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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
OR
[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _________ TO _______
Commission File Number: 0-8898
MIDCOAST ENERGY RESOURCES, INC.
(Name of Registrant as Specified in its Charter)
Nevada 76-0378638
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)
1100 Louisiana, Suite 2950
Houston, Texas 77002
(Address of Principal Executive Offices) (Zip Code)
ISSUER'S TELEPHONE NUMBER: (713) 650-8900
SECURITIES REGISTERED UNDER SECTION 12(b) OF THE ACT: Common Stock,
Par Value $.01 Per Share
SECURITIES REGISTERED UNDER SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the issuer (1) filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
during of 1934 during the preceding 12 months (or for such shorter period that
registrant was required to file such reports), and (2)has been subject to such
filing requirements for the past 90 days.
Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. []
The aggregate market value of the Common Stock, par value $.01 per
share, held by non-affiliates of Registrant as of March 11, 1998 was
$96,263,945.
The number of shares of Common Stock, par value $.01 per share,
outstanding as of March 31, 1998 was 5,681,330.
DOCUMENTS INCORPORATED BY REFERENCE
The information required by Part III of this Report (Items 10, 11, 12
and 13) is incorporated by reference from the registrant's proxy statement to be
filed pursuant to Regulation 14A with respect to the annual meeting of
shareholders scheduled to be held on May 15, 1998.
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TABLE OF CONTENTS
PART I
ITEM 1. BUSINESS............................................................3
ITEM 2. PROPERTIES.........................................................14
ITEM 3. LEGAL PROCEEDINGS..................................................14
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS................14
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED
SHAREHOLDER MATTERS.............................................14
ITEM 6. SELECTED FINANCIAL DATA............................................15
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS.......................................16
ITEM 8. FINANCIAL STATEMENTS...............................................24
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE........................................42
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.................42
ITEM 11. EXECUTIVE COMPENSATION.............................................42
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.....42
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.....................42
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS
ON FORM 8-K.....................................................43
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PART I
ITEM 1. BUSINESS.
GENERAL
Midcoast Energy Resources, Inc., its subsidiaries and affiliated companies
(referred to collectively as the "Company" or "Midcoast") is primarily engaged
in the transportation, gathering, processing and marketing of natural gas and
other petroleum products. The Company owns and operates two interstate
transmission pipeline systems, three intrastate transmission systems, 20
end-user systems and 26 gathering systems representing over 1,400 miles of
pipeline with an aggregate daily throughput capacity of over 1.3 Bcf/day. The
Company's principal business consists of providing transportation services
through its pipelines to both end-users and natural gas producers, providing
natural gas marketing services to these customers and processing natural gas. In
connection with these services, the Company acquires and constructs pipelines to
supply natural gas directly to industrial and municipal end-users and provides
access to pipeline systems for natural gas producers through its gathering
systems.
The Company's principal assets are located in the Gulf Coast area and
include (i) a 288 mile interstate transmission pipeline and two end-user
pipelines in northern Alabama, Mississippi and southern Tennessee (collectively,
the "MIT Systems"), (ii) a 386 mile interstate transmission pipeline along with
one intrastate, two end-user pipelines and two offshore gathering pipelines,
located in Louisiana (collectively, the "Midla Systems"), (iii) a 111 mile
natural gas transmission and gathering pipeline in the Black Warrior Basin of
central Alabama (the "Magnolia System") and (iv) a 155 mile natural gas
gathering pipeline and sour gas processing plant in Mississippi (the "Harmony
System").
Midcoast was incorporated as a Nevada corporation in 1992. Midcoast leases
its principal executive offices at 1100 Louisiana, Suite 2950, Houston, Texas
77002, and its telephone number is (713) 650-8900. Midcoast also owns or leases
other regional offices in Alabama, Louisiana, Mississippi and Texas.
BUSINESS GROWTH STRATEGY
The Company's principal business strategy is to increase its earnings and
cash flow by acquiring or constructing pipeline systems, aggressively pursuing
end-user customers, increasing the utilization of its existing pipeline systems
and processing plants in order to enhance the Company's profitability and
improving cost efficiencies.
The Company implements its strategy through the following steps:
ACQUISITION OR CONSTRUCTION OF PIPELINE AND PROCESSING SYSTEMS. The
Company seeks to acquire or construct natural gas transmission,
end-user, gathering and processing systems which offer the opportunity
for increased utilization and expansion of the system due to their
proximity to geographic areas where municipal and industrial demand for
natural gas is growing or where drilling activity is expected to
increase. The Company seeks to acquire or construct additional
transmission and gathering systems or processing facilities in its core
geographic areas of operation when the Company believes such additional
systems will enhance the overall profitability of the area of operation.
FOCUS ON END-USERS. As a result of recent regulatory changes, natural
gas customers have more flexibility to negotiate their natural gas
purchase and transportation contracts. The Company actively pursues
direct sales to these end-users, such as industrial plants and
municipalities, which are seeking alternative supplies to meet their
energy needs. The Company seeks to build pipeline systems directly
connecting these customers to transmission systems and to enter into
long-term transportation agreements that provide the Company with a
stable, non-depletive gas throughput and cash flow. The Company also
offers gas marketing services to its end-user customers who typically
incur a reduced transportation cost by receiving natural gas through a
Company-owned pipeline.
UTILIZATION OF EXISTING SYSTEMS' CAPACITY. After a system is acquired or
constructed, the Company begins an aggressive marketing effort to fully
utilize the system's capacity. As part of this process, the Company
focuses on providing quality service to its end-user and natural gas
producer customers. Many of the Company's existing pipeline and
processing systems were designed with excess
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throughput capacity that provide the Company with opportunities to
pursue additional gas volumes with little incremental capital cost and
to provide higher-margin "swing" sales during periods of increased gas
demand.
COST EFFICIENCIES. The Company generally seeks to achieve administrative
and operational efficiencies by reducing overhead, increasing
utilization of equipment and personnel, capitalizing on the geographic
proximity of many of its systems and further integrating gas
transmission and marketing services. The Company also seeks to acquire
or construct additional transmission and gathering systems or processing
facilities in its core geographic areas of operation where it can
achieve administrative or operational efficiencies when integrated with
the Company's existing systems. The Company actively focuses on
eliminating duplicative efforts, to install advanced technologies and
control systems and other efficiency-targeted projects which will help
to minimize costs and enhance the Company's flexibility to respond to
emerging opportunities.
PIPELINE ACQUISITIONS AND CONSTRUCTION
Since the first quarter of 1994, the Company has acquired ownership of or
interests in 44 pipelines, 11 of which occurred in 1997. Of the total, five are
transmission lines, 13 are end-user pipelines and 26 are gathering systems.
During this time, the Company has expanded into the interstate pipeline and
natural gas processing markets with their acquisitions of the Midla, MIT and
Harmony Systems. The following is a summary of the Company's acquisition and
construction activities during 1997.
ACQUISITIONS
THE MIT SYSTEMS. Consistent with the Company's business strategy, in May 1997,
Midcoast acquired the MIT Systems and their related pipeline and energy services
operations from Atrion Corporation ("Atrion") for cash consideration of $38.2
million and up to $2 million in contingent deferred payments (the "MIT
Acquisition"). The acquisition was initially funded through the Company's
existing credit facility. Subsequently the proceeds from the Company's common
stock offering on July 2, 1997 were used to retire the indebtedness incurred on
the MIT Acquisition. The MIT operations include (i) a 288 mile interstate
transmission pipeline located in northern Alabama, Mississippi and southern
Tennessee which transports natural gas to industrial and municipal customers
(the "MIT System"), (ii) a 38 mile and a one mile pipeline in northern Alabama
which primarily serve two large industrial customers (the "Champion System" and
"Monsanto System," respectively) and (iii) a natural gas marketing company which
primarily serves customers of the MIT Systems.
THE MIDLA SYSTEMS. In October 1997, the Company completed its merger of Republic
Gas Partners L.L.C. ("Republic"), which owned Mid Louisiana Gas Company
("MLGC"), Mid Louisiana Gas Transmission Company ("MLGT") and Mid Louisiana
Marketing Company, for cash consideration of $3.2 million, the assumption of
approximately $19.1 million in bank indebtedness, 385,000 shares of Midcoast
common stock, par value $.01 per share ("Common Stock"), warrants to acquire
110,000 shares of Common Stock and an additional 27,500 warrants to acquire
Common Stock subject to certain contingencies which were later met (the "Midla
Acquisition"). The Midla Systems include (i)a 386 mile interstate gas
pipeline which runs from the Monroe gas field in northern Louisiana, southward
through Mississippi to Baton Rouge, Louisiana ("MLGC System"), (ii) one
intrastate and two end-user gas pipelines with a collective length of 7.4 miles
and (iii) two offshore lateral gas pipelines with a collective length of 8.6
miles (the "T33" and "T51" systems). Also acquired in the Midla Acquisition were
two compressor stations with a total of 5,875 horsepower. These pipelines serve
a number of large industrial markets and municipalities including Entergy Gulf
States Inc., the local distribution company for Baton Rouge; Mississippi Valley
Gas Company, the local distribution company for Natchez, Mississippi and several
surrounding communities; International Paper Co.'s facility near Natchez,
Louisana and Exxon Chemical America's complex near Baton Rogue, Louisana, the
Crown Vantage Inc.'s St. Francisville plant in West Feliciana Parish, Louisana
and the Farmland Industries Inc.'s plant in Grant Parish, Louisiana.
Both the MIT Acquisition and Midla Acquisition complement the Company's
existing operations in the Gulf Coast area, which include the Magnolia System,
the Harmony System and numerous other gathering and transmission systems. The
Company believes there are significant opportunities for increasing the
utilization of the MIT and Midla Systems. Since these acquisitions, Midcoast has
succeeded in increasing contracted firm transportation volumes on the MIT system
by 28% for the winter 1998 season, through the completion of two successful open
seasons, and has negotiated new long-term
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marketing, services to an industrial facility near Port Hudson, Louisiana,
as well as, 20 Mmcf/day of natural gas transportation and 40 Mmcf/day
of natural gas marketing services to a new cogeneration facility near Baton
Rouge subject to the construction of additional pipelines facilities scheduled
for completion in the fourth quarter of 1998.
THE RAYMOND SYSTEM. In March 1997, Midcoast acquired a controlling interest in
the Raymond System in south-central Kansas from MAPCO Natural Gas Liquids, Inc.
The system was acquired in exchange for the Cat Springs and Stratton Ridge
systems that were previously owned by Midcoast. The Raymond system consists of a
compressor station and approximately 120 miles of 2" to 6" pipeline located in
McPherson, Rice, Barton and Stafford counties, in Kansas. The system gathers
natural gas from 16 producers across 25 leases for delivery into MAPCO's Conway
Fractionation Facility.
CONSTRUCTION
HARMONY SYSTEM. A $.6 million expansion of the Harmony Plant was completed in
the fourth quarter of 1997. The expansion added five miles of 6" gathering
pipeline that connects to four producing wells. As a result of the expansion,
the incremental deliveries into the Harmony Plant have increased natural gas
liquid ("NGL") sales and residue gas sales by approximately 11% and 5%,
respectively.
MIT SYSTEM. The Company has filed an application with the Federal Energy
Regulatory Commission ("FERC") for the approval of a $2.5 million expansion of
the MIT System consisting of the construction of a 7.38 mile pipeline and
related looping facility in Colbert County, Alabama. The pipeline construction
is expected to be completed in the fourth quarter of 1998.
MIDLA SYSTEMS. The Company embarked on a $10.0 million high-pressure pipeline
construction project in 1997 as a result of new marketing and transportation
contracts to service Exxon Chemical America's cogeneration facility in Baton
Rouge and Georgia Pacific's Port Hudson Paper Plant. The new pipeline is
designed to accommodate other potential customers that have operations along the
proposed construction route. The project is expected to be completed in the
fourth quarter of 1998.
The Company further intends to pursue new construction and acquisition
opportunities in this core geographic area through the acquisition of additional
transmission systems that interconnect to or otherwise provide synergies with
the Midla or MIT Systems as well as the Company's other existing pipeline
systems in the region. The Company intends to continue to pursue cost-saving
measures while emphasizing its gas marketing efforts throughout this region. The
Company plans to continue to evaluate investments in pipelines which involve not
only natural gas, but also liquified petroleum gas, as well as both hydrocarbon
and non-hydrocarbon gases. Management believes that more acquisition
opportunities will become available as major pipeline companies divest of their
existing systems due to regulatory considerations or need to spin-off smaller
non-strategic systems acquired in connection with larger acquisitions. The
Company believes it can capitalize on these opportunities due to the strategic
locations of its pipelines and proximity to other companies' pipeline systems
and in large part to the Company's experience and relationships with others in
the pipeline industry.
OPERATIONS
Substantially all of the Company's revenues are derived from transportation
fees from pipeline systems owned by the Company, the processing and treating of
natural gas and the marketing of natural gas. The Company's various operations
involve the following activities:
MAINLINE TRANSMISSION. The Company's transmission pipelines primarily
receive and deliver natural gas to and from other pipelines, and secondarily
involve some end-user or gathering functions. Transportation fees are received
by the Company for transporting gas owned by other parties through the Company's
pipeline systems. The Company has greatly expanded its transmission pipeline
activities with the Magnolia, MIT and Midla Acquisitions in August 1995, May
1997 and October 1997, respectively. The Company seeks to further expand its
activities in this area through the acquisition
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or construction of natural gas transmission pipelines in its core geographic
areas of operation where operational synergies and market opportunities exist or
in new geographic regions where there is increasing demand for gas by municipal
and industrial users. The Company owns two interstate and three intrastate
transmission pipelines.
END-USER TRANSMISSION. The Company also contracts with industrial
end-users, municipalities or electrical generating facilities to provide natural
gas and natural gas transportation services to their facilities through
interconnect gas pipelines constructed or acquired by the Company. These
pipelines provide a supply of natural gas to new industrial facilities or to
existing facilities as an alternative energy source. The Company intends to
continue to pursue direct sales to these end-users who have more flexibility in
recent years to negotiate their gas purchase and transportation contracts as a
result of industry deregulation. Frequently, the Company is able to offer its
end-user customers rates lower than the customer's current energy supplier. The
Company's contracts with end-user customers typically provide for the payment of
a transportation fee by the customer based on the volume of natural gas
transported through the Company's pipeline. The Company strives to structure the
terms and transportation fees for its end-user systems in such a way as to
provide an acceptable rate of return regardless of any natural gas marketing
revenues. The Company owns interests in 20 end-user pipelines.
GATHERING. The Company's gathering systems typically consist of a network
of small diameter pipelines which collect natural gas or crude oil from points
near producing wells and transport it to larger pipelines for further
transmission. Gathering systems may include meters, separators, dehydration
facilities and other treating equipment owned by the Company or others. The
Company derives revenues from gathering systems by transporting natural gas or
crude oil owned by others through its pipelines for a transportation fee, by
purchasing natural gas and utilizing its pipelines to transport the natural gas
to a customer in another location where the natural gas is resold or, in certain
instances, by purchasing natural gas and arranging for the delivery and resale
of an equivalent quantity of natural gas to a customer not directly served by
the Company's pipelines. Transactions with customers not directly served by the
Company's pipelines are typically accomplished by entering into agreements
whereby the Company exchanges natural gas in its pipelines for natural gas in
the pipelines of other transmission companies. The Company intends to pursue the
construction of additional gas gathering systems in or near its core geographic
operating areas and where drilling activity is expected to provide opportunities
for the expansion of gathering or processing facilities. The Company currently
owns an interest in and operates 26 gathering systems.
NATURAL GAS PROCESSING. The Company's natural gas processing revenues are
realized from the extraction and sale of NGLs as well as the sale of the
residual natural gas. Once extracted the NGLs are further fractionated in the
Company's facilities into products such as ethane, propane, butanes, natural
gasoline and condensate and then sold to various wholesalers along with raw
sulphur from the Company's sulphur recovery plant. The Company, in most
instances, enters into agreements with natural gas producers wherein the Company
and the producer share in the revenue generated from the sale of the NGLs and
natural gas extracted at the Company's facilities. The Company entered the
natural gas processing business in October 1996 with its purchase of the Harmony
System, in central Mississippi. The Company intends to pursue expansion of the
Harmony System through the construction of additional interconnections with
wells in the area.
GAS MARKETING. Historically, the Company's gas marketing activities have
been focused on the Company's systems with a strategic focus to provide quality
and consistent service to its customers connected to the Company's pipeline
network. As a result of the MIT and Midla Acquisitions, the Company has greatly
expanded its natural gas marketing activities in the Alabama/Mississippi and
Louisiana areas. The Company's marketing activities include providing natural
gas supply and sales services to some of its end-user customers by purchasing
the natural gas supply from other marketers or pipeline affiliates and reselling
the natural gas to the end-user. The Company also purchases natural gas directly
from well operators on many of the Company's gathering systems and resells the
natural gas to other marketers or pipeline affiliates. Many of the contracts
pertaining to the Company's gas marketing activities are month-to-month spot
market transactions with numerous gas suppliers or producers in the industry.
The Company also offers other gas services to the customers of its MIT and Midla
Systems, such as management of capacity release, storage service and gas
balancing. The Company intends to further enhance its increased natural gas
marketing presence in its core geographic areas of operation through an
aggressive marketing program focused on end-users' need for additional supplies.
Typically, the Company purchases natural gas at a price determined by
prevailing
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market conditions. Simultaneous with the purchase of natural gas by the Company,
the Company generally resells natural gas at a higher price under a sales
contract which is comparable in its terms to the purchase contract, including
any price escalation provisions. In most instances, natural gas marketing is
characterized by small margins since there are numerous companies of greatly
varying size and financial capacity who compete with the Company in the
marketing of natural gas. The profitability of the natural gas marketing
operations of the Company depends in large part on the ability of the Company's
management to assess and respond to changing market conditions in negotiating
these natural gas purchase and sale agreements. As a consequence of the increase
in competition in the industry and volatility of natural gas prices there has
been a reluctance of end-users to enter into long-term purchase contracts.
Moreover, consumers have shown an increased willingness to switch fuels between
gas and alternate fuels in response to relative price fluctuations in the
market. The inability of management to respond appropriately in changing market
conditions could have a negative effect on the Company's profitability.
Accordingly, historical operating income associated with this revenue stream has
varied depending on market conditions. The Company's gas marketing activities
which utilize third party transporters also exposes the Company to economic risk
resulting from imbalances or nominated volume discrepancies which can result
either in penalties having a negative impact on earnings or a transaction gain,
depending on how and when imbalances are corrected. The Company believes the
marketing of natural gas is an important complement to its transportation
services.
MAJOR CUSTOMERS
The Company's principal customers are industrial end-users, municipalities,
resellers and producers of natural gas. The Company typically enters into one to
five year transportation agreements which may also include provisions regarding
guaranteed minimum volumes and price reductions after the customer meets certain
transportation commitments. The Company also enters into marketing agreements
with many of its customers related to gas supply and other services. For its
FERC regulated entities, the Company enters into transportation contracts
regarding firm and interruptible transportation using the tariff rates approved
by FERC. In certain situations, the Company has offered discounts from its
tariffs in response to specific market conditions.
Key customers under these contracts, representing in excess of 10% of the
Company's gross margin, on a pro forma basis include Champion and Entergy Gulf
States, Inc. Gross margin represents transportation revenues earned in
transmission contracts and the difference between the contract price of the gas
purchased and the contract price of the gas sold. The agreement with Champion,
which expires in 2004, provides for 28 Mmcf/day of firm transportation and a
rate reduction of 41% in the event that Champion meets a minimum transportation
volume, which is expected to occur in 2001 based on Champion's current usage.
The agreements with Entergy Gulf States, Inc., expire in 2000 and 1998, for
marketing and transportation services, respectively. The marketing agreement
provides for volumes which range from 15,000 Mmbtu's to 110,000 Mmbtu's/day. The
marketing agreement will renew on an annual period after the primary expiration.
The transportation agreement provides for volumes which range from 25,000
Mmbtu's to 100,000 Mmbtu's/day. The agreement will renew on an annual period
after the primary expiration.
COMPETITION
The natural gas transportation, gathering, processing and marketing
industries are highly competitive. In marketing natural gas, the Company has
numerous competitors, including marketing affiliates of interstate pipelines,
major integrated oil companies, and local and national natural gas gatherers,
brokers and marketers of widely varying sizes, financial resources and
experience. Many of these competitors, particularly those affiliated with major
integrated oil and interstate and intrastate pipeline companies, have financial
resources substantially greater than those available to the Company. Local
utilities and distributors of natural gas are, in some cases, engaged directly,
and through affiliates, in marketing activities that compete with the Company.
Some of the Company's contracts are month-to-month arrangements and as such,
these agreements are affected by existing competition in the natural gas markets
at the time of sale as well as competition for the cost of natural gas supplies.
The Company competes against other companies in the transmission, gathering
and marketing businesses for supplies of natural gas and for sales customers.
Competition for natural gas supplies is primarily based on efficiency,
reliability, availability of transportation and the ability to offer a
competitive price for natural gas.
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Competition for customers is primarily based upon reliability and price of
deliverable natural gas. For customers that have the capability of using
alternative fuels, such as oil and coal, the Company also competes against
companies capable of providing these alternative fuels at a competitive price.
NATURAL GAS SUPPLY
The Company's transmission and end-user pipelines have connections with
major interstate and intrastate pipelines which management believes have ample
supplies of natural gas in excess of the volumes required for these systems.
However, these purchase contracts may be affected by factors beyond both the
Company's and the gas suppliers' control such as capacity constraints, temporary
regional supply shortages, and, with regard to its gathering systems, other
parties having control over the drilling of new wells, inability of wells to
deliver gas at required pipeline quality and pressure, and depletion of
reserves. The future performance of the Company will depend to a great extent on
the throughput levels achieved by the Company with respect to its existing
pipelines and the pipelines acquired or constructed by it in the future. In
order to maintain the throughput on its gathering systems at current levels, the
Company must access new natural gas supplies to offset the natural decline in
reserves as such supplies are produced. In connection with the construction and
acquisition of its gathering systems, evaluations were made of well and
reservoir data furnished by producers to determine the availability of natural
gas supply for the systems. Based on those evaluations, it is management's
belief that there should be adequate natural gas supply for the Company to
recoup its investment with an adequate rate of return. As such, management does
not routinely obtain independent evaluation of reserves dedicated to its systems
due to the cost of such evaluations. Accordingly, the Company does not have
estimates of total reserves dedicated to its systems or the anticipated life of
such producing reserves.
RATE AND REGULATORY MATTERS
Various aspects of the transportation of natural gas are subject to or
affected by extensive federal regulation under the Natural Gas Act ("NGA"), the
Natural Gas Policy Act of 1978 ("NGPA"), the Natural Gas Wellhead Decontrol Act
of 1989 ("Decontrol Act") and regulations promulgated by the FERC.
Historically, interstate pipeline companies acted as wholesale merchants by
purchasing natural gas from producers, transporting that natural gas from the
fields to their markets, and reselling the natural gas to local distribution
companies and large end-users. Prior to the enactment of the NGPA in 1978 and
the Decontrol Act of 1989, all sales of natural gas for resale in interstate
commerce, including sales by producers, were subject to the rates and service
jurisdiction of the FERC under the NGA and NGPA. However, as a result of the
NGPA and the Decontrol Act, all so-called "first sales" of natural gas were
federally deregulated, thus allowing all types of non-pipeline and non-local
distribution sellers to market their natural gas free from federal controls.
Moreover, pursuant to Section 311 of the NGPA ("Section 311"), the FERC
promulgated regulations by which wholly-intrastate natural gas pipeline
companies could engage in interstate transactions without becoming subject to
the FERC's full rates and service jurisdiction under the NGA. At the same time,
however, the FERC has retained its traditional jurisdiction over the activities
of interstate pipelines. Thus, under the NGA and NGPA, the transportation and
resale of natural gas by interstate pipeline companies have been subject to
extensive regulation, and the construction of new facilities, the extension of
existing facilities, and the commencement and cessation of sales, resales or
transportation services by pipeline companies generally have required prior FERC
authorization.
Commencing in 1985 with the promulgation of Order No. 436, the FERC adopted
regulatory changes that have significantly altered the transportation, sale and
marketing of natural gas. These changes were intended to foster competition in
the natural gas industry by, among other things, transforming the role of the
interstate pipeline companies from wholesale marketers of natural gas to
primarily natural gas transporters, and mandating that interstate pipeline
companies provide open and nondiscriminatory transportation services to all
producers, distributors, marketers and other shippers that seek such services
(so-called "open access" requirements). As an incentive to cause the interstate
pipeline companies to revamp their services, the FERC also sought to expedite
the certification process for new services, facilities, and operations of those
pipeline companies providing "open access" services. Throughout the early years
of this process, the FERC's actions in these areas were subject to extensive
judicial review and generated significant industry comment and proposals for
modification to existing regulations.
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In 1992, the FERC issued its most comprehensive restructuring ruling, Order
636, a complex regulation that has had a major impact on natural gas pipeline
operations, services and rates. Among other things, Order 636 generally required
each interstate pipeline company to "unbundle" its traditional wholesale
services and make available on an open and nondiscriminatory basis numerous
constituent services (such as gathering services, storage services, and firm and
interruptible transportation services) and to adopt a new rate making
methodology to determine appropriate rates for those services. To the extent the
pipeline company or its sales affiliate makes natural gas sales as a merchant in
the future, it will do so pursuant to a blanket sales certificate that puts
those entities in direct competition with all other sellers pursuant to private
contracts, however, pipeline companies were not required by Order 636 to remain
merchants of natural gas, and several of the interstate pipeline companies have
elected to become transporters only. The FERC required that each pipeline
company develop the specific terms of service in individual pipeline
restructuring proceedings by means of a compliance filing that set forth the
pipeline company's new, detailed procedures. In subsequent orders, the FERC
largely affirmed the significant features of Order 636 and denied requests for
stay of the implementation of the new rules pending judicial review. In July
1996, the United States Court of Appeals for the District of Columbia Circuit
(the "D.C. Circuit") largely upheld Order 636, but did remand certain aspects of
Order 636 to the FERC for further explanation including, INTER ALIA, the right
of first refusal mechanism and the eligibility of customers to receive no-notice
transportation service. On February 27, 1997, the FERC issued Order No. 636-C,
its order on remand from the D.C. Circuit. Order No. 636-C is currently pending
on rehearing before the FERC. Orders approving the individual pipeline
restructuring proceedings, however, are the subject of numerous appeals to the
United States Court of Appeals. The outcome of such proceedings and the ultimate
impact that they may have on the Company's business is uncertain. Furthermore,
there can be no assurance that such regulations will be effective in meeting
their goals of creating a level playing field for all natural gas buyers and
sellers. FERC could issue new regulations which may subject some portion of the
Company's unregulated business activity to FERC regulation, subject the MIT and
Midla System to additional regulation or adversely affect the conduct of the
Company's business.
In late 1996 and early 1997, the FERC issued a series of orders
incorporating certain business practice standards of interstate pipelines which
was intended to establish a more efficient and integrated pipeline grid which
will reduce the variations in pipeline business practices and allow customers to
obtain and transport gas from all potential sources of supply more easily and
efficiently. Certain aspects of these orders are currently pending on appeal
before the D.C. Circuit.
INTERSTATE PIPELINE REGULATION. The MIT and MLGC operations constitute
the operations of a "natural gas company," as defined in the NGA. As such, they
are subject to the jurisdiction of FERC. The interstate pipeline operations of
MIT and MLGC are operated pursuant to certificates of public convenience and
necessity and other authorization issued under the NGA and pursuant to the NGPA.
FERC regulates the interstate transportation and certain sales of natural gas,
including among other things, rates and charges allowed natural gas companies,
extensions and abandonment of facilities and service, rates of depreciation and
amortization and certain accounting methods utilized by MIT and MLGC.
Pipeline rates for MIT and MLGC must be filed and approved by FERC, and
such rates are typically submitted as cost-based in order to be deemed to be
just and reasonable. FERC may suspend for up to five months the effectiveness of
rate changes filed by the pipeline, and thereafter permit the changed rate to go
into effect subject to refund. FERC may require the pipeline to refund, with
interest, all or any portion of any increased amount that it finds not to be
just and reasonable. FERC also may investigate, either on its own motion or
pursuant to protests by third parties, the lawfulness of pipeline rates that are
on file.
On April 1, 1993, the MIT System increased its jurisdictional rates from
rates that had been in effect since April 1990. This rate increase was agreed to
in an uncontested settlement with the MIT System's customers which the FERC
approved on December 30, 1993. That agreement was amended in September 1996 to
eliminate the requirement that the MIT System file a new rate case in September
1996 or any year thereafter. As part of that agreement, the MIT System reduced
its rates by 6% effective September 1, 1996.
On June 28, 1996, the MLGC System proposed a decrease in its jurisdictional
rates from rates that had been in effect since 1990. This rate decrease was
agreed to in an uncontested settlement with MLGC's customers and was certified
to the FERC by the presiding Administrative Law Judge on November 26, 1996.
Accordingly, the FERC approved the settlement by letter order dated March 28,
1997.
9
<PAGE>
INTRASTATE PIPELINE REGULATION. The Company's intrastate pipeline
operations, are generally not subject to regulation by the FERC, but are subject
to regulation by various agencies of the states in which the Company operates.
The Magnolia System is subject to the jurisdiction of the FERC with respect to
the transportation rates under Section 311. Under Section 311, an intrastate
pipeline can provide transportation service "on behalf of" any interstate
pipeline or local distribution company without prior FERC authorization.
Specifically, the FERC adopted a so-called transport or title standard requiring
that for purposes of interstate transportation under Section 311, the on behalf
of entity must either (1) have physical custody of or (2) hold title to the gas
at some point during the transaction. Section 311 service must be provided
without undue discrimination or preference and is subject to certain FERC filing
and reporting requirements. The Champion and Monsanto Systems are regulated by
the Alabama Public Service Commission ("APSC"). The rates for transportation to
customers on these two systems are determined by negotiated contracts which are
approved by the APSC. The Company's operations in Texas are subject to the Texas
Gas Utility Regulatory Act, as implemented by the Texas Railroad Commission (the
"TRC"). Generally, the TRC is vested with authority to ensure that rates charged
for natural gas sales and transportation services are just and reasonable. The
Company must also make filings with the TRC for all new and increased rates. The
Company's intrastate systems in Louisiana are subject to the regulations of the
Office of Conservation, Pipeline Division of the Department of Natural Resources
("Commission"). As in other states, this agency possesses authority to review
and authorize transactions of those entities under its jurisdiction. This may
include, but not be limited to, the construction, acquisition, abandonment, and
interconnection of physical facilities and issues regarding transportation rates
and contract pricing. The Company currently conducts no transportation for
others through its Louisiana facilities and, therefore, remains regulated only
on issues governing the construction or abandonment of physical facilities and
contract pricing only to the extent that no claims of "unjust" treatment are
received by the Commission. As in the case of potential federal regulatory
changes, there can be no assurances that state regulatory measures will not
adversely affect the Company's business and financial condition. In such events,
the states' regulatory authorities could temporarily suspend or hinder
operations in a particular state, depending on the authority's view of its
jurisdiction.
GATHERING OPERATIONS REGULATION. The NGA exempts gas gathering facilities
from the direct jurisdiction of the FERC. The Company believes that its
gathering facilities and operations meet the current tests that the FERC uses to
grant nonjurisdictional gathering facility status. Some of the recent cases
applying these tests in a manner favorable to the determination of the Company's
nonjurisdictional status are, however, still subject to rehearing and appeal. In
addition, the FERC's articulation and application of the tests used to
distinguish between jurisdictional pipelines and nonjurisdictional gathering
facilities have varied over time. While the Company believes the current
definitions create nonjurisdictional status for the Company's gathering
facilities, no assurance is available that such facilities will not, in the
future, be classified as regulated transmission facilities and thus, the rates,
terms, and conditions of the services rendered by those facilities would become
subject to regulation by the FERC.
No state in which the Company operates currently regulates gathering fees.
Although the Company is not aware that any state in which it operates a natural
gas gathering system is likely to begin regulation of the Company's natural gas
gathering activities and fees, new or increased state regulation has been
adopted or proposed in other natural gas producing states and there can be no
assurance that such regulation will not be proposed or adopted in states where
the Company conducts gathering activities or that the Company will not expand
into or acquire operations in a state where such regulations could be imposed.
ENVIRONMENTAL AND SAFETY MATTERS. The Company's activities in connection
with the operation and construction of pipelines and other facilities for
transporting, processing, treating, or storing natural gas and other products
are subject to environmental and safety regulation by numerous federal, state
and local authorities. This can include ongoing oversight regulation as well as
requirements for construction or other permits and clearances which must be
granted in connection with new projects or expansions. On the federal level,
regulatory agencies can include the Environmental Protection Agency ("EPA"), the
Occupational Safety and Health Administration, the U.S. Army Corp of Engineers,
the U.S. Fish and Wildlife Service and others. State regulatory agencies or
boards can include various air and water quality control boards, historical and
cultural resources offices, fish and game services and others. Regulatory
requirements can increase the cost of planning, designing, initial installation
and operation of such facilities. Sanctions for violation of these requirements
include a variety of civil and criminal enforcement measures including
assessment of monetary penalties, assessment and remediation requirements and
injunctions as to future compliance. The following is a discussion of certain
environmental and safety concerns related to the Company. It is not intended to
constitute a complete discussion of the various federal, state and local
statutes, rules, regulations, or orders to which the Company's operations may be
subject.
In most instances, the regulatory requirements of, including, without
limitation, those state agencies mentioned above and the EPA, relate to the
release of substances into the environment and include measures to control water
and air pollution. Moreover,
10
<PAGE>
the Company, without regard to fault, could incur liability under the
Comprehensive Environmental Response, Compensation, and Liability Act of 1980,
as amended, or state counterparts, in connection with the disposal or other
releases of hazardous substances, including those arising out of historical
operations conducted by the Company's predecessors. Further, the recent trend in
environmental legislation and regulations is toward stricter standards, and this
will likely continue in the future.
Environmental laws and regulations may also require the acquisition of a
permit before certain activities may be conducted by the Company. Further, these
laws and regulations may limit or prohibit activities on certain lands lying
within wilderness areas, wetlands, areas providing habitat for certain species
or other protected areas. The Company is also subject to other federal, state
and local laws covering the handling, storage or discharge of materials used by
the Company, or otherwise relating to protection of the environment, safety and
health. As an employer, the Company is required to maintain a workplace free of
recognized hazards likely to cause death or serious injury and to comply with
specific safety standards.
The Company will make expenditures in connection with environmental matters
as part of its normal operations and capital expenditures and the possibility
exists that stricter laws, regulations or enforcement policies could
significantly increase the Company's compliance costs and the cost of any
remediation which may become necessary. There is inherent risk of the incurrence
of environmental costs and liabilities in the Company's business due to its
handling of oil, gas and petroleum products, historical industry waste disposal
practices and prior use of gas flow meters containing mercury. There can be no
assurance that material environmental costs and liabilities will not be incurred
by the Company. Management believes, based on its current knowledge, that the
Company has obtained and is in current compliance with all necessary and
material permits and that the Company is in substantial compliance with
applicable material environmental and safety regulations. Further, the Company
maintains insurance coverages that it believes are customary in the industry,
although there can be no assurance that the Company's environmental impairment
insurance will provide sufficient coverage in the event an environmental claim
is made against the Company. An uninsured or underinsured claim of sufficient
magnitude could have a material adverse effect on the Company's financial
condition. The Company's operations are subject to the many hazards inherent in
the natural gas transmission industry. These include damage to pipelines,
related equipment and surrounding properties caused by hurricanes, floods, fires
and other acts of God, inadvertent damage from construction and farm equipment,
leakage of natural gas and other hydrocarbons, fires and explosions, and other
hazards that could also result in personal injury and loss of life, pollution
and suspension of operations. There is no assurance that any such insurance
protection will be sufficient or effective under all circumstances or against
all hazards to which the Company may be subject. The occurrence of a significant
event not fully insured against could materially adversely affect the Company's
operations and financial condition. No assurance can be given that the Company
will be able to maintain adequate insurance in the future at rates it considers
reasonable. Should catastrophic conditions occur which interrupt delivery of gas
for any reason, such occurrence could have a material impact on the
profitability of the Company's operations. The Company is not aware of any
existing environmental or safety claims that would have a material impact upon
its financial position or results of operations. See "Insurance."
PIPELINE SYSTEMS
The Company owns an interest in and operates 51 pipelines. Two interstate
transmission pipelines, three intrastate transmission pipelines, twenty end-user
pipelines and twenty-six gathering pipelines. The majority of these pipelines
are situated strategically in the Company's core Gulf Coast operating area.
Certain information concerning the Company's pipelines is summarized in the
following table:
11
<PAGE>
<TABLE>
<CAPTION>
DATE OF AVERAGE DAILY
ACQUISITION DAILY VOLUME
OR INITIAL LENGTH VOLUME(2) CAPACITY(2)
PIPELINE SYSTEM(1) OPERATIONS LOCATION IN MILES (Mmbtu/DAY) (Mmbtu/DAY)
- ------------------------------------- ---------------- ------------------------------ --------- ---------- ------------
<S> <C> <C> <C> <C>
INTERSTATE TRANSMISSION:
MIT................................ May 1997 Selmer, TN to Huntsville, AL 288.0 96,310 140,000
MLGC............................... Oct 1997 Monroe, LA to Baton Rouge, LA 386.2 98,630 190,000
INTRASTATE TRANSMISSION:
Magnolia........................... September 1995 Central AL 111.0 28,849 120,000
Moores Bridge...................... May 1996 Tuscaloosa Co., AL 4.5 0 4,000
MLGT............................... Oct 1997 E. Baton Rouge, LA .6 14,904 68,000
END-USER:
Burnet............................. December 1989 Burnet Co., TX 1.3 759 3,000
Conway............................. December 1989 Rice Co., KS --(3) 4,511 14,000
Turkey Creek....................... January 1991 Fort Bend Co., TX 15.6 974 5,000
OC/Kansas.......................... June 1991 Wyandotte Co., KS 1.0 2,568 6,500
Clemens Dome....................... February 1992 Brazoria Co., TX --(3) 252 3,000
Augusta............................ July 1993 Butler Co., KS 0.5 165 5,000
Westlake........................... November 1993 Calcasieu Parish, LA 1.3 13,895 50,000
Quindaro........................... November 1994 Wyandotte Co., KS 3.1 774 60,000
OC/Albany.......................... December 1994 Albany Co., NY 0.5 1,334 3,000
Guadalupe (4)...................... February 1996 Culberson Co., TX 6.1 345 10,000
Roane Co (5)....................... August 1996 Roane Co., TN 2.1 496 5,000
South Fulton (5)................... September 1996 Obion Co., TN 0.6 50 1,200
Salt Creek (4)..................... September 1996 Kent & Scurry Cos., TX 39.1 4,509 20,000
Cuero.............................. October 1996 DeWitt Co., TX 5.4 87 2,000
STEC............................... October 1996 Victoria Co., TX 4.0 314 10,000
Falfurrias......................... January 1997 Brooks Co., TX --(3) 260 8,000
Monsanto........................... May 1997 Morgan Co., AL 1.0 3,713 20,000
Champion........................... May 1997 Lawrence & Colbert Cos., AL 38.0 20,224 50,000
Crown Vantage...................... Oct 1997 West Feliciana, LA 2.5 18,958 32,800
Farmlands.......................... Oct 1997 Grant Parish, LA 4.3 22,530 62,000
GATHERING:
Zmeskal............................ June 1994 Victoria Co., TX --(3) 311 3,000
Cook Inlet Gas (5)................. July 1994 Cook Inlet, AK 2.7 334 15,000
Cook Inlet Oil (5)................. July 1994 Cook Inlet, AK 2.7 10,606(6) 120,000(6)
Foss............................... December 1994 Custer Co., OK 4.1 371 5,000
Flores (7)......................... January 1996 Starr Co., TX 9.9 1,177 5,000
Chapa (4).......................... February 1996 Live Oak Co., TX 20.7 2,127 50,000
Guerra (4)......................... February 1996 Webb & Duval Cos., TX 8.4 6,307 50,000
Loma Novia (4)..................... February 1996 Duval & McMullen Cos., TX 15.2 9,048 25,000
Detroit............................ May 1996 Lamar Co., AL 16.5 49 3,000
Fayette............................ May 1996 Fayette Co., AL 62.8 1,015 10,000
Greenwood Springs.................. May 1996 Monroe Co., MS 7.9 141 5,000
Happy Hill......................... May 1996 Fayette Co., AL 5.5 72 3,000
Heidelberg-Koch.................... May 1996 Jasper Co., MS 1.0 140 3,000
Heidelberg-TGP..................... May 1996 Jasper Co., MS 3.5 718 2,500
Millbrook.......................... May 1996 Wilkinson Co., MS 8.9 226 5,000
Sizemore........................... May 1996 Lamar Co., AL 1.0 13 3,000
Lake Rosemound..................... September 1996 Wilkinson Co., MS 18.4 1,970 10,000
Chaparral.......................... October 1996 Monroe Co., MS 9.6 359 3,000
Harmony............................ October 1996 Central MS 155.4 5,069 20,000
Minnie Bock........................ November 1996 Nueces Co., TX 14.0 2,283 10,000
Minnie Bock East................... November 1996 Nueces Co., TX 2.5 183 5,000
Port............................... November 1996 Nueces Co., TX 1.5 1,022 5,000
Rowden............................. November 1996 Duval Co., TX 1.0 117 3,000
Raymond (8)........................ March 1997 Central KS 120.0 661 5,000
T-33............................... October 1997 Offshore, LA 3.9 14,968 24,000
T-51............................... October 1997 Offshore, LA 4.7 6,259 72,000
--------- ---------- ------------
Totals......................... 1,418.5(9) 400,957 1,357,000(9)
========= ========== ============
</TABLE>
- ------------
(1) Unless otherwise indicated, all systems are 100% owned and operated by the
Company.
(2) All volume and capacity information is approximate. Average daily volumes
are based on total volumes transported during the twelve-month period ended
December 31, 1997, except for the Raymond, MIT, Monsanto, Champion, MLGC,
MLGT, Crown Vantage, Farmlands, T-33 and T-51 Systems that were acquired
during 1997. For these systems the average daily volumes are based on total
volumes transported from the date of acquisition or initial operation
through December 31, 1997.
(3) This system is less than a quarter-mile in length.
(4) This system is owned by Pan Grande Pipeline L.L.C. ("Pan Grande"), in which
the Company owns a 50% interest, and is operated by the Company.
(5) These systems are owned and operated by third-parties and the Company
receives throughput charges from these systems.
(6) Volume has been converted from barrels of oil to Mmbtu's of gas using one
barrel of oil to six Mmbtu's.
12
<PAGE>
(7) This system is owned by Starr County Gathering System, a Joint Venture
("Starr County")in which the Company owns a 60% interest, and is operated
by the Company.
(8) The Company owns approximately 66% of this system.
(9) This total excludes inactive systems owned by the Company.
OIL AND GAS PROPERTIES
The Company owns several non-operated working interests in producing and
non-producing oil and gas properties. For the year ended December 31, 1997,
revenues from the Company's oil and gas properties were less than 1% of its
total revenues, and for the same period the Company's oil and gas properties
represented less than 1% of its total assets. The Company owns working interests
in 3,560 gross acres of oil and gas leases and 12 producing wells as well as
other overriding royalty interests. Although it is not expected to become a
major line of business for the Company, management expects that acquisition and
ownership of non-operated oil and gas interests will remain a facet of the
Company's business for the foreseeable future.
TITLE TO PROPERTIES
The Company, as part of its pipeline construction process, must obtain
certain right-of-way agreements from landowners whose property the proposed
pipeline will cross. The terms and cost of these agreements can vary greatly due
to a number of factors. In addition, as part of its acquisition process, the
Company will typically evaluate the underlying right-of-way agreements for the
particular pipeline to be acquired to determine that the pipeline owner has met
all terms and conditions of the underlying right-of-way agreements and that the
agreements are still in full force and effect.
The Company typically relies upon outside service organizations to review
the right-of-way agreements and to make suggestions to the seller as to any
curative work required before closing. The Company typically does not receive a
title opinion or title policy as to these right-of-way agreements due to the
complexity of the records and expense. Occasionally, the Company may seek to
initiate condemnation proceedings where permitted under state law to obtain a
right-of-way necessary for pipeline construction projects. The Company believes
that this process is consistent with standards in the pipeline industry and that
it holds good title to its pipeline systems, subject only to defects which the
Company believes are not material to the ownership of its properties or results
of operations. Substantially all of the Company's pipeline systems are pledged
to secure borrowings under the Company's credit facility. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources and Liquidity."
INSURANCE
The Company's operations are subject to many hazards inherent in the
natural gas transmission industry. The Company maintains insurance coverage for
its operations and properties considered to be customary in the industry. There
can be no assurance, though, that the Company's insurance coverage will be
available or adequate for any particular risk or loss. Although, management
believes that the Company's assets are adequately covered by insurance, a
substantial uninsured loss could have a materially adverse impact on the Company
and its financial position.
EMPLOYEES AND CONTRACT SERVICE ORGANIZATIONS
The Company had 103 full-time employees on December 31, 1997. The Company
has arrangements with other unaffiliated independent pipeline operating
companies who service and operate the Company's extensive field operations and
provide for emergency response measures. The Company is not party to any
collective bargaining agreements. There have been no significant labor disputes
in the past.
FORWARD LOOKING STATEMENTS
See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Disclosure Regarding Forward Looking Statements" for
a discussion of forward looking statements contained above and elsewhere in this
Report.
13
<PAGE>
ITEM 2. PROPERTIES.
See "Item 1. Business" for a discussion of properties and locations.
ITEM 3. LEGAL PROCEEDINGS.
On September 13, 1996, an involuntary petition for relief under Chapter 11
of the United States Bankruptcy Code was filed against Stewart Petroleum Company
("Stewart") in the United States Bankruptcy Court for the District of Alaska
(the "Court") by certain working interest owners in the West McArthur River Unit
("WMRU") Production Facility, which was operated by Stewart. The Company
receives a throughput fee for all oil and natural gas transported through the
WMRU pipeline; however, payment of the Company's throughput fee was suspended by
the Court, and only those claims deemed to be necessary to avoid immediate and
irreparable harm to the Stewart estate were paid. Stewart consented to a order
for relief in January 1997 and subsequently filed a Disclosure Statement and
Plan for Reorganization, as amended (the "Stewart Plan"). In May 1997, the Court
approved the sale to a third party of substantially all Stewart's assets,
including the WMRU. The sale, which was completed in June 1997, was effective
January 1, 1997. Subsequent to the sale, the Company negotiated an assumption
agreement with the purchaser for the Company's throughput interest, wherein the
purchaser paid the Company for all accrued but unpaid throughput fees subsequent
to the effective date and agreed to pay the Company for all future throughput
fees as they become due. An order approving the Stewart Plan was granted by the
court on August 4, 1997 and pursuant to the Stewart Plan, the Company was paid
in full for all throughput fees which were accrued prior to January 1, 1997.
On February 28, 1998, Pan Grande, of which Midcoast owns a 50% interest,
filed for an arbitration hearing with the American Arbitration Association
pursuant to the provisions of a certain contract with regard to a contractual
dispute with Lone Star Gas Company ("Lone Star"). The dispute concerns the
relative obligation of the parties to purchase and sell natural gas. Subsequent
to the arbitration filing by Pan Grande, Lone Star withheld $732,910 from
payments it owes for gas delivered by Pan Grande to Lone Star. These funds were
purportedly withheld for damages claimed by Lone Star as a result of the failure
of Pan Grande to deliver natural gas to Lone Star on a separate occasion. It is
Pan Grande's belief that Lone Star has no legal basis to withhold the funds and
therefore no allowance for bad debt has been provided for in the financial
statements.
The Company is currently involved in certain other litigation. Management
believes that all such litigation arose in the ordinary course of business and
that costs of settlements or judgements arising from such suits will not have a
material adverse effect on the Company's consolidated financial position or
results of operations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company did not submit any matters during the fourth quarter to a vote
of security holders.
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS.
MARKET INFORMATION
The Company's Common Stock began trading August 9, 1996 on the American
Stock Exchange ("AMEX") under the symbol "MRS". The following table sets forth
the high and low sales prices for the Company's Common Stock for the period from
August 9, 1996 to December 31, 1997.
DIVIDENDS
HIGH(1) LOW(1) PAID PER SHARE
1996 --------- ---------- --------------
Third Quarter (partial).. $ 9 5/16 $ 8 15/64 $.07
Fourth Quarter.......... 9 57/64 8 55/64 $.07
1997
First Quarter .......... $ 15 29/32 $ 9 5/16 $.07
14
<PAGE>
Second Quarter.......... 15 51/64 12 25/64 $.07
Third Quarter........... 20 5/8 14 35/64 $.07
Fourth Quarter.......... 25 29/64 17 47/64 $.07
(1) All prices and dividends per share have been adjusted to reflect the 10%
stock dividend declared on February 3, 1998 and paid on March 2, 1998 to
shareholders of record on February 13, 1998.
On March 11, 1998, the closing price for the Common Stock, as reported by
the AMEX, was $21.25 per share. As of March 11, 1998, there were 326 holders of
record of Common Stock. The Company believes that there are substantially more
beneficial holders of Common Stock.
DIVIDEND POLICY
The Company historically paid dividends on the 5% Preferred, which was
redeemed in May 1996. Holders of shares of the Company's Common Stock are
entitled to receive cash dividends out of Company funds legally available
subject to the qualification that dividends need not be declared or paid by the
Board of Directors ("Board") if to do so would be in violation of laws or of
restrictions under contractual arrangements (including credit agreements) to
which the Company is or may hereafter become a party. The Board declared the
Company's initial Common Stock dividend of $.07 per share on August 16, 1996,
which was paid on September 3, 1996, and the Company has declared and paid a
$.07 per share cash dividend on its Common Stock in each successive quarter
since that time. On February 3, 1998, the Board declared a 10% stock dividend to
shareholders of record at the close of business on February 13, 1998. No
fractional shares were issued and shareholders entitled to a fractional share
received a cash payment equal to the market value of the fractional share at the
close of the market on March 2, 1998, which was $22.50.
It is the Company's policy to pay a quarterly dividend, however, the
ability of the Company to pay regular quarterly dividends will depend on the
earnings and financial condition, applicable to state law of the Company, and
payment of future dividends may be restricted by the Company's financial
condition and the Company's credit agreements. Therefore, there can be no
assurances that future dividends will be paid. See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Capital Resources and Liquidity"
ITEM 6. SELECTED FINANCIAL DATA.
The following table sets forth, for the periods and at the dates indicated,
selected historical consolidated financial data for Midcoast. This financial
data has been derived from and should be read in conjunction with the
consolidated financial statements of Midcoast and notes thereto included in Part
II, Item 8.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------------------
1993 1994 1995 1996 1997
-------- -------- -------- ------- --------
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C>
STATEMENTS OF OPERATIONS DATA:
Operating revenues ..................... $ 17,757 $ 14,969 $ 15,622 $29,415 $112,744
Operating income(1) .................... 1,273 349 2,569 2,573 7,291
Interest expense ....................... $ 178 $ 189 $ 339 $ 413 $ 1,067
Income before income taxes and
cumulative effect of a change in
accounting principle ................. 818 148 2,193 1,914 5,914
Net income ............................. 765 27 2,193 1,914 5,764
Net income (loss) applicable to
common shareholders .................. 706 (32) 2,134 1,891 5,764
PER SHARE DATA:
Net income (loss) applicable to common
shareholders
Basic ................................ $ 0.47 $ (.02) $ 1.35 $ .91 $ 1.41
Diluted .............................. $ 0.47 $ (.02) $ 1.35 $ .91 $ 1.37
Weighted average number of common shares
outstanding
Basic ................................ 1,496 1,530 1,584 2,074 4,092
Diluted .............................. 1,496 1,530 1,584 2,078 4,201
Cash dividends declared per common share $ -- $ -- $ -- $ .07 $ .29
OTHER DATA:
Depreciation, depletion and
15
<PAGE>
amortization ......................... $ 264 $ 259 $ 452 $ 818 $ 1,592
General and administrative ............. 889 849 785 1,223 3,455
Cash flow from operating
activities ........................... 815 (515) 2,361 2,564 3,857
BALANCE SHEET DATA:
Working capital (deficit) .............. $ (393) $ (1,105) $ (99) $ 1,135 $ 1,888
Property, plant and equipment,
net .................................. 2,780 4,994 8,206 16,965 97,552
Total assets ........................... 6,439 7,272 11,089 27,303 128,038
Long-term debt, net of current
portion .............................. 670 1,781 3,961 4,015 28,923
Redeemable Preferred stock ............ 200 200 200 -- --
Shareholders' equity ................... 2,029 2,007 4,157 13,593 61,451
</TABLE>
(1) Operating revenues less operating expenses.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion of the historical financial condition and results
of operations of Midcoast should be read in conjunction with "Selected Financial
Data" contained in Part I, Item 6 and with the consolidated financial statements
and related notes thereto contained in Part II, Item 8.
GENERAL
Since its formation, the Company has grown significantly as a result of the
construction and acquisition of new pipeline facilities. Since the first quarter
of 1994, the Company acquired or constructed 44 pipelines for an aggregate
acquisition cost of over $81 million. See "Pipeline Systems". The Company
believes the historical results of operations do not fully reflect the operating
efficiencies and improvements that are expected to be achieved by integrating
the acquired and newly constructed pipeline systems. As the Company pursues its
growth strategy in the future, its financial position and results of operations
may fluctuate significantly from period to period.
The Company's results of operations are determined primarily by the volumes
of gas transported, purchased and sold through its pipeline systems or processed
at its processing facility. Most of the Company's operating costs do not vary
directly with volume on existing systems, thus, increases or decreases in
transportation volumes on existing systems generally have a direct effect on net
income. Also, the addition of new pipeline systems typically results in a larger
percentage of revenues being added to operating income as fixed overhead
components are allocated over more systems. The Company derives its revenues
from three primary sources: (i) transportation fees from pipeline systems owned
by the Company, (ii) the processing and treating of natural gas and (iii) the
marketing of natural gas.
Transportation fees are received by the Company for transporting gas owned
by other parties through the Company's pipeline systems. Typically, the Company
incurs very little incremental operating or administrative overhead cost to
transport gas through its pipeline systems, thereby recognizing a substantial
portion of incremental transportation revenues as operating income.
The Company's natural gas processing revenues are realized from the
extraction and sale of NGLs as well as the sale of the residual natural gas.
Once extracted, the NGLs are further fractionated in the Company's facilities
into products such as ethane, propane, butanes, natural gasoline and condensate,
then sold to various wholesalers along with raw sulfur from the Company's sulfur
recovery plant. Typically, the Company enters into agreements with natural gas
producers wherein the Company and the producer share in the revenue generated
from the sale of NGLs extracted at the Company's facilities. The Company's
processing operations can be adversely affected by declines in NGL prices,
declines in gas throughput or increases in shrinkage or fuel costs. The Company
entered the processing business in October 1996 with its purchase of the Harmony
System.
The Company's gas marketing revenues are realized through the purchase and
resale of natural gas to the Company's customers. Generally, gas marketing
activities will
16
<PAGE>
generate higher revenues and correspondingly higher expenses than revenues and
expenses associated with transportation activities, given the same volumes of
gas. This relationship exists because, unlike revenues derived from
transportation activities, gas marketing revenues and associated expenses
include the full commodity price of the natural gas acquired. The operating
income the Company recognizes from its gas marketing efforts is the difference
between the price at which the gas was purchased and the price at which it was
resold to the Company's customers. The Company's strategy is to focus its
marketing activities on Company owned pipelines. The Company's marketing
activities have historically varied greatly in response to market fluctuations.
The Company has had quarter-to-quarter fluctuations in its financial
results in the past due to the fact that the Company's natural gas sales and
pipeline throughputs can be affected by changes in demand for natural gas
primarily because of the weather. Although, historically, quarter-to-quarter
fluctuations resulting from weather variations have not been significant, the
acquisitions of the Magnolia System, the MIT System and the Midla Systems have
increased the impact that weather conditions have on the Company's financial
results. In particular, demand on the Magnolia System, MIT System and Midla
Systems fluctuate due to weather variations because of the large municipal and
other seasonal customers which are served by the respective systems. As a
result, historically the winter months have generated more income than summer
months on these systems. There can be no assurances that the Company's efforts
to minimize such effects will have any impact on future quarter-to-quarter
fluctuations due to changes in demand resulting from variations in weather
conditions. Furthermore, future results could differ materially from historical
results due to a number of factors including but not limited to interruption or
cancellation of existing contracts, the impact of competitive products and
services, pricing of and demand for such products and services and the presence
of competitors with greater financial resources.
The Company has also from time to time derived significant income by
capitalizing on opportunities in the industry to sell its pipeline systems on
favorable terms as the Company receives offers for such systems which are suited
to another company's pipeline network. Although no substantial divestitures are
currently under consideration, the Company will from time to time solicit bids
for selected properties which are no longer suited to its business strategy.
RESULTS OF OPERATIONS
As indicated in Note 3 - Pipeline Construction and Acquisition, in the
Notes to the Consolidated Financial Statements, Midcoast has acquired or
constructed numerous pipelines in the three year period ended December 31, 1997.
These assets were acquired from numerous sellers, at different periods
throughout the year and all were accounted for under the purchase method of
accounting for business combinations and accordingly, the results of operations
for such pipelines are included in the Company's financial statements only from
the applicable date of the acquisition. As a consequence, the historical results
of operations for the periods presented may not be comparable.
The following tables present certain data for major operating units of
Midcoast for the three years ended December 31, 1997. A discussion follows which
explains significant factors that have affected Midcoast's operating results
during these periods. Gross margin for each of the units is defined as the
revenues of the unit less related direct costs and expenses of the unit. As
previously discussed, the Company provides natural gas marketing services to its
customers. For analysis purposes, the Company accounts for the marketing
services by recording the marketing activity on the operating unit where it
occurs. Therefore, the gross margin for each of the major operating units
include a transportation and marketing component.
TRANSMISSION PIPELINES
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
1995 1996 1997
------ ------- -------
(IN THOUSANDS, EXCEPT
GROSS MARGIN PER Mmbtu)
OPERATING REVENUES:
Transportation Fees .......................... $ 329 $ 979 $ 3,512
Marketing .................................... 2,482 6,586 61,275
------ ------- -------
TOTAL OPERATING REVENUES ............. 2,811 7,565 64,787
------ ------- -------
17
<PAGE>
OPERATING EXPENSES:
Cost of Natural Gas and Transportation Charges 2,453 6,468 57,332
Operating Expenses ........................... 191 301 1,592
------ ------- -------
TOTAL OPERATING EXPENSES ............. 2,644 6,769 58,924
------ ------- -------
GROSS MARGIN ......................... $ 167 $ 796 $ 5,863
====== ======= =======
VOLUME (in Mmbtu)
Transportation ............................... 2,583 9,914 30,752
Marketing .................................... 1,638 2,759 22,454
------ ------- -------
TOTAL VOLUME .................................. 4,221 12,673 53,206
------ ------- -------
GROSS MARGIN per Mmbtu ......................... $ .04 $ .06 $ .11
------ ------- -------
The Company's entrance into the regulated interstate pipeline business
with the acquisition of the MIT System and the MLGC System significantly
enhanced the gross margin generated from the transmission pipelines operating
unit in 1997. The Company's capacity on its transmission pipelines increased
from 139,000 Mmbtu/day to 522,000 Mmbtu/day in 1997 and capacity utilization
rates increased from 20% in 1996 to 46% in 1997.
As a result of the increased capacity utilization rates and additional
transmission pipeline customers utilizing the marketing services of the Company,
the gross margin generated by the transmission pipeline unit increased from
$796,000 in 1996 to $5,863,000 in 1997. In addition, gross margin per Mmbtu
increased 75% from $.06 to $.11 in 1997 due to the higher transportation rates
received on the MIT System and the MLGC System, as well as, negotiating higher
transportation rates from customers on the Magnolia System.
The Company has succeeded in increasing contracted transportation
volumes on both the MIT System and the MLGC System since completing the
acquisitions. Through the completion of two successful open seasons, contracted
demand on the MIT System has increased by 28% for the winter of 1998 which
includes new long term transportation agreements with the cities of Huntsville
and Decatur, Alabama. Construction of new pipeline facilities on the MIT System
is planned to accommodate the incremental volumes generated by the new
transportation contracts and is awaiting FERC approval. Contracted demand on the
MLGC System has increased due to the execution of a new 20 Mmcf/day gas
transportation contract to service a new cogeneration facility near Baton Rouge.
Transportation services under the new contract will commence upon the completion
of related construction of new facilities expected in the fourth quarter of
1998.
END-USER PIPELINES
FOR THE YEAR ENDED
DECEMBER 31,
--------------------------
1995 1996 1997
------ ------- -------
(IN THOUSANDS, EXCEPT
GROSS MARGIN PER Mmbtu)
OPERATING REVENUES:
End-User Transportation Fees .................... $ 845 $ 1,144 $ 2,487
Marketing ....................................... 7,211 13,367 33,862
------ ------- -------
TOTAL OPERATING REVENUES ................ 8,056 14,511 36,349
------ ------- -------
OPERATING EXPENSES:
Cost of Natural Gas and Transportation Charges .. 7,040 13,011 32,673
Operating Expenses .............................. 79 106 208
------ ------- -------
TOTAL OPERATING EXPENSES ................ 7,119 13,117 32,881
------ ------- -------
GROSS MARGIN ............................ $ 937 $ 1,394 $ 3,468
====== ======= =======
VOLUME (in Mmbtu)
Transportation .................................. 4,922 6,682 12,415
Marketing ....................................... 4,328 5,822 11,867
------ ------- -------
TOTAL VOLUME ..................................... 9,250 12,504 24,282
------ ------- -------
GROSS MARGIN per Mmbtu ............................ $ .10 $ .11 $ .14
18
<PAGE>
The Company's gross margin for the end-user pipelines operating unit
increased 149% from $1,394,000 in 1996 to $3,468,000 in 1997. The results of
operations of the TRIGAS subsidiary acquired in the MIT Acquisition accounted
for 75% of the increase. In addition, 1997 included a full year of operations
for several end-user pipeline acquisitions made during 1996. Capacity on the
Company's end-user pipelines increased through acquisitions to 370,500 Mmbtu/day
but only experienced a utilization rate of 26% in 1997. The excess capacity
would allow Midcoast to service any incremental needs of its end-user customers
with little or no additional costs.
Since Midcoast's ownership of MLGT, new contracts have been executed to
provide 25 Mmcf/day of new marketing services beginning January 1, 1998 to an
industrial facility near Port Hudson, Louisiana, and an additional 40 Mmcf/day
of natural gas marketing services to a new cogeneration facility near Baton
Rouge by the end of 1998. The Company is currently constructing a new high
pressure end-user pipeline system to service the new contracts. The new pipeline
will allow the Company to compete for potential new customers along the
industrial corridor of the Mississippi River requiring natural gas at pressures
previously not available through the Midla Systems.
GATHERING PIPELINES AND NATURAL GAS PROCESSING
FOR THE YEAR ENDED DECEMBER 31,
1995 1996 1997
------ ------- -------
(IN THOUSANDS, EXCEPT
GROSS MARGIN PER Mmbtu)
OPERATING REVENUES:
Gathering Transportation Fees ................... $ 463 $ 825 $ 693
Processing Revenue .............................. -- 2,460 4,956
Marketing ....................................... 140 3,595 5,597
------ ------- -------
TOTAL OPERATING REVENUES ................ 603 6,880 11,246
------ ------- -------
OPERATING EXPENSES:
Processing Costs ................................ -- $ 1,443 $ 3,566
Cost of Natural Gas and Transportation Charges .. 117 3,057 4,548
Operating Expenses .............................. 16 227 415
------ ------- -------
TOTAL OPERATING EXPENSES ................ $ 133 $ 4,727 $ 8,529
------ ------- -------
GROSS MARGIN ............................ $ 470 $ 2,153 $ 2,717
====== ======= =======
VOLUME (in Mmbtu)
Gathering ....................................... 5,570 15,635 13,603
Processing ...................................... -- 799 1,850
Marketing ....................................... 108 972 2,170
------ ------- -------
TOTAL VOLUME ..................................... 5,678 17,406 17,623
------ ------- -------
GROSS MARGIN per Mmbtu ............................ $ .08 $ .12 $ .15
The gathering pipelines and natural gas processing operating unit
reflected mixed results in 1997 as compared to 1996. The gross margin for the
operating unit as a whole increased to $2,717,000 in 1997 from $2,153,000 in
1996. Gathering transportation fees decreased by $133,000 due principally to
throughput declines on the Company's
19
<PAGE>
pipeline investment in Alaska. This decrease was more than offset by increased
margins created from marketing transactions on gathering pipelines acquired in
the fourth quarter of 1996.
The volumes and gross margin related to the Company's processing plant
increased in 1997 as a result of having a full year of operations. However, the
processing margins on a per unit basis were negatively impacted by lower
commodity prices in 1997 as compared to 1996. The Company's share of proceeds
from the sale of NGLs and the residue natural gas declines as the price of the
commodity declines. However, a $600,000 expansion of the Harmony Plant's
gathering pipeline in the fourth quarter of 1997 connected four new wells and
increased NGL sales and residue gas sales by approximately 11% and 5%,
respectively. The future profitability of the Harmony Plant will be affected by
changes in commodity pricing of NGLs and natural gas, production curtailments,
shut-in wells and also the natural declines in the deliverability of the
reservoirs connected and dedicated to Midcoast's processing plant.
OTHER INCOME, COSTS AND EXPENSES
In 1997, the Company received revenues of $362,000 from its oil and gas
properties as compared to $248,000 over the same period in 1996. The increase is
primarily associated with a successful drilling program in the Company's Sun
Field properties. In addition, certain of Midcoast's oil and gas properties have
been approved for changes in well spacing and tertiary recovery by
depressurization. The Company believes these factors may contribute to increased
volumes and revenues for its oil and gas properties.
In 1997, the Company's depreciation, depletion and amortization
increased when compared to 1996 primarily due to increased depreciation on
assets acquired in the MIT and Midla Acquisitions. Collectively, these new
acquisitions accounted for 70% of the increase of $775,000.
In 1997, the Company's general and administrative expenses increased
when compared to 1996 primarily due to increased costs associated with the
management of the assets acquired in the MIT and Midla Acquisitions.
Collectively, these new acquisitions accounted for 94% of the increase of
$2,233,000. In addition, the increase can be attributed to the Company's
expansion of its infrastructure to allow for continued growth.
In 1997, the Company's interest expense increased 159% when compared to
the year ended 1996, from $413,000 to $1,067,000. The increase is associated
with additional borrowings of approximately $37.0 million, which were
outstanding for one month and used to bridge finance the MIT Acquisition and the
addition of approximately $21.8 million in debt, that was outstanding for
November and December and used to finance the Midla Acquisition.
The Company recognized annual operating income and net income in 1997 of
$7.3 million and $5.8 million, respectively, as compared to $2.6 million in
operating income and $1.9 million in net income for the year ended 1996. Basic
earnings per share ("EPS") increased 55% from $0.91 in 1996 to $1.41 in 1997.
The Company achieved the increased EPS despite the dilutive effects of issuing
additional shares in the August 1996 and July 1997 common stock offerings. The
significant improvement in EPS is primarily attributable to the positive impact
of accretive acquisitions consummated during 1997.
INCOME TAXES
As of December 31, 1997, the Company had net operating loss ("NOL")
carryforwards of approximately $17.0 million, subject to revision based on
Republics final tax returns, expiring in various amounts from 1998 through 2012.
These NOLs were generated by the Company's predecessor and Republic. The ability
of the Company to utilize the carryforwards is dependent upon the Company
generating sufficient taxable income and will be affected by annual limitations
(currently estimated at approximately $4.9 million)on the use of such
carryforwards due to a change in Shareholder control under the Internal Revenue
Code triggered by the Company's July 1997 Common stock offering and the change
of ownership created by the acquisition of Republic. The Company believes,
however, that the limitation will not materially impact the Company's ability to
utilize the NOL carryforwards prior to their expiration. Depending on
profitability, the limitation could result in the Company's income tax expense
to increase as compared to previous years where no such limitation existed.
CAPITAL RESOURCES AND LIQUIDITY
20
<PAGE>
The Company had historically funded its capital requirements through
cash flow from operations and borrowings from affiliates and various commercial
lenders. However, the capital resources of the Company were significantly
improved with the equity infusion derived from its initial and secondary Common
Stock offerings in August 1996 and July 1997, respectively.
The net proceeds of the Company's combined stock offerings contributed
approximately $42.1 million and significantly improved the Company's financial
flexibility. This increased flexibility has allowed the Company to pursue
acquisition and expansion opportunities utilizing lower cost conventional bank
debt financing. The proceeds from the secondary offering were used to reduce
outstanding bank debt and effectively lowered the Company's long-term debt to
total capitalization ratio to 32% at December 31, 1997.
Based on a re-evaluation of the cash flows generated from the MIT
Acquisition and other Midcoast assets, and the completion of the Company's Midla
Acquisition, the Company has increased its borrowing availability under its bank
financing agreements with Bank One Texas, N.A. ("Bank One"). On October 31,
1997, amendments to the credit agreements were entered into which increased the
Company's borrowing availability from $46.5 million to $80.0 million, eliminated
principal reduction requirements, lowered the interest rate on borrowings, and
extended the maturity of the facility one year to August 22, 2000.
Bank One has committed to lending, in the aggregate, up to $60.0 million
of the $80.0 million in borrowing availability. If required, the additional
$20.0 million may be accessed with the inclusion of another bank lender in a
bank syndication. The amended Credit Agreements provide borrowing availability
as follows: (i) a $15.0 million LC Line of Credit Facility, of which $3.0
million can be used for working capital needs and $12.0 million is available for
issuance of letters of credit, (ii) a $60.0 million Revolver which expires in
August 2000 and (iii) a $5.0 million MIT Revolver expiring August 2000
(collectively the "Credit Agreements".)
When borrowings under the amended Credit Agreements are less than 50% of
the $80.0 million borrowing base, at the Company's option, interest will accrue
at LIBOR plus 1.5% or the Bank One base rate. When borrowings are greater than
50% of available credit, an additional .25% will be added to the above rates.
These rates reflect a 1% reduction in the LIBOR option and a .25% reduction in
the Bank One base rate option effective September 2, 1997. In addition, the
Company is subject to a non-recurring 1% facility fee as funds are borrowed, as
well as a .375% commitment fee payable quarterly on the unused portion of
borrowing availability. The Credit Agreement is secured by all accounts
receivable, contracts, the pledge of the stock of MIT, MLGC and Magnolia
Pipeline Corporation and a first lien security interest in the Company's
pipeline systems.
The borrowing availability under each line is subject to revision, on a
monthly basis for the LC Line of Credit Facility and a semi-annual basis for the
Revolver's, based on the performance of the Company's existing assets and any
asset dispositions or additions from new construction or acquisitions. The
Credit Agreements contains a number of customary covenants that require the
Company to maintain certain financial ratios, and limit the Company's ability to
incur additional indebtedness, transfer or sell assets, create liens, or enter
into a merger or consolidation. Midcoast was in compliance with such financial
covenants, as amended, at December 31, 1997.
The only outstanding long-term indebtedness other than the indebtedness
under the Credit Agreements, are the notes payable to banks associated with the
acquisition of a gas gathering pipeline by Starr County (the "Starr County
Note") and the acquisition of six pipelines by Pan Grande (the "Pan Grande
Note"). The Pan Grande Note was entered into by Pan Grande in March 1996 to
finance the acquisition of the Guadalupe, Chapa, Guerra and Loma Novia pipeline
systems. The Pan Grande Note is secured by each respective system and all
associated transportation revenues with guarantees by each member of Pan Grande
proportionate to their ownership interest. The Pan Grande Note bears interest at
the prime rate plus 1% (9.5% at December 31, 1997). Upon maturity, accelerated
to May 2000 due to prepayments on the note, the balance of principal plus
accrued interest then outstanding is payable in full. The Starr County Note was
entered into by Starr County in January 1996 to finance the acquisition of the
Flores gathering system. The Starr County Note is secured by the Flores System
and all transportation revenues pertaining to the system, with guarantees by
each partner of Starr County, proportionate to their ownership interest.
Accordingly, the Company has guaranteed 60% of the loan value. The Starr County
Note bears interest at the prime rate plus 1% (9.5% at December 31, 1997). Upon
maturity, accelerated to August 1998 due to prepayments on the note, the balance
of principal plus accrued interest then remaining outstanding is payable in
full.
21
<PAGE>
For the year ended December 31, 1997, the Company generated cash flow
from operating activities of approximately $7.6 million before changes in
working capital accounts and had approximately $50.6 million available to the
Company under its Credit Agreements. At December 31, 1997, the Company had
committed to making approximately $12.5 million in capital expenditures in 1998
- - see "Construction". The Company believes that its existing Credit Agreement
and funds provided by operations will be sufficient for it to meet its operating
cash needs for the foreseeable future, and its projected capital expenditures of
approximately $12.5 million. If funds under the Credit Agreement are not
available to fund acquisition and construction projects the Company would seek
to obtain such financing for the sale of equity securities or other debt
financing. There can be no assurances that any such financing will be available
on terms acceptable to the Company. Should sufficient capital not be available,
the Company will not be able to implement its acquisition strategy.
RISK MANAGEMENT
According to guidelines provided by the Board, the Company enters into
exchange-traded commodity futures, options and swap contracts to reduce the
exposure to market fluctuations in price and transportation costs of energy
commodities and is not to engage in speculative trading. Approvals are required
from senior management prior to the execution of any financial derivative. The
financial derivatives have pricing terms indexed to both the New York Mercantile
Exchange and the Kansas City Board of Trade. The Company's market exposures
arise from inventory balances and fixed price purchase and sale commitments. The
Company uses the exchange-traded commodities to manage and hedge price risk
related to these market exposures.
Gas futures involve the buying and selling of natural gas at a fixed
price. Over-the-counter swap agreements require the Company to receive or make
payments based on the difference between a specified price and the actual price
of natural gas. The Company uses futures and swaps to manage margins on
offsetting fixed-price purchase or sales commitments for physical quantities of
natural gas. Options held to hedge risk provide the right, but not the
obligation, to buy or sell energy commodities at a fixed price. The Company
utilizes options to manage margins and to limit overall price risk exposure.
(See Note 13 - Risk Management, in the Notes to the Consolidated Financial
Statements).
RECENT ACCOUNTING PRONOUNCEMENTS
The FASB issued SFAS No. 123, "Accounting for Stock Based Compensation,"
effective for fiscal years beginning after December 15, 1995. This statement
allows companies to choose to adopt the statement's new rules for accounting for
employee stock based compensation plans. For those companies who choose not to
adopt the new rules, the statement requires disclosures as to what earnings per
share would have been if the new rules had been adopted. Management has adopted
the disclosure requirements of this statement in 1997 (See Note 12 - Stock
Option Plans, in the Notes to the Consolidated Financial Statements).
The FASB also issued SFAS No. 128, entitled "Earnings Per Share", during
February 1997. The new statement, which is effective for financial statements
issued after December 31, 1997, including interim periods, establishes standards
for computing and presenting earnings per share. The new statement requires
retroactive restatement of all prior-period earnings per share data presented.
The new statement has been adopted by the Company, as a result current earnings
and all prior earnings have been retroactively restated.
The FASB also issued SFAS No. 130, "Reporting Comprehensive Income" and
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information". SFAS No. 130 establishes standards for reporting and display of
comprehensive income, its components and accumulated balances. Comprehensive
income is defined to include all changes in equity except those resulting from
investments by owners and distribution to owners. Among other disclosures, SFAS
No. 130 requires that all items that are required to be recognized under current
accounting standards as components of comprehensive income be reported in a
financial statement that displays with the same prominence as other financial
statements. SFAS No. 131 supercedes SFAS No. 14, "Financial Reporting for
Segments of a Business Enterprise". SFAS No. 131 establishes standards on the
way that public companies report financial information about operating segments
in annual financial statements and requires reporting of selected information
about operating segments in interim financial statements issued to the public.
It also establishes standards for disclosures regarding products and services,
geographic areas
22
<PAGE>
and major customers. SFAS No. 131 defines operating segments as components of a
company about which separate financial information is available that is
evaluated regularly by the chief operating decision maker in deciding how to
allocate resources and in assessing performance.
SFAS Nos. 130 and 131 are effective for financial statements for periods
beginning after December 15, 1997 and require comparative information for
earlier years to be restated. Because of the recent issuance of these standards,
management has been unable to fully evaluate the impact, if any, the standards
may have on the future financial statement disclosures. Results of operations
and financial position, however, will be unaffected by implementation of these
standards.
YEAR 2000
In 1998, the Company will commence a year 2000 data conversion project.
Project completion is planned for third quarter 1998. The Company has determined
that it will replace certain systems, whose associated costs would be recorded
as assets and amortized. Accordingly, the Company does not expect the amounts
required to be expensed over the next two years to have a material effect on its
financial position or results of operations. There were no expenses incurred in
1997.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This report includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Exchange Act of 1934. All statements other than statements of historical fact
included in this report are forward looking statements. Such forward looking
statements include, without limitation, statements under "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Capital Resources and Liquidity" regarding Midcoast's estimate of the
sufficiency of existing capital resources, whether funds provided by operations
will be sufficient to meet its operational needs in the foreseeable future, and
its ability to utilize NOL carryforwards prior to their expiration. Although
Midcoast believes that the expectations reflected in such forward looking
statements are reasonable, it can give no assurance that such expectations
reflected in such forward looking statements will prove to be correct. The
ability to achieve Midcoast's expectations is contingent upon a number of
factors which include (i) timely approval of Midcoast's acquisition candidates
by appropriate governmental and regulatory agencies, (ii) the effect of any
current or future competition, (iii) retention of key personnel and (iv)
obtaining and timing of sufficient financing to fund operations and/or
construction or acquisition opportunities. Important factors that could cause
actual results to differ materially from the Company's expectations ("Cautionary
Statements") are disclosed in this report, including without limitation those
statements made in conjunction with the forward looking statements included in
this report. All subsequent written and oral forward looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.
23
<PAGE>
ITEM 8. FINANCIAL STATEMENTS
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
Index to Consolidated Financial Statements
PAGE
----
Independent Auditors Report ............................................... 25
Consolidated Balance Sheets ............................................... 26
Consolidated Statements of Operations ..................................... 27
Consolidated Statements of Shareholders' Equity ........................... 28
Consolidated Statements of Cash Flows ..................................... 29
Notes to Consolidated Financial Statements ................................ 30
24
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Board of Directors and Shareholders
Midcoast Energy Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Midcoast
Energy Resources, Inc. and subsidiaries as of December 31, 1996 and 1997, and
the related consolidated statements of operations, shareholders' equity and cash
flows for each of the years in the three year period ended December 31, 1997.
These consolidated 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 audits to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Midcoast
Energy Resources, Inc., and subsidiaries as of December 31, 1996 and 1997, and
the results of their operations and their cash flows for each of the years in
the three year period ended December 31, 1997, in conformity with generally
accepted accounting principles.
HEIN + ASSOCIATES LLP
Houston, Texas
February 27, 1998
25
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
<TABLE>
<CAPTION>
December 31, December 31,
1996 1997
------------- -------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ................................................ $ 1,167,825 $ 307,652
Accounts receivable, no allowance for doubtful accounts .................. 8,891,808 27,523,904
Materials and supplies, at average cost .................................. -- 1,225,490
------------- -------------
Total current assets ............................................... 10,059,633 29,057,046
------------- -------------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities ...................................... 11,939,173 90,858,552
Investment in transmission facilities .................................... 1,302,303 1,341,506
Natural gas processing facilities ........................................ 3,735,262 4,625,862
Oil and gas properties, using the full-cost method of accounting.......... 1,274,436 1,343,765
Other property and equipment ............................................. 264,842 2,411,361
------------- -------------
18,516,016 100,581,046
ACCUMULATED DEPRECIATION, DEPLETION
AND AMORTIZATION ......................................................... (1,550,670) (3,029,031)
------------- -------------
16,965,346 97,552,015
OTHER ASSETS, net of amortization .......................................... 278,235 1,429,260
------------- -------------
Total assets ....................................................... $ 27,303,214 $ 128,038,321
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities ................................. $ 8,464,395 $ 25,779,227
Other current liabilities ................................................ 83,000 491,205
Short-term borrowing from bank ........................................... 180,000 700,000
Current portion of long-term debt payable to banks ....................... 196,831 198,857
------------- -------------
Total current liabilities .......................................... 8,924,226 27,169,289
------------- -------------
LONG-TERM DEBT PAYABLE TO BANKS ............................................ 4,015,146 28,923,239
OTHER LIABILITIES .......................................................... 152,167 189,348
DEFERRED INCOME TAXES ...................................................... -- 9,612,987
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES ............................. 618,591 692,354
COMMITMENTS AND CONTINGENCIES (Note 6)
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value, 10 million shares authorized, 2,499,999 and
5,681,330 shares issued and outstanding at
December 31, 1996 and December 31, 1997, respectively ................. 25,000 56,813
Paid-in capital .......................................................... 26,941,660 80,694,489
Accumulated deficit ...................................................... (13,283,876) (19,282,598)
Unearned compensation .................................................... (89,700) (17,600)
------------- -------------
Total shareholders' equity ......................................... 13,593,084 61,451,104
------------- -------------
Total liabilities and shareholders' equity ........................ $ 27,303,214 $ 128,038,321
============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
26
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
--------------------------------------------
December 31, December 31, December 31,
1995 1996 1997
------------ ------------ -------------
<S> <C> <C> <C>
OPERATING REVENUES:
Sale of natural gas ........................... $ 9,832,769 $ 23,547,722 $ 100,733,681
Transportation fees ........................... 1,636,625 2,948,253 6,692,560
Natural gas processing revenue ................ -- 2,459,683 4,955,874
Sale of pipelines ............................. 4,092,850 211,888 --
Oil and gas revenues .......................... 60,046 247,787 361,915
------------ ------------ -------------
Total operating revenues .............. 15,622,290 29,415,333 112,744,030
------------ ------------ -------------
OPERATING EXPENSES:
Cost of natural gas and transportation charges 9,895,793 23,169,573 96,767,971
Natural gas processing cost ................... -- 1,442,681 3,565,904
Cost of pipelines sold ........................ 1,909,624 131,055 --
Production of oil and gas ..................... 11,544 58,472 71,052
Depreciation, depletion and amortization ..... 451,551 817,807 1,592,362
General and administrative .................... 784,653 1,222,531 3,455,415
------------ ------------ -------------
Total operating expenses .............. 13,053,165 26,842,119 105,452,704
------------ ------------ -------------
Operating income ...................... 2,569,125 2,573,214 7,291,326
NON-OPERATING ITEMS:
Interest expense .............................. (339,324) (412,629) (1,066,738)
Minority interest in consolidated subsidiaries -- (197,731) (222,123)
Other income (expense), net ................... (36,400) (48,765) (88,014)
------------ ------------ -------------
Total non-operating items ............. (375,724) (659,125) (1,376,875)
------------ ------------ -------------
INCOME BEFORE INCOME TAXES ...................... 2,193,401 1,914,089 5,914,451
PROVISION FOR INCOME TAXES ...................... -- -- (150,000)
------------ ------------ -------------
Net income ............................ 2,193,401 1,914,089 5,764,451
5% CUMULATIVE PREFERRED STOCK DIVIDENDS ......... (59,183) (22,863) --
------------ ------------ -------------
NET INCOME TO COMMON SHAREHOLDERS ............... $ 2,134,218 $ 1,891,226 $ 5,764,451
============ ============ =============
EARNINGS PER COMMON SHARE
Basic ................................. $ 1.35 $ .91 $ 1.41
============ ============ =============
Diluted ............................... $ 1.35 $ .91 $ 1.37
============ ============ =============
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING
Basic ................................. 1,583,567 2,074,155 4,092,135
============ ============ =============
Diluted ............................... 1,583,567 2,078,119 4,201,165
============ ============ =============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
27
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
5%
CUMULATIVE TOTAL
PREFERRED COMMON PAID-IN ACCUMULATED UNEARNED SHAREHOLDERS'
STOCK STOCK CAPITAL DEFICIT COMPENSATION EQUITY
--------- ------- ----------- ------------ --------- ------------
<S> <C> <C> <C> <C> <C> <C>
BALANCE, December 31, 1994 ....................... $ 200,000 $14,023 $18,740,252 $(16,909,320) $ (38,400) $ 2,006,555
Shares issued or vested under various
stock-based compensation arrangements .......... -- 634 84,429 -- (68,400) 16,663
Net income ....................................... -- -- -- 2,193,401 -- 2,193,401
5% cumulative preferred stock dividends .......... -- -- -- (59,183) -- (59,183)
--------- ------- ----------- ------------ --------- ------------
BALANCE, December 31, 1995 ....................... $ 200,000 $14,657 $18,824,681 $(14,775,102) $(106,800) $ 4,157,436
Shares issued in conjunction with a
financing agreement with an affiliate .......... -- 45 5,955 -- -- 6,000
Shares issued or vested under various
stock-based compensation arrangements .......... -- 298 38,401 -- 17,100 55,799
Redemption of 200,000 shares of 5%
cumulative preferred stock ..................... (200,000) -- 81,634 -- -- (118,366)
Sale of 1,000,000 shares of common stock ......... -- 10,000 7,990,989 -- -- 8,000,989
Net income ....................................... -- -- -- 1,914,089 -- 1,914,089
5% cumulative preferred stock dividends .......... -- -- -- (22,863) -- (22,863)
Common stock dividends,
$.07 per share ................................. -- -- -- (400,000) -- (400,000)
--------- ------- ----------- ------------ --------- ------------
BALANCE, December 31, 1996 ....................... $ -- $25,000 $26,941,660 $(13,283,876) $ (89,700) $ 13,593,084
Shares vested under various stock-based
compensation arrangements ...................... -- -- -- -- 72,100 72,100
Sale of 2,315,000 shares of common stock ......... -- 23,150 34,029,669 -- -- 34,052,819
Common stock and warrants issued in conjunction
with the Midla Acquisition (Note 3)............. -- 3,500 9,167,375 -- -- 9,170,875
10% stock dividend (516,330 shares)(Note 7) ...... -- 5,163 10,555,785 (10,564,773) -- (3,825)
Net income ....................................... -- -- -- 5,764,451 -- 5,764,451
Common stock dividends,
$.29 per share ................................. -- -- -- (1,198,400) -- (1,198,400)
--------- ------- ----------- ------------ --------- ------------
BALANCE, December 31, 1997 ....................... $ -- $56,813 $80,694,489 $(19,282,598) $ (17,600) $ 61,451,104
========= ======= =========== ============ ========= ============
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
28
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
<TABLE>
<CAPTION>
FOR THE YEAR ENDED
-----------------------------------------
December 31, December 31, December 31,
1995 1996 1997
----------- ------------ ----------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income applicable to common shareholders ..........$ 2,134,218 $ 1,891,226 $5,764,451
Adjustments to arrive at net cash provided by
operating activities-
Depreciation, depletion and amortization ............ 451,551 817,807 1,592,362
Gain on sale of operating pipeline .................. -- (80,833) --
Recognition of deferred income ...................... (83,000) (83,000) (83,000)
Minority interest in consolidated subsidiaries ...... -- 197,731 222,123
Other ............................................... (27,205) 8,486 69,378
Changes in working capital accounts-
Increase in accounts receivable ..................... (321,155) (6,574,566) (12,021,959)
Increase in other current assets .................... -- -- (933,394)
Increase in accounts payable and accrued liabilities. 206,455 6,387,125 9,246,770
----------- ------------ ----------
Net cash provided by operating activities ..... 2,360,864 2,563,976 3,856,731
----------- ------------ ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions .......................................... (3,455,589) (8,362,519) (60,778,474)
Capital expenditures .................................. (429,693) (1,028,447) (1,410,129)
Sale of operating pipelines ........................... -- 211,888 --
Other ................................................. (18,644) 337,185 (308,400)
----------- ------------ ----------
Net cash used by investing activities ......... (3,903,926) (8,841,893) (62,497,003)
----------- ------------ ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings .................................. 5,857,505 9,288,000 65,320,742
Bank debt repayments .................................. (5,011,023) (8,388,968) (39,890,623)
Net proceeds from equity offering ..................... -- 8,113,058 34,052,819
Proceeds from notes payable to shareholders
and affiliates ....................................... 3,906,272 100,000 --
Repayments on notes payable to shareholders
and affiliates ....................................... (3,147,450) (1,133,822) -
Financing costs ....................................... (22,011) (120,312) (504,439)
Redemption of 5% cumulative preferred stock ........... -- (118,366) --
Dividends on common stock ............................. -- (400,000) (1,198,400)
----------- ------------ ----------
Net cash provided by financing activities .... 1,583,293 7,339,590 57,780,099
----------- ------------ ----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS ................................... 40,231 1,061,673 (860,173)
----------- ------------ ----------
CASH AND CASH EQUIVALENTS, beginning of year ............ 65,921 106,152 1,167,825
----------- ------------ ----------
CASH AND CASH EQUIVALENTS, end of year .................. $ 106,152 $ 1,167,825 $ 307,652
=========== ============ ==========
CASH PAID FOR INTEREST .................................. $ 323,376 $ 410,897 $ 705,631
=========== ============ ==========
CASH PAID FOR INCOME TAXES .............................. $ -- $ 40,000 $ 241,357
=========== ============ ==========
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
29
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BACKGROUND AND INFORMATION:
Midcoast Energy Resources, Inc. ("Midcoast" or "the Company") was formed on
May 11,1992, as a Nevada corporation and, in September 1992, became the
successor to Nugget Oil Corporation. The merger was accounted for as a pooling
of interests.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
BASIS OF PRESENTATION
The accompanying consolidated financial statements include the accounts of
the Company, all of its wholly-owned subsidiaries and those subsidiaries in
which the Company owns a controlling interest or is in a control position. As of
December 31, 1997, the Company's wholly-owned subsidiaries include Magnolia
Pipeline Corporation ("Magnolia), Magnolia Resources, Inc., Magnolia Gathering,
Inc., H&W Pipeline Corporation, Midcoast Holdings No. One, Inc., Midcoast
Marketing, Inc. ("MMI"), Midcoast Gas Pipeline, Inc., Nugget Drilling
Corporation, Midcoast Interstate Transmission Inc. ("MIT"), Tennessee River
Interstate Gas Company, Inc. ("TRIGAS"), Mid Louisiana Gas Company ("MLGC"), Mid
Louisiana Gas Transmission Company ("MLGT") and Mid Louisiana Marketing Company
("MLMC"). The consolidated subsidiaries in which the Company owns a controlling
interest or is in a control position are Starr County Gathering System, a Joint
Venture ("Starr County"), Pan Grande Pipeline, L.L.C., a Texas limited liability
company ("Pan Grande") and Arcadia/Midcoast Pipeline of New York, L.L.C., a New
York limited liability company. All significant intercompany transactions and
balances have been eliminated. Certain reclassification entries were made with
regard to Consolidated Financial Statements for the year ended December 31, 1995
and December 31, 1996 so that the presentation of the information is consistent
with reporting for the Consolidated Financial Statements for the year ended
December 31, 1997.
INCOME TAXES
Midcoast and its subsidiaries file a consolidated federal income tax
return. Midcoast accounts for income taxes under the provisions of Statement of
Financial Accounting Standards (SFAS) No. 109 -- "Accounting for Income Taxes."
Under SFAS 109, the Company recognizes deferred income taxes for the differences
between the financial and income tax bases of its assets and liabilities.
REGULATED PIPELINES
MIT and MLGC are subject to the provisions of SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation." Regulatory assets represent
probable future revenue to MIT and Midla associated with certain costs which
will be recovered from customers through the regulatory, or the rate making
process. MIT and MLGC had no material regulatory assets or liabilities on its
books as of December 31, 1997.
FERC regulates the interstate transportation and certain sales of natural
gas, including among other things, rates and charges allowed natural gas
companies, extensions and abandonment of facilities and service, rates of
depreciation and amortization and certain accounting methods utilized by MIT and
MLGC.
PROPERTY, PLANT AND EQUIPMENT
Interstate and intrastate natural gas transmission, distribution and
processing facilities and other equipment are depreciated by the straight-line
method at rates based on the following estimated useful lives of the assets:
Interstate natural gas
transmission facilities................ 15 - 66 years
Intrastate natural gas
transmission facilities................ 15 - 60 years
Pipeline right-of-ways.................. 17.5 years
Natural gas processing facilities....... 30 years
Other property and equipment............ 3 - 10 years
30
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For regulated interstate natural gas transmission facilities the cost of
additions to property, plant and equipment includes direct labor and material
allocable overheads and an allowance for the estimated cost of funds used during
construction ("AFUDC"). Such provisions for AFUDC are not reflected separately
in the accompanying consolidated statements of income due to the amounts not
being material. Maintenance and repairs, including the cost of renewals of minor
items of property, are charged principally to expense as incurred. Replacements
of property (exclusive of minor items or property) are charged to the
appropriate property accounts. Upon retirement of a pipeline plant asset, its
cost is charged to accumulated depreciation together with the cost of removal,
less salvage value.
For all other non-regulated assets repairs and maintenance are charged to
expense as incurred; renewals and betterments are capitalized including any
direct labor.
The Company accounts for its oil and gas production activities using the
full cost method of accounting. Under this method of accounting, all costs,
including indirect costs related to exploration and development activities, are
capitalized as oil and gas property costs. No gains or losses are recognized on
the sale or disposition of oil and gas reserves, except for sales which include
a significant portion of the total remaining reserves.
CASH AND CASH EQUIVALENTS
For purposes of the statement of cash flows, the Company considers
short-term, highly liquid investments that have an original maturity of three
months or less to be cash equivalents.
TRANSPORTATION AND EXCHANGE GAS IMBALANCES
In the course of providing transportation and exchange services to
customers, natural gas pipelines may receive different quantities of gas from
shippers than the quantities delivered on behalf of those shippers. These
transactions result in transportation and exchange gas imbalance receivables and
payables that are settled through cash-out procedures specified in each tariff
or recovered or repaid through the receipt or delivery of gas in the future.
Such imbalances are recorded as current assets or current liabilities on the
balance sheet using the posted index prices of the applicable FERC-approved
tariffs, which approximate market rates. Transportation and exchange gas
imbalances were not material as of December 31, 1996 and 1997.
DEFERRED CONTRACT COSTS
Costs incurred to construct natural gas transmission facilities pursuant to
long-term natural gas sales or transportation contracts, which upon completion
of construction are assigned to the contracting party, are capitalized as
deferred contract costs and classified as "Other Assets" on the consolidated
balance sheet. These costs are amortized over the life of the initial contract
on a straight-line basis.
HEDGING ACTIVITIES
It is Midcoast's policy to maintain as nearly as practicable a fully hedged
position on its net natural gas purchase and sales commitments using back-to-
back physical transactions. When a back-to-back physical transactions cannot be
completed, the Company will periodically enter into financial instruments to
reduce its exposure to commodity price risk. Midcoast uses futures and options
with maturities of eighteen months or less to hedge against the volatility of
the price of natural gas purchases and sales. The financial derivatives have
pricing terms indexed to both the New York Mercantile Exchange ("NYMEX") and
Kansas City Board of Trade ("KBOT") futures contract. Gains or losses on hedging
activities are deferred until the physical transaction occurs. See Note 13 -
Risk Management, for detail of market value, notional amounts and notional
contracts at December 31, 1997.
STOCK ISSUANCE COSTS
Direct costs incurred by the Company in connection with its offering of
securities (see Note 7 - Capital Stock) were applied as a reduction of the
offering proceeds.
31
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REVENUE RECOGNITION
Customers are invoiced and the related revenue is recorded as natural gas
deliveries are made. Pipeline sales are recognized upon closing the sale
transaction. Oil and gas revenue from the Company's interests in producing wells
is recognized as oil and gas is produced from those wells.
RECENT ACCOUNTING PRONOUNCEMENTS
The FASB issued SFAS No. 123, "Accounting for Stock Based Compensation,"
effective for fiscal years beginning after December 15, 1995. This statement
allows companies to choose to adopt the statement's new rules for accounting for
employee stock based compensation plans. For those companies who choose not to
adopt the new rules, the statement requires disclosures as to what earnings per
share would have been if the new rules had been adopted. Management has adopted
the disclosure requirements of this statement in 1997 (See Note 12 - Stock
Option Plans).
The FASB also issued SFAS No. 128, entitled "Earnings Per Share", during
February 1997. The new statement, which is effective for financial statements
issued after December 31, 1997, including interim periods, establishes standards
for computing and presenting earnings per share. The new statement requires
retroactive restatement of all prior-period earnings per share data presented.
The new statement has been adopted by the Company, as a result current earnings
and all prior earnings have been retroactively restated.
The FASB also issued SFAS No. 130, "Reporting Comprehensive Income" and
SFAS No. 131, "Disclosures About Segments of an Enterprise and Related
Information". SFAS No. 130 establishes standards for reporting and display of
comprehensive income, its components and accumulated balances. Comprehensive
income is defined to include all changes in equity except those resulting from
investments by owners and distribution to owners. Among other disclosures, SFAS
No. 130 requires that all items that are required to be recognized under current
accounting standards as components of comprehensive income be reported in a
financial statement that displays with the same prominence as other financial
statements. SFAS No. 131 supercedes SFAS No. 14, "Financial Reporting for
Segments of a Business Enterprise". SFAS No. 131 establishes standards on the
way that public companies report financial information about operating segments
in annual financial statements and requires reporting of selected information
about operating segments in interim financial statements issued to the public.
It also establishes standards for disclosures regarding products and services,
geographic areas and major customers. SFAS No. 131 defines operating segments as
components of a company about which separate financial information is available
that is evaluated regularly by the chief operating decision maker in deciding
how to allocate resources and in assessing performance.
SFAS Nos. 130 and 131 are effective for financial statements for periods
beginning after December 15, 1997 and require comparative information for
earlier years to be restated. Because of the recent issuance of these standards,
management has been unable to fully evaluate the impact, if any, the standards
may have on the future financial statement disclosures. Results of operations
and financial position, however, will be unaffected by implementation of these
standards.
USE OF ESTIMATES
The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that effect the amounts reported in
these financial statements and accompanying notes. Actual results could differ
from those estimates.
NET INCOME PER COMMON SHARE
Net income per common share was computed by dividing net income applicable
to common shareholders by the weighted average common shares outstanding for
that period. All share and per share amounts in the accompanying consolidated
financial statements have been adjusted to reflect the 10% stock dividend issued
in March, 1998.
3. PIPELINE CONSTRUCTION AND ACQUISITIONS:
Midcoast consummated the acquisition of the Harmony gas processing plant
and gathering pipeline system ("Harmony System") from Koch Hydrocarbons Company,
a division
32
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of Koch Industries, Inc. effective August 1996, for cash consideration of
approximately $3,640,000. The Harmony system gathers gas from producing fields
located in Mississippi. It consists of over 155 miles of high and low pressure
gas gathering pipeline with 4620 horsepower of field and inlet compression. The
processing plant is a refrigerated propane natural gas liquid extraction plant
with design capacity of over 20 MMcf/day. The plant has sulfur extraction as
well as full fractionation facilities and markets propane, butanes, natural
gasoline, condensate and sulfur. The acquisition was partially funded with
proceeds from the Company's August 1996 sale of Common Stock (see Note 7 -
Capital Stock) and the remainder was financed through the revolving line of
credit with Bank One, Texas N.A. ("Bank One") as discussed in Note 4 - Debt
Obligations.
In May 1997, the Company consummated the acquisition of the stock of three
subsidiaries of Atrion Corporation ("Atrion") for cash consideration of $39.4
million and up to $2 million of deferred contingent payments to be paid over an
eight year period (the "MIT Acquisition"). In September 1997, $1.2 million was
reimbursed to the Company pursuant to post closing adjustments. The three
subsidiaries included MIT(f/k/a Alabama Tennessee Natural Gas Company),TRIGAS
and AlaTenn Energy Marketing Company, Inc. ("ATEMCO"), which was subsequently
merged into MMI. MIT owns and operates a 288 mile interstate pipeline, with two
compressor stations, that runs from Selmer Tennessee to Huntsville, Alabama
serving a number of large industrial and municipal customers. TRIGAS owns and
operates a 38 mile pipeline extending from Barton, Alabama to Courtland, Alabama
and a one mile pipeline in Morgan County, Alabama, which transport gas to two
industrial customers. ATEMCO was a natural gas marketing company which primarily
serviced the natural gas needs of the customers on MIT and TRIGAS. The
acquisition was initially financed through the Company's credit facility, and
subsequently repaid with the proceeds of its Common stock offering on July 2,
1997 (see Note 7 - Capital Stock).
In October 1997, the Company completed its acquisition through merger of
Republic Gas Partners, L.L.C. ("Republic"), which owned MLGC, MLTC and MLMC
(collectively the "Midla Acquisition"). Under the terms of the agreement, the
Republic partners received $3.2 million in cash, 385,000 shares of Midcoast
common stock, par value $.01 per share ("Common Stock"), warrants for 110,000
common shares and an additional 27,500 warrants subject to certain contingencies
which were subsequently met. Finally, additional warrants and cash consideration
were offered subject to certain contingencies which at December 31, 1997 have
not been met. (See Note 6 - Commitments and Contingencies). The Company also
repaid approximately $19.1 million in Republic bank debt. The acquisition was
primarily funded with $21.8 million of additional borrowings under the Company's
credit agreements with Bank One. The shares of Common Stock issued to Republic
had a fair value of approximately $8.7 million based on the market price of the
Company's stock at the approximate date upon which the purchase and sale
agreement was executed. The fair value of the warrants were determined to be
$749,000. The securities underlying these warrants are subject to piggyback
registration rights.
MLGC owns a 386 mile interstate gas pipeline which runs from the Monroe gas
field in northern Louisiana, southward through Mississippi to Baton Rouge,
Louisiana. The system includes two compressor stations with a total of 5,875
horsepower, has a throughput capacity of 200 Mmcf/day and serves a number of
large industrial markets and municipalities. MLGC also owns various gathering
systems. MLTC is an intrastate pipeline company which owns two pipelines that
serve two industrial customers. Both MLGC and MLGT have an agreement to provide
gas transportation and gas marketing services, respectively to serve a new
cogeneration facility in the Baton Rouge area that will require an approximate
$10.0 million construction of a high pressure pipeline. The pipeline is expected
to be completed no later than the fourth quarter of 1998. MLMC was a natural gas
marketing company which provided gas supply, transportation, storage and related
services primarily for customers on the MLGC and MLTC systems.
The Company utilized the purchase method of accounting to record all of its
acquisitions. No goodwill arose from these transactions.
Midcoast's 1997 operating revenues, net income applicable to common
shareholders, and basic and diluted earnings per common share on an unaudited
pro forma basis are $294 million, $3.8 million, $.67 and $.66, respectively. The
pro forma amounts are based on estimates and assume (i) the MIT Acquisition,
(ii) the Midla Acquisition and (iii) the issuance and sale of 2,315,000 shares
of the Company's Common Stock at $16.00 per share occurred as of the beginning
of 1997. The pro forma combined results presented are not necessarily indicative
of actual results that would have been achieved had the acquisitions occurred at
the beginning of 1997.
33
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For further information regarding the MIT or Midla Acquisitions, refer to
the Company's Form 8-K and 8-KA filed on November 13, 1997 and January 12, 1998,
respectively.
4. DEBT OBLIGATIONS:
At December 31, 1996 and 1997, the Company had outstanding debt obligations
as follows (in thousands):
DECEMBER 31, DECEMBER 31,
1996 1997
-------- ---------
(a) Note payable by Starr County to a bank
under a term loan bearing interest at
the prime rate plus 1% (9.5% at December
31, 1997), principal and accrued
interest are payable in 47 monthly
installments of $4,408 with a final
payment of the remaining unpaid
principal and
interest due in August 1998 135 31
(b) Note payable by Pan Grande to a bank
under a term loan bearing interest at
the prime rate plus 1% (9.5% at December
31, 1997), principal and accrued
interest are payable in 59 installments
of $16,754 with a final payment of the
remaining unpaid principal and interest
due in May 2000 577 425
(c) Revolving credit line with a bank under
a $100 million promissory note (see
following discussion) 3,500 28,666
(c) Revolving credit line with a bank under
a $100 million promissory note (see
following discussion) 180 700
------- --------
Total debt 4,392 29,822
------- --------
Less current portion (377) (899)
------- --------
Total long-term debt $ 4,015 $ 28,923
------- --------
(a) In January 1996, Starr County, in which Midcoast owns a 60% interest
and acts as manager, obtained $175,000 from a bank lender to finance the
acquisition of a gas gathering pipeline. The loan is secured by the pipeline and
related contracts. Furthermore, each member of Starr County has guaranteed the
loan in an amount equal to their respective ownership interest.
(b) In March 1996, Pan Grande obtained $800,000 from a bank to partially
finance the acquisition of six pipelines. The loan is secured by the pipelines
and related contracts. Furthermore, each member of Pan Grande has guaranteed the
loan in an amount equal to their respective ownership interest.
(c) On October 31, 1997, Midcoast amended its credit agreements with Bank
One. The amendments increased the Company's borrowing availability from $46.5
million to $80.0 million. The amendments also eliminated principal reduction
requirements and lowered the interest rate on borrowings.
Of the $80.0 million in borrowing availability, the lender has committed to
lending, in the aggregate, up to $60.0 million. If required, the additional
$20.0 million may be accessed with the inclusion of another bank lender in a
bank syndication. The amended credit agreements provide borrowing availability
as follows: (i) a $15.0 million LC Line of Credit Facility, of which $3.0
million may be used for working capital needs and $12.0 million of which is
available for issuance of letters of credit, (ii) a $60.0 million revolver which
expires in August 2000 and (iii) a $5.0 million MIT revolver expiring in August
2000 (collectively the "Credit Agreements").
34
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
When borrowings under the amended Credit Agreements are less than 50% of
the $80.0 million borrowing base, at the Company's option, interest will accrue
at LIBOR plus 1.5% or the Bank One base rate. When borrowings are greater than
50% of available credit, an additional .25% will be added to the above rates.
These rates reflect a 1% reduction in the LIBOR option and a .25% reduction in
the Bank One base rate option effective September 2, 1997. In an effort to
mitigate interest rate fluctuations exposure, the Company entered into a
two-year, $25 million interest rate swap with Bank One in December 1997 (See
Note 13 - Risk Management). In addition, the Company is subject to a
non-recurring 1% facility fee as funds are borrowed, as well as a .375%
commitment fee payable quarterly on the unused portion of borrowing
availability. The Credit Agreements are collateralized by all accounts
receivable, contracts, the pledge of the stock of MIT, the pledge of the stock
of Magnolia and a first lien security interest in the Company's pipeline
systems.
The borrowing availability under each line is subject to revision, on a
monthly basis for the LC Line of Credit Facility and a semi-annual basis for the
Revolver's, based on the performance of the Company's existing assets and any
asset dispositions or additions from new construction or acquisitions. The
Credit Agreements contain a number of customary covenants that require the
Company to maintain certain financial ratios, and limit the Company's ability to
incur additional indebtedness, transfer or sell assets, create liens, or enter
into a merger or consolidation. Midcoast was in compliance with such financial
covenants at December 31, 1997.
The aggregate maturities of long-term debt at December 31, 1997 are as
follows:
FOR THE YEAR ENDING
DECEMBER 31, (IN THOUSANDS)
----------------------------------- --------------
1998............................... $ 199
1999............................... 184
2000............................... 28,739
--------------
Total.............................. $29,122
==============
5. RELATED PARTY TRANSACTIONS:
In April 1994, affiliates owned by former officers and directors of the
Company extended the collateral to obtain the long-term bank financing for the
Alaska investment. The collateral was outstanding for a period of approximately
eight months at which point the Company replaced the loan with another
commercial lender and the collateral was released. In consideration for
extending the collateral on the initial loan, the Company assigned a five
percent net revenue interest on the net income derived from the Company's
investment in the oil and natural gas gathering pipelines near Cook Inlet,
Alaska. However, the five percent net revenue interest applies only after all
costs associated with the investment have been recouped by the Company. As of
December 31, 1997, no amounts have been paid under the assignment of the net
revenue interest.
In December 1994, an affiliate owned by certain former officers and
directors of the Company provided a $275,000 loan which, as amended, bore
interest at the Mercantile Bank, Corpus Christi ("Mercantile") prime rate plus
1.5%. Interest was payable monthly and principal and remaining accrued interest
were due in full at maturity on April 1, 1997. The proceeds of the loan were
used for general corporate purposes including the repayment of other
indebtedness. Principal of $75,000 was repaid in November 1995 with the
remaining $200,000 repaid in August 1996 with proceeds from the Common Stock
offering (see Note 7 - Capital Stock). Cash payments of $39,106 were made for
interest during the term of the loan.
In May 1995, an affiliate owned by former officers and directors of the
Company provided a $173,822 loan to partially finance the acquisition of a 23%
working interest in oil and gas production from two leases located in Starr
County, Texas. The loan, as amended in March 1996, bore interest at the
Mercantile prime rate plus 1% and matured on April 1, 1997. However, the loan
was repaid in full in August 1996 with proceeds from the Company's Common Stock
offering (see Note 7 - Capital Stock). Cash payments of interest amounting to
$3,346 and $18,124 were made during 1995 and 1996, respectively. No collateral
was required to obtain this loan, although, as additional consideration for
extending the loan, the affiliated company was assigned a one-half percent
working interest in the oil and gas properties.
35
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As additional consideration for extending a loan for the acquisition of the
Magnolia System in 1995, Midcoast granted an affiliate owned by a former officer
and director of the Company a 5% net revenue interest in the Magnolia System's
earnings before interest, income taxes and depreciation to be paid on a monthly
basis. The net revenue interest, as amended in May 1996, applied only after the
Magnolia System's acquisition cost had been recouped by the Company. No amounts
related to the Magnolia System's earnings were paid under the assignment of the
net revenue interest. The Company had the right to repurchase this net revenue
interest for a cash payment of $25,000, with such amount increased an additional
$25,000 on November 1, 1995 and each following month up to a maximum of
$500,000. In July 1996, the Company exercised it's right to repurchase the net
revenue interest for cash consideration of $250,000.
In March 1996, the Company borrowed $100,000 from an affiliate owned by a
former officer and director of the Company for its equity contribution in Pan
Grande (see Note 4 - Debt Obligations) pursuant to a promissory note. The note,
as amended, bore interest at the prime rate plus 2.5% and was payable in 59
monthly installments of $1,667 plus accrued interest and a final installment at
March 15, 2001 in the amount of the remaining principal and accrued interest
then outstanding and unpaid. The note was secured by the Company's interest in
Pan Grande. The affiliate also committed to lend up to an additional $75,000 in
the event an additional system was purchased by Pan Grande. In consideration for
the financing of the equity contribution and the commitment for additional
financing, the Company issued the affiliate 4,906 shares of the Company's Common
Stock. The note plus accrued interest of $4,896 was repaid in full in August
1996 with proceeds from the Company's Common Stock offering (see Note 7 Capital
Stock).
In May 1996, the Board of Directors ("Board") approved the redemption of 5%
cumulative preferred stock ("5% Preferred") for $118,366 held by a director and
officer and two former directors and officers of the Company (see Note 7 -
Capital Stock).
6. COMMITMENTS AND CONTINGENCIES:
EMPLOYMENT CONTRACTS
Certain executive officers of the Company have entered into employment
contracts which, through amendments, provide for employment terms of varying
lengths the longest of which expires in April 2001. These agreements may be
terminated by mutual consent or at the option of the Company for cause, death or
disability. In the event termination is due to death, disability or defined
changes in the ownership of the Company, the full amount of compensation
remaining to be paid during the term of the agreement will be paid to the
employee or their estate, after discounting at 12% to reflect the current value
of unpaid amounts.
LEASES
In March 1996, Midcoast entered into a non-cancelable operating lease for
its office space in Houston, Texas. In September 1997, the lease was amended to
extend its term through April 2002. In addition, the Company has subleased some
adjacent office space for a term which expires January, 2001. In October 1996,
Midcoast assumed an office lease in Corpus Christi, that was extended in
September 1997 through August 1999.
The Company incurred net lease expenses of $50,600, $72,700, and $118,000
during the years ended 1995, 1996 and 1997, after being reduced by rental income
and other adjustments of $0, $1,400 and $18,500, respectively. As of December
31, 1997, future minimum lease payments due under these leases are approximately
$276,000, $193,000, $177,000, $120,000 and $43,000 for years ended 1998, 1999,
2000, 2001 and 2002, respectively.
MIT CONTINGENCY
As part of the MIT Acquisition, the Company has agreed to pay additional
contingent annual payments, which will be treated as deferred purchase price
adjustments, not to exceed $250,000 per year. The amount each year is dependent
upon revenues received by the Company from certain gas transportation contracts.
The contingency is due over an eight-year period commencing April 1, 1998, and
payable at the end of each anniversary date. The Company is obligated to pay the
lesser of 50% of the gross revenues received under these contracts or $250,000
(see Note 14 Subsequent Events). The acquisition agreement for the MIT
Acquisition also limits the
36
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
amount of damages recoverable by Midcoast if there is a breach by Atrion of the
representations and warranties to $10 million after damages have exceeded
$500,000, and requires Midcoast to assert any such claims within 18 months of
the closing.
MIDLA CONTINGENCY
As part of the Midla Acquisition, the Company agreed that if a specific
contract with a third party was executed prior to October 2, 1999, which
included specific provisions regarding price and throughputs, Midcoast would be
obligated to issue 110,000 warrants to acquire Midcoast Common Stock at an
exercise price of $19.773 per share to Republic. In addition, concurrent with
initial expenditures on the project, the Company would incur a $1.2 million cash
obligation to Republic. At December 31, 1997, none of the provisions of this
contingency have been met.
7. CAPITAL STOCK:
At December 31, 1997, the Company had authorized 10,000,000 shares of
Common Stock, of which 5,681,330 shares were issued and outstanding. There are
13,085 shares issued and outstanding at December 31, 1997 which are subject to a
vesting schedule in connection with employee agreements entered into during 1994
and 1996 (see Note 11 Employee Benefits).
In February 1996, the Company issued warrants to purchase 37,785 shares of
the Company's Common Stock at $7.136 per share. These warrants were issued in
connection with the Company's August 1996 Common Stock offering and expire on
February 1, 1999 and have certain piggyback registration rights.
In May 1996, the Board approved the redemption of the 5% Preferred for
$118,366 held by a director and officer and two former directors and officers of
the Company. The shares were redeemed for ten percent of the stated liquidation
value ($1,183,665). Subsequently, no shares of the Company's preferred stock
remain outstanding. Following redemption of the Company's 5% Preferred, the
Company's articles of incorporation were amended to reflect only one class of
outstanding securities, the Company's Common Stock.
In July 1996, the Board and a majority of the Company's shareholders
authorized amending the Company's articles of incorporation to increase the
number of authorized common shares from 6,000,000 shares to 10,000,000 shares.
In addition, the Board authorized an approximate 4.46 for 1 stock split in
anticipation of the Company's Common Stock offering discussed below.
On August 9, 1996, the Company's Registration Statement on Form SB-2 was
declared effective by the SEC. On August 14, 1996, the Company sold 1,000,000
shares of its Common Stock at an offering price of $10.00 per share. The
Company's stock is listed on the American Stock Exchange ("AMEX") under the
symbol "MRS." Under the terms of the underwriting agreement, the underwriters
received warrants to acquire 110,000 shares at 142% of the initial offering
price per share. The securities underlying these warrants are subject to
piggyback registration rights and expire August 13, 2001. After deducting
underwriting commissions and other underwriting expenses of the offering,
proceeds of approximately $8,841,000 were received by the Company from the
underwriter. The proceeds were used to repay indebtedness with the remainder
applied to acquisitions of pipelines and related assets.
On June 27, 1997, the Company's Registration Statement on Form S-1 was
declared effective by the SEC. On July 2, 1997, after considering the
underwriters exercising the over-allotment option, the Company sold 2,315,000
shares of its Common Stock at an offering price of $16.00 per share. After
deducting the underwriting discounts of $1.04 per share, net proceeds to the
Company were $34,632,400. The proceeds were used to repay the indebtedness
incurred on the MIT Acquisition.
On February 3, 1998, the Board declared a 10 percent stock dividend on the
Company's Common Stock. On March 2, 1998, shareholders of record as of February
13, 1998, received one additional share for each ten shares held. Earnings per
share, dividends per share and weighted average shares outstanding have been
retroactively restated to reflect the 10 percent stock dividend.
8. INCOME TAXES:
The Company has net operating loss ("NOL") carryforwards of approximately
$17.0
37
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
million, subject to change based on Republic's final tax returns, expiring in
various amounts from 1998 through 2012. In addition, the Company had an
investment tax credit ("ITC") carryforward of approximately $108,000 which
expires in various amounts from 1993 to 2000. These loss carryforwards were
generated by the Company's predecessor and Republic. The ability of the Company
to utilize the carryforwards is dependent upon the Company generating sufficient
taxable income and will be affected by annual limitations (currently estimated
at $4.9 million)on the use of such carryforwards due to a change in shareholder
control under the Internal Revenue Code triggered by the Company's July 1997
Common Stock offering and the change of ownership created by the acquisition of
Republic.
The tax effect of significant temporary differences representing deferred
tax assets and liabilities at December 31, 1996 and 1997, are as follows (in
thousands):
DECEMBER 31,
--------------------
1996 1997
--------- ---------
Net operating loss carryforwards.... $ 3,723 $ 5,756
Investment tax credit
carryforwards...................... 348 108
Alternative minimum tax credit....... 86 94
Financial basis of assets in excess
of tax basis....................... (344) (10,990)
Valuation allowance.................. (3,727) (4,581)
--------- ---------
Net deferred tax assets (liabilities) $ 86 $(9,613)
========= =========
The valuation allowance declined $1,107,000 in the year ended December 31,
1996 because of NOL carryforwards utilized and capital loss carryforwards which
expired. A $854,000 increase to the valuation allowance was generated in 1997 as
a result of reserving against the NOL's acquired in the Midla Acquisition
mitigated by the utilization of previous NOL's.
A reconciliation of the 1995, 1996 and 1997 provision for income taxes to
the statutory United States tax rate is as follows (in thousands):
1995 1996 1997
--------- --------- ---------
Federal tax computed at statutory
rate.................................. $ 771 $ 643 $ 1,960
Utilization of net operating loss
carryforwards......................... (771) (643) (1,810)
--------- --------- ---------
Actual provision........................ $ -- $ -- $ 150
========= ========= =========
9. MAJOR CUSTOMERS:
For the years ended December 31, 1995, 1996 and 1997, the Company derived
40% and 14% of total sales from two customers in 1995, 31% and 15% from the same
customers in 1996, and 12% from a new customer in 1997.
10. CONCENTRATION OF CREDIT RISK:
The Company derives revenue from commercial companies located in Alabama,
Alaska, Kansas, Louisiana, Mississippi, New York, Oklahoma, Tennessee and Texas.
Two of Midcoast's largest customers account for 23% or approximately $6.3
million of the outstanding accounts receivable at December 31, 1997. These
accounts receivable were subsequently collected under normal credit terms and
the Company believes that future accounts receivable with these companies will
continue to be collected under normal credit terms based on previous experience.
The Company performs ongoing evaluations of its customers and generally does not
require collateral. The Company assesses its credit risk and provides an
allowance for doubtful accounts for any accounts which it deems doubtful of
collection. At December 31, 1997, no provision for doubtful accounts was
provided.
The Company periodically maintains cash balances with banks exceeding the
amounts
38
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
insured by the Federal Deposit Insurance Corporation ("FDIC"). As of December
31, 1997, one of the Companies cash balances with banks exceeded FDIC limits. At
December 31, 1997 and 1996 the Company had $0 and $1.8 million, respectively of
cash or cash equivalents under repurchase agreements originated by the Company's
bank under an arrangement whereby collected balances held in the Company's main
operating account are invested overnight. These repurchase agreements are not
covered by FDIC insurance. The Company does not anticipate any losses from these
excess balances.
The derivative financial instruments utilized by the Company in its hedging
activities include NYMEX and KBOT futures and option contracts which are
guaranteed by their respective exchange and have nominal risk. The change in
market value of futures and option contracts requires daily cash settlement in
margin accounts with brokers. At December 31, 1997 the Company had $317,000 in
margin cash accounts to service these derivative financial instruments. Swap
contracts and most other over-the-counter instruments are generally settled at
the expiration of the contract term. The Company is exposed to credit risk in
the event of nonperformance by a counterparty. For each counterparty, the
Company analyzes its financial condition prior to entering into the agreement,
establishes credit limits and monitors the appropriateness of these limits on an
ongoing basis.
11. EMPLOYEE BENEFITS:
The Company issued a total of 69,677 and 28,608 shares of the Company's
Common Stock to certain key employees in 1995 and 1996, respectively. Of the
shares issued in 1996, 9,813 were issued in connection with employment
agreements with certain employees and vest in equal amounts over a three-year
period. The shares were valued at the estimated fair market value on the date of
issuance. Compensation expense is being recognized ratably over the vesting
period.
In December 1996, the Company established a defined contribution 401(k)
Profit Sharing Plan for its employees. The plan provides participants a
mechanism for making contributions for retirement savings. Each participant may
contribute certain amounts of eligible compensation. The Company makes a
matching contribution to the plan which amounted to approximately $16,000 in
1996 and $81,000 for the year ended December 31, 1997.
12. STOCK OPTION PLANS:
The Company has two stock option plans: the 1996 Incentive Stock Plan (the
"Incentive Plan") and the 1997 Non-Employee Director Stock Option Plan (the
"Director's Plan").
In May 1996, the Board adopted the Incentive Plan, which was subsequently
approved by the Company's shareholders in May 1997. All employees, including
officers (whether or not directors) and consultants of the Company and its
subsidiaries are currently eligible to participate in the Incentive Plan.
Persons who are not in an employment or consulting relationship with the Company
or any of its subsidiaries, including non-employee directors, are not eligible
to participate in the Incentive Plan. Under the Incentive Plan, the Compensation
Committee may grant incentive awards with respect to a number of shares of
Common Stock that in the aggregate do not exceed 253,000 shares of Common Stock,
subject to adjustment upon the occurrence of certain recapitalization's of the
Company.
The Incentive Plan provides for the grant of (i) incentive stock options,
(ii) shares of restricted stock, (iii) performance awards payable in cash or
Common Stock, (iv) shares of phantom stock, and (v) stock bonuses. In addition,
the Incentive Plan provides for the grant of cash bonuses payable when a
participant is required to recognize income for federal income tax purposes in
connection with the vesting of shares of restricted stock or the issuance of
shares of Common Stock upon the grant of a performance award or a stock bonus,
provided, that such cash bonus may not exceed the fair market value (as defined)
of the shares of Common Stock received on the grant or exercise, as the case may
be, of an Incentive Award. No Incentive Award may be granted under the Incentive
Plan after ten years from the Incentive Plan adoption date.
With respect to incentive stock options, no option may be granted more than
ten years after the effective date of the stock option plan or exercised more
than ten years after the date of the grant (five years if the optionee owns more
than 10% of the Common Stock of the Company at the date of the grant).
Additionally, with regard to incentive stock options, the exercise price of the
options may not be less than the fair market value of the Common Stock at the
date of the grant (110% if the optionee owns more than 10% of the Common Stock
of the Company). Subject to certain limited
39
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
exceptions, options may not be exercised unless, at the time of the exercise,
the optionee is in the service of the Company. As of December 31, 1997, options
to purchase an aggregate 236,500 shares of Common Stock are issued and
outstanding under the Incentive Plan at an average price of $10.817 per share.
Of the total shares, 62,700 are exercisable at a price of $10.50 per share,
113,300 are exercisable at a price of $9.545 per share, 58,300 are exercisable
at a price of $13.125 per share and 2,200 are exercisable at a price of $24.205
per share.
On November 11, 1997, the Board adopted an amendment to the Incentive Plan
which would increase the shares available under the plan from 253,000 to 425,000
shares, the increase is subject to approval by the Company's shareholders.
As of December 31, 1997, there were no options vested under the Incentive
Plan. The options have a weighted average exercise price of $10.817 per share.
The majority of the options vest 20% per year and all the options will be fully
vested in 2002.
In April 1997, the Board adopted the Director Plan, which was subsequently
approved by the Company's shareholders in May 1997. The Director Plan is for the
benefit of Directors of the Company, who at the time of their service, are not
employees of the Company or any of its subsidiaries. Under the Director Plan,
55,000 shares of the Company's Common Stock are reserved for issuance.
The Director Plan provides for the granting of non-qualified stock options
("NQO"), the provisions of which do not qualify as "incentive stock options"
under the Internal Revenue Code. Options granted under the Director Plan must
have an exercise price at least equal to the fair market value of the Company's
Common Stock on the date of the grant. Pursuant to the Director Plan, options to
purchase 15,000 shares of Common Stock are granted to each non-employee director
upon their election to the Board. In addition, all non-employee Director are
eligible to receive a NQO to purchase 5,000 shares of Common Stock at the time
of the Directors re-election to the Board, subject to share availability.
Options granted under the Director Plan are fully vested upon issue and expire
ten years after the date of the grant. As of December 31, 1997, options to
purchase an aggregate of 22,000 shares of Common Stock are issued and
outstanding under the Director Plan, 5,500 of which are exercisable at a price
of $13.75 per share and 16,500 which are exercisable at a price of $14.716 per
share.
As of December 31, 1997, the entire 22,000 shares of the Company's Common
Stock, under the Director's Plan, were fully vested and exercisable at a
weighted average price of $14.475 per share.
The Company applies APB Opinion No, 25, Accounting for Stock Issued to
Employees, and related Interpretations in accounting for its plans. Accordingly,
no compensation cost has been recognized for its stock option plans. Had
compensation expense for the Company's stock-based compensation plans been
determined based on the Black Scholes option pricing model with the following
assumptions used for grants: risk-free interest rates of 5.59% and 6.7%;
expected volatility of 45.2%; and a dividend yield of 0.4%., the Company's net
income and earnings per common share would have been decreased to the pro forma
amounts indicated below:
Year Ended Year Ended
December 31, December 31,
1996 1997
------------- -----------
Net income
As reported .................................. $ 1,891,226 $ 5,764,451
Pro forma .................................... $ 1,891,226 $ 5,686,133
Earnings per common share (basic)
As reported .................................. $ .91 $ 1.41
Pro forma .................................... $ .91 $ 1.39
Earnings per common share (diluted)
As reported .................................. $ .91 $ 1.37
Pro forma .................................... $ .91 $ 1.35
13. RISK MANAGEMENT
According to guidelines provided by the Board, the Company enters into
exchange-traded commodity futures, options and swap contracts to reduce the
exposure to market fluctuations in price and transportation costs of energy
commodities and is not to
40
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
engage in speculative trading. Approvals are required from senior management
prior to the execution of any financial derivative. The financial derivatives
have pricing terms indexed to both the NYMEX and KBOT. The Company's market
exposures arise from inventory balances and fixed price purchase and sale
commitments. The Company uses the exchange-traded commodities to manage and
hedge price risk related to these market exposures.
Gas futures involve the buying and selling of natural gas at a fixed
price. Over-the-counter swap agreements require the Company to receive or make
payments based on the difference between a specified price and the actual price
of natural gas. The Company uses futures and swaps to manage margins on
offsetting fixed-price purchase or sales commitments for physical quantities of
natural gas. Options held to hedge risk provide the right, but not the
obligation, to buy or sell energy commodities at a fixed price. The Company
utilizes options to manage margins and to limit overall price risk exposure.
The gains, losses and related costs to the financial instruments that
qualify as a hedge are not recognized until the underlying physical transaction
occurs. At December 31, 1997, the Company had deferred losses from such
contracts of $386,860. The market value, notional amount and notional contract
quantity of open commodities futures, options and swaps contracts used for
hedging purposes were as follows:
December 31,
1997
------------
Market Value:
Future contracts ......................................... $846,680
Options .................................................. 249,000
Notional Amount:
Future contracts ......................................... 924,000
Options .................................................. 252,000
Notional Contract Quantity (Mmbtu):
Future contracts ......................................... 390,000
Options .................................................. 1,320,000
In an effort to mitigate interest rate fluctuations exposure, the
Company entered into a two-year, $25 million interest rate swap with Bank One in
December 1997. The agreement provides a fixed 6.02% LIBOR interest rate to
Midcoast over the two year term, notwithstanding the additional margin the bank
is charging on outstanding borrowings. The variable three month LIBOR rate
resets quarterly on the second of March, June, September and December for the
term of the agreement. Midcoast is obligated to reimburse Bank One when the
three-month LIBOR rate is reset below 6.02%. Conversely, Bank One is obligated
to reimburse Midcoast when the three-month LIBOR rate is reset above 6.02%. At
December 31, 1997, the fair value of the interest rate swap was a net liability
of $81,000.
14. SUBSEQUENT EVENTS:
On January 20, 1998, MIT entered into certain contracts to provide
transportation services which triggered obligations assumed by the Company in
connection with the MIT Acquisition. The amount of such deferred purchase costs
is contingent upon the amount of gross revenue derived from this contract with a
maximum annual contingency of $250,000 (see Note 6 - Commitments and
Contingencies).
On February 3, 1998, the Board declared a 10% stock dividend to
shareholders of record at the close of business on February 13, 1998. No
fractional shares were issued and shareholders entitled to a fractional share
received a cash payment equal to the market value of the fractional share at the
close of the market on March 2, 1998, which was $22.50. All share and per share
amounts have been retroactively restated to reflect the effect of the 10% stock
dividend.
41
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
ITEM 11. EXECUTIVE COMPENSATION.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are
omitted because the Company will file with the SEC a definitive proxy statement
(the "Proxy Statement") pursuant to regulation 14A under the Securities Exchange
Act of 1934 not later than 120 days after the close of the fiscal year. The
information required by such Items will be included in the Proxy Statement to be
filed in connection with the Company's annual meeting of shareholders scheduled
for May 15, 1998 and is hereby incorporated by reference.
42
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:
1. Financial statements.
All financial statements of Midcoast Energy Resources, Inc. and
subsidiaries are included under Item 8 beginning on page 24 of this Form 10-K.
2. Exhibits.
EXHIBITS DESCRIPTION OF EXHIBITS
-------- -----------------------
2.1 Agreement for Purchase and Sale of Stock dated September 6, 1995, by
and between Midcoast Holdings No. One, Inc. and Koch Gateway Pipeline
Company (Incorporated by reference from Midcoast Form 10-KSB for the
fiscal year ended December 31, 1995, as Exhibit 10.25).
2.2 First Amendment to Agreement for Purchase and Sale of Stock dated
September 6, 1995, by and between Midcoast Holdings No. One, Inc. and
Koch Gateway Pipeline Company dated October 2, 1995 (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1995, as Exhibit 10.26).
2.3 Agreement for Purchase and Sale of Stock dated September 13, 1995, by
and between Five Flags Holding Company and Midcoast Holdings No. One,
Inc. (Incorporated by reference from Midcoast Form 10-KSB for the
fiscal year ended December 31, 1995, as Exhibit 10.27).
2.4 Agreement for Purchase of Stock dated September 13, 1995, by and
between Midcoast Holdings No. One, Inc. and Rainbow Investments
Company (Incorporated by reference from Midcoast Form 10-KSB for the
fiscal year ended December 31, 1995, as Exhibit 10.28).
2.5 Agreement for Purchase and Sale of Stock dated July 27, 1995, by and
between Williams Holdings of Delaware, Inc. and Midcoast Holdings No.
One, Inc. (Incorporated by reference from Midcoast Form 8-K dated
September 22, 1995).
2.6 Agreement for Sale and Purchase of Harmony Gas Processing Plant and
Related Gathering System dated October 3, 1996, by and between Koch
Hydrocarbon Company, a division of Koch Industries, Inc. and Midcoast
Holdings No. One, Inc. (Incorporated by reference from Midcoast Form
8-K dated October 21, 1996, as Exhibit 2.1).
2.7 Stock Purchase Agreement dated March 18, 1997, by and between Midcoast
Energy Resources, Inc. and Atrion Corporation. (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1996, as Exhibit 2.7).
3.1 Articles of Incorporation of Midcoast Energy Resources, Inc.
(Incorporated by reference from Midcoast Form 10-KSB for the fiscal
year ended December 31, 1992).
3.2 Certificate of Amendment of Articles of Incorporation of Midcoast
Energy Resources, Inc. (Incorporated by reference from Midcoast
Registration Statement on Form SB-2 (No. 333-4643) dated August 8,
1996).
3.3 Bylaws of Midcoast Energy Resources, Inc. (Incorporated by reference
from Midcoast Form 10-KSB for the fiscal year ended December 1, 1992).
4.1 Shareholder Agreement dated April 30, 1994, by and between Midcoast
Energy Resources, Inc. and Bill G. Bray (Incorporated by reference
from Midcoast Form 10-KSB for the fiscal year ended December 31,
1994).
4.2 Shareholder Agreement dated April 30, 1994, by and between Midcoast
Energy Resources, Inc. and Duane S. Herbst (Incorporated by reference
from Midcoast Form 10-KSB for the fiscal year ended December 31,
1994).
4.3 Shareholder Agreement dated April 30, 1994, by and between Midcoast
Energy Resources, Inc. and Richard A. Robert (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1994).
4.4 Shareholder Agreement dated April 30, 1994, by and between Midcoast
Energy Resources, Inc. and I. J. Berthelot, II (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1994).
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<PAGE>
4.5 Specimen Certificate for Shares of Common Stock, par value $.01 per
share. (Incorporated by reference from Midcoast Registration Statement
on Form SB-2 (No. 333-4643) dated August 8, 1996).
4.6 Representative's Warrants. (Incorporated by reference from Midcoast
Registration Statement on Form SB-2 (No. 333-4643) dated August 8,
1996).
4.7 Voting Proxy Agreement dated August 5, 1996, by and between Midcoast
Energy Resources, Inc., Stevens G. Herbst, Kenneth B. Holmes, Jr.,
Rainbow Investments Company and Texas Commerce Bank National
Association. (Incorporated by reference from Midcoast Registration
Statement on Form SB-2 (No. 333-4643) dated August 8, 1996).
4.8 Registration Rights Agreement dated August 5, 1996, by and between
Midcoast Energy Resources, Inc. and Stevens G. Herbst. (Incorporated
by reference from Midcoast Registration Statement on Form SB-2 (No.
333-4643) dated August 8, 1996).
4.9 Registration Rights Agreement dated August 5, 1996, by and between
Midcoast Energy Resources, Inc. and Kenneth B. Holmes, Jr.
(Incorporated by reference from Midcoast Registration Statement on
Form SB-2 (No. 333-4643) dated August 8, 1996).
4.10 Registration Rights Agreement dated August 5, 1996, by and between
Midcoast Energy Resources, Inc. and Rainbow Investments Company.
(Incorporated by reference from Midcoast Registration Statement on
Form SB-2 (No. 333-4643) dated August 8, 1996).
*4.11 Executive Severance Agreement by and between Midcoast Energy
Resources, Inc. and Dan Tutcher, dated August 15, 1997.
*4.12 Executive Severance Agreement by and between Midcoast Energy
Resources, Inc. and I.J. Berthelot, II, dated August 15, 1997.
*4.13 Executive Severance Agreement by and between Midcoast Energy
Resources, Inc. and Richard Robert, dated August 15, 1997.
*4.13 Executive Severance Agreement by and between Midcoast Energy
Resources, Inc.and Duane Herbst, dated August 15, 1997.
10.1 Employment Agreement dated January 1, 1993, by and between Midcoast
Energy Resources, Inc. and Dan C. Tutcher (Incorporated by reference
from Midcoast Form 10-KSB for the fiscal year ended December 31,
1992).
10.2 Amendment to the Employment Agreement dated April 1, 1993, by and
between Midcoast Energy Resources, Inc. and Dan C. Tutcher
(Incorporated by reference from Midcoast Form 10-KSB for the fiscal
year ended December 31, 1993).
10.3 Amendment to Employment Agreement dated April 14, 1997, by and between
Midcoast Energy Resources, Inc. and Dan Tutcher (Incorporated by
reference from Midcoast Form 10-QSB for the three-month period ended
March 31, 1997).
10.4 Employment Agreement dated April 30, 1994, by and between Midcoast
Energy Resources, Inc. and Richard A. Robert (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1994).
10.5 Amendment to the Employment Agreement dated April 8, 1996, by and
between Midcoast Energy Resources, Inc. and Richard A. Robert
(Incorporated by reference from Midcoast Form 10-QSB for the
three-month period ended March 31, 1996).
10.6 Employment Agreement dated July 1, 1994, by and between Midcoast
Energy Resources, Inc. and Bill G. Bray (Incorporated by reference
from Midcoast Form 10-KSB for the fiscal year ended December 31,
1994).
10.7 Employment Agreement dated April 25, 1995, by and between Midcoast
Energy Resources, Inc. and I.J. Berthelot, II (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1995).
10.9 Amendment to Employment Agreement dated December 8, 1995, by and
between Midcoast Energy Resources, Inc. and I.J. Berthelot, II
(Incorporated by reference from Midcoast Form 10-KSB for the fiscal
year ended December 31, 1995).
10.8 Amendment to Employment Agreement dated April 14, 1997, by and between
Midcoast Energy Resources, Inc. and I.J. Berthelot, II (Incorporated
by reference from Midcoast Form 10-QSB for the three-month period
ended March 31, 1997).
10.10 Assignment of Net Revenue Interest dated July 1, 1994, by and between
Texline Gas Company and Midcoast Energy Resources, Inc. (Incorporated
by reference from Midcoast Form 10-KSB for the fiscal year ended
December 31, 1994).
44
<PAGE>
10.11 Assignment of Net Revenue Interest dated July 1, 1994, by and between
Rainbow Investments Co. and Midcoast Energy Resources, Inc.
(Incorporated by reference from Midcoast Form 10-KSB for the fiscal
year ended December 31, 1994).
10.12 Agreement dated March 31, 1994, by and between Midcoast Energy
Resources, Inc., and Stewart Petroleum Company (Incorporated by
reference from Midcoast Form 10-KSB for the fiscal year ended December
31, 1993).
10.13 Operating Agreement of Pan Grande Pipeline, L.L.C. dated February 28,
1996, by and between Midcoast Holdings No. One, Inc. and Resource
Energy Development, L.L.C. (Incorporated by reference from Midcoast
Form 10-KSB for the fiscal year ended December 31, 1995).
10.14 Warrant by and between Triumph Resources Corporation and Midcoast
Energy Resources, Inc. (Incorporated by reference from Midcoast
Registration Statement on Form SB-2 (No. 333-4643) dated August 8,
1996).
10.15 Midcoast Energy Resources, Inc. 1996 Incentive Stock Plan.
(Incorporated by reference from Midcoast Registration Statement on
Form SB-2 (No. 333-4643) dated August 8, 1996).
10.16 Credit Agreement dated August 22, 1996, by and between Bank One, Texas
N.A. and Midcoast Energy Resources, Inc., Magnolia Pipeline
Corporation and H&W Pipeline Corporation. (Incorporated by reference
from Midcoast Form 10-QSB for the nine-month period ended September
30, 1996).
10.17 Midcoast Energy Resources, Inc. 1997 Non-Employee Director Stock
Option Plan (Incorporated by reference from Midcoast Form 10-QSB for
the three-month period ended March 31, 1997).
10.18 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and Richard A. Robert. (Incorporated by reference from
Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
26, 1997)
10.19 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and I.J. Berthelot, II. (Incorporated by reference
from Midcoast Registration Statement on Form S-1 (No. 333-27885) dated
June 26, 1997)
10.20 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and E.P. Marinos (Incorporated by reference from
Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
26, 1997)
10.21 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and Richard N. Richards. (Incorporated by reference
from Midcoast Registration Statement on Form S-1 (No. 333-27885) dated
June 26, 1997)
10.22 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and Duane S. Herbst. (Incorporated by reference from
Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
26, 1997)
10.23 Indemnity Agreement dated April 23, 1997 between Midcoast Energy
Resources, Inc. and Dan C. Tutcher. (Incorporated by reference from
Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
26, 1997)
10.24 First Amendment to Credit Agreement dated May 30, 1997 by and between
Bank One, Texas N.A. and Midcoast Energy Resources, Inc. , Magnolia
Pipeline Corporation, H&W Pipeline Corporation, Magnolia Resources,
Inc., Magnolia Gathering Inc., Midcoast Holdings No. One, Inc.,
Midcoast Gas Pipeline, Inc., Nugget Drilling Corporation, Midcoast
Marketing, Inc., AlaTenn Energy Marketing Company, and Tennessee River
Intrastate Gas Co. (Incorporated by reference from Midcoast
Registration Statement on Form S-1 (No. 333-27885) dated June 26,
1997)
10.25 Second Amendment to Credit Agreement dated October 31, 1997 by and
between Bank One, Texas N.A. and Midcoast Energy Resources, Inc. ,
Magnolia Pipeline Corporation, H&W Pipeline Corporation, Magnolia
Resources, Inc., Magnolia Gathering Inc., Midcoast Holdings No. One,
Inc., Midcoast Gas Pipeline, Inc., Nugget Drilling Corporation,
Midcoast Marketing, Inc., AlaTenn Energy Marketing Company, Tennessee
river Intrastate Gas Co., Mid Louisiana Gas Company, Mid Louisiana Gas
Transmission Company and Midla Energy Services Company. (Incorporated
by reference from Midcoast Form 8-K dated October 13, 1997).
10.26 First Amendment to Credit Agreement dated October 31, 1997 by and
between Bank One, Texas N.A. and Midcoast Interstate Transmission,
Inc. (f/k/a/ Alabama Tennessee Natural Gas Company). (Incorporated by
reference from Midcoast Form 8-K dated October 13, 1997).
*10.27 Third Amendment to Employment Agreement dated March 2, 1998 by and
between Midcoast Energy Resources, Inc. and Dan Tutcher.
*10.28 Third Amendment to Employment Agreement dated March 18, 1998 by and
between Midcoast Energy Resources, Inc. and I.J. Berthelot, II.
45
<PAGE>
*10.29 Third Amendment to Employment Agreement dated March 18, 1998 by and
between Midcoast Energy Resources, Inc. and Richard Robert.
*11 Computation of Earnings Per Share
*21.1 Schedule listing subsidiaries of Midcoast Energy Resources, Inc.
*27.1 Financial Data Schedule for the year ended December 31, 1997.
- ------------
* Filed herewith
(b) Reports of Form 8-K
A report on Form 8-K was filed during the fourth quarter of 1997. Such
report was filed on November 13, 1997 to report the Agreement and Plan of Merger
dated October 31, 1997 by and between Republic Gas Partners, L.L.C. and Midcoast
Energy Resources, Inc. In addition, a report on Form 8-K/A was filed on January
12, 1998 as an amendment to the Form 8-K filed on November 13, 1997 mentioned
above. The amendment was filed to include the required audited financial
statements of Republic Gas Partners, L.L.C. including the Historical
Consolidated Statement of Operations, Consolidated Statement of Members Deficit
and Consolidated Statement of Cash Flows for the nine months ended September 30,
1997 and year ended December 31, 1996 and the audited Consolidated Balance Sheet
at September 30, 1997 and December 31, 1996. In addition, the unaudited Midcoast
Pro Forma Statement of Operations for the nine months ended September 30, 1997
and for the year ended December 31, 1996 and unaudited Pro Forma Balance Sheet
at September 30, 1997.
46
<PAGE>
SIGNATURES
In accordance with Section 13 or 15 (d) of the Securities and Exchange Act
of 1934, the registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
MIDCOAST ENERGY RESOURCES, INC.
(Registrant)
BY:/s/ DAN C. TUTCHER
Dan C. Tutcher
Chief Executive Officer
Date: March 31, 1998
In accordance with the Securities and Exchange Act of 1934, this report has
been signed by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.
SIGNATURES CAPACITY IN WHICH SIGNED
- ---------- ------------------------
/s/ DAN C. TUTCHER Chairman of the Board
(Dan C. Tutcher) Chief Executive Officer
and President
Date:
/s/ I. J. BERTHELOT, II Executive Vice President, Chief Operating
(I. J. Berthelot, II) Officer and Director
Date:
/s/ TED COLLINS, JR. Director
(Ted Collins, Jr.)
Date:
/s/ JERRY J. LANGDON Director
(Jerry J. Langdon)
Date:
/s/ RICHARD N. RICHARDS Director
(Richard N. Richards)
Date:
/s/ RICHARD A. ROBERT Treasurer, Principal Financial Officer
(Richard A. Robert) Principal Accounting Officer
Date:
/s/ BRUCE M. WITHERS Director
(Bruce M. Withers)
Date:
47
MIDCOAST ENERGY RESOURCES, INC AND SUBSIDIARIES
EXHIBIT 11: COMPUTATION OF EARNINGS PER COMMON SHARE
Year Ended Year Ended
December 31, December 31,
1996 1997
---------------------
Weighted average common shares outstanding, Basic ...... $2,074,155 $4,092,135
Net effect of dilutive stock options - based on
the treasury stock method using
average market price ............................... 3,964 109,030
---------- ----------
Weighted average common shares outstanding, Diluted .... 2,078,119 4,201,165
Net income ............................................. $1,891,226 $5,764,451
========== ==========
Earnings per common share, Basic ....................... $ .91 $ 1.41
Earnings per common share, Diluted ..................... $ .91 $ 1.37
48
MIDCOAST ENERGY RESOURCES, INC AND SUBSIDIARIES
EXHIBIT 21.1: SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
YEAR OF STATE OF
NAME INCORPORATION INCORPORATION OWNERSHIP
- ---- ------------- ------------- ---------
<S> <C> <C>
Magnolia Resources, Inc. 1996 Mississippi 100%
Magnolia Gathering, Inc. 1996 Alabama 100%
Magnolia Pipeline Corporation 1989 Alabama 100%
H & W Pipeline Corporation * 1976 Alabama 100%
Midcoast Holdings No. One, Inc. 1993 Delaware 100%
Arcadia/Midcoast Pipeline of New York L.L.C.* 1996 New York 50%
Nugget Drilling Corporation * 1982 Minnesota 100%
Midcoast Marketing, Inc. 1991 Texas 100%
Midcoast Interstate Transmission, Inc. 1966 Alabama 100%
Tennessee River Intrastate Gas Company, Inc. 1986 Alabama 100%
Mid Louisiana Gas Transmission Company 1987 Delaware 100%
Mid Louisiana Gas Company 1953 Delaware 100%
Midcoast Gas Pipeline, Inc. 1997 Texas 100%
Pan Grande Pipeline, L.L.C. 1996 Texas 50%
Starr County Gathering System - A Joint Venture 1996 Texas 60%
- ------------
* Presently Inactive
</TABLE>
49
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<CASH> 307,652
<SECURITIES> 0
<RECEIVABLES> 27,523,904
<ALLOWANCES> 0
<INVENTORY> 1,225,490
<CURRENT-ASSETS> 29,057,046
<PP&E> 100,581,046
<DEPRECIATION> 3,029,031
<TOTAL-ASSETS> 128,039,321
<CURRENT-LIABILITIES> 27,169,289
<BONDS> 0
0
0
<COMMON> 56,813
<OTHER-SE> 61,394,291
<TOTAL-LIABILITY-AND-EQUITY> 128,038,321
<SALES> 112,744,030
<TOTAL-REVENUES> 112,744,030
<CGS> 100,404,927
<TOTAL-COSTS> 105,452,704
<OTHER-EXPENSES> 310,137
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,066,738
<INCOME-PRETAX> 5,914,451
<INCOME-TAX> 150,000
<INCOME-CONTINUING> 5,764,451
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,764,451
<EPS-PRIMARY> 1.37
<EPS-DILUTED> 1.37
</TABLE>
