in the manner specified below, with respect to the following events: (i)
acquisitions that have been made by such Person or any of its Restricted
Subsidiaries, including through mergers or consolidations and including any
related financing transactions, during the four-quarter reference period or
subsequent to such reference period and on or prior to the Calculation Date
(including, without limitation, any acquisition to occur on the Calculation
Date) shall be deemed to have occurred on the first day of the four-quarter
reference period and Consolidated Cash Flow for such reference period shall be
calculated (a) without giving effect to clause (iii) of the proviso set forth in
the definition of Consolidated Net Income and (b) giving effect to pro forma
adjustments relating to such acquisition that would generally be permitted under
applicable accounting standards with respect to pro forma financial statements,
(ii) the net proceeds of Indebtedness incurred or Disqualified Stock issued by
such Person pursuant to the first paragraph of the covenant described under the
caption "-- Certain Covenants -- Incurrence of Indebt-
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edness and Issuance of Disqualified Stock" during the four-quarter reference
period or subsequent to such reference period and on or prior to the Calculation
Date shall be deemed to have been received by such Person or any of its
Restricted Subsidiaries on the first day of the four-quarter reference period
and applied to its intended use on such date, (iii) the Consolidated Cash Flow
attributable to discontinued operations, as determined in accordance with GAAP,
and operations or businesses disposed of prior to the Calculation Date, shall be
excluded, and (iv) the Fixed Charges attributable to discontinued operations, as
determined in accordance with GAAP, and operations or businesses disposed of
prior to the Calculation Date, shall be excluded, but only to the extent that
the obligations giving rise to such Fixed Charges will not be obligations of the
referent Person or any of its Restricted Subsidiaries following the Calculation
Date.
"Fixed Charges" means, with respect to any Person for any period, the sum,
without duplication, of (i) the consolidated interest expense of such Person and
its Restricted Subsidiaries (excluding the interest expense at Mountaineer) for
such period, whether paid or accrued (including, without limitation,
amortization of original issue discount, non-cash interest payments, the
interest component of any deferred payment obligations, the interest component
of all payments associated with Capital Lease Obligations, imputed interest with
respect to Attributable Debt, commissions, discounts and other fees and charges
incurred in respect of letter of credit or bankers' acceptance financings, and
net payments (if any) pursuant to Interest Rate Hedging Agreements), (ii) the
consolidated interest expense of such Person and its Restricted Subsidiaries
that was capitalized during such period, (iii) any interest expense on
Indebtedness of another Person that is guaranteed by such Person or any of its
Restricted Subsidiaries or secured by a Lien on assets of such Person or any of
its Restricted Subsidiaries (whether or not such guarantee or Lien is called
upon) and (iv) the product of (a) all cash dividend payments (and non-cash
dividend payments in the case of a Person that is a Restricted Subsidiary) on
any series of preferred stock of such Person or any of its Restricted
Subsidiaries, times (b) a fraction, the numerator of which is one and the
denominator of which is one minus the then current combined federal, state and
local statutory tax rate of such Person, expressed as a decimal, in each case,
on a consolidated basis and in accordance with GAAP.
"GAAP" means generally accepted accounting principles set forth in the
opinions and pronouncements of the Accounting Principles Board of the American
Institute of Certified Public Accountants and statements and pronouncements of
the Financial Accounting Standards Board or in such other statements by such
other entity as have been approved by a significant segment of the accounting
profession, which are in effect on the date of the Indenture.
"Guarantee" means a guarantee (other than by endorsement of negotiable
instruments for collection in the ordinary course of business), direct or
indirect, in any manner (including, without limitation, letters of credit and
reimbursement agreements in respect thereof), of all or any part of any
Indebtedness.
"Guarantor Senior Indebtedness" means any Indebtedness of a Subsidiary
Guarantor permitted to be incurred under the terms of the Indenture, unless the
instrument under which such Indebtedness is incurred expressly provides that it
is on a parity with or subordinated in right of payment to the Subsidiary
Guarantee of such Subsidiary Guarantor, including interest accruing subsequent
to the filing of, or which would have accrued but for the filing of, a petition
for bankruptcy, whether or not such interest is an allowable claim in such
bankruptcy proceeding. Notwithstanding anything to the contrary in the
foregoing, Guarantor Senior Indebtedness will not include (1) any liability for
federal, state, local or other taxes owed or owing by any Subsidiary Guarantor,
(2) any obligation of a Subsidiary Guarantor to the Company, (3) any accounts
payable or trade liabilities of a Subsidiary Guarantor arising in the ordinary
course of business (including instruments evidencing such liabilities), (4) any
Indebtedness of a Subsidiary Guarantor that is incurred in violation of the
Indenture, (5) Indebtedness of a Subsidiary Guarantor which, when incurred and
without respect to any election under Section 1111(b) of Title 11, United States
Code, is without recourse to such Subsidiary Guarantor, (6) any Indebtedness,
guarantee or obligation of a Subsidiary Guarantor
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which is subordinate or junior to any other Indebtedness, guarantee or
obligation of such Subsidiary Guarantor, (7) Indebtedness evidenced by a
Subsidiary Guarantee and (8) Capital Stock of a Subsidiary Guarantor.
"Indebtedness" means, with respect to any Person, without duplication, (a)
any indebtedness of such Person, whether or not contingent, (i) in respect of
borrowed money, (ii) evidenced by bonds, notes, debentures or similar
instruments, (iii) evidenced by letters of credit (or reimbursement agreements
in respect thereof) or banker's acceptances, (iv) representing Capital Lease
Obligations, (v) representing the balance deferred and unpaid of the purchase
price of any property, except any such balance that constitutes an accrued
expense or trade payable, (vi) representing any obligations in respect of
Interest Rate Hedging Agreements or Oil and Gas Hedging Contracts, and (vii) in
respect of any Production Payment, (b) all indebtedness of others secured by a
Lien on any asset of such Person (whether or not such indebtedness is assumed by
such Person), (c) obligations of such Person in respect of production
imbalances, (d) Attributable Debt of such Person, and (e) to the extent not
otherwise included in the foregoing, the guarantee by such Person of any
indebtedness of any other Person.
"Interest Rate Hedging Agreements" means, with respect to any Person, the
obligations of such Person under (i) interest rate swap agreements, interest
rate cap agreements and interest rate collar agreements and (ii) other
agreements or arrangements designed to protect such Person against fluctuations
in interest rates.
"Investments" means, with respect to any Person, all investments by such
Person in other Persons (including Affiliates) in the forms of direct or
indirect loans (including guarantees of Indebtedness or other obligations, but
excluding trade credit and other ordinary course advances customarily made in
the Energy Business), advances or capital contributions (excluding commission,
travel and similar advances to officers and employees made in the ordinary
course of business), purchases or other acquisitions for consideration of
Indebtedness, Equity Interests or other securities, together with all items that
are or would be classified as investments on a balance sheet prepared in
accordance with GAAP; provided that the following shall not constitute
Investments: (i) an acquisition of assets, Equity Interests or other securities
by the Company for consideration consisting of common equity securities of the
Company, (ii) Interest Rate Hedging Agreements entered into in accordance with
the limitations set forth in clause (g) of the second paragraph of the covenant
described under the caption "-- Certain Covenants -- Incurrence of Indebtedness
and Issuance of Disqualified Stock" and (iii) Oil and Gas Hedging Contracts
entered into in accordance with the limitations set forth in clause (h) of the
second paragraph of the covenant described under the caption "-- Certain
Covenants -- Incurrence of Indebtedness and Issuance of Disqualified Stock." If
such Person or any Subsidiary of such Person sells or otherwise disposes of any
Equity Interests of any direct or indirect Subsidiary of such Person such that,
after giving effect to any such sale or disposition, such entity is no longer a
Subsidiary of such Person, such Person shall be deemed to have made an
Investment on the date of any such sale or disposition equal to the fair market
value of the Equity Interests of such Subsidiary not sold or disposed of.
"Lien" means, with respect to any asset, any mortgage, lien, pledge,
charge, security interest or encumbrance of any kind in respect of such asset,
whether or not filed, recorded or otherwise perfected under applicable law
(including any conditional sale or other title retention agreement, any lease in
the nature thereof, any option or other agreement to sell or give a security
interest in and any filing of or agreement to give any financing statement under
the Uniform Commercial Code (or equivalent statutes) of any jurisdiction, other
than a precautionary financing statement respecting a lease not intended as a
security agreement and other than a financing statement relating to a sale of
accounts receivable).
"Net Income" means, with respect to any Person, the net income (loss) of
such Person, determined in accordance with GAAP and before any reduction in
respect of preferred stock
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dividends, excluding, however, (i) any gain (but not loss), together with any
related provision for taxes on such gain (but not loss), realized in connection
with (a) any Asset Sale (including, without limitation, dispositions pursuant to
sale and leaseback transactions) or (b) the disposition of any securities by
such Person or any of its Restricted Subsidiaries or the extinguishment of any
Indebtedness of such Person or any of its Restricted Subsidiaries and (ii) any
extraordinary or nonrecurring gain (but not loss), together with any related
provision for taxes on such extraordinary or nonrecurring gain (but not loss).
"Net Proceeds" means the aggregate cash proceeds received by the Company or
any of its Restricted Subsidiaries in respect of any Asset Sale (including,
without limitation, any cash received upon the sale or other disposition of any
non-cash consideration received in any Asset Sale, but excluding cash amounts
placed in escrow, until such amounts are released to the Company), net of the
direct costs relating to such Asset Sale (including, without limitation, legal,
accounting and investment banking fees, and sales commissions) and any
relocation expenses incurred as a result thereof, taxes paid or payable as a
result thereof (after taking into account any available tax credits or
deductions and any tax sharing arrangements), amounts required to be applied to
the repayment of Indebtedness (other than Indebtedness under any Credit
Facility) secured by a Lien on the asset or assets that were the subject of such
Asset Sale and any reserve for adjustment in respect of the sale price of such
asset or assets established in accordance with GAAP and any reserve established
for future liabilities.
"Non-Recourse Debt" means Indebtedness as to which as (a) neither the
Company nor any Restricted Subsidiary is directly or indirectly liable pursuant
to the terms of such Indebtedness and (b) no default with respect to such
Indebtedness would permit (upon notice, lapse of time or otherwise) any holder
of any other Indebtedness of the Company or any Restricted Subsidiary to declare
a default on such other indebtedness or cause the payment thereof to be
accelerated or payable prior to its stated maturity.
"Obligations" means any principal, interest, penalties, fees,
indemnifications, reimbursements, damages and other liabilities payable under
the documentation governing any Indebtedness.
"Oil and Gas Hedging Contracts" means any oil and gas purchase or hedging
agreement, and other agreement or arrangement, in each case, that is designed to
provide protection against oil and gas price fluctuations.
"Pari Passu Debt" means (a) with respect to the Notes, Indebtedness that
ranks pari passu in right of payment to the Notes and (b) with respect to any
Subsidiary Guarantee, Indebtedness which ranks pari passu in right of payment to
such Subsidiary Guarantee.
"Permitted Indebtedness" has the meaning given in the covenant described
under the caption "-- Certain Covenants -- Incurrence of Indebtedness and
Issuance of Disqualified Stock."
"Permitted Investments" of a Person means (a) any Investment in such Person
or in a Restricted Subsidiary of such Person; (b) any Investment in Cash
Equivalents or securities issued or directly and fully guaranteed or insured by
the United States government or any agency or instrumentality thereof having
maturities of not more than one year from the date of acquisition; (c) any
Investment by such Person or any Restricted Subsidiary of such Person in a
Person if, as a result of such Investment and any related transactions that at
the time of such Investment are contractually mandated to occur, (i) such Person
becomes a Wholly Owned Restricted Subsidiary of such Person or (ii) such Person
is merged, consolidated or amalgamated with or into, or transfers or conveys all
or substantially all of its assets to, or is liquidated into, such Person or a
Wholly Owned Restricted Subsidiary of such Person; (d) any Investment made as a
result of the receipt of non-cash consideration from an Asset Sale that was made
pursuant to and in compliance with the covenant described above under the
caption "-- Repurchase at the Option of Holders -- Asset Sales"; (e) Investments
by the Company or any Wholly Owned Restricted Subsidiary in any Person which is
a Wholly Owned Restricted Subsidiary; (f) Investments in the Company by any
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Wholly Owned Restricted Subsidiary; (g) Investments in any Person the
consideration for which consists of Equity Interests in the Company (other than
Disqualified Stock); (h) other Investments in any Person or Persons having an
aggregate fair market value (measured on the date each such Investment was made
and without giving effect to subsequent changes in value (as determined in good
faith by the Board of Directors of the Company, which determination shall be
evidenced by a resolution of such Board)), when taken together with all other
Investments made by the Company and its Restricted Subsidiaries pursuant to this
clause (h) that are at the time outstanding, not to exceed 5% of Total Assets at
the time such Investment is made; (i) any Investment acquired by the Company in
exchange for Equity Interests in the Company (other than Disqualified Stock);
(j) shares of Capital Stock received in connection with any good faith
settlement of a bankruptcy proceeding involving a trade creditor; (k) entry into
operating agreements, joint ventures, partnership agreements, working interests,
royalty interests, mineral leases, processing agreements, farm-in agreements,
farm-out agreements, contracts for the sale, transportation or exchange of oil
and natural gas, unitization agreements, pooling arrangements, area of mutual
interest agreements, joint development agreements, concession, license or permit
agreements relating to exploration and development of oil and gas properties,
production sharing agreements or other similar or customary agreements,
transactions, properties, interests or arrangements, and Investments and
expenditures in connection therewith or pursuant thereto, in each case made or
entered into the ordinary course of the Energy Business, excluding, however,
Investments in corporations other than any Investment otherwise permitted by
this definition; (l) stock, obligations or securities received in settlement of
debts created in the ordinary course of business and owing to the Company or any
Restricted Subsidiary or in satisfaction of judgments; (m) the acceptance of
notes payable from employees of the Company or any of its Subsidiaries as
payment for the purchase of Capital Stock of the Company or any of its
Subsidiaries by such employees provided that any such note payable is secured by
a pledge of the shares of Capital Stock of a Subsidiary purchased therewith; (n)
endorsements of negotiable instruments and documents in the ordinary course of
business; and (o) any Investments outstanding on the date of the Indenture (and
any reinvestment of the proceeds thereof in any similar investment).
"Permitted Liens" means (i) Liens securing Indebtedness of a Restricted
Subsidiary or Senior Debt that is outstanding on the date of issuance of the
Notes (after giving effect to the application of the proceeds therefrom), Liens
securing Senior Debt that is permitted by the terms of the Indenture to be
incurred and Liens securing Permitted Refinancing Debt relating to Indebtedness
or Senior Debt referred to in this clause (i) (provided that, with respect to
Permitted Refinancing Debt, such Liens extend to or cover only the property or
assets securing the Indebtedness or Senior Debt being refinanced); (ii) Liens in
favor of the Company; (iii) Liens on property existing at the time of
acquisition thereof by the Company or any Subsidiary of the Company, Liens upon
any property of any Person existing at the time such Person is merged or
consolidated with the Company or any Subsidiary and Liens on property or assets
of a Subsidiary existing at the time it became a Subsidiary, provided that in
each case such Lien has not been created in contemplation of such acquisition,
merger, consolidation or transfer, and provided further that in each such case
no such Lien shall extend to or cover any property of the Company or any
Subsidiary other than the property being acquired (through purchase, merger,
consolidation or otherwise) and improvements thereon; (iv) Liens incurred or
deposits made in the ordinary course of business in connection with workers'
compensation, unemployment insurance or other kinds of social security, old age
pension or public liability obligations or to secure the payment or performance
of bids, tenders, statutory or regulatory obligations, surety, stay or appeal
bonds, performance bonds or other obligations of a like nature incurred in the
ordinary course of business (including lessee or operator obligations under
statutes, governmental regulations or instruments related to the ownership,
exploration and production of oil, gas and minerals on state or federal lands or
waters); (v) Liens existing on the date of the Indenture (after giving effect to
the application of proceeds therefrom); (vi) Liens for taxes, assessments or
governmental charges or claims that are not yet delinquent or that are being
contested in good faith by appropriate proceedings promptly instituted and
diligently concluded,
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provided that any reserve or other appropriate provision as shall be required in
conformity with GAAP shall have been made therefor; (vii) statutory liens of
landlords, mechanics, suppliers, vendors, warehousemen, carriers or other like
Liens arising in the ordinary course of business; (viii) judgment Liens not
giving rise to an Event of Default so long as any appropriate legal proceeding
that may have been duly initiated for the review of such judgment shall not have
been finally terminated or the period within which such proceeding may be
initiated shall not have expired; (ix) Liens on, or related to, properties or
assets to secure all or part of the costs incurred in the ordinary course of the
Energy Business for the exploration, drilling, development, or operation
thereof; (x) Liens in pipeline or pipeline facilities that arise under operation
of law; (xi) Liens arising under operating agreements, joint venture agreements,
joint development agreements, partnership agreements, oil and gas leases,
farm-out agreements, division orders, contracts for the sale, transportation or
exchange of oil or natural gas, unitization and pooling declarations and
agreements, area of mutual interest agreements and other agreements that are
customary in the Energy Business; (xii) Liens reserved in oil and gas mineral
leases for bonus or rental payments and for compliance with the terms of such
leases; (xiii) Liens securing any Interest Rate Hedging Agreement permitted to
be entered into pursuant to the covenant described above under the caption
"-- Incurrence of Indebtedness and Issuance of Disqualified Stock"; (xiv) Liens
securing any Oil and Gas Hedging Contract permitted to be entered into pursuant
to the covenant described above under the caption "-- Incurrence of Indebtedness
and Issuance of Disqualified Stock"; (xv) survey exceptions, encumbrances,
easements or reservations of, or rights of others for, rights of way, zoning or
other restrictions as to the use of real properties, and minor defects in title
which, in the case of any of the foregoing, were not incurred or created to
secure the payment of borrowed money or the deferred purchase price of property
or services, and in the aggregate do not materially adversely affect the value
of such properties or materially impair use for the purposes of which such
properties are held by the Company or any Subsidiaries; (xvi) judgment and
attachment Liens not giving rise to an Event of Default or Liens created by or
existing from any litigation or legal proceeding that are currently being
contested in good faith by appropriate proceedings and for which adequate
reserves have been made; (xvii) Liens in favor of collecting or payor banks
having a right of setoff, revocation, refund or chargeback with respect to money
or instruments of the Company or any Subsidiary on deposit with or in possession
of such bank; (xviii) purchase money security interests granted in connection
with the acquisition of fixed assets in the ordinary course of business and
consistent with past practices, provided, that (A) such Liens attach only to the
property so acquired with the purchase money indebtedness secured thereby and
(B) such Liens secure only Indebtedness that is not in excess of 100% of the
purchase price of such fixed assets; (xix) Liens to secure Dollar-Denominated
Production Payments and Volumetric Production Payments; (xx) Liens securing the
Notes; and (xxi) Liens not otherwise permitted by clauses (i) through (xx) that
are incurred in the ordinary course of business of the Company or any Subsidiary
of the Company with respect to obligations that do not exceed $5 million at any
one time outstanding.
"Permitted Refinancing Debt" means any Indebtedness of the Company or any
of its Restricted Subsidiaries issued in exchange for, or the net proceeds of
which are used to extend, refinance, renew, replace, defease or refund other
Indebtedness (other than Indebtedness incurred under a Credit Facility) of the
Company or any of its Restricted Subsidiaries, provided that: (i) the principal
amount of such Permitted Refinancing Indebtedness (or, if such Indebtedness is
issued at a price less than the principal amount thereof, the aggregate amount
of gross proceeds therefrom) does not exceed the principal amount of the
Indebtedness so extended, refinanced, renewed, replaced, defeased or refunded
plus the amount of reasonable expenses incurred in connection therewith (or if
the Indebtedness being renewed, extended, refinanced, refunded or repurchased
was issued at a price less than the principal amount thereof, then not in excess
of the amount of liability in respect thereof determined in accordance with
GAAP); (ii) such Permitted Refinancing Indebtedness has a final maturity date on
or later than the final maturity date of, and has a Weighted Average Life to
Maturity equal to or greater than the Weighted Average Life to Maturity of, the
Indebtedness being
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extended, refinanced, renewed, replaced, defeased or refunded; (iii) if the
Indebtedness being extended, refinanced, renewed, replaced, defeased or refunded
is subordinated in right of payment to the Notes or the Subsidiary Guarantees,
as the case may be, such Permitted Refinancing Indebtedness has a final maturity
date later than the final maturity date of, and is subordinated in right of
payment to, the Notes or the Subsidiary Guarantees, as the case may be, on terms
at least as favorable taken as a whole to the holders of the Notes or the
Subsidiary Guarantees, as the case may be, as those contained in the
documentation governing the Indebtedness being extended, refinanced, renewed,
replaced, defeased or refunded; and (iv) such Indebtedness is incurred either by
the Company or by the Restricted Subsidiary who is the obligor on the
Indebtedness being extended, refinanced, renewed, replaced, defeased or
refunded.
"Person" means any individual, corporation, limited liability company,
partnership, joint venture, association, joint-stock company, trust,
unincorporated organization, government or any agency or political subdivision
thereof or any other entity.
"Production Payments" means Dollar-Denominated Production Payments and
Volumetric Production Payments, collectively.
"Restricted Investment" means an Investment other than a Permitted
Investment.
"Restricted Subsidiary" means any direct or indirect Subsidiary of the
Company that is not an Unrestricted Subsidiary.
"Senior Debt" means (i) Indebtedness of the Company or any Subsidiary of
the Company under or in respect of any Credit Facility, whether for principal,
interest (including interest accruing after the filing of a petition initiating
any proceeding pursuant to any bankruptcy law, whether or not the claim for such
interest is allowed as a claim in such proceeding), reimbursement obligations,
fees, commissions, expenses, indemnities or other amounts, and (ii) any other
Indebtedness permitted under the terms of the Indenture, unless the instrument
under which such Indebtedness is incurred expressly provides that it is on a
parity with or subordinated in right of payment to the Notes. Notwithstanding
anything to the contrary in the foregoing sentence, Senior Debt will not include
(w) any liability for federal, state, local or other taxes owed or owing by the
Company, (x) any Indebtedness of the Company to any of its Subsidiaries or other
Affiliates, (y) any trade payables or (z) any Indebtedness that is incurred in
violation of the Indenture (other than Indebtedness under (i) any Credit
Agreement or (ii) any other Credit Facility that is incurred on the basis of a
representation by the Company to the applicable lenders that it is permitted to
incur such Indebtedness under the Indenture).
"Subordinated Indebtedness" means any Indebtedness of the Company or any
Restricted Subsidiary (whether outstanding on the date of the issuance of the
Securities or thereafter incurred) which is subordinate and junior in right of
payment to the Notes pursuant to a written agreement.
"Subsidiary" means, with respect to any Person, (i) any corporation,
association or other business entity of which more than 50% of the total voting
power of shares of Capital Stock, entitled (without regard to the occurrence of
any contingency) to vote in the election of directors, managers or trustees
thereof is at the time owned or controlled, directly or indirectly, by such
Person or one or more of the other Subsidiaries of that Person (or a combination
thereof) and (ii) any partnership (a) the sole general partner or the managing
general partner of which is such Person or a Subsidiary of such Person or (b)
the only general partners of which are such Person or of one or more
Subsidiaries of such Person (or any combination thereof).
"Subsidiary Guarantee" means any guarantee of the obligations of the
Company under the Indenture and the Notes by any Person in accordance with the
provisions of the Indenture.
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"Subsidiary Guarantor" means any Person that incurs a Subsidiary Guarantee;
provided that upon the release and discharge of such Person from its Subsidiary
Guarantee in accordance with the Indenture, such Person shall cease to be a
Subsidiary Guarantor.
"Total Assets" means, with respect to any Person, the total consolidated
assets of such Person and its Subsidiaries, as shown on the most recent balance
sheet of such Person.
"Unrestricted Subsidiary" means (i) any Subsidiary of the Company which at
the time of determination shall be an Unrestricted Subsidiary (as designated by
the Board of Directors of the Company, as provided below) and (ii) any
Subsidiary of an Unrestricted Subsidiary. The Board of Directors of the Company
may designate any Subsidiary of the Company (including any newly acquired or
newly formed Subsidiary or a Person becoming a Subsidiary through merger or
consolidation or Investment therein) to be an Unrestricted Subsidiary only if
(a) such Subsidiary does not own any Capital Stock of, or own or hold any Lien
on any property of, any other Subsidiary of the Company which is not a
Subsidiary of the Subsidiary to be so designated or otherwise an Unrestricted
Subsidiary; (b) all the Indebtedness of such Subsidiary shall, at the date of
designation, and will at all times thereafter, consist of Non-Recourse Debt; (c)
the Company certifies that such designation complies with the "Limitation on
Restricted Payments" covenant; (d) such Subsidiary, either alone or in the
aggregate with all other Unrestricted Subsidiaries, does not operate, directly
or indirectly, all or substantially all of the business of the Company and its
Subsidiaries; (e) such Subsidiary does not, directly or indirectly, own any
Indebtedness of or Equity Interest in, and has no investments in, the Company or
any Restricted Subsidiary; (f) such Subsidiary is a Person with respect to which
neither the Company nor any of its Restricted Subsidiaries has any direct or
indirect obligation (1) to subscribe for additional Equity Interests or (2) to
maintain or preserve such Person's financial condition or to cause such Person
to achieve any specified levels of operating results; and (g) on the date such
Subsidiary is designated an Unrestricted Subsidiary, such Subsidiary is not a
party to any agreement, contract, arrangement or understanding with the Company
or any Restricted Subsidiary with terms substantially less favorable to the
Company than those that might have been obtained from Persons who are not
Affiliates of the Company. Any such designation by the Board of Directors of the
Company shall be evidenced to the Trustee by filing with the Trustee a
resolution of the Board of Directors of the Company giving effect to such
designation and an Officers' Certificate certifying that such designation
complied with the foregoing conditions. If, at any time, any Unrestricted
Subsidiary would fail to meet the foregoing requirements as an Unrestricted
Subsidiary, it shall thereafter cease to be an Unrestricted Subsidiary for
purposes of the Indenture and any Indebtedness of such Subsidiary shall be
deemed to be incurred as of such date. The Board of Directors of the Company may
designate any Unrestricted Subsidiary to be a Restricted Subsidiary; provided,
that (i) immediately after giving effect to such designation, no Default or
Event of Default shall have occurred and be continuing or would occur as a
consequence thereof and the Company could incur at least $1.00 of additional
Indebtedness (excluding Permitted Indebtedness) pursuant to the first paragraph
of the "Incurrence of Indebtedness and Issuance of Disqualified Stock" covenant
on a pro forma basis taking into account such designation.
"Volumetric Production Payments" means production payment obligations
recorded as deferred revenue in accordance with GAAP, together with all
undertakings and obligations in connection therewith.
"Voting Stock" means, with respect to any Person, securities of any class
or classes of Capital Stock in such Person normally entitling the holders
thereof to vote in the election of members of the Board of Directors or other
governing body of such Person.
"Weighted Average Life to Maturity" means, when applied to any Indebtedness
at any date, the number of years obtained by dividing (i) the sum of the
products obtained by multiplying (a) the amount of each then remaining
installment, sinking fund, serial maturity or other required payments of
principal, including payment at final maturity, in respect thereof, by (b) the
number of years
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(calculated to the nearest one-twelfth) that will elapse between such date and
the making of such payment, by (ii) the then outstanding principal amount of
such Indebtedness.
"Wholly Owned Restricted Subsidiary" of any Person means a Restricted
Subsidiary of such Person all of the outstanding Voting Stock or other ownership
interests of which (other than directors' qualifying shares) shall at the time
be owned, directly or indirectly, by such Person or by one or more Wholly Owned
Restricted Subsidiaries of such Person.
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DESCRIPTION OF OTHER INDEBTEDNESS
INDEBTEDNESS OF THE COMPANY
CREDIT AGREEMENT. Concurrently with the closing of the Offering, the
Company entered into the Credit Agreement with a group of lenders for which
General Electric Capital Corporation acts as the administrative agent (the
"Agent").
The Credit Agreement permits the Company to obtain revolving credit loans
from time to time in an aggregate amount not to exceed $50.0 million. The
Borrowing Base, initially set at $50.0 million under the Credit Agreement, is
subject to determination at the sole discretion of the Agent, based on a variety
of factors, including the discounted present value of estimated future net cash
flow from oil and gas production.
At the Company's option, loans may be prepaid, and revolving credit
commitments may be reduced, in whole or in part, at any time without penalty
(except for breakage and related costs associated with payments of Eurodollar
loans). The Credit Agreement matures May 20, 2002.
The Company's obligations under the Credit Agreement are secured by first
priority mortgages and security interests in gas and oil properties in which
Eastern American has an ownership, leasehold or other interest, as well as all
of Eastern American's gas gathering and gas marketing contracts.
At the Company's option, the applicable interest rate per annum is either
the Eurodollar loan rate plus a margin ranging from 1.0% to 1.5% or the ABR (as
defined below) plus a margin ranging from 0% to 0.5%. ABR is the higher of (x)
the rate of interest publicly quoted from time to time by The Wall Street
Journal as the base rate on corporate loans posted by at least 75% of the 30
largest banks in the United States and (y) the Federal Funds rate in effect on
the date of determination plus one-half of one percent ( 1/2 of 1%).
The Credit Agreement contains various covenants that, among other things,
will restrict the ability of the Company to dispose of assets, incur additional
indebtedness, repay other indebtedness, pay dividends, create liens on assets,
make investment or acquisitions, engage in mergers, and engage in certain
transactions with affiliates. In addition, under the Credit Agreement, the
Company is required to comply with specified minimum interest coverage and
maximum leverage ratios.
OTHER INDEBTEDNESS. The Company currently does not have any long or
short-term debt obligations, except for certain guarantees which have been given
in support of Eastern American's credit agreement with The Bank of Nova Scotia
and Eastern American's $12.0 million letter of credit. In addition, the Company
has guaranteed certain obligations of Eastern American, Allegheny & Western
Energy Corporation and Eastern Exploration Corporation, wholly owned
subsidiaries of Eastern American, under an agreement of limited partnership
dated November 15, 1995 providing for the formation of Eastern Producing Limited
Partnership. See "Business and Properties -- Significant Acquisitions and
Dispositions -- Section 2.9 Monetization".
INDEBTEDNESS OF SUBSIDIARIES
MOUNTAINEER AND ESC. In October 1995, ESC, a direct subsidiary of the
Company, entered into a note purchase agreement with The John Hancock Mutual
Life Insurance Company pursuant to which ESC issued $35.0 million in aggregate
principal amount of 10.75% Senior Notes due October 1, 2005 secured by a pledge
of the outstanding stock of its direct subsidiary Mountaineer Gas Company. The
ESC notes were repaid with proceeds from the Offering.
In October 1995, Mountaineer, a direct subsidiary of ESC, entered into a
note purchase agreement with The John Hancock Mutual Life Insurance Company
pursuant to which Mountaineer issued $60 million in aggregate principal amount
of 7.59% Senior Notes due October 1, 2010. The
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note purchase agreement requires Mountaineer to maintain certain financial
conditions, including a minimum net worth and further contains restrictions on
incurring debt, disposing of assets and other restrictions. The note purchase
agreement also prohibits Mountaineer from making any restricted payment unless,
after giving effect to the payment, (i) no default has occurred, (ii)
Mountaineer would be permitted to incur $1.00 of additional funded indebtedness
under such note purchase agreement and (iii) the aggregate amount of all
restricted payments made by Mountaineer and its restricted subsidiaries since
the date of the issuance of such notes on October 12, 1995 does not exceed $8
million plus 90% of the cumulative consolidated net income of Mountaineer from
the date of the issuance of such Notes. As of March 31, 1997, the aggregate
amount of all restricted payments made by Mountaineer and its restricted
subsidiaries since the date of the issuance of such Notes was $8.3 million, and
such note purchase agreement would have permitted Mountaineer to make additional
restricted payments of $23.7 million through March 31, 1997.
Mountaineer also had unsecured lines of credit totaling $71 million with
PNC Bank, One Valley Bank and Bank One at March 31, 1997. During the nine months
ended March 31, 1997, the maximum outstanding daily balance was $45.1 million
and the average daily balance was $30.3 million. The weighted average interest
rate was 5.97%. The outstanding borrowings on these lines of credit at March 31,
1997 was $26.6 million.
EASTERN AMERICAN. Eastern American entered into a Credit Agreement dated as
of June 19, 1995 with a group of lenders for which The Bank of Nova Scotia acts,
as administrative Agent providing for a loan in the original principal amount of
$175.0 million. The Company used proceeds from the Offering to repay all of the
outstanding indebtedness under the Credit Agreement.
Eastern American has outstanding a $12.0 million letter of credit issued by
a bank in support of Eastern American's obligations under a gas purchase
contract with the Royalty Trust. See "Business and Properties -- Significant Gas
Sales and Purchase Contracts." The letter of credit reduces by $3 million on
June 30 of each year until its expiration on June 30, 2000. As of March 31,
1997, no drawings have been made under the Letter of Credit. The letter of
credit agreement between Eastern American and the bank requires Eastern American
to maintain certain financial conditions, including a minimum net worth and
interest coverage ratio.
Eastern American also has unsecured revolving lines of credit totaling $2.0
million with One Valley Bank. As of March 31, 1997, no drawings have been made
under these lines of credits. These lines of credit are used primarily to
provide standby letters of credit for gas purchase arrangements made by its
subsidiary Eastern Marketing.
BOOK-ENTRY; DELIVERY AND FORM
The Old Notes were initially represented in the form of one registered Note
in global form without coupons (the "Global Old Note"). The Global Old Note was
deposited on the date of the closing of the sale of the Notes (the "Closing
Date") with, or on behalf of, the Depository Trust Company ("DTC") and
registered in the name of Cede & Co., as nominee of DTC, or will remain in the
custody of the Trustee pursuant to the FAST Balance Certificate Agreement
between DTC and the Trustee. The Exchange Notes also will be issued in the form
of one or more Global Notes (the "Global Exchange Notes" and, together with the
Global Old Note, the "Global Notes"). The Global Exchange Notes will be
deposited on the original date of issuance of the Exchange Notes with, or on
behalf of, DTC and registered in the name of Cede & Co., as nominee of DTC.
DTC has advised the Company that it is (i) a limited purpose trust company
organized under the laws of the State of New York, (ii) a "banking organization"
within the meaning of the New York banking law, (iii) a member of the Federal
Reserve System, (iv) a "clearing corporation" within the meaning of the Uniform
Commercial Code, as amended, and (v) a "Clearing Agency" registered pursuant to
Section 17A of the Exchange Act. DTC was created to hold securities for its
participants (collectively, the "Participants") and facilitates the clearance
and settlement of securities transac-
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tions between Participants through electronic book-entry changes to the accounts
of its Participants, thereby eliminating the need for physical transfer and
delivery of certificates. Participants include securities brokers and dealers
(including the Initial Purchasers), banks and trust companies, clearing
corporations and certain other organizations. Indirect access to DTC's system is
also available to other entities such as banks, brokers, dealers and trust
companies (collectively, the "Indirect Participants") that clear through or
maintain a custodial relationship with a Participant, either directly or
indirectly. QIBs may elect to hold Notes through DTC. QIBs who are not
Participants may beneficially own securities held by or on behalf of DTC only
through Participants or Indirect Participants.
The Company expects that pursuant to procedures established by DTC (i) upon
deposit of the Global Notes, DTC will credit the accounts of Participants
designated by the Initial Purchasers with an interest in the Global Note and
(ii) ownership of beneficial interests in the Global Notes will be shown on, and
the transfer of beneficial ownership therein will be effected only through,
records maintained by DTC (with respect to the interest of the Participants),
the Participants and the Indirect Participants. For certain other restrictions
on the transferability of the Notes, see "Transfer Restrictions."
So long as DTC or its nominee is the registered owner of a Global Note, DTC
or such nominee, as the case may be, will be considered the sole owner or holder
of the Notes represented by the Global Note for all purposes under the Indenture
and the Notes. Except as provided below, owners of beneficial interests in a
Global Note will not be entitled to have Notes represented by such Global Note
registered in their names, will not receive or be entitled to receive physical
delivery of Certificated Securities, and will not be considered the owners or
holders thereof under the Indenture for any purpose, including with respect to
giving of any directions, instruction or approval to the Trustee thereunder. As
a result, the ability of a person having a beneficial interest in Notes
represented by a Global Note to pledge or transfer such interest to persons or
entities that do not participate in DTC's system or to otherwise take action
with respect to such interest, may be affected by the lack of a physical
certificate evidencing such interest.
Accordingly, each QIB owning a beneficial interest in a Global Note must
rely on the procedures of DTC and, if such QIB is not a Participant or an
Indirect Participant, on the procedures of the Participant through which such
QIB owns its interest, to exercise any rights of a holder of Notes under the
Indenture or such Global Note. The Company understands that under existing
industry practice, in the event the Company requests any action of holders of
Notes or a QIB that is an owner of a beneficial interest in a Global Note
desires to take any action that DTC, as the holder of such Global Note, is
entitled to take, DTC would authorize the Participants to take such action and
the Participant would authorize QIBs owning through such Participants to take
such action or would otherwise act upon the instruction of such QIBs. Neither
the Company nor the Trustee will have any responsibility or liability for any
aspect of the records relating to or payments made on account of Notes by DTC,
or for maintaining, supervising or reviewing any records of DTC relating to such
Notes or for any other matter relating to the actions or procedures of DTC.
Payments with respect to the principal of, premium, if any, and interest
on, any Notes represented by a Global Note registered in the name of DTC or its
nominee on the applicable record date will be payable by the Trustee to or at
the direction of DTC or its nominee in its capacity as the registered holder of
the Global Note representing such Notes under the Indenture. Under the terms of
the Indenture, the Company and the Trustee may treat the persons in whose names
the Notes, including the Global Notes, are registered as the owners thereof for
the purpose of receiving such payment and for any and all other purposes
whatsoever. Consequently, neither the Company nor the Trustee has or will have
any responsibility or liability for the payment of such amounts to beneficial
owners of interest in the Global Note (including principal, premium, if any, and
interest), or to immediately credit the accounts of the relevant Participants
with such payment, in amounts proportionate to their respective holdings in
principal amount of beneficial interest in the Global Note as shown on the
records of DTC. The Company expects that payments by the Participants and the
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Indirect Participants to the beneficial owners of interests in the Global Note
will be governed by standing instructions and customary practice and will be the
responsibility of the Participants or the Indirect Participants and DTC.
The information in this section concerning DTC and DTC's book-entry system
has been obtained from sources the Company believes to be reliable, but the
Company takes no responsibility for the accuracy thereof.
CERTIFICATED SECURITIES
If (i) the Company notifies the Trustee in writing that DTC is no longer
willing or able to act as a depository or DTC ceases to be registered as a
clearing agency under the Exchange Act and the Company is unable to locate a
qualified successor within 90 days, (ii) the Company, at its option, notifies
the Trustee in writing that it elects to cause the issuance of Notes in
definitive form under the Indenture or (iii) upon the occurrence of certain
other events, then, upon surrender by DTC of its Global Notes, then Certificated
Securities will be issued to each person that DTC identifies as the beneficial
owner of the Notes represented by the Global Note. Upon any such issuance, the
Trustee is required to register such Certificated Securities in the name of such
person or persons (or the nominee of any thereof), and cause the same to be
delivered thereto.
Neither the Company nor the Trustee shall be liable for any delay by DTC or
any Participant or Indirect Participant in identifying the beneficial owners of
the related Notes and each such person may conclusively rely on, and shall be
protected in relying on, instructions from DTC for all purposes (including with
respect to the registration and delivery, and the respective principal amounts,
of the Notes to be issued).
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PLAN OF DISTRIBUTION
Each broker-dealer that receives Exchange Notes for its own account
pursuant to the Exchange Offer must acknowledge that it will deliver a
prospectus in connection with any resale of such Exchange Notes. This
Prospectus, as it may be amended or supplemented from time to time, may be used
by a broker-dealer in connection with resales of Exchange Notes received in
exchange for Old Notes where such Old Notes were acquired as a result of
market-making activities or other trading activities. The Company has agreed
that, for a period of 180 days after the Expiration Date, it will make this
prospectus, as amended or supplemented, available to any broker-dealer for use
in connection with any such resale. In addition, until , 1997, all
dealers effecting transactions in the Exchange Notes may be required to deliver
a prospectus.
The Company will not receive any proceeds from any sale of Exchange Notes
by broker-dealers. Exchange Notes received by broker-dealers for their own
account pursuant to the Exchange Offer may be sold from time to time in one or
more transactions in the over-the-counter market, in negotiated transactions,
through the writing of options on the Exchange Notes or a combination of such
methods of resale, at market prices prevailing at the time of resale, at prices
related to such prevailing market prices or at negotiated prices. Any such
resale may be made directly to purchasers or to or through brokers or dealers
who may receive compensation in the form of commissions or concessions from any
such broker-dealer or the purchasers of any such Exchange Notes. Any
broker-dealer that resells Exchange Notes that were received by it for its own
account pursuant to the Exchange Offer and any broker or dealer that
participates in a distribution of such Exchange Notes may be deemed to be an
"underwriter" within the meaning of the Securities Act and any profit on any
such resale of Exchange Notes and any commission or concessions received by any
such person may be deemed to be underwriting compensation under the Securities
Act. The Letter of Transmittal states that, by acknowledging that it will
deliver and by delivering a prospectus, a broker-dealer will not be deemed to
admit that it is an "underwriter", within the meaning of the Securities Act.
For a period of 180 days after the Expiration Date the Company will
promptly send additional copies of this Prospectus and any amendment or
supplement to this Prospectus to any broker-dealer that requests such documents
in the Letter of Transmittal. The Company has agreed to pay all expenses
incident to the Exchange Offer (including the expenses of one counsel for the
holders of the Notes), other than commissions or concessions of any
broker-dealers, and will indemnify the holders of the Notes (including any
broker-dealers) against certain liabilities, including liabilities under the
Securities Act.
LEGAL MATTERS
Certain legal matters with respect to the Exchange Notes offered hereby
will be passed upon for the Company by Andrews & Kurth L.L.P., Houston, Texas
and Goodwin & Goodwin, LLP, Charleston, West Virginia.
EXPERTS
The consolidated financial statements of the Company, as of March 31, 1997
and June 30, 1996 and for the nine month period ended March 31, 1997 and the
years ended June 30, 1996 and 1995 and the consolidated statement of income of
Allegheny & Western Energy Corporation and subsidiaries for the year ended June
30, 1995, included in this Prospectus, and the related financial statement
schedules, included elsewhere in the Registration Statement, have been audited
by Deloitte & Touche LLP, independent auditors, as stated in their reports
appearing herein and elsewhere in the Registration Statement, and are included
in reliance upon the reports of such firm given upon their authority as experts
in accounting and auditing.
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Certain information with respect to the gas and oil reserves of the Company
has been derived from the respective reports of Ryder Scott Company and Joseph
J. Mendoza, independent petroleum engineers.
CHANGE OF ACCOUNTANTS
Coopers & Lybrand, the accounting firm that had previously been engaged as
the principal accountant to audit the Company's financial statements, resigned
in December 1996. The audit reports previously issued by Coopers & Lybrand with
respect to the Company's financial statements did not contain an adverse opinion
or a disclaimer of opinion, nor were such reports qualified or modified as to
uncertainty, audit scope or accounting principles. There were no disagreements
between the Company and Coopers & Lybrand on any matters of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure. The Company's Board of Directors approved the selection of Deloitte &
Touche LLP as auditors for the Company's financial statements for the fiscal
year ending June 30, 1997, and Deloitte & Touche LLP was engaged for such
purpose in January 1997. The Company's Board of Directors did not make any
determination with respect to a change in accounting firms prior to the
resignation of Coopers & Lybrand.
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GLOSSARY
The definitions set forth below shall apply to the indicated terms as used
in this Prospectus. All volumes of natural gas referred to herein are stated at
the legal pressure base of the state or area where the reserves exist and at 60
degrees Fahrenheit and in most instances are rounded to the nearest major
multiple.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf
of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein
in reference to crude oil or other liquid hydrocarbons.
Btu. British thermal unit, which is the heat required to raise the
temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
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.
Degree Day. Degree Days measure the amount by which the average of the high
and low temperature on a given day is below 65 degrees Fahrenheit. For example,
if the high temperature is 60 degrees and the low temperature is 40 degrees for
a National Oceanic and Atmospheric Administration measurement location, the
average temperature is 50 degrees and the number of degree days for that day is
15.
Developed acreage. The number of acres which are allocated or assignable to
producing wells or wells capable of production.
Development well. A well drilled within the proved area of an oil or gas
reservoir to the depth of a stratigraphic horizon known to be productive.
Direct finding costs. The total of all costs incurred with respect to
reserve additions resulting from acquisitions and drilling activities, less
internal capitalized charges, divided by reserve additions.
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.
Dth. One dekatherm (equal to 1,000 Btu).
Exploratory well. A well drilled to find and produce oil or gas reserves
not classified as proved.
Farm-in or farm-out. An agreement whereunder the owner of a working
interest in an oil and gas lease assigns the working interest or a portion
thereof to another party who desires to drill on the leased acreage. Generally,
the assignee is required to drill one or more wells in order to earn its
interest in the acreage. The assignor usually retains a royalty or reversionary
interest in the lease. The interest received by an assignee is a "farm-in" while
the interest transferred by the assignor is a "farm-out."
Field. An area consisting of a single reservoir or multiple reservoirs all
grouped on or related to the same individual geological structural feature
and/or stratigraphic condition.
Field operating expenses. Lifting and operating expense less internal
capitalized costs and well operation and service revenue.
Gross acres or gross wells. The total acres or wells, as the case may be,
in which a working interest is owned.
Lifting and operating expense. The total of all field operating expenses,
net of well operations and service revenues.
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Liquids. Crude oil, condensate and natural gas liquids.
Mbbls. One thousand barrels of crude oil or other liquid hydrocarbons.
Mbtu. One thousand Btus.
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six
Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.
Mmbbls. One million barrels of crude oil or other liquid hydrocarbons.
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.
Net acres or net wells. The sum of the fractional working interests owned
in gross acres or gross wells.
NGLs. Natural gas liquids.
Operating Margin. The dollar amount calculated as oil and gas sales plus
well and service revenues, less lifting and operating expense and general and
administrative expense and production taxes.
Oil. Crude oil and condensate.
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 found to be capable of producing
hydrocarbons in sufficient quantities such that proceeds from the sale of such
production exceed production expenses and taxes.
Proved developed producing reserves. Proved developed reserves that are
expected to be recovered from completion intervals currently open in existing
well and able to produce to market.
Proved reserves. The estimated quantities of crude oil, natural gas and
natural gas liquids which geological and engineering date demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions.
Proved undeveloped reserves. Proved reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required from recompletion.
Royalty interest. An interest in an oil and gas property entitling the
owner to a share of oil or gas production free of costs or production.
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 which gives the owner the right to
drill, produce and conduct operating activities on the property and a share of
production.
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<PAGE> 123
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
----
<S> <C>
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES CONSOLIDATED
FINANCIAL STATEMENTS FOR THE NINE MONTH PERIOD ENDED MARCH
31, 1997 AND FOR THE YEARS ENDED JUNE 30, 1996 AND 1995
Independent Auditors' Report................................ F-2
Consolidated Balance Sheets................................. F-3
Consolidated Statements of Income........................... F-4
Consolidated Statements of Stockholders' Equity............. F-5
Consolidated Statements of Cash Flows....................... F-6
Notes to Consolidated Financial Statements.................. F-7
ALLEGHENY & WESTERN CORPORATION CONSOLIDATED STATEMENT OF
OPERATIONS FOR THE YEAR ENDED JUNE 30, 1995
Independent Auditors' Report................................ F-30
Consolidated Statement of Income............................ F-31
Notes to Consolidated Statement of Income................... F-32
</TABLE>
F-1
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INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of
Energy Corporation of America:
We have audited the accompanying consolidated balance sheets of Energy
Corporation of America and Subsidiaries as of March 31, 1997 and June 30, 1996,
and the related consolidated statements of income, stockholders' equity, and
cash flows for the nine month period ended March 31, 1997 and for the years
ended June 30, 1996 and 1995. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on
these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Energy Corporation of America
and Subsidiaries as of March 31, 1997 and June 30, 1996, and the results of
their operations and their cash flows for the nine month period ended March 31,
1997 and for the years ended June 30, 1996 and 1995 in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
April 21, 1997
F-2
<PAGE> 125
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
MARCH 31, 1997 AND JUNE 30, 1996
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
ASSETS
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................. $ 14,331 $ 14,197
Accounts receivable:
Utility gas and transportation.......................... 42,649 23,317
Gas marketing and pipeline.............................. 5,284 8,931
Oil and gas sales....................................... 7,145 6,875
Other................................................... 13,020 6,423
-------- --------
68,098 45,546
Less allowance for doubtful accounts.................... (1,368) (1,744)
-------- --------
66,730 43,802
Gas in storage, at average cost........................... 6,464 12,457
Income taxes receivable................................... 3,242
Deferred income taxes..................................... 5,599 6,337
Prepaid and other current assets.......................... 3,246 3,860
-------- --------
Total current assets................................ 96,370 83,895
-------- --------
NET PROPERTY, PLANT AND EQUIPMENT........................... 318,846 339,793
-------- --------
OTHER ASSETS:
Deferred financing costs, less accumulated amortization of
$1,729 and $1,144, respectively......................... 7,533 8,198
Notes receivable.......................................... 5,802 4,219
Notes receivable -- related party......................... 1,470 1,528
Deferred charges.......................................... 18,181 16,302
Deferred income taxes..................................... 1,118 1,357
Other..................................................... 5,126 6,212
-------- --------
Total other assets.................................. 39,230 37,816
-------- --------
TOTAL....................................................... $454,446 $461,504
======== ========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses..................... $ 34,947 $ 39,798
Current portion of long-term debt......................... 12,002 10,051
Short-term debt........................................... 26,614 8,392
Funds held for future distribution........................ 6,736 5,191
Income taxes payable...................................... 1,515 --
Overrecovered gas costs................................... 10,257 11,778
Accrued taxes, other than income.......................... 8,686 3,743
Other current liabilities................................. 11,197 12,948
-------- --------
Total current liabilities........................... 111,954 91,901
LONG-TERM OBLIGATIONS, LESS CURRENT PORTION:
Long-term debt............................................ 219,806 254,647
Gas delivery obligation and deferred trust revenue........ 19,226 21,473
Deferred income taxes..................................... 39,488 38,366
Other long-term obligations............................... 14,118 14,849
-------- --------
Total liabilities................................... 404,592 421,236
-------- --------
COMMITMENTS AND CONTINGENCIES
MINORITY INTEREST........................................... 1,949 2,718
-------- --------
STOCKHOLDERS' EQUITY:
Common stock, par value $1.00; 2,000 shares authorized;
714 and 711 shares issued in 1997 and 1996,
respectively............................................ 714 711
Additional paid-in capital................................ 4,211 4,086
Retained earnings......................................... 45,828 34,099
Treasury stock and notes receivable arising from issuance
of common stock......................................... (2,870) (1,371)
Cumulative foreign currency translation adjustment........ 22 25
-------- --------
Total stockholders' equity.......................... 47,905 37,550
-------- --------
TOTAL....................................................... $454,446 $461,504
======== ========
</TABLE>
See notes to consolidated financial statements.
F-3
<PAGE> 126
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
FOR THE NINE MONTH PERIOD ENDED MARCH 31, 1997 AND
THE YEARS ENDED JUNE 30, 1996 AND 1995
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
1997 1996 1995
------------- -------- --------
(NINE MONTHS)
<S> <C> <C> <C>
REVENUES:
Utility gas sales and transportation................ $146,965 $182,929
Gas marketing and pipeline sales.................... 120,257 146,398 $103,015
Oil and gas sales................................... 27,002 31,940 29,277
Well operations and service revenues................ 10,700 14,003 3,955
Contract settlement and other....................... 229 524 9,247
-------- -------- --------
305,153 375,794 145,494
-------- -------- --------
COSTS AND EXPENSES:
Utility gas purchased............................... 85,705 95,157
Gas marketing and pipeline cost of sales............ 112,913 138,067 100,251
Field operating expenses............................ 15,162 21,796 11,510
Utility operations and maintenance.................. 15,480 23,841
General and administrative.......................... 16,479 23,967 6,689
Taxes, other than income............................ 15,039 16,165 1,560
Depletion, depreciation and amortization of oil and
gas properties................................... 6,509 9,204 9,763
Depreciation of pipelines, other property and
equipment........................................ 8,471 9,613 2,278
Exploration and impairment.......................... 3,613 6,756 281
-------- -------- --------
279,371 344,566 132,332
-------- -------- --------
Income from operations...................... 25,782 31,228 13,162
-------- -------- --------
OTHER (INCOME) AND EXPENSE:
Interest............................................ 17,005 23,182 8,744
Gain on sale of assets.............................. (8,153) (3,934) (279)
Other............................................... (604) 693 367
-------- -------- --------
8,248 19,941 8,832
-------- -------- --------
INCOME BEFORE INCOME TAXES AND MINORITY INTEREST...... 17,534 11,287 4,330
PROVISION FOR INCOME TAXES............................ 4,960 3,274 2,710
-------- -------- --------
INCOME BEFORE MINORITY INTEREST....................... 12,574 8,013 1,620
MINORITY INTEREST..................................... 339 193 435
-------- -------- --------
NET INCOME............................................ $ 12,235 $ 7,820 $ 1,185
======== ======== ========
NET INCOME PER SHARE.................................. $ 17.67 $ 11.02 $ 1.67
======== ======== ========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING......................................... 692 710 710
======== ======== ========
</TABLE>
See notes to consolidated financial statements.
F-4
<PAGE> 127
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
FOR THE NINE MONTH PERIOD ENDED MARCH 31, 1997 AND
THE YEARS ENDED JUNE 30, 1996 AND 1995
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<CAPTION>
NOTES
RECEIVED CUMULATIVE
ADDITIONAL FROM FOREIGN TOTAL
COMMON PAID-IN RETAINED TREASURY ISSUANCE OF CURRENCY STOCKHOLDERS'
STOCK CAPITAL EARNINGS STOCK COMMON STOCK TRANSLATION EQUITY
------ ---------- -------- -------- ------------ ----------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, June 30, 1994........... $704 $3,805 $27,008 $ (7) $(269) $31,241
Net income..................... 1,185 1,185
Cash dividends ($0.645 per
share)...................... (457) (457)
Exercise of employee stock
options for notes
receivable.................. 4 156 (160)
Purchase of treasury stock..... (482) 32 (450)
Reduction of notes
receivable.................. 94 94
---- ------ ------- ------- ----- ---- -------
Balance, June 30, 1995........... 708 3,961 27,736 (489) (303) 31,613
---- ------ ------- ------- ----- ---- -------
Net income..................... 7,820 7,820
Cash dividends ($2.10 per
share)...................... (1,457) (1,457)
Exercise of employee stock
options..................... 3 125 128
Purchase of treasury stock..... (632) (632)
Reduction of notes
receivable.................. 53 53
Adjustment for foreign currency
translation................. $ 25 25
---- ------ ------- ------- ----- ---- -------
Balance, June 30, 1996........... 711 4,086 34,099 (1,121) (250) 25 37,550
---- ------ ------- ------- ----- ---- -------
Net income..................... 12,235 12,235
Cash dividends ($0.75 per
share)...................... (506) (506)
Exercise of employee stock
options for notes
receivable.................. 3 125 (128)
Purchase of treasury stock..... (1,493) (1,493)
Reduction of notes
receivable.................. 122 122
Adjustment for foreign currency
translation................. (3) (3)
---- ------ ------- ------- ----- ---- -------
Balance, March 31, 1997.......... $714 $4,211 $45,828 $(2,614) $(256) $ 22 $47,905
==== ====== ======= ======= ===== ==== =======
</TABLE>
See notes to consolidated financial statements.
F-5
<PAGE> 128
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE NINE MONTH PERIOD ENDED MARCH 31, 1997 AND
THE YEARS ENDED JUNE 30, 1996 AND 1995
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
1997 1996 1995
------------- -------- ---------
(NINE MONTHS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income........................................ $ 12,235 $ 7,820 $ 1,185
Adjustments to reconcile net income to net cash
provided by operating activities:
Minority interest.............................. 339 193 435
Depreciation, depletion and amortization....... 15,645 19,471 12,584
Gain on sale of assets......................... (8,153) (3,934) (279)
Deferred income taxes.......................... 2,099 1,518 3,437
Exploration and impairment expense............. 3,613 6,756 281
Provision for losses on accounts receivable.... 1,153 1,800
Other, net..................................... (1,575) (2,447) (3,049)
-------- -------- ---------
25,356 31,177 14,594
Changes in assets and liabilities:
Accounts receivable............................ (26,447) (17,288) (3,118)
Gas in storage................................. 5,993 3,154 654
Income taxes receivable........................ 3,242 1,723 1,920
Prepaid and other assets....................... (2,285) 6,155 (1,021)
Accounts payable and other current
liabilities.................................. 704 4,081 1,061
Funds held for future distribution............. 1,545 (1,946) 1,185
Income tax payable............................. 1,515
Overrecovered gas costs........................ (1,521) (8,741)
Other.......................................... (1,403) (1,221) (1,255)
-------- -------- ---------
Net cash provided by operating
activities.............................. 6,699 17,094 14,020
-------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property, plant and equipment.... (21,555) (39,445) (20,036)
Acquisition of A&W, net of cash acquired.......... (73,190)
Proceeds from sale of oil and gas properties...... 779 17,426 413
Proceeds from sale of limited partnership......... 11,250
Notes receivable.................................. (25) (804) 373
-------- -------- ---------
Net cash used in investing activities..... (9,551) (22,823) (92,440)
-------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from issuance of long-term debt.......... 71,000 250,998 254,386
Principal payments on long-term debt.............. (84,223) (218,352) (157,568)
Short-term borrowings, net........................ 18,222 (27,203)
Purchase of treasury stock (common stock)......... (1,493) (632) (450)
Dividends and distributions paid.................. (506) (1,199) (618)
Other equity transactions......................... 9 109 (166)
Deferred financing costs.......................... (23) (3,919) (4,953)
-------- -------- ---------
Net cash used in financing activities..... 2,986 (198) 90,631
-------- -------- ---------
Net increase (decrease) in cash and cash
equivalents............................. 134 (5,927) 12,211
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD...... 14,197 20,124 7,913
-------- -------- ---------
CASH AND CASH EQUIVALENTS, END OF PERIOD............ $ 14,331 $ 14,197 $ 20,124
======== ======== =========
</TABLE>
See notes to consolidated financial statements.
F-6
<PAGE> 129
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE NINE MONTH PERIOD ENDED MARCH 31, 1997 AND
THE YEARS ENDED JUNE 30, 1996 AND 1995
1. NATURE OF ORGANIZATION
Energy Corporation of America (the "Company") was established in June 1993
through an exchange of shares with the common stockholders of Eastern American
Energy Corporation ("Eastern"). The Company is an independent integrated energy
company that, through its subsidiaries, is primarily engaged in operating a
natural gas distribution system in West Virginia and oil and gas operations in
West Virginia and Pennsylvania. The Company also is engaged in the exploration
and production of oil and natural gas in other parts of the United States,
primarily in the Rocky Mountains and New Zealand. All references to the
"Company" include Energy Corporation of America and its consolidated
subsidiaries.
Natural Gas Distribution System -- The Company operates, through its
wholly-owned subsidiary Mountaineer Gas Company ("Mountaineer"), a natural gas
distribution system in West Virginia. Mountaineer provides natural gas sales,
transportation and distribution service to residential, commercial, industrial
and wholesale customers. As a public utility, Mountaineer is subject to
regulation by the West Virginia Public Service Commission ("WVPSC").
Oil and Gas Exploration, Development, Production and Marketing -- The
Company, primarily through its subsidiary Eastern, is engaged in exploration,
development and production, transportation and marketing of natural gas
primarily within the Appalachian Basin in the states of West Virginia,
Pennsylvania and Ohio. The Company owns all of the voting common shares of
Eastern, while certain officers and stockholders of the Company ("minority
interest") own non-voting common shares representing less than five percent of
all Eastern common shares.
The Company, through its wholly-owned subsidiaries Westech Energy
Corporation ("Westech") and Westside Acquisition Corporation ("Westside"), is
also engaged in the exploration for and production of oil and natural gas
primarily in the Rocky Mountains and New Zealand.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following is a summary of the significant accounting policies followed
by the Company and its subsidiaries.
Principles of Consolidation -- The consolidated financial statements
include the accounts of the Company; Eastern and its subsidiaries; Eastern
Systems Corporation ("ESC") and its wholly-owned subsidiary, Mountaineer and
subsidiary; Westech, and Westech Energy New Zealand Ltd. and its investment in
certain New Zealand oil and gas exploration joint ventures. The Company has
investments in oil and gas limited partnerships and joint ventures and has
recognized its proportionate share of these entities' revenues, expenses, assets
and liabilities. All significant intercompany transactions have been eliminated
in consolidation except gas sales between Eastern and Mountaineer, a regulated
utility.
The Company's wholly-owned subsidiary, Westside, owned an 80% interest in a
limited partnership ("Westside Operating Partnership LP") until the end of March
1997 (see Note 3). This investment had been consolidated prior to March 31, 1997
(see Note 11).
Cash and Cash Equivalents -- Cash and cash equivalents include short-term
investments maturing in three months or less from the date acquired.
Property, Plant and Equipment -- Oil and gas properties are accounted for
using the successful efforts method of accounting. Under this method, certain
expenditures such as exploratory geologi-
F-7
<PAGE> 130
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
cal and geophysical costs, exploratory dry hole costs, delay rentals and other
costs related to exploration are recognized currently as expenses. All direct
and certain indirect costs relating to property acquisition, successful
exploratory wells, development costs, and support equipment and facilities are
capitalized. The Company computes depletion, depreciation and amortization of
capitalized oil and gas property costs on the units-of-production method using
proved developed reserves. Direct production costs, production overhead and
other costs are charged against income as incurred. Gains and losses on the sale
of oil and gas property interests are generally included in operations.
The provision for depreciation of Mountaineer's utility plant is based on a
composite straight-line method. The average composite depreciation rate was
3.10% and 3.71% for 1997 and 1996, respectively. Mountaineer's property, plant
and equipment includes capitalized overhead for payroll related costs and
administrative and general expenses, as well as an allowance for funds used
during construction ("AFUDC") of approximately $43,200 and $49,600 for the nine
month period ended March 31, 1997 and for the year ended June 30, 1996. AFUDC is
an accounting procedure which capitalizes the cost of funds used to finance
utility construction projects as part of utility plant on the balance sheet and
credits the cost as a non-cash item on the income statement. During the nine
month period ended March 31, 1997 and for the year ended June 30, 1996 this
amount related only to debt financing in accordance with WVPSC policies.
Other property, equipment, pipelines and buildings are stated at cost and
are depreciated using straight-line and accelerated methods over estimated
useful lives ranging from three to 30 years.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains or losses related to
retirement of utility property, net of any salvage and cost of removal, are
credited or charged to accumulated depreciation. Gains and losses on
dispositions of other property, equipment, pipelines and buildings are included
in operations.
Property, plant and equipment includes the following balances (in
thousands):
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
Oil and gas properties...................................... $204,207 $219,683
Utility plant............................................... 158,491 151,699
Other property and equipment................................ 22,874 23,925
Pipelines................................................... 16,920 16,670
Land and buildings.......................................... 2,426 2,426
-------- --------
404,918 414,403
Less accumulated depreciation, depletion and amortization... (86,072) (74,610)
-------- --------
Net property, plant and equipment........................... $318,846 $339,793
======== ========
</TABLE>
Long-Lived Assets -- In March 1995, Statement of Financial Accounting
Standards ("SFAS") No. 121, "Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to be Disposed Of," was issued. The standard requires
all companies to assess long-lived assets and assets to be disposed of for
impairment and requires rate-regulated companies to write-off regulatory assets
to earnings whenever those assets no longer meet the criteria for recognition of
a regulatory asset as defined by SFAS No. 7l, "Accounting for the Effects of
Certain Types of Regulation." During 1997, the Company adopted this statement
and determined that no impairment loss needed to be recognized for applicable
assets of continuing operations.
Gas in Storage -- Gas in storage is stated at the lower of average cost or
market value.
F-8
<PAGE> 131
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Deferred Financing Costs -- Certain legal, underwriting fees and other
direct expenses associated with the issuance of credit agreements, lines of
credit and other financing transactions have been capitalized. These financing
costs are being amortized over the term of the related revolving credit
agreement.
Foreign Currency Translation -- The translation of applicable foreign
currencies into U.S. dollars is performed for balance sheet accounts using
current exchange rates in effect at the balance sheet date and for revenue and
expense accounts using an average exchange rate during the period. The
cumulative translation adjustment is included in stockholder's equity.
Income Taxes -- Deferred income taxes reflect the impact of "temporary
differences" between assets and liabilities recognized for financial reporting
purposes and such amounts as measured by tax laws. These temporary differences
are determined in accordance with SFAS No. 109, "Accounting For Income Taxes."
Gas Delivery Obligation -- Gas delivery obligation represents deferred
revenues on gas sales where the Company has received an advance payment. The
Company recognizes the actual gas sales revenue in the period the gas delivery
takes place.
Revenues and Purchased Gas Costs -- Utility gas sales and transportation
revenues included in income are based on amounts billed to customers on a cycle
basis and estimated amounts for gas delivered but unbilled at the end of each
accounting period.
Prior to November 1, 1995, Mountaineer recognized utility gas purchased
based on the amount billed to customers through a purchased gas adjustment
clause ("PGA"). The difference between amounts billed and actual gas costs
incurred were recognized as over/underrecovered gas costs. Effective November 1,
1995, the PGA was temporarily suspended through October 31, 1998 in accordance
with a Joint Stipulation and Agreement for Settlement (the "Agreement") between
Mountaineer and WVPSC. Accordingly, beginning November 1, 1995, gas costs are
expensed as incurred and the rates charged to customers are not adjusted to
reflect changes in the cost of gas. In accordance with the Agreement, the
estimated overrecovered balance at October 31, 1995 of $12,000,000 is to be
amortized over a three-year period beginning November 1, 1995. For the nine-
month period ended March 31, 1997 and for the year ended June 30, 1996, the
Company amortized to cost of gas $3,000,000 and $2,667,000, respectively. At
October 31, 1995, the actual overrecovered gas cost balance was determined to be
$12,682,000. The amount in excess of $12,000,000 and certain transportation
revenues, storage balancing fees and standby charges are being deferred as
authorized by the WVPSC and will be addressed in Mountaineer's next general rate
case proceeding (see Note 17).
Oil and gas sales are recognized as income when the oil or gas is produced
and sold.
Stock Compensation -- In October 1995 SFAS No. 123, "Accounting for
Stock-Based Compensation," was issued. As permitted under SFAS No. 123, the
Company has elected to continue to measure compensation costs for stock-based
employee compensation plans as prescribed by Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees."
Hedging Activities -- The Company periodically hedges a portion of its oil
and gas production through swap agreements. The purpose of the hedges is to
provide a measure of stability in the volatile environment of oil and gas
prices. The Company recognizes gains and losses in the swap agreements at the
time the hedged volumes are sold.
The Company enters into interest rate swap agreements to manage exposure to
changes in interest rates. The transactions generally involve the exchange of
fixed and floating interest payment obligations without the exchange of
underlying principal amounts. The net effect of interest
F-9
<PAGE> 132
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
rate swap activity is reflected as an increase or decrease in interest expense.
Any gains on termination of interest rate swap agreements that were marked to
market are included in other income. In addition to the financial risk that will
vary during the life of these swap agreements in relation to the maturity of the
underlying debt and market interest rates, the Company is subject to credit risk
exposure from nonperformance of the counterparties to the swap agreements.
Earnings per Share of Common Stock -- Earnings per share of common stock is
computed by dividing net income attributable to the shares of common stock by
the weighted average number of common shares and common share equivalents
outstanding during the reporting period. The number of equivalent shares was
computed using the treasury stock method which assumes that the increase in the
number of shares is reduced by the number of shares which could have been
repurchased by the Company with proceeds from the exercise of options (which
were assumed to have been made at the average market price of the common shares
during the reporting period). Fully diluted earnings per share and provisions of
the newly issued accounting statement (SFAS 128) regarding earnings per share
are no different than primary earnings per share because of minimal stock
equivalents.
Use of Estimates -- The preparation of financial statements in conformity
with generally accepted accounting principles requires management to make
estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements and the reported amounts of revenues and expenses
during the reporting period. Actual results could differ from those estimates.
The Company's financial statements are based on a number of significant
estimates including oil and gas reserve quantities which are the basis for the
calculation of depreciation, depletion, amortization and impairment of oil and
gas properties. Management emphasizes that reserve estimates are inherently
imprecise.
The Company records certain utility assets and liabilities in accordance
with SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation."
If the Company were required, for any reason, to terminate application of SFAS
No. 71 for its regulated operations, all regulatory assets and liabilities would
be recognized in the income statement at that time. Such amounts are primarily
related to future amounts recoverable for income taxes (see Note 6).
Concentration of Credit Risk -- The Company maintains its cash accounts
primarily with a single bank and invests cash in money market accounts which the
Company believes to have minimal risk. As operator of jointly owned oil and gas
properties, the Company sells oil and gas production to numerous U.S. oil and
gas purchasers, and pays vendors on behalf of joint owners for oil and gas
services. Both purchasers and joint owners are located primarily in the
northeastern United States and California. The risk of nonpayment by the
purchasers or joint owners is considered minimal. The Company, as owner of a
utility, has receivables from both residential and commercial customers who are
located in West Virginia. The risk of significant nonpayment by the utility
customers is considered minimal.
Environmental Concerns -- The Company is continually taking actions it
believes necessary in its operations to ensure conformity with applicable
federal, state and local environmental regulations. As of March 31, 1997, the
Company has not been fined or cited for any environmental violations which would
have a material adverse effect upon capital expenditures, earnings or the
competitive position of the Company.
F-10
<PAGE> 133
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Supplemental Disclosures of Cash Flow Information -- Supplemental cash flow
information for the nine-month period ended March 31, 1997 and for the years
ended June 30, 1996 and 1995 is as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- ------
<S> <C> <C> <C>
Cash paid for:
Interest (net of capitalized interest of $270, $630
and $642 in 1997, 1996 and 1995,
respectively)................................... $13,208 $15,207 $7,861
Income taxes, net of amounts refunded.............. (1,600) 2,440 275
</TABLE>
3. ACQUISITIONS AND DISPOSITIONS
Allegheny & Western Energy Corporation -- On June 23, 1995, the Company
acquired 100% of the common stock of Allegheny & Western Energy Corporation
("A&W") and its wholly-owned subsidiary Mountaineer in a business combination
accounted for as a purchase effective June 30, 1995 with all operations
consolidated on a prospective basis. The business of A&W consisted of
Mountaineer, a regulated public gas utility, ownership interests in oil and gas
wells, undeveloped acreage, pipeline and gathering systems, well operating
rights, marketing company assets and certain other assets. The total purchase
price for this acquisition was approximately $95.3 million which was allocated
based on estimates of relative fair value as follows (in thousands):
<TABLE>
<S> <C>
Working capital............................................. $ 13,139
Property, plant, and equipment.............................. 160,921
Other noncurrent assets..................................... 19,147
Noncurrent liabilities assumed.............................. (97,862)
--------
Purchase of A&W............................................. 95,345
Less:
Accrual of acquisition costs.............................. (5,361)
Cash acquired............................................. (16,794)
========
Net cash used to acquire A&W................................ $ 73,190
========
</TABLE>
In connection with the acquisition, the Company recorded liabilities of
approximately $2.1 million primarily related to estimated payments associated
with disposing of certain nonessential net assets held for sale as well as
severance payments. Approximately $164,000 and $1.6 million was charged against
these liabilities in the nine months ended March 31, 1997 and in the year ended
June 30, 1996, respectively.
Eastern Producing Limited Partnership -- In November 1995, the Company sold
interests in certain producing natural gas properties for total cash
consideration of $17,360,000 realizing a gain on sale of $3,269,000. The Company
contributed its remaining interest in these properties in exchange for a general
partner interest in the partnership that acquired the properties, representing a
1% interest until "payout" (as defined in the purchase agreement), at which time
the Company's interest increases to 49%.
Westside Operating Partnerships L.P. -- In March 1997 the Company exchanged
warrants held representing a 30% ownership interest of a third party for a 30%
interest in a newly formed oil and gas limited liability company ("LLC"), the
successor to Westside Operating Partnership LP ("WOPLP") (owned 80% by the
Company). The LLC redeemed the Company's previous interest and purchased certain
oil and gas properties paying the Company $11,250,000 plus a $1,500,000 variable
rate note with certain conversion options and distributing certain WOPLP oil and
gas
F-11
<PAGE> 134
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
properties and real estate to the Company. The Company has recognized a gain of
$7,800,000 and its interest in LLC ($250,000) is included in other assets at
March 31, 1997.
4. RISK MANAGEMENT
Natural Gas Hedges -- The Company is a party to oil and natural gas swaps
in the normal course of business to reduce its exposure to fluctuations in the
price of oil and natural gas. These instruments involve, to varying degrees,
elements of market and credit risk in excess of the amount recognized in the
consolidated balance sheets.
As of March 31, 1997, the Company had natural gas swap agreements totalling
a notional quantity of approximately 16.7 MMBTU per day through October 31, 1997
and 2.7 MMBTU per day through October 31, 1998. At March 31, 1997, the market
value of these swaps is estimated to be a loss of $82,000, the net amount the
Company would have to pay to terminate the swap agreements.
For the nine months ended March 31, 1997, and the years ended June 30, 1996
and 1995 the Company recognized a net gain (loss) on its oil and natural gas
hedging activities of ($251,000), ($388,000), and $694,000, respectively.
Mountaineer is party to certain fixed price gas purchase options to
mitigate Mountaineer's exposure to fluctuations in gas prices. At March 31,
1997, the face amount of fixed price call options is $4,328,000 and have a fair
value of $4,314,000. Mountaineer accounts for the cost of the call options as
prepaid gas expense ($743,000 at March 31, 1997) that will be charged to cost of
gas when the call option is exercised and the gas is delivered or the option
expires.
Interest Rate Hedges -- Effective September 30, 1996, the Company entered
into an interest rate cap agreement and an interest rate collar agreement, for
purposes other than trading, to reduce the potential impact of changes in
interest rates on its floating rate long-term debt. Realized gains and losses on
the agreements are recognized in interest expense as settlement occurs.
Amortization of the cap premium is recognized in interest expense on a straight
line basis over the life of the cap. The interest rate cap and collar agreements
have a notional combined principal amount of $60 million and an estimated market
value, the payment the Company would receive to terminate these, of
approximately $13,000 as of March 31, 1997. There were no payments made or
received under these agreements for the nine months ended March 31, 1997.
For the years ended June 30, 1996 and 1995, the Company paid $359,875 and
$389,187, respectively on an interest rate swap that was in place during those
periods. The swap agreement expired on June 28, 1996.
F-12
<PAGE> 135
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
5. DEBT
Long-term debt -- At March 31, 1997 and June 30, 1996 long-term debt
consisted of the following (in thousands):
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
Credit agreements:
Eastern revolving credit facility......................... $136,648 $150,000
Westside revolving facility............................... 19,500
ESC senior secured note, interest at 10.75% payable
quarterly, due October 1, 2005............................ 35,000 35,000
Mountaineer unsecured senior notes, interest at 7.59%
payable semi-annually, due October 1, 2010................ 60,000 60,000
Installment notes payable, collateralized by deeds of trust,
at interest rates ranging from 7% to 8%, respectively..... 160 198
-------- --------
231,808 264,698
Less current portion........................................ (12,002) (10,051)
-------- --------
$219,806 $254,647
======== ========
</TABLE>
As of March 31, 1997, Eastern was a party to a revolving facility credit
agreement (the "Eastern Credit Agreement"), most recently amended on December 1,
1996, and provides for an aggregate maximum credit amount of $145,000,000 with a
borrowing base of $124,700,000. Beginning on September 30, 1998, the aggregate
maximum available borrowings will be reduced by $7,250,000 quarterly through
June 30, 2003, the expiration date of the Eastern Credit Agreement. The Company
may request up to three one-year extensions of the initial reduction date of
September 30, 1998. These extensions must be approved by the lenders at their
sole discretion. All outstanding borrowings under the Eastern Credit Agreement
are charged interest at the bank's base rate or LIBOR plus an applicable margin
as determined by a Usage Ratio, as defined in the Eastern Credit Agreement, and
the total of outstanding borrowings and letters of credit at that time. The
applicable margin for base rate loans ranges from .75% to 1.00% and for LIBOR
loans from 1.75% to 2.25%. The Company is required to pay a commitment fee
annually of .5% of unused available borrowings under the Eastern Credit
Agreement. Indebtedness under the Eastern Credit Agreement is collateralized by
substantially all of Eastern's assets.
At June 30, 1996, Westside, as a result of consolidating its previous 80%
interest in WOPLP, had a revolving credit facility agreement dated April 28,
1995, most recently amended June 11, 1996. Under terms of the agreement, the
partnership could borrow up to $40,000,000 through December 31, 1997, or if
extended, through December 31, 2001. The borrowing rate until maturity was based
on 1.5% to 2% over the LIBOR interest rate of up to .5% over the bank's prime
interest rate, depending on the method of borrowing funds under the agreement.
At June 30, 1995, ESC had a $35 million revolving facility credit
agreement. Borrowings under this agreement were used in the acquisition of A&W
(Note 3) and were due June 30, 1996. In October 1995, ESC paid off the agreement
and replaced it with a $35 million, 10.75% senior secured note payable (as
amended in April 1997) to a financial institution which is due October 1, 2005.
Effective July 1, 1997 interest payments are due quarterly. ESC has pledged the
stock of Mountaineer as collateral under the secured note.
F-13
<PAGE> 136
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company's various debt agreements contain certain restrictions and
conditions among which are limitations on indebtedness, funding of certain
subsidiaries, dividends and investments, and certain tangible net worth and debt
and interest coverage ratio requirements.
The scheduled maturities of the Company's long-term debt, at March 31, 1997
for each of the next five years and thereafter are as follows (in thousands):
<TABLE>
<CAPTION>
MARCH 31,
---------
<S> <C>
1998....................................................... $ 12,002
1999....................................................... 21,800
2000....................................................... 29,048
2001....................................................... 29,008
2002....................................................... 29,000
Thereafter................................................. 110,950
--------
$231,808
========
</TABLE>
Short-Term Debt -- Mountaineer had unsecured bank lines of credit totaling
$71 million and $70 million as of March 31, 1997 and June 30, 1996. During the
nine-month period ended March 31, 1997 and the year ended June 30, 1996, the
maximum outstanding balance was $45,064,000 and $58,064,900, respectively, and
the average daily balance was $30,309,063 and $18,176,445, respectively. The
weighted average interest rate was 6.0% and 6.3% on the balance outstanding
during the nine-month period ended March 31, 1997 and the year ended June 30,
1996, respectively. The outstanding borrowings on these lines of credit as of
March 31, 1997 and June 30, 1996 were $26,613,900 and $8,392,000, respectively.
Letter of Credit -- Eastern has outstanding a $12.0 million letter of
credit issued by a bank in support of Eastern's obligations under a gas purchase
contract with the Royalty Trust (see Note 14). The letter of credit reduces by
$3 million on June 30 of each year until its expiration on June 30, 2000. As of
March 31, 1997, no draws have been made under the Letter of Credit. The letter
of credit agreement between Eastern and the bank requires Eastern to maintain
certain financial conditions, including a minimum net worth and interest
coverage ratio.
6. INCOME TAXES
The following table details the components of the Company's provision
(benefit) for income taxes for the nine-month period ended March 31, 1997 and
the years ended June 30, 1996 and 1995 (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------ ------ ------
<S> <C> <C> <C>
Current:
Federal.............................................. $2,292 $1,278 $ (727)
State................................................ 569 478
------ ------ ------
Total current................................ 2,861 1,756 (727)
------ ------ ------
Deferred:
Federal.............................................. 1,280 (159) 3,111
State................................................ 819 1,677 326
------ ------ ------
Total deferred............................... 2,099 1,518 3,437
------ ------ ------
Total provision for income taxes............. $4,960 $3,274 $2,710
====== ====== ======
</TABLE>
F-14
<PAGE> 137
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the provision for income taxes computed at the
statutory rate to the provision for income taxes as shown in the consolidated
statements of income for the nine-month period ended March 31, 1997 and for the
years ended June 30, 1996 and 1995 is summarized below (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- ------
<S> <C> <C> <C>
Tax expense at the federal statutory rate............ $ 5,962 $ 4,448 $2,288
State taxes net of federal benefit................... 1,062 806 421
Percentage depletion................................. (228)
Section 29 tax credits............................... (2,390) (1,129)
Increase (decrease) in valuation allowance on state
deferred tax asset, net of federal benefit......... (369) 1,161
Change in estimate................................... (1,178)
Other, net........................................... 695 (834) 229
------- ------- ------
Provision for income taxes........................... $ 4,960 $ 3,274 $2,710
======= ======= ======
</TABLE>
In 1995, the Company estimated that it would carry back its 1995 tax loss
and realize the tax benefit based on the alternative minimum tax rate. During
fiscal year 1996, management decided to carry forward this loss, at regular tax
rates, which generated a $1.2 million tax benefit in 1996.
Components of the Company's federal and state deferred tax assets and
liabilities, as of March 31, 1997 and June 30, 1996 are as follows (in
thousands):
<TABLE>
<CAPTION>
1997 1996
---------------------------- ----------------------------
FEDERAL STATE TOTAL FEDERAL STATE TOTAL
-------- -------- ------ -------- -------- ------
<S> <C> <C> <C> <C> <C> <C>
Deferred tax assets:
Overrecovered gas costs.............. $ 4,005 $ 737 $ 4,005 $ 707
Bad debt allowance................... 499 92 660 118
Deferred compensation and profit
sharing............................ 1,555 286 1,491 267
Other postretirement benefit and
pension obligation................. 2,901 534 2,773 489
Tax credits, federal................. 13,555 12,899
Tax credit and carryforwards,
state.............................. 12,910 15,238
Other long-term obligations.......... 1,177 217 1,272 234
Other................................ 41 8 1,048 416
-------- -------- -------- --------
Total deferred tax assets..... 23,733 14,784 24,148 17,469
-------- -------- -------- --------
Deferred tax liabilities:
Property, plant and equipment........ (53,619) (9,981) (51,905) (9,789)
Federal income tax on state tax
credits............................ (3,184) (5,384)
Other liabilities.................... (1,779) (328) (434) (345)
-------- -------- -------- --------
Total deferred tax
liabilities................. (58,582) (10,309) (57,723) (10,134)
-------- -------- -------- --------
Valuation allowance.................... (2,397) (4,432)
-------- -------- -------- --------
Net deferred income tax asset
(liability).......................... (34,849) 2,078 (33,575) 2,903
-------- -------- -------- --------
Less current deferred tax asset........ 4,639 960 $5,599 4,791 1,546 $6,337
-------- -------- ====== -------- -------- ======
Long-term deferred tax asset
(liability).......................... $(39,488) $ 1,118 $(38,366) $ 1,357
======== ======== ======== ========
</TABLE>
F-15
<PAGE> 138
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At March 31, 1997, the Company has the following federal and state tax
credits and carryforwards (in thousands):
<TABLE>
<CAPTION>
YEAR OF
TAX CREDITS OR CARRYFORWARDS AMOUNT EXPIRATION
---------------------------- ------- ----------
<S> <C> <C>
AMT tax credits............................................ $11,817 None
Investment tax credits..................................... 1,738 1997-2001
-------
Total federal credits...................................... $13,555
=======
West Virginia tax credits, net............................. $11,762 1997-2002
West Virginia net operating loss carryforwards............. 1,058 2010
-------
Total state credits and carryforwards...................... $12,820
=======
</TABLE>
The Company is eligible for relocation incentives taken in the form of tax
credits from West Virginia. The incentive amounts are based upon investments
made and jobs created in that state. Tax credits generated by the Company are
used primarily to offset the payment of severance, property and state income
taxes. In connection with the adoption of SFAS No. 109, the Company recorded the
benefits of existing West Virginia state tax credits as a state deferred tax
asset.
Based on certain tax planning strategies, which include the utilization of
the credit against taxes payable by subsidiaries, and projections of future West
Virginia severance, property and state income taxes, management believes that it
is more likely than not these credits are realizable in the carryforward period.
The amount of deferred tax asset considered realizable, however, could be
reduced in the near term if future taxable income is reduced.
Included in other long-term assets as of March 31, 1997 and June 30, 1996,
is a $11.3 million and $10.6 million, respectively, net regulatory asset
recorded by Mountaineer in accordance with state utility ratemaking practices
related to future amounts recoverable for income taxes.
7. EMPLOYEE BENEFIT PLANS
The Company and certain operating subsidiaries, have a Profit
Sharing/Incentive Stock Plan (the "Plan") for the stated purpose of expanding
and improving profits and prosperity and to assist the Company in attracting and
retaining key personnel. The Plan is noncontributory, and its continuance from
year to year is at the discretion of the Board of Directors. The annual profit
sharing pool is based on calculations set forth in the Plan. One-half of the
pool is generally paid to eligible employees within 120 days of the end of the
fiscal year and one-half is deferred to the following year. Generally, to be
eligible to participate, an employee must have been continuously employed for
two or more years, however employees with less than two years of employment may
participate under certain circumstances. Additionally, Eastern participants may
elect to receive their profit sharing award in the form of nonvoting and
nontransferable common stock of Eastern, subject to the applicable terms and
conditions of the Plan document. The Company recognized $200,000 in the nine
month period ended March 31, 1997 and $3.1 million of expense during the year
ended June 30, 1996. No expense was recognized in the year ended June 30, 1995.
For certain subsidiaries, the Company sponsors a Section 401(k) plan
covering all full-time employees who wish to participate. The Company's
contributions, which are principally based on a percentage of the employee
contributions, are charged against income as incurred, totaled $101,859 for the
nine-month period ended March 31, 1997 and $144,530 and $149,691 for the years
ended June 30, 1996 and 1995, respectively.
F-16
<PAGE> 139
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
8. PENSION PLAN
Mountaineer sponsors a Retirement Income Plan (the "Pension Plan") which
covers substantially all qualified Mountaineer employees 21 years of age and
over. Employees become fully vested upon completion of five years of credited
service, as defined in the Pension Plan. Retirement income is based on credited
years of service and the employees' level of compensation, as defined in the
Pension Plan. The Pension Plan is subject to the provisions of the Employee
Retirement Income Security Act of 1974 ("ERISA"). The determination of
contributions is made in consultation with the Pension Plan's actuary and is
based upon anticipated earnings of the Pension Plan, mortality and turnover
experience, the funded status of the Pension Plan and anticipated future
compensation levels. Mountaineer's funding policy is to be in compliance with
ERISA guidelines and to make annual contributions to the Pension Plan to assure
that all employees' benefits will be fully provided for by the time they retire.
The following table sets forth the Pension Plan's funded status and amounts
recognized in the consolidated balance sheets at the dates shown, as determined
by an independent actuary (in thousands):
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits
of $25,348 and $25,198 at March 31, 1997 and June 30,
1996, respectively.................................... $(27,120) $(27,120)
======== ========
Projected benefit obligations for service rendered to
date..................................................... $(29,489) $(30,507)
Plan assets at fair value.................................. 23,389 23,152
-------- --------
Projected benefit obligation in excess of plan assets...... (6,100) (7,355)
Unrecognized net loss from past experience................. 1,112 2,444
-------- --------
Accrued pension cost (included in other long-term
obligations)............................................. $ (4,988) $ (4,911)
======== ========
</TABLE>
Net pension cost for the nine month period ended March 31, 1997 and the
year ended June 30, 1996 as determined by an independent actuary, included the
following components (in thousands):
<TABLE>
<CAPTION>
1997 1996
------- -------
<S> <C> <C>
Service cost................................................ $ 442 $ 638
Interest cost............................................... 1,654 2,083
Actual return on plan assets................................ (1,602) (2,147)
Net amortization and deferral............................... 260 366
------- -------
Net periodic pension cost................................... 754 940
Amount capitalized as construction cost and charged to
others.................................................... (125) (173)
------- -------
Amount charged to expense................................... $ 629 $ 767
======= =======
</TABLE>
The expected long-term rate of return used in the calculation was 8.0% for
the nine month period ended March 31, 1997 and 8.25% for the year ended June 30,
1996. The weighted average discount rate used in the calculations was 7.75% for
the nine month period ended March 31, 1997 and for the year ended June 30, 1996.
The expected average increase in future compensation levels
F-17
<PAGE> 140
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was 4.0% for the nine month period ended March 31, 1997 and 4.5% for the year
ended June 30, 1996.
9. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
Mountaineer provides certain medical and life insurance benefits for
retired employees. Substantially all of Mountaineer's employees may become
eligible for these benefits if they choose to retire after reaching age 55 while
working for Mountaineer and are provided until age 65. Life insurance benefits
of approximately two times annual salary are provided while an employee is
active and working at Mountaineer. On the date of an employee's retirement and
on the date the employee reaches age 70, life insurance benefits decrease to
approximately 80% and 40% of annual salary, respectively. These benefits are
provided to retirees who meet the service requirements of 10 continuous years of
service prior to retirement at age 55 or 5 continuous years of service prior to
retirement at age 65. The plan is unfunded.
The following table sets forth the postretirement medical and life
insurance plans' funded status and amounts recognized in the consolidated
balance sheets, as determined by an independent actuary (in thousands):
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees.................................................. $3,747 $3,198
Fully eligible active participants........................ 1,526 1,952
Other active employees.................................... 1,665 1,640
------ ------
Total accumulated postretirement benefit obligation......... 6,938 6,790
Unrecognized actuarial gain................................. 265 274
------ ------
Accrued postretirement benefit liability (included in other
long-term liabilities).................................... $7,203 $7,064
====== ======
</TABLE>
Net periodic postretirement benefit cost for the nine month period ended
March 31, 1997 and for the year ended June 30, 1996, as determined by an
independent actuary, included the following components (in thousands):
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
Service cost-benefits attributable to service during the
period.................................................... $ 282 $ 362
Interest cost on the accumulated postretirement benefit
obligation................................................ 375 514
----- -----
Net periodic postretirement benefit cost.................... 657 876
Amount capitalized as construction cost..................... (121) (220)
----- -----
Amount charged to expense................................... $ 536 $ 656
===== =====
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 9.5% in the nine month period ended March
31, 1997 and 10.0% in the year ended June 30, 1996, declining gradually to 5.5%
in 2005 and remaining at that level thereafter. The health care cost trend rate
assumption has a significant effect on the amounts reported. A one percentage
point increase in the assumed health care cost trend rate would increase the
aggregate service and interest cost by $39,240 for the nine month period ended
March 31, 1997 and accumulated postretirement benefit obligation as of March 31,
1997 by $231,731. The weighted average discount rate used in determining the
accumulated postretirement benefit obligation was
F-18
<PAGE> 141
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
7.75% in the nine month period ended March 31, 1997 and for the year ended June
30, 1996. The average assumed annual rate of salary increase for the life
insurance benefit plan was 4.0% in 1997 and 5.0% in 1996.
As a part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled
that the permitted rate recovery mechanism for other post retirement benefits
would be a modified accrual method. The modified accrual method allows for the
recovery of current services costs on an accrual basis and recovery of the
transition obligation on a cash basis.
10. COMMON STOCK
Voting Common Stock -- In May 1995, the Company was reincorporated in the
State of West Virginia. As part of this reincorporation, each outstanding share
of then existing no-par value common stock was converted automatically to one
share of $1 par value common stock.
The Company has an agreement with a stockholder covering the sale or
disposition of stock that provides the stockholder cannot sell stock without
first offering such shares to the Company. Under certain circumstances, the
Company would be required to purchase the related stock if not previously
tendered to the Company or otherwise sold or disposed of in accordance with the
provisions of the agreement.
Treasury Stock -- The Company has 40,188 and 20,438 shares of treasury
stock, which are carried at cost, at March 31, 1997 and June 30, 1996,
respectively.
Stock Options -- In 1994, the Company created an incentive stock option
plan (the "Stock Option Plan"). Under the Stock Option Plan, options vest
annually in 25% increments from January 1, 1994 to December 31, 1997, and are
exercisable at $40 per share. However, if any of the optionees' employment with
the Company is terminated within four years, the optionee must resell any
exercised options back to the Company at $40 per share.
A summary of the Company's Option Plan as of March 31, 1997, June 30, 1996
and June 30, 1995, and the changes during the periods then ended is presented
below:
<TABLE>
<CAPTION>
1997 1996 1995
----------------- ----------------- -----------------
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
------ -------- ------ -------- ------ --------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of year........... 6,400 $40.00 9,600 $40.00 12,800 $40.00
Exercised.................................. 3,200 40.00 3,200 40.00 3,200 40.00
----- ------ ----- ------ ------ ------
Outstanding at end of year................. 3,200 $40.00 6,400 $40.00 9,600 $40.00
===== ====== ===== ====== ====== ======
Options exercisable at year end............ 3,200 3,200 3,200
===== ===== ======
</TABLE>
The option exercises above were paid for in the form of notes which have
been charged against equity until collected.
F-19
<PAGE> 142
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
11. UNCONSOLIDATED AFFILIATE
The Company's investment in LLC at March 31, 1997 (previously consolidated)
is accounted for under the equity method (see Note 3). Summarized financial
information for the LLC at March 31, 1997 is as follows (in thousands):
<TABLE>
<S> <C> <C> <C>
Current assets.................... $ 3,024 Long-term debt.................... $19,700
Oil and gas properties............ 20,703 Other liabilities................. 2,363
Other assets...................... 1,462 Equity............................ 3,126
------- -------
Total assets............ $25,189 Total liabilities and equity...... $25,189
======= =======
</TABLE>
12. OPERATING LEASES
The Company has noncancelable operating lease agreements for the rental of
office space, computer and other equipment. Certain of these leases contain
purchase options or renewal clauses. Rental expense for operating leases was
approximately $931,000, $1.2 million and $1.4 million for the nine-month period
ended March 31, 1997 and for the years ended June 30, 1996 and 1995,
respectively.
At March 31, 1997 future minimum lease payments for each of the next five
years ending March 31 and thereafter are as follows (in thousands):
<TABLE>
<S> <C>
1998........................................................ $1,073
1999........................................................ 888
2000........................................................ 876
2001........................................................ 844
2002........................................................ 713
Thereafter.................................................. 975
------
$5,369
======
</TABLE>
13. RELATED PARTY TRANSACTIONS
Certain officers, directors, employees and affiliates regularly participate
in Company-sponsored drilling programs on a cost basis for which the Company
advances funds on behalf of these participants. Notes receivable at March 31,
1997 and June 30, 1996 in connection with these programs total $944,000 and $1
million, respectively.
Eastern has entered into a rental arrangement for the building used as its
headquarters from a partnership in which certain officers are partners. Rent
payments totaled approximately $250,000 for the nine-month period ended March
31, 1997 and $300,000 and $415,000 for the years ended June 30, 1996 and 1995,
respectively.
Mountaineer purchases a portion of its gas supply requirements from its
subsidiary and Eastern. The price paid for such purchases has been approved by
the WVPSC. During 1997 and 1996, Mountaineer purchased approximately $3,936,000
and $5,342,000, respectively, from its subsidiary and $14,628,000 and
$15,258,000, respectively from Eastern. The related revenues and expenses
between Mountaineer and its subsidiary and Eastern have not been eliminated in
these financial statements due to the regulated nature of Mountaineer. At March
31, 1997, Mountaineer has $22,429,000 of outstanding gas purchase commitments
with Eastern.
F-20
<PAGE> 143
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company advanced funds to certain officers in 1991 and 1994, which bear
interest at 8% and are secured by non-voting common shares of Eastern. Balances
totaled $570,000 at March 31, 1997 and June 30, 1996 and are due in 2001.
The Company also advanced funds in 1988 to certain officers and directors
which bear interest at 8%, are secured by interests in oil and gas properties
and are repayable out of net proceeds from the oil and gas production on these
properties. Balances outstanding at March 31, 1997 and June 30, 1996 totalled
$898,000 and $1,012,000, respectively.
14. COMMITMENTS AND CONTINGENCIES
In 1992, Eastern entered into a 15-year gas sale and purchase agreement
with an independent power project whereby Eastern will deliver approximately
12,000 MCF per day to the project at a fixed price per MCF. The terms of the
agreement provide for annual price escalations.
In 1993, the Company sold working interests in certain Appalachian gas
properties in connection with the formation of a royalty trust (the "Trust"). A
portion of the proceeds from the sale of these interests, representing a term
net profits interest, was accounted for as a production payment. As a result, at
March 31, 1997 and June 30, 1996, such proceeds totaling $15,565,412 and
$17,243,931, respectively, have been classified as deferred trust revenue.
Certain gas production attributable to the Trust is purchased by a
wholly-owned subsidiary of the Company pursuant to a gas purchase contract which
expires in 2013. The purchase price under the contract is based on escalating
fixed price and spot market components. To hedge the Company's position on this
contract, the Company dedicated the fixed price sales contract with the
independent power project discussed above, which has similar prices and volumes
as the fixed price component of the contract, and purchased a floor price
futures contract to cover the variable component. The fixed price component
expires on January 1, 2000. The obligation of the subsidiary to make payments
under the contract is partially supported by a standby letter of credit with a
face amount of $12,000,000. The letter of credit is subject to annual reductions
of $3,000,000 beginning June 30, 1996, and fully expires on June 30, 2000.
The Company has entered into an agreement whereby it will fund a specified
monthly amount, through December 31, 1996, to assist in the development of oil
and gas projects by a third party. No remaining commitment exists as of March
31, 1997 and as of June 30, 1996, the remaining commitment was $450,000. Amounts
funded are accounted for as an advance and all outstanding amounts are due on
January 1, 1999. As of March 31, 1997 and June 30, 1996, the Company has $2.5
million and $2.4 million, respectively, in long-term notes receivable relating
to this agreement. In addition to the commitment, the Company has certain other
rights and options regarding the acquisition, exploration and development of the
oil and gas projects that may be acquired as a result of this agreement.
In connection with an existing gas delivery obligation agreement, whereby
Eastern received an advance payment, its subsidiary entered into a credit line
deed of trust which has an available balance of $11 million as of March 31, 1997
and June 30, 1996 to collateralize the performance under the gas delivery
obligation. This credit line deed of trust declines at a rate of 7.5% per year.
FERC Matters -- On November 22, 1996, Mountaineer entered into a settlement
agreement with Columbia Gas and other Columbia Gas customers in a rate
proceeding initiated by Columbia Gas in 1995. Among the material provisions of
the settlement affecting Mountaineer include (i) the receipt by Mountaineer of
approximately $7.1 million annually, through 2004, in demand charge credits, and
(ii) a rate moratorium on Columbia Gas until the year 2000. On April 17, 1997
the FERC approved the settlement agreement. As of March 31, 1997, Mountaineer is
due refunds under the settlement
F-21
<PAGE> 144
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
agreement of $6 million including zone credits earned and transportation charges
paid in excess of settled rates. As a result of the previous settlement and FERC
order, Mountaineer recorded a receivable and associated reduction in gas costs
of $6 million for the nine months ended March 31, 1997.
Legal Matters -- The Company is involved in various legal actions and
claims arising in the ordinary course of business. In addition, Columbia Gas
filed a suit in March 1997 against Eastern alleging that Eastern's wells are
producing storage gas from a Columbia Gas storage field in West Virginia.
Columbia Gas estimates its alleged damages to be in excess of $5 million.
Eastern purchased the wells in question from Great Western Onshore Inc. and
Great Western Drilling Inc. (collectively "Great Western") pursuant to an Asset
Purchase and Sale Agreement dated January 28, 1992. Pursuant to the terms of the
Asset Purchase and Sale Agreement, Eastern believes that it is entitled to
indemnification from Forcenergy, Inc., successor in interest to Great Western as
a result of Forcenergy's breach of certain representations and warranties
contained therein. While the outcome of this lawsuit and other proceedings
against the Company cannot be predicted with certainty, management does not
expect these matters to have a material adverse effect on the Company's
financial position.
15. FINANCIAL INSTRUMENTS
The estimated fair values of the Company's financial instruments have been
determined using appropriate market information and valuation methodologies.
Considerable judgment is required to develop the estimates of fair value; thus,
the estimates provided below are not necessarily indicative of the amount that
the Company could realize upon the sale or refinancing of such financial
instruments (in thousands):
<TABLE>
<CAPTION>
MARCH 31, 1997 JUNE 30, 1996
------------------ ------------------
CARRYING FAIR CARRYING FAIR
VALUE VALUE VALUE VALUE
-------- ------- -------- -------
<S> <C> <C> <C> <C>
Assets:
Cash and cash equivalents.................. $ 14,331 $14,331 $ 14,197 $14,197
Accounts receivable........................ 66,730 66,730 43,802 43,802
Notes receivable........................... 7,328 5,634 5,803 4,012
Liabilities:
Accounts payable and accrued expenses...... 34,947 34,947 39,798 39,798
Current portion of long-term debt.......... 12,002 12,002 10,051 10,051
Short-term debt............................ 26,614 26,614 8,392 8,392
Long-term debt............................. 219,806 224,718 254,647 261,196
Other long-term obligations................ 14,118 14,118 14,849 14,849
Interest rate hedge contracts.............. 13 13
Oil and gas hedge contracts................ 96 455
</TABLE>
The following methods and assumptions were used by the Company in
estimating the fair value of its financial instruments:
Cash and Cash Equivalents, Accounts Receivable and Accounts Payable and
Accrued Expenses -- Due to the short-term nature of these instruments, the
carrying value approximates the fair value.
Notes Receivable -- The notes receivable accrue interest at a fixed rate.
Fair value was estimated using discounted cash flows based on current interest
rates for notes with similar maturities.
F-22
<PAGE> 145
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Short-Term Debt and Line of Credit -- The short-term debt is borrowed on a
revolving basis at a variable interest rate; as a result, the carrying value
approximates the fair value of the outstanding debt. Due to the short-term
nature of the line of credit, the carrying value approximates the fair value of
the outstanding debt.
Long-Term Debt -- A portion of long-term debt was borrowed under a
revolving credit facility which accrues interest at variable rates; as a result,
carrying value approximates fair value. The remaining portion of the Company's
long-term debt is comprised of fixed rate facilities; for this portion, fair
value was estimated using discounted cash flows based upon the Company's current
borrowing rates for debt with similar maturities.
Other Long-Term Obligations -- The other long-term obligations were
borrowed under agreements which accrue interest at variable rates; as a result,
carrying value approximates fair value.
16. CONTRACT SETTLEMENT
In 1991, Columbia Transmission and Columbia Gas Systems, Inc. ("Columbia")
filed for protection under Chapter 11 of the Bankruptcy Code. The settlement
relates to damages paid by Columbia Gas as a result of its rejection in
bankruptcy of certain gas purchase contracts. As part of Columbia's amended plan
of reorganization, the Company has recorded revenue of $8.8 million in 1995.
17. RATE MATTERS
In June 1995, Mountaineer agreed to a Joint Stipulation and Agreement for
Settlement (the "Agreement") with various parties, regarding a January 1995 base
rate filing, as well as Mountaineer's upcoming PGA filing and a tariff filing
concerning primarily telemetering requirements for transportation customers. The
Agreement allowed for a $4 million increase in base rates, with the portion of
the increase allocable to sales customers to be offset by the amortization of
the PGA overrecovered balance existing as of October 31, 1995 over a three-year
moratorium period beginning November 1, 1995. A final order was issued on
January 10, 1996.
The Agreement stipulates that during the three-year moratorium,
Mountaineer's annual PGA filing with the WVPSC will be temporarily suspended and
the deferred accounting for purchased gas costs will not be in effect. During
this period Mountaineer can utilize its expertise in entering into gas supply
and service contracts benefiting from its successes while assuming the risks and
costs of its actions. Consequently, Mountaineer has assumed the risk of any
changes in interstate pipeline rates and charges during the moratorium period.
It is the intent of the Agreement that Mountaineer be permitted to keep the
benefit of, and absorb the costs of, its decisions during the moratorium period
without review of its actions. The parties believe the Agreement provides
benefits for both Mountaineer and its customers and is in the public's best
interest. Mountaineer expects that natural gas distribution operations will
continue to be regulated following the moratorium period in a manner which will
allow Mountaineer to recover its costs of operations and earn a reasonable
return on its equity.
F-23
<PAGE> 146
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
18. INDUSTRY SEGMENTS
The following table sets forth the Company's principal industry segments
and their contributions to its revenues, operating profits, capital expenditures
and depletion, depreciation and amortization for the periods. Also shown are the
identifiable assets associated with each segment as of the end of each period
indicated:
<TABLE>
<CAPTION>
NINE-MONTHS ENDED MARCH 31, 1997
------------------------------------------------------
REGULATED ADJUSTMENTS
OIL AND GAS UTILITY AND
OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
----------- ---------- ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Sales to unaffiliated customers..... $139,624 $146,965 $286,589
Intersegment........................ 18,564 18,564
-------- -------- ----- --------
Total revenue....................... 158,188 146,965 305,153
-------- -------- ----- --------
Operating profit.................... 7,786 18,536 $(540) 25,782
Other income (expense).............. (1,101) (7,687) 540 (8,248)
-------- -------- ----- --------
Income before income taxes.......... 6,685 10,849 17,534
======== ======== ===== ========
Depletion, depreciation and
amortization (including reduction
in the carrying amount of oil and
gas properties)................... 8,978 6,002 14,980
Capital expenditures................ 13,862 7,693 21,555
-------- -------- ----- --------
Identifiable assets................. 204,608 216,861 421,469
Corporate assets.................... 14,350 18,627 32,977
-------- -------- ----- --------
Total assets........................ $218,958 $235,488 $454,446
======== ======== ===== ========
</TABLE>
<TABLE>
<CAPTION>
YEAR ENDED JUNE 30, 1996
------------------------------------------------------
REGULATED ADJUSTMENTS
OIL AND GAS UTILITY AND
OPERATIONS OPERATIONS ELIMINATIONS CONSOLIDATED
----------- ---------- ------------ ------------
(IN THOUSANDS)
<S> <C> <C> <C> <C>
Sales to unaffiliated customers..... $172,265 $182,929 $355,194
Intersegment........................ 20,600 20,600
-------- -------- -------- --------
Total revenue....................... 192,865 182,929 375,794
Operating profit.................... 4,805 26,423 31,228
Other income (expense).............. (8,957) (10,984) (19,941)
Income (loss) before income taxes... (4,152) 15,439 11,287
Depletion, depreciation and
amortization including reduction
in the carrying amount of oil and
gas properties)................... 12,053 6,764 18,817
Capital expenditures................ 25,968 13,477 39,445
Identifiable assets................. 236,367 194,565 430,932
Corporate assets.................... 14,219 16,353 30,572
-------- -------- -------- --------
Total assets........................ $250,586 $210,918 $461,504
======== ======== ======== ========
</TABLE>
The Company operates in two industry segments, oil and gas operations
including exploration and development, production, aggregation and marketing of
Company owned as well as third party
F-24
<PAGE> 147
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
oil and gas. In addition, the Company operates a regulated local gas
distribution company. Operating profit represents revenues less costs which are
directly associated with such operations. Revenues are priced and accounted for
consistently for both unaffiliated and intersegment sales. Intersegment sales
have not been eliminated in consolidation because of the regulated nature of the
gas distribution segment.
Identifiable assets by industry segment are those assets that are used in
the Company's operations in each segment. Corporate assets are primarily cash,
cash equivalents and deferred charges.
19. SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
(UNAUDITED)
Costs -- The following tables set forth capitalized costs at March 31, 1997
and June 30, 1996, and costs incurred, including capitalized overhead, for oil
and gas producing activities for the nine-month period ended March 31, 1997 and
for the years ended June 30, 1996 and 1995 (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- -------
<S> <C> <C> <C>
Capitalized costs:
Proved properties............................... $195,732 $211,309
Unproved properties............................. 8,476 8,209
-------- --------
Total........................................... 204,208 219,518
Less accumulated depletion...................... (54,839) (52,186)
-------- --------
Net capitalized costs........................... $149,369 $167,332
======== ========
Costs incurred:
Acquisition of properties:
Proved.......................................... $ 0 $ 4,318 $14,190
Development costs............................... 9,684 13,470 14,345
Exploration costs............................... 3,703 6,141 2,240
-------- -------- -------
Total costs incurred............................ $ 13,387 $ 23,929 $30,775
======== ======== =======
</TABLE>
Results of Operations -- The results of operations for oil and gas
producing activities, excluding corporate overhead and interest costs for the
nine-month period ended March 31, 1997 and for the years ended June 30, 1996 and
1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
------- ------- -------
<S> <C> <C> <C>
Revenues from sale of oil and gas:
Sales.......................................... $27,002 $31,940 $29,277
Production costs.................................... 4,462 7,793 7,555
Production taxes.................................... 1,417 1,407 1,560
Exploration and impairment.......................... 3,613 6,756 281
Depreciation, depletion and amortization............ 6,509 9,204 9,763
Other............................................... 339 193 435
Income tax expense.................................. 2,665 1,647 2,421
------- ------- -------
Results of operations............................... $ 7,997 $ 4,940 $ 7,262
======= ======= =======
</TABLE>
Production costs include those costs incurred to operate and maintain
productive wells and related equipment and include costs such as labor, repairs
and maintenance, materials, supplies,
F-25
<PAGE> 148
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
fuel consumed, insurance and production taxes. In addition, production costs are
net of well tending fees which are included in well operations revenues in the
accompanying consolidated income statements.
Exploration and impairment expense include the costs of geological and
geophysical activity, unsuccessful exploratory wells and leasehold impairment
allowances.
Depletion, depreciation and amortization include costs associated with
capitalized acquisition, exploration, and development costs, but does not
include depreciation applicable to support equipment.
The provision for income taxes is computed at the statutory federal income
tax rate and is reduced to the extent of permanent differences which have been
recognized in the Company's tax provision, such as investment tax credits,
statutory depletion allowed for income tax purposes and the utilization of
Federal tax credits permitted for fuel produced from a non-conventional source.
Reserve Quantity Information -- Reserve estimates are subject to numerous
uncertainties inherent in the estimation of quantities of proved reserves and in
the projection of future rates of production and the timing of development
expenditures. The accuracy of such estimates is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Results of subsequent drilling, testing and production may cause either upward
or downward revisions of previous estimates. Further, the volumes considered to
be commercially recoverable fluctuate with changes in prices and operating
costs. Reserve estimates, by their nature, are generally less precise than other
financial statement disclosures.
F-26
<PAGE> 149
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The following table sets forth information for the nine-month period ended
March 31, 1997 and for the years ended June 30, 1996 and 1995 with respect to
changes in the Company's proved reserves, all of which are in the United States.
The Company has no significant undeveloped reserves.
<TABLE>
<CAPTION>
NATURAL
GAS CRUDE OIL
(MMCF) (MBBLS)
------- ---------
<S> <C> <C>
PROVED RESERVES:
June 30, 1994........................................ 170,311 7,003
Revisions of previous estimates...................... (23,726) (429)
Extensions and discoveries........................... 4,908 974
Purchases of reserves in place....................... 29,309 7
Production........................................... (8,984) (535)
------- ------
June 30, 1995........................................ 171,818 7,020
Revisions of previous estimates...................... 3,693 170
Purchases of reserves in place....................... 7,500
Extensions and discoveries........................... 5,950
Sales of reserves in place........................... (19,700)
Production........................................... (9,812) (522)
------- ------
June 30, 1996........................................ 159,449 6,668
Revision of previous estimates....................... (3,146) (268)
Extensions and discoveries........................... 19,000 598
Sales of reserves in place(1)........................ (3,614) (5,181)
Production........................................... (7,115) (426)
------- ------
March 31, 1997....................................... 164,574 1,391
======= ======
PROVED DEVELOPED:
June 30, 1995........................................ 167,428 6,886
======= ======
June 30, 1996........................................ 153,232 6,668
======= ======
March 31, 1997....................................... 148,358 1,146
======= ======
</TABLE>
- ---------------
(1) Includes 1,084 MMcf of proved gas reserves and 1,554 MBbls of proved crude
oil reserves otherwise retained as a result of the Company's 30% equity
investment in LLC.
Standardized Measure of Discounted Future Net Cash Flows -- Estimated
discounted future net cash flows and changes therein were determined in
accordance with SFAS No. 69, "Disclosures About Oil and Gas Producing
Activities." Certain information concerning the assumptions used in computing
the valuation of proved reserves and their inherent limitations are discussed
below. The Company believes such information is essential for a proper
understanding and assessment of the data presented.
Future cash inflows are computed by applying period-end prices of oil and
gas relating to the Company's proved reserves to the period-end quantities of
those reserves. Future price changes are considered only to the extent provided
by contractual arrangements, including futures contracts, in existence at
period-end.
The assumptions used to compute estimated future net revenues do not
necessarily reflect the Company's expectations of actual revenues or costs, nor
their present worth. In addition, variations from the expected production rates
also could result directly or indirectly from factors outside of the
F-27
<PAGE> 150
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company's control, such as unintentional delays in development, changes in
prices or regulatory controls. The reserve valuation further assumes that all
reserves will be disposed of by production. However, if reserves are sold in
place, additional economic considerations could also affect the amount of cash
eventually realized.
Future development and production costs are computed by estimating the
expenditures to be incurred in developing and producing the proved oil and gas
reserves at the end of year, based on period-end costs and assuming continuation
of existing economic conditions.
Future income tax expenses are computed by applying the appropriate
year-end statutory tax rates, with consideration of future tax rates already
legislated, to the future pretax net cash flows relating to the Company's proved
oil and gas reserves.
An annual discount rate of 10% was used to reflect the timing of the future
net cash flows relating to proved oil and gas reserves.
Information with respect to the Company's estimated discounted future cash
flows from its oil and gas properties as of March 31, 1997, June 30, 1996 and
June 30, 1995 is as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Future cash in flows......................... $ 508,306 $ 500,839 $ 474,249
Future production costs and development
costs...................................... (175,033) (196,602) (199,598)
Future income tax expense.................... (85,345) (48,860) (37,054)
--------- --------- ---------
Future net cash flows before discount........ 247,928 255,377 237,597
10% discount to present value................ (154,734) (145,436) (126,858)
--------- --------- ---------
Standardized measure of discounted future net
cash flows related to proved oil and gas
reserves................................... $ 93,194 $ 109,941 $ 110,739
========= ========= =========
</TABLE>
The following amounts represent the Company's share of the reserve
quantities and values of its equity investee Breitburn LLC at March 31, 1997.
Costs incurred and results of operations are included in the previous tables.
<TABLE>
<CAPTION>
GAS OIL
(MMCF) (MBBL)
------ ------
<S> <C> <C> <C>
Proved oil and gas reserve quantities.................. 1,084 1,554
====== ======
Standardized measure of discounted future net cash
flows................................................ $7,277
======
</TABLE>
F-28
<PAGE> 151
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Principal changes in the standardized measure of discounted future net cash
flows for the nine-month period ended March 31, 1997 and for the years ended
June 30, 1996 and 1995 are as follows (in thousands):
<TABLE>
<CAPTION>
1997 1996 1995
-------- -------- --------
<S> <C> <C> <C>
Standardized measure of discounted future net
cash flows at beginning of period............. $109,941 $110,739 $126,247
Sales of oil and gas produced, net of production
costs......................................... (15,333) (16,528) (16,242)
Net changes in prices and production costs...... 22,099 21,717 (36,142)
Extensions, discoveries and other additions, net
of future production and development costs.... 17,160 3,944 6,466
Changes in estimated future development costs... (14,953) (9,071) (6,007)
Development costs incurred...................... 6,898 8,856 9,899
Revisions of previous quantity estimates........ (3,637) 3,120 (15,689)
Purchases of reserves in place.................. 0 4,918 18,653
Sales of reserves in place...................... (24,256) (12,919) 0
Accretion of discount........................... 10,994 11,074 12,625
Net change in income taxes...................... (13,398) (4,852) 23,444
Changes in production rates and other........... (2,321) (11,057) (12,515)
-------- -------- --------
Standardized measure of discounted future net
cash flows at end of period................... $ 93,194 $109,941 $110,739
======== ======== ========
</TABLE>
F-29
<PAGE> 152
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of
Allegheny & Western Energy Corporation and Subsidiaries:
We have audited the accompanying consolidated statement of income of
Allegheny & Western Energy Corporation and Subsidiaries for the year ended June
30, 1995. This financial statement is the responsibility of the Company's
management. Our responsibility is to express an opinion on this financial
statement 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 consolidated statement of income is free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the consolidated statement of income.
An audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall statement of
income presentation. We believe that our audit of the consolidated statement of
income provides a reasonable basis for our opinion.
In our opinion, such consolidated statement of income presents fairly, in
all material respects, the consolidated results of operations of Allegheny &
Western Energy Corporation and Subsidiaries for the year ended June 30, 1995 in
conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Denver, Colorado
April 21, 1997
F-30
<PAGE> 153
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED JUNE 30, 1995
(AMOUNTS IN THOUSANDS, EXCEPT PER SHARE DATA)
<TABLE>
<S> <C>
REVENUES:
Utility gas sales and transportation...................... $156,754
Gas marketing and pipeline sales.......................... 17,965
Oil and gas sales......................................... 7,081
Well operation and service revenues....................... 8,784
Investment and other income............................... 623
--------
191,207
COSTS AND EXPENSES:
Utility gas purchased..................................... 95,999
Gas marketing and pipeline................................ 16,845
Utility operations and maintenance........................ 21,086
Field operating expenses.................................. 26,959
General and administrative................................ 15,830
Depletion, depreciation and amortization.................. 8,635
Interest.................................................. 4,453
--------
189,807
--------
INCOME BEFORE INCOME TAXES.................................. 1,400
INCOME TAX BENEFIT.......................................... 900
--------
NET INCOME.................................................. $ 2,300
========
NET INCOME PER SHARE........................................ $ 0.30
========
WEIGHTED AVERAGE COMMON AND COMMON EQUIVALENT SHARES
OUTSTANDING............................................... 7,786
========
</TABLE>
See notes to consolidated statement of income
F-31
<PAGE> 154
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENT OF INCOME
FOR THE YEAR ENDED JUNE 30, 1995
1. NATURE OF ORGANIZATION
Allegheny & Western Energy Corporation (Allegheny or the Company) and its
wholly-owned subsidiaries (collectively, "Mountaineer") are engaged in the
exploration, production, distribution and marketing of natural gas. The
exploration and production of natural gas is performed in the Appalachian Basin
of West Virginia.
Mountaineer Gas Company ("MGC") is a regulated gas distribution utility
serving approximately 200,000 residential, commercial, industrial and wholesale
customers in the State of West Virginia. During fiscal year 1993, MGC formed a
wholly-owned subsidiary, Mountaineer Gas Services, Inc. ("MGS"), for the purpose
of owning and operating the producing properties and transmission plant assets.
The Company markets natural gas directly to industrial, commercial and
municipal customers through its non-regulated subsidiary, G.A.S.
Effective June 30, 1995, 100% of the common stock of Allegheny was acquired
by Energy Corporation of America ("ECA").
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The following is a summary of the significant accounting policies followed
by the Company and its subsidiaries. The accounting principles are in accordance
with generally accepted accounting principles.
Principles of Consolidation -- The consolidated statement of income
includes the accounts of Allegheny and its subsidiaries. All significant
intercompany items have been eliminated except those relating to sales of
natural gas to MGC by Allegheny and MGS. During 1995, MGC purchased $288,000 and
$4,874,000 from Allegheny and MGS, respectively. Prices at which natural gas is
sold by affiliates to MGC is regulated and approved by the West Virginia Public
Service Commission ("WVPSC").
Basis of Accounts -- MGC and MGS maintain their accounts in conformity with
generally accepted accounting principles for regulated entities which is in
accordance with the accounting requirements and ratemaking practices prescribed
by the WVPSC.
Revenue Recognition -- Oil and gas production, including royalties and
overrides, is recognized as income as it is extracted and sold. Income from
field services is recognized as the related services are performed.
Utility revenues are based on amounts billed to customers on a cycle basis
and estimated amounts for gas delivered but unbilled at the end of each
accounting period. MGC is subject to a purchased gas adjustment clause and
records gas cost as an expense as it is recovered through billings to customers.
The differences between actual gas costs and those recovered are deferred.
WVPSC regulations provide for annual proceedings concerning gas purchases and
cost recovery.
Revenues of G.A.S. are based on volumes delivered at the end of each month.
Gas purchases are accrued at prices negotiated with vendors and matched with the
corresponding gas sales.
Property, Plant and Equipment -- Oil and gas properties are accounted for
using the successful efforts method of accounting. Under this method, certain
expenditures such as exploratory geological and geophysical costs, exploratory
dry hole costs, delay rentals and other costs related to
F-32
<PAGE> 155
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENT OF INCOME -- (CONTINUED)
exploration are recognized currently as expenses. All direct and certain
indirect costs relating to property acquisition, successful exploratory wells,
development costs, and support equipment and facilities are capitalized. The
Company computes depletion, depreciation and amortization of capitalized oil and
gas property costs on the units-of-production method using proved developed
reserves. Direct production costs, production overhead and other costs are
charged against income as incurred. Gains and losses on the sale of oil and gas
property interests are generally included in operations.
Other property, equipment, pipelines and buildings are stated at cost and
are depreciated using straight-line and accelerated methods over estimated
useful lives ranging from three to 30 years.
The provision for depreciation of Mountaineer utility plant is based on a
composite straight-line method. The average composite depreciation rate was
3.67% for 1995. Depreciation on a majority of transmission plant is computed on
a straight-line basis over periods of five to 30 years. Mountaineer's property,
plant and equipment includes overheads for payroll related costs, administrative
and general expenses, as well as an allowance for funds used during construction
("AFUDC") of approximately $50,600 for the year ended June 30, 1995. AFUDC is an
accounting procedure which capitalizes the cost of funds used to finance utility
construction projects as part of utility plant on the balance sheet and
crediting the cost as a non-cash item on the income statement. During the year
ended June 30, 1995 this amount related to debt financing in accordance with
WVPSC policies.
Oil and gas lease acquisition costs are capitalized when incurred. Unproved
properties are assessed on a property-by-property basis and any impairment in
value is recognized. If the unproved properties are determined to be productive,
the appropriate related costs are transferred to proved oil and gas properties.
Lease rentals are expensed as incurred.
Repairs and maintenance costs are charged against income as incurred;
significant renewals and betterments are capitalized. Gains and losses on
dispositions of other property, equipment, pipelines and buildings are included
in operations. Utility plant retirements are credited to property, plant and
equipment at cost and charged to accumulated depreciation, net of cost of
removal and salvage. No gain or loss is recognized on utility plant retirements.
Income Taxes -- Deferred income taxes reflect the impact of "temporary
differences" between assets and liabilities recognized for financial reporting
purposes and such amounts as measured by tax laws. These temporary differences
are determined in accordance with Statement of Financial Accounting Standards
("SFAS") No. 109, "Accounting For Income Taxes."
Operating Leases -- Mountaineer has noncancelable operating lease
agreements for the rental of office space, computer and other equipment. Rental
expense for operating leases was $638,283 for the year ended June 30, 1995.
Earnings per Share of Common Stock -- Earnings per share of common stock is
computed by dividing net income attributable to the shares of common stock by
the weighted average number of common and common equivalent shares outstanding
during the reporting period. The number of equivalent shares was computed using
the treasury stock method which assumes that the increase in the number of
shares is reduced by the number of shares which could have been repurchased by
the Company with proceeds from the exercise of options (which were assumed to
have been made at the average market price of the common shares during the
reporting period). The computation of fully diluted earnings per share of common
stock for the year ended June 30, 1995 was not dilutive; therefore, only primary
earnings per share of common stock is presented.
Use of Estimates -- The preparation of the consolidated statement of income
in conformity with generally accepted accounting principles requires management
to make estimates and assumptions
F-33
<PAGE> 156
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENT OF INCOME -- (CONTINUED)
that affect the reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Allegheny's consolidated statement of income is based on a number of
significant estimates including oil and gas reserve quantities which are the
basis for the calculation of depreciation, depletion, amortization and
impairment of oil and gas properties. Allegheny's reserve quantities are
determined by petroleum engineers. Management emphasizes that reserve estimates
are inherently imprecise.
3. INCOME TAXES
A reconciliation of the provision for income taxes computed at the
statutory rate to the benefit for income taxes as shown in the consolidated
statement of income for the year ended June 30, 1995 is summarized below (in
thousands):
<TABLE>
<S> <C>
Tax expense at the federal statutory rate................... $ 476
State taxes, net of federal benefit......................... 46
Tax credits................................................. (980)
Other, net.................................................. (442)
-----
Total benefit for income taxes.............................. $(900)
=====
</TABLE>
4. PENSION PLAN
MGC sponsors a Retirement Plan (the "Pension Plan") which covers
substantially all qualified employees 21 years of age and over. Employees become
fully vested upon completion of five years of credited service, as defined in
the Pension Plan. Retirement income is based on credited years of service and
the employees' level of compensation, as defined in the Pension Plan. The
Pension Plan is subject to the provisions of the Employee Retirement Income
Security Act of 1974 ("ERISA"). The determination of contributions is made in
consultation with the Pension Plan's actuary and is based upon anticipated
earnings of the Pension Plan, mortality and turnover experience, the funded
status of the Pension Plan and anticipated future compensation levels. MGC's
funding policy is to be in compliance with ERISA guidelines and to make annual
contributions to the Pension Plan to assure that all employees' benefits will be
fully provided for by the time they retire.
Net pension cost for the year ended June 30, 1995, as determined by an
independent actuary, included the following components (in thousands):
<TABLE>
<S> <C>
Service cost................................................ $ 615
Interest cost............................................... 2,124
Actual return on plan assets................................ (2,633)
Net amortization and deferral............................... 1,223
-------
Net periodic pension cost................................... 1,329
Less amount capitalized as construction cost and charged to
others.................................................... (255)
-------
Amount charged to expense................................... $ 1,074
=======
</TABLE>
5. POSTRETIREMENT MEDICAL AND LIFE INSURANCE BENEFITS
MGC provides certain medical and life insurance benefits for retired
employees. Substantially all employees may become eligible for these benefits if
they choose to retire after reaching age 55 while working for MGC and are
provided until age 65. Life insurance benefits of approximately two
F-34
<PAGE> 157
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENT OF INCOME -- (CONTINUED)
times annual salary are provided while an employee is active and working at MGC.
On the date of an employee's retirement and on the date the employee reaches age
70, life insurance benefits decrease to approximately 80% and 40% of annual
salary, respectively. These benefits are provided to retirees who meet the
service requirements of 10 continuous years of service prior to retirement at
age 55 or 5 continuous years of service prior to retirement at age 65. The plan
is unfunded.
Net periodic postretirement benefit cost for the year ended June 30, 1995,
as determined by an independent actuary, included the following components (in
thousands):
<TABLE>
<S> <C>
Service cost-benefits attributable to service during the
period.................................................... $ 333
Amortization of the transition obligation................... 310
Interest cost on the accumulated postretirement benefit
obligation................................................ 501
------
Net periodic postretirement benefit cost.................... 1,144
Less amount capitalized as construction cost................ (184)
------
Amount charged to expense................................... $ 960
======
</TABLE>
As part of a WVPSC rate order dated October 29, 1993, the WVPSC ruled that
the permitted rate recovery mechanism for other post retirement benefits
("OPEB") will be a modified accrual method. The modified accrual method allows
for the recovery of current services costs on an accrual basis and recovery of
the transition obligation on a cash basis.
6. RELATED PARTY TRANSACTIONS
The Company's field services revenue includes revenue from partnerships and
joint ventures in which the Company is the general partner or operator. Certain
officers and directors of the Company and their relatives and other related
parties participate as limited partners in certain partnerships in which the
Company is the general partner.
7. REGULATORY MATTERS
In January 1995, MGC filed for a base rate increase with the WVPSC. In June
1995, the Company agreed to a Joint Stipulation and Agreement for Settlement
(the "Agreement") with various parties, including the staff of WVPSC and the
Consumer Advocate Division, regarding the base rate filing as well as the
Company's upcoming PGA filing and a tariff filing concerning, inter alia,
telemetering requirements for transportation customers. The Agreement allows for
a $4 million increase in base rates, with the portion of the increase allocable
to sales customers to be offset by the amortization of the PGA overrecovered
balance existing as of October 31, 1995 over a three-year moratorium period
beginning November 1, 1995.
F-35
<PAGE> 158
ALLEGHENY & WESTERN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED STATEMENT OF INCOME -- (CONTINUED)
8. OIL AND GAS PRODUCING ACTIVITIES
The results of oil and gas producing activities for 1995 are as follows:
<TABLE>
<S> <C>
Revenue from sale of oil and gas:
Sales to unaffiliated parties............................. $ --
Sales to affiliates....................................... 6,022
------
Total............................................. 6,022
------
Production costs.......................................... 2,923
Exploration costs......................................... 137
Depletion, depreciation and amortization.................. 1,823
Income tax (benefit)...................................... (729)
------
Results of operations....................................... $1,868
======
</TABLE>
F-36
<PAGE> 159
ALL TENDERED OLD NOTES, EXECUTED LETTERS OF TRANSMITTAL AND OTHER RELATED
DOCUMENTS SHOULD BE DIRECTED TO THE EXCHANGE AGENT. QUESTIONS AND REQUESTS FOR
ASSISTANCE AND REQUESTS FOR ADDITIONAL COPIES OF THE PROSPECTUS, THE LETTER OF
TRANSMITTAL AND OTHER RELATED DOCUMENTS SHOULD BE ADDRESSED TO THE EXCHANGE
AGENT AS FOLLOWS:
By Mail or Hand Delivery:
The Bank of New York
Reorganization Section
101 Barclay Street -- 7E
New York, New York 10286
Attention: Walter Gitlin
By Facsimile Transmission:
(for Eligible Institutions only)
(212) 571-3080
Attention: Walter Gitlin
Confirm by Telephone
(212) 815-3687
(Originals of all documents submitted by facsimile should be sent promptly by
hand, overnight delivery, or registered or certified mail.)
------------------------------------------------------
NO DEALER, SALESPERSON OR ANY OTHER PERSON HAS BEEN AUTHORIZED TO GIVE ANY
INFORMATION OR TO MAKE ANY REPRESENTATION NOT CONTAINED IN THIS PROSPECTUS AND,
IF GIVEN OR MADE, SUCH INFORMATION OR REPRESENTATION MUST NOT BE RELIED UPON AS
HAVING BEEN AUTHORIZED BY THE COMPANY. THIS PROSPECTUS DOES NOT CONSTITUTE AN
OFFER TO SELL OR A SOLICITATION OF AN OFFER TO BUY ANY OF THE SECURITIES OFFERED
HEREBY IN ANY JURISDICTION TO ANY PERSON TO WHOM IT IS UNLAWFUL TO MAKE SUCH
OFFER IN SUCH JURISDICTION. NEITHER THE DELIVERY OF THIS PROSPECTUS NOR ANY SALE
MADE HEREUNDER SHALL, UNDER ANY CIRCUMSTANCES, CREATE ANY IMPLICATION THAT THE
INFORMATION HEREIN IS CORRECT AS OF ANY TIME SUBSEQUENT TO THE DATE HEREOF OR
THAT THERE HAS BEEN NO CHANGE IN THE AFFAIRS OF THE COMPANY SINCE SUCH DATE.
$200,000,000
EXCHANGE OFFER
ENERGY CORPORATION OF
AMERICA
9 1/2% SENIOR SUBORDINATED NOTES
DUE 2007, SERIES A
[ECA LOGO]
TABLE OF CONTENTS
<TABLE>
<S> <C>
Other Information...................... iii
Summary................................ 1
Risk Factors........................... 14
The Exchange Offer..................... 24
Use of Proceeds........................ 33
Capitalization......................... 34
Selected Consolidated Financial Data... 35
Management's Discussion and Analysis of
Financial Condition and Results of
Operations........................... 37
Business and Properties................ 46
Management............................. 66
Principal Stockholders and Share
Ownership of Management.............. 73
Certain Relationships and Related
Transactions......................... 74
Description of the Notes............... 76
Description of Other Indebtedness...... 109
Book Entry; Delivery and Form.......... 110
Plan of Distribution................... 113
Legal Matters.......................... 113
Experts................................ 113
Change of Accountants.................. 114
Glossary............................... 115
Index to Consolidated Financial
Statements........................... F-1
</TABLE>
August , 1997
<PAGE> 160
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
ITEM 20. INDEMNIFICATION OF DIRECTORS AND OFFICERS
The West Virginia Corporation Act (the "Act") provides that a corporation
may indemnify any person who was or is a party or may be made a party to any
threatened, pending or completed action, suit or proceeding, whether civil,
criminal, administrative or investigative, except for actions brought by or in
the right of the corporation. The indemnity covers all expenses, including legal
expenses, fines, judgments and amount paid in settlement actually and reasonably
incurred. Such parties are only eligible if their actions were made in good
faith, not in opposition to the corporation and without cause to believe any
action was unlawful. This indemnity provision is limited to those persons that
are or may be parties based on the fact that the person was or is a director,
officer, employee or agent of the corporation or was serving at the request of
the corporation as a director, officer, employee or agent of another business
entity.
The Act also allows a corporation to indemnify any person who was or is
threatened to be made party to any action or suit brought by or in the right of
the corporation against all expenses, fines, judgments and payments made in
settlement, including legal fees. The person must have acted in good faith with
no reason to believe the actions taken were in opposition to the corporation.
Indemnification is not permitted in situations where the party seeking the
indemnity was adjudged liable for negligence or misconduct regarding tax
matters.
The Act also provides that corporations may purchase and maintain insurance
to cover possible indemnities, regardless of whether the corporation is
otherwise allowed to indemnify the party under its provisions.
Article XI of the Company's Certificate of Incorporation provides that no
director of the Corporation shall be liable to the Corporation or its
stockholders for monetary damages for breach of fiduciary duty as a director,
except for liability (i) for any breach of the director's duty of loyalty to the
Corporation or its stockholders, (ii) for acts or omissions not in good faith or
which involve intentional misconduct or a knowing violation of law, (iii) under
Section 9 of the Act or (iv) for any transaction from which the director derived
an improper personal benefit.
ITEM 21. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
The following is a complete list of Exhibits filed as part of, or
incorporated by reference into, this Amendment No. 2 to the Registration
Statement (except as otherwise indicated, all exhibits have been previously
filed):
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION
NUMBER OF EXHIBIT
------- -----------
<C> <S>
3.1 -- Articles of Incorporation of Energy Corporation of
America.
3.2 -- Bylaws of Energy Corporation of America.
4.1 -- Credit Agreement among Energy Corporation of America,
General Electric Capital Corporation as Agent, and the
lenders named therein, dated as of May 20, 1997.
4.2 -- Note Purchase Agreement between Mountaineer Gas Company
and The John Hancock Mutual Life Insurance Company dated
as of October 12, 1995.
4.3 -- Indenture, dated as of May 23, 1997, between Energy
Corporation of America and The Bank of New York, as
Trustee, with respect to the 9 1/2% Senior Subordinated
Notes Due 2007 (including form of 9 1/2% Senior
Subordinated Note Due 2007).
4.4 -- Form of 9 1/2% Senior Subordinated Note due 2007, Series
A.
</TABLE>
II-1
<PAGE> 161
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION
NUMBER OF EXHIBIT
- ------------------------- ------------------------------------------------------------------------------------------
<C> <S>
5.1 -- Opinion of Andrews & Kurth L.L.P. as to the legality of the securities being
registered.
*5.2 -- Opinion of Goodwin & Goodwin LLP as to the legality of the securities being offered.
10.1 -- Eastern American Energy Corporation Profit Sharing/Incentive Stock Plan dated as of
June 4, 1997.
10.2 -- Buy-Sell Stock Option Agreement dated as of May 19, 1997 among Energy Corporation of
America, F.H. McCullough, II and Kathy L. McCullough.
10.3 -- Buy-Sell Stock Option Agreement dated as of July 8, 1996 between Energy Corporation of
America and Kenneth W. Brill.
10.4 -- Incentive Stock Option Agreement dated as of December 21, 1994 between Energy
Corporation of America and Donald C. Supcoe.
10.5 -- First Amendment to Incentive Stock Option Agreement dated as of August 28, 1995 between
Energy Corporation of America and Donald C. Supcoe.
10.6 -- Incentive Stock Option Agreement dated as of December 19, 1994 between Energy
Corporation of America and Richard E. Heffelfinger.
10.7 -- First Amendment to Incentive Stock Option Agreement dated as of August 28, 1995 between
Energy Corporation of America and Richard G. Heffelfinger.
10.8 -- Incentive Stock Option Agreement dated as of December 9, 1994 between Energy
Corporation of America and J. Michael Forbes.
10.9 -- First Amendment to Incentive Stock Option Agreement dated as of August 28, 1995 between
Energy Corporation of America and J. Michael Forbes.
10.10 -- Gas Purchase Agreement dated as of August 29, 1995 among Eastern American Energy
Corporation, Eastern Pipeline Corporation and Hope Gas, Inc.
10.11 -- Gas Sale and Purchase Agreement dated as of March 27, 1991 between Eastern American
Energy Corporation and Seneca Power Partners, L.P.
10.12 -- Gas Purchase Contract dated as of September 13, 1995 among Eastern American Energy
Corporation, Eastern Marketing Corporation and Mountaineer Gas Company.
10.13 -- Gas Purchase Contract dated as of January 1, 1993 between Eastern American Energy
Corporation and Eastern Marketing Corporation.
10.14 -- FTSI Service Agreement No. 37994 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gulf Transmission Company.
10.15 -- Service Agreement No. 42794 dated as of November 1, 1994 between Mountaineer Gas
Company and Columbia Gulf Transmission Company.
10.16 -- SST Service Agreement No. 38087 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.17 -- FTS Service Agreement No. 38037 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.18 -- Supplement No. 1 to Transportation Service Agreement No. 38137 dated as of May 6, 1994
between Mountaineer Gas Company and Columbia Gas Transmission Corporation.
</TABLE>
II-2
<PAGE> 162
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION
NUMBER OF EXHIBIT
------- -----------
<S> <C>
10.19 -- FSS Service Agreement No. 38077 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.20 -- NTS Service Agreement No. 39272 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.21 -- SIT Service Agreement No. 40251 dated as of December 13, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.22 -- FTS Service Agreement No. 38113 dated as of November 1, 1993 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.23 -- Supplement No. 1 to Transportation Service Agreement No. 38113 dated as of May 6, 1994
between Mountaineer Gas Company and Columbia Gas Transmission Corporation.
10.24 -- Gas Transportation Agreement dated as of October 1, 1994 between Mountaineer Gas
Company and Tennessee Gas Pipeline Company.
10.25 -- Amendment No. 1 to Gas Transportation Agreement dated as of May 5, 1995 between
Mountaineer Gas Company and Tennessee Gas Pipeline Company.
12.1 -- Computation of ratio of earnings to fixed charges.
16.1 -- Letter from Coopers & Lybrand regarding change of accountants.
21.1 -- Subsidiaries of Energy Corporation of America.
*23.1 -- Independent Auditors' Consent and Report on Schedules.
23.2 -- Consent of Andrews & Kurth L.L.P. (included in Exhibit 5.1).
*23.3 -- Consent of Ryder Scott Company
*23.4 -- Consent of Joseph J. Mendoza.
24.1 -- Power of Attorney set forth on the signature page contained in Part II of this
Registration Statement.
*25.1 -- Statement of Eligibility and Qualification of Form T-1 of The Bank of New York.
27.1 -- Financial Data Schedule.
99.1 -- Form of Letter of Transmittal.
99.2 -- Form of Notice of Guaranteed Delivery.
</TABLE>
- ---------------
* Filed herewith.
II-3
<PAGE> 163
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
Denver, State of Colorado, on the 16th day of July, 1997.
ENERGY CORPORATION OF AMERICA
By: /s/ JOHN MORK
-------------------------------------
John Mork
President, Chief Executive Officer
and Director
Pursuant to the requirements of the Securities Act of 1933, this Amendment
No. 2 to the Registration Statement has been signed on the day of July,
1997, by the following persons in the capacities indicated.
<TABLE>
<CAPTION>
SIGNATURE TITLE
--------- -----
<C> <S>
KENNETH W. BRILL* Chairman of the Board of Directors
- -----------------------------------------------------
Kenneth W. Brill
/s/ JOHN MORK President, Chief Executive Officer and
- ----------------------------------------------------- Director (principal executive officer)
John Mork
JOSEPH E. CASABONA* Executive Vice President (principal accounting
- ----------------------------------------------------- officer)
Joseph E. Casabona
J. MICHAEL FORBES* Vice President and Treasurer
- ----------------------------------------------------- (principal financial officer)
J. Michael Forbes
RICHARD E. HEFFELFINGER* Director
- -----------------------------------------------------
Richard E. Heffelfinger
F. H. MCCULLOUGH, III* Director
- -----------------------------------------------------
F. H. McCullough III
PETER H. COORS* Director
- -----------------------------------------------------
Peter H. Coors
L.B. CURTIS* Director
- -----------------------------------------------------
L.B. Curtis
JOHN J. DORGAN* Director
- -----------------------------------------------------
John J. Dorgan
JULIE MORK* Director
- -----------------------------------------------------
Julie Mork
ARTHUR C. NIELSEN, JR.* Director
- -----------------------------------------------------
Arthur C. Nielsen, Jr.
* By /s/ JOHN MORK
-----------------------------------------------
John Mork
by Power of Attorney
</TABLE>
II-4
<PAGE> 164
SCHEDULE I
ENERGY CORPORATION OF AMERICA
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEET INFORMATION
(DOLLARS IN THOUSANDS)
ASSETS
<TABLE>
<CAPTION>
MARCH 31, JUNE 30,
1997 1996
--------- --------
<S> <C> <C>
CURRENT ASSETS:
Cash...................................................... $ 753 $ 3,454
Accounts receivable, other................................ 139 313
Accounts receivable, affiliates........................... 13,219 8,709
Other current assets...................................... 46 207
------- -------
Total current assets.............................. 14,157 12,683
PROPERTY, PLANT AND EQUIPMENT -- Net........................ 210 99
INVESTMENT IN SUBSIDIARIES.................................. 41,819 30,849
OTHER ASSETS................................................ 69
------- -------
TOTAL............................................. $56,255 $43,631
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued expenses..................... $ 1,083 $ 601
Income taxes.............................................. 4,080 2,198
------- -------
Total current liabilities......................... 5,163 2,799
LONG-TERM LIABILITIES....................................... 3,209 3,307
COMMITMENTS AND CONTINGENCIES
STOCKHOLDERS' EQUITY........................................ 47,883 37,525
------- -------
TOTAL............................................. $56,255 $43,631
======= =======
</TABLE>
See notes to condensed financial information.
S-1
<PAGE> 165
ENERGY CORPORATION OF AMERICA
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS INFORMATION
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS
ENDED YEAR ENDED JUNE 30,
-------------- --------------------
MARCH 31, 1997 1996 1995
-------------- -------- --------
<S> <C> <C> <C>
COSTS AND EXPENSES:
General and administrative........................... $ 2,014 $ 2,352 $ 1,278
Depreciation of property, plant and equipment........ 29 24 107
------- ------- -------
LOSS FROM OPERATIONS................................... (2,043) (2,376) (1,385)
OTHER (INCOME) EXPENSE................................. (914) 1,931 (794)
------- ------- -------
LOSS BEFORE INCOME TAXES AND EQUITY IN EARNINGS OF
SUBSIDIARIES......................................... (1,129) (4,307) (591)
BENEFIT FROM INCOME TAXES.............................. (316) (1,142) (356)
------- ------- -------
LOSS BEFORE EQUITY IN EARNINGS OF SUBSIDIARIES......... (813) (3,165) (235)
EQUITY IN EARNINGS OF SUBSIDIARIES..................... 13,048 10,985 1,420
------- ------- -------
NET INCOME............................................. $12,235 $ 7,820 $ 1,185
======= ======= =======
</TABLE>
See notes to condensed financial information.
S-2
<PAGE> 166
ENERGY CORPORATION OF AMERICA
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS INFORMATION
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
NINE MONTHS YEAR ENDED
ENDED JUNE 30,
-------------- -----------------
MARCH 31, 1997 1996 1995
-------------- ------- ------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATIONS:
Net income............................................. $ 12,235 $ 7,820 $1,185
Adjustments to reconcile net income to cash provided by
(used in) operations:
Equity in undistributed earnings of subsidiaries.... (10,970) (3,429) 1,558
Depreciation........................................ 29 24 107
Changes in operating assets and liabilities......... (1,811) (5,824) 1,539
Other............................................... (45) 801 1,918
-------- ------- ------
Net cash provided by (used in) operating
activities........................................ (562) (608) 6,307
-------- ------- ------
CASH FLOWS FROM INVESTING ACTIVITIES:
Expenditures for property.............................. (140) (113) (65)
-------- ------- ------
Net cash provided by investing activities........... (140) (113) (65)
-------- ------- ------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends paid......................................... (506) (1,457) (457)
Proceeds from exercise of stock options................ 128
Repurchase of common stock............................. (1,493) (632) (450)
-------- ------- ------
Net cash used in financing activities............... (1,999) (1,961) (907)
-------- ------- ------
INCREASE (DECREASE) IN CASH.............................. (2,701) (2,682) 5,335
CASH AT BEGINNING OF PERIOD.............................. 3,454 6,136 801
-------- ------- ------
CASH AT END OF PERIOD.................................... $ 753 $ 3,454 $6,136
======== ======= ======
</TABLE>
See notes to condensed financial information.
S-3
<PAGE> 167
ENERGY CORPORATION OF AMERICA
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED FINANCIAL INFORMATION
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Investments in Subsidiaries -- The financial statements of Energy
Corporation of America (The "Company") reflect investments in Eastern American
Energy Corporation, Eastern Systems Corporation, Westech Energy Corporation,
Westech Energy New Zealand, and Westside Acquisition Corporation ("the
subsidiaries"), majority or wholly-owned subsidiaries, using the equity method.
Income Taxes -- The benefit for income taxes is based on losses recognized
for financial statement purposes determined on a separate company basis.
Deferred income taxes are recognized for the tax effects of temporary
differences between such losses and those recognized for income tax purposes.
The Company files a consolidated U.S. income tax return with its subsidiaries.
2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related
Notes of Energy Corporation of America and Subsidiaries enclosed elsewhere
herein for additional information.
3. LONG-TERM DEBT
Information concerning debt of the Company on a consolidated basis is
disclosed in Note 5 of the Notes to the Consolidated Financial Statements of
Energy Corporation of America and Subsidiaries included elsewhere herein. All
maturities of long-term debt during the next five years were prepaid with
proceeds from the Company's issuance of $200,000,000 million in 9 1/2% senior
subordinated notes due 2007.
4. DIVIDENDS RECEIVED
The Company has received cash dividends from its subsidiaries of $2,079,000
for the nine months ended March 31, 1997 and $7,556,000 and $2,978,000 for the
years ended June 30, 1996 and 1995, respectively.
* * * * *
S-4
<PAGE> 168
SCHEDULE II
ENERGY CORPORATION OF AMERICA AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
FOR THE NINE MONTHS ENDED MARCH 31, 1997 AND
THE YEARS ENDED JUNE 30, 1996 AND 1995
(AMOUNTS IN THOUSANDS)
<TABLE>
<CAPTION>
FOR THE NINE FOR THE YEAR
MONTH PERIOD ENDED JUNE 30,
ENDED MARCH 31, -----------------
1997 1996 1995
--------------- ------- ------
<S> <C> <C> <C>
Balance at beginning of period......................... $ 1,744 $ 1,141 $ 297
Charged to costs and expenses.......................... 1,153 1,800
Charged to other accounts(1)........................... 844(2)
Deductions(3).......................................... (1,529) (1,197)
------- ------- ------
Balance at end of period............................... $ 1,368 $ 1,744 $1,141
======= ======= ======
</TABLE>
- ---------------
(1) Recoveries of accounts previously written off.
(2) Includes the beginning balance ($756) of the allowance for doubtful accounts
of Mountaineer Gas Company acquired by ECA at 6/30/95.
(3) Accounts written off.
S-5
<PAGE> 169
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION
NUMBER OF EXHIBIT
------- -----------
<C> <S>
3.1 -- Articles of Incorporation of Energy Corporation of
America.
3.2 -- Bylaws of Energy Corporation of America.
4.1 -- Credit Agreement among Energy Corporation of America,
General Electric Capital Corporation as Agent, and the
lenders named therein, dated as of May 20, 1997.
4.2 -- Note Purchase Agreement between Mountaineer Gas Company
and The John Hancock Mutual Life Insurance Company dated
as of October 12, 1995.
4.3 -- Indenture, dated as of May 23, 1997, between Energy
Corporation of America and The Bank of New York, as
Trustee, with respect to the 9 1/2% Senior Subordinated
Notes Due 2007 (including form of 9 1/2% Senior
Subordinated Note Due 2007).
4.4 -- Form of 9 1/2% Senior Subordinated Note due 2007, Series
A.
4.5 -- Registration Rights Agreement, dated as of May 20, 1997,
among Energy Corporation of America, as issuer, and Chase
Securities Inc. and Prudential Securities Inc.
5.1 -- Opinion of Andrews & Kurth L.L.P. as to the legality of
the securities being registered.
*5.2 -- Opinion of Goodwin & Goodwin LLP as to the legality of
the securities being registered.
10.1 -- Eastern American Energy Corporation Profit
Sharing/Incentive Stock Plan dated as of June 4, 1997.
10.2 -- Buy-Sell Stock Option Agreement dated as of May 19, 1997
among Energy Corporation of America, F.H. McCullough, II
and Kathy L. McCullough.
10.3 -- Buy-Sell Stock Option Agreement dated as of July 8, 1996
between Energy Corporation of America and Kenneth W.
Brill.
10.4 -- Incentive Stock Option Agreement dated as of December 21,
1994 between Energy Corporation of America and Donald C.
Supcoe.
10.5 -- First Amendment to Incentive Stock Option Agreement dated
as of August 28, 1995 between Energy Corporation of
America and Donald C. Supcoe.
10.6 -- Incentive Stock Option Agreement dated as of December 19,
1994 between Energy Corporation of America and Richard E.
Heffelfinger.
10.7 -- First Amendment to Incentive Stock Option Agreement dated
as of August 28, 1995 between Energy Corporation of
America and Richard G. Heffelfinger.
10.8 -- Incentive Stock Option Agreement dated as of December 9,
1994 between Energy Corporation of America and J. Michael
Forbes.
10.9 -- First Amendment to Incentive Stock Option Agreement dated
as of August 28, 1995 between Energy Corporation of
America and J. Michael Forbes.
10.10 -- Gas Purchase Agreement dated as of August 29, 1995 among
Eastern American Energy Corporation, Eastern Pipeline
Corporation and Hope Gas, Inc.
10.11 -- Gas Sale and Purchase Agreement dated as of March 27,
1991 between Eastern American Energy Corporation and
Seneca Power Partners, L.P.
10.12 -- Gas Purchase Contract dated as of September 13, 1995
among Eastern American Energy Corporation, Eastern
Marketing Corporation and Mountaineer Gas Company.
</TABLE>
<PAGE> 170
<TABLE>
<CAPTION>
EXHIBIT DESCRIPTION
NUMBER OF EXHIBIT
------- -----------
<C> <S>
10.13 -- Gas Purchase Contract dated as of January 1, 1993 between
Eastern American Energy Corporation and Eastern Marketing
Corporation.
10.14 -- FTS1 Service Agreement No. 37994 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gulf
Transmission Company.
10.15 -- FTS2 Service Agreement No. 42794 dated as of November 1,
1994 between Mountaineer Gas Company and Columbia Gulf
Transmission Company.
10.16 -- SST Service Agreement No. 38087 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.17 -- FTS Service Agreement No. 38137 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.18 -- Supplement No. 1 to Transportation Service Agreement No.
38137 dated as of May 6, 1994 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.19 -- FSS Service Agreement No. 38077 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.20 -- NTS Service Agreement No. 39272 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.21 -- SIT Service Agreement No. 40251 dated as of December 13,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.22 -- FTS Service Agreement No. 38113 dated as of November 1,
1993 between Mountaineer Gas Company and Columbia Gas
Transmission Corporation.
10.23 -- Supplement No. 1 to Transportation Service Agreement No.
38113 dated as of May 6, 1994 between Mountaineer Gas
Company and Columbia Gas Transmission Corporation.
10.24 -- Gas Transportation Agreement No. 8396 dated as of October
1, 1994 between Mountaineer Gas Company and Tennessee Gas
Pipeline Company.
10.25 -- Amendment No. 1 to Gas Transportation Agreement dated as
of May 5, 1995 between Mountaineer Gas Company and
Tennessee Gas Pipeline Company.
12.1 -- Computation of ratio of earnings to fixed charges.
16.1 -- Letter from Coopers & Lybrand regarding change of
accountants.
21.1 -- Subsidiaries of Energy Corporation of America.
*23.1 -- Independent Auditors' Consent and Report on Schedules.
23.2 -- Consent of Andrews & Kurth L.L.P. (included in Exhibit
5.1).
*23.3 -- Consent of Ryder Scott Company
*23.4 -- Consent of Joseph J. Mendoza.
24.1 -- Power of Attorney set forth on the signature page
contained in Part II of this Registration Statement.
*25.1 -- Statement of Eligibility and Qualification of Form T-1 of
The Bank of New York.
27.1 -- Financial Data Schedule.
99.1 -- Form of Letter of Transmittal.
99.2 -- Form of Notice of Guaranteed Delivery.
</TABLE>
- ---------------
* Filed herewith.
<PAGE> 1
EXHIBIT 5.2
Charleston
July 16, 1997
Board of Directors
Energy Corporation of America
4643 South Ulster Street, Suite 1100
Denver, CO 80237
Ladies and Gentlemen:
We have acted as counsel to Energy Corporation of America, a West
Virginia corporation, (the "Company") in connection with the Company's
Registration Statement on Form S-4 (the "Registration Statement") relating to
the registration under the Securities Act of 1933, as amended, (the "Securities
Act") of the offer by the Company to exchange up to $200,000,000 aggregate
principal amount of its 9 1/2% Senior Subordinated Notes Due 2007, Series A
(the "Exchange Notes") for its existing 9 1/2% Senior Subordinated Notes Due
2007 (the "Existing Notes"). The Exchange Notes are proposed to be issued in
accordance with the provisions of the Indenture, dated as of May 23, 1997,
between the Company and The Bank of New York, as Trustee (the "Indenture").
In arriving at the opinions expressed below, we have examined the
Registration Statement, the Prospectus contained therein, the Indenture, which
is filed as an exhibit to the Registration Statement, and the originals or
copies certified or otherwise identified to our satisfaction of such other
instruments and other certificates of public officials and officers and
representatives of the Company. In such examination, we have assumed and have
not verified (i) that the signatures on all documents that we have examined are
genuine, (ii) the authenticity of all documents submitted to us as originals,
(iii) the conformity with the authentic originals of all documents submitted to
us as certified, photostatic or faxed copies, and (iv) that all documents in
respect of which forms were filed with the Securities and Exchange Commission
as exhibits to the Registration Statement will conform in all material respects
to the forms thereof that we have examined. In addition, as the basis for the
opinion hereinafter expressed, we have examined such statutes, regulations,
corporate records and documents, certificates of corporate and public officials
and other instruments as we have deemed necessary or advisable for the purpose
of this opinion.
<PAGE> 2
Based upon the foregoing, having due regard for such legal
considerations as we deem relevant and assuming the due authorization,
execution and delivery of the Exchange Notes by the Company, we are of the
opinion that the Exchange Notes, (a) when exchanged in the manner described in
the Registration Statement, (b) when duly executed, authenticated, issued and
delivered in accordance with the terms of the Indenture, (c) when the Indenture
has been duly qualified under the Trust Indenture Act of 1939, as amended, and
(d) when applicable provisions of "blue sky" laws have been complied with, will
constitute valid and legally binding obligations of the Company, entitled to
the benefits of the Indenture and enforceable against the Company in accordance
with their terms, except to the extent that such enforceability may be limited
by applicable bankruptcy, insolvency, fraudulent conveyance, reorganization,
moratorium and similar laws of general applicability relating to or affecting
creditors rights and by general equitable principles (whether considered in a
proceeding in equity or at law).
We are qualified to practice law in the State of West Virginia. We
express no opinion as to, and for the purposes of the opinions set forth
herein, we have conducted no investigation of, and do not purport to be experts
on, any laws other than the laws of the State of West Virginia. We hereby
consent to the use of this opinion as an exhibit to the Registration Statement
and to the use of the firm name under the heading "Legal Matters" in the
Registration Statement.
Sincerely,
Goodwin & Goodwin, LLP
TJO:seb
<PAGE> 1
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULES
We consent to the use in this Pre-Effective Amendment No. 2 to Registration
Statement No. 333-29001 of Energy Corporation of America on Form S-4 of our
reports dated April 21, 1997, appearing in the Prospectus, which is part of this
Registration Statement, and to the references to us under the headings "Summary
Financial Information", "Selected Consolidated Financial Information", "Change
of Accountants" and "Experts" in such Prospectus.
Our audit of the consolidated financial statements of Energy Corporation of
America referred to in our aforementioned report also included the financial
statement schedules of Energy Corporation of America, listed in Item 21. These
financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion based on our audits. In
our opinion, such financial statement schedules, when considered in relation to
the basic consolidated financial statements of Energy Corporation of America
taken as a whole, present fairly in all material respects the information set
forth therein.
DELOITTE & TOUCHE LLP
Denver, Colorado
July 16, 1997
<PAGE> 1
EXHIBIT 23.3
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
We hereby consent to the reference to us under the headings "Business
and Properties -- Oil and Gas Reserves" and "Experts" in the Prospectus
constituting part of this Registration Statement on Form S-4 of Energy
Corporation of America.
Very truly yours,
/s/ Ryder Scott Company
RYDER SCOTT COMPANY
PETROLEUM ENGINEERS
Denver, Colorado
Date: July 15, 1997
<PAGE> 1
EXHIBIT 23.4
CONSENT OF INDEPENDENT PETROLEUM ENGINEER
I hereby consent to the reference to us under the headings "Business
and Properties -- Oil and Gas Reserves" and "Experts" in the Prospectus
constituting part of this Registration Statement on Form S-4 of Energy
Corporation of America.
/s/ Joseph J. Mendoza
- -----------------------------------
Consulting Petroleum Engineer
31 Champney Place
Laguna Niguel, CA 92677
July 15, 1997
<PAGE> 1
EXHIBIT 25.1
================================================================================
FORM T-1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
STATEMENT OF ELIGIBILITY
UNDER THE TRUST INDENTURE ACT OF 1939 OF A
CORPORATION DESIGNATED TO ACT AS TRUSTEE
CHECK IF AN APPLICATION TO DETERMINE
ELIGIBILITY OF A TRUSTEE PURSUANT TO
SECTION 305(b)(2) |__|
___________________________
THE BANK OF NEW YORK
(Exact name of trustee as specified in its charter)
New York 13-5160382
(State of incorporation (I.R.S. employer
if not a U.S. national bank) identification no.)
48 Wall Street, New York, N.Y. 10286
(Address of principal executive offices) (Zip code)
___________________________
ENERGY CORPORATION OF AMERICA
(Exact name of obligor as specified in its charter)
West Virginia 841235822
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
4643 South Ulster Street, Suite 1100
Denver, Colorado 80237
(Address of principal executive offices) (Zip code)
___________________________
9 1/2% Senior Subordinated Notes due 2007, Series A
(Title of the indenture securities)
================================================================================
<PAGE> 2
1. GENERAL INFORMATION. FURNISH THE FOLLOWING INFORMATION AS TO THE
TRUSTEE:
(A) NAME AND ADDRESS OF EACH EXAMINING OR SUPERVISING AUTHORITY TO
WHICH IT IS SUBJECT.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------
Name Address
- ----------------------------------------------------------------------------------
<S> <C>
Superintendent of Banks of the State of 2 Rector Street, New York,
New York N.Y. 10006, and Albany, N.Y.
12203
Federal Reserve Bank of New York 33 Liberty Plaza, New York,
N.Y. 10045
Federal Deposit Insurance Corporation Washington, D.C. 20429
New York Clearing House Association New York, New York 10005
</TABLE>
(B) WHETHER IT IS AUTHORIZED TO EXERCISE CORPORATE TRUST POWERS.
Yes.
2. AFFILIATIONS WITH OBLIGOR.
IF THE OBLIGOR IS AN AFFILIATE OF THE TRUSTEE, DESCRIBE EACH SUCH
AFFILIATION.
None.
16. LIST OF EXHIBITS.
EXHIBITS IDENTIFIED IN PARENTHESES BELOW, ON FILE WITH THE COMMISSION,
ARE INCORPORATED HEREIN BY REFERENCE AS AN EXHIBIT HERETO, PURSUANT TO
RULE 7A-29 UNDER THE TRUST INDENTURE ACT OF 1939 (THE "ACT") AND 17
C.F.R. 229.10(D).
1. A copy of the Organization Certificate of The Bank of New York
(formerly Irving Trust Company) as now in effect, which
contains the authority to commence business and a grant of
powers to exercise corporate trust powers. (Exhibit 1 to
Amendment No. 1 to Form T-1 filed with Registration Statement
No. 33-6215, Exhibits 1a and 1b to Form T-1 filed with
Registration Statement No. 33-21672 and Exhibit 1 to Form T-1
filed with Registration Statement No. 33-29637.)
4. A copy of the existing By-laws of the Trustee. (Exhibit 4 to
Form T-1 filed with Registration Statement No. 33-31019.)
-2-
<PAGE> 3
6. The consent of the Trustee required by Section 321(b) of the
Act. (Exhibit 6 to Form T-1 filed with Registration Statement
No. 33-44051.)
7. A copy of the latest report of condition of the Trustee
published pursuant to law or to the requirements of its
supervising or examining authority.
-3-
<PAGE> 4
SIGNATURE
Pursuant to the requirements of the Act, the Trustee, The Bank of New
York, a corporation organized and existing under the laws of the State of New
York, has duly caused this statement of eligibility to be signed on its behalf
by the undersigned, thereunto duly authorized, all in The City of New York, and
State of New York, on the 16th day of July, 1997.
THE BANK OF NEW YORK
By: /s/ WALTER GITLIN
--------------------------------
Name: Walter Gitlin
Title: Vice President
-4-
<PAGE> 5
________________________________________________________________________________
Consolidated Report of Condition of
THE BANK OF NEW YORK
of 48 Wall Street, New York, N.Y. 10286
And Foreign and Domestic Subsidiaries,
a member of the Federal Reserve System, at the close of business March 31,
1997, published in accordance with a call made by the Federal Reserve Bank of
this District pursuant to the provisions of the Federal Reserve Act.
<TABLE>
<CAPTION>
Dollar Amounts
ASSETS in Thousands
<S> <C>
Cash and balances due from depos-
itory institutions:
Noninterest-bearing balances and
currency and coin .................. $ 8,249,820
Interest-bearing balances .......... 1,031,026
Securities:
Held-to-maturity securities ........ 1,118,463
Available-for-sale securities ...... 3,005,838
Federal funds sold and Securities pur-
chased under agreements to resell... 3,100,281
Loans and lease financing
receivables:
Loans and leases, net of unearned
income .................32,895,077
LESS: Allowance for loan and
lease losses ..............633,877
LESS: Allocated transfer risk
reserve........................429
Loans and leases, net of unearned
income, allowance, and reserve 32,260,771
Assets held in trading accounts ...... 1,715,214
Premises and fixed assets (including
capitalized leases) ................ 684,704
Other real estate owned .............. 21,738
Investments in unconsolidated
subsidiaries and associated
companies .......................... 195,761
Customers' liability to this bank on
acceptances outstanding ............ 1,152,899
Intangible assets .................... 683,503
Other assets ......................... 1,526,113
-----------
Total assets ......................... $54,746,131
===========
LIABILITIES
Deposits:
In domestic offices ................ $25,614,961
Noninterest-bearing ......10,564,652
Interest-bearing .........15,050,309
In foreign offices, Edge and
Agreement subsidiaries, and IBFs ... 15,103,615
Noninterest-bearing .........560,944
Interest-bearing .........14,542,671
Federal funds purchased and Securities
sold under agreements to repurchase. 2,093,286
Demand notes issued to the U.S.
Treasury ........................... 239,354
Trading liabilities .................. 1,399,064
Other borrowed money:
With remaining maturity of one year
or less .......................... 2,075,092
With remaining maturity of more than
one year ......................... 20,679
Bank's liability on acceptances exe-
cuted and outstanding .............. 1,160,012
Subordinated notes and debentures .... 1,014,400
Other liabilities .................... 1,840,245
-----------
Total liabilities .................... 50,560,708
-----------
EQUITY CAPITAL
Common stock ........................ 942,284
Surplus ............................. 731,319
Undivided profits and capital
reserves .......................... 2,544,303
Net unrealized holding gains
(losses) on available-for-sale
securities ........................ ( 19,449)
Cumulative foreign currency transla-
tion adjustments .................. ( 13,034)
------------
Total equity capital ................ 4,185,423
-----------
Total liabilities and equity
capital ........................... $54,746,131
===========
</TABLE>
I, Robert E. Keilman, Senior Vice President and Comptroller of the
above-named bank do hereby declare that this Report of Condition has been
prepared in conformance with the instructions issued by the Board of Governors
of the Federal Reserve System and is true to the best of my knowledge and
belief.
Robert E. Keilman
We, the undersigned directors, attest to the correctness of this Report of
Condition and declare that it has been examined by us and to the best of our
knowledge and belief has been prepared in conformance with the instructions
issued by the Board of Governors of the Federal Reserve System and is true and
correct.
Alan R. Griffith )
J. Carter Bacot ) Directors
Thomas A. Renyi )
________________________________________________________________________________
