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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
----------------------
FORM 10-K
(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, 1999
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.
(Exact Name of Registrant as Specified in its Charter)
TEXAS 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)
Registrant's Telephone Number, Including Area Code: (713) 650-8900
Securities Registered Pursuant To Section 12(b) Of The Act:
Title of Each Class Name of Each Exchange on Which Registered
Common Stock, Par Value $.01 Per Share American Stock Exchange
Securities Registered under Section 12(g) of the Act: none
Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
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. [_]
State The Aggregate Market Value of The Voting Stock Held By Non-Affiliates of
The Registrant.
Aggregate market value of the voting stock (which consists solely of shares
of common stock) held by non-affiliates of the registrant as of March 27, 2000,
computed by reference to the closing sale price of the registrant's common stock
on the American Stock Exchange on such date: $203,029,515.
Common Stock, par value $.01 per share. Shares outstanding on March 27,
2000 was 12,494,124.
DOCUMENTS INCORPORATED BY REFERENCE
List hereunder the following documents if incorporated by reference and the
Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: Portions of Midcoast Energy Resources, Inc. definitive Proxy
Statement for the 1999 Annual Meeting of Shareholders, to be filed not later
than 120 days after the end of the fiscal year covered by this report, are
incorporated by reference into Part III.
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MIDCOAST ENERGY RESOURCES, INC.
TABLE OF CONTENTS
CAPTION PAGE
Glossary......................................................... 3
PART I
Item 1. Business................................................ 4
Item 2. Properties.............................................. 13
Item 3. Legal Proceedings....................................... 13
Item 4. Submission of Matters to a Vote of Security Holders..... 13
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.................................... 16
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk........................................ 23
Item 8. Financial Statements..................................... 25
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure...................... 52
PART III
Item 10. Directors and Executive Officers of the Registrant....... 52
Item 11. Executive Compensation................................... 52
Item 12. Security Ownership of Certain Beneficial Owners and
Management............................................... 52
Item 13. Certain Relationships and Related Transactions........... 52
PART IV
Item 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K...................................... 52
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GLOSSARY
The following abbreviations, acronyms or defined terms used in this Form 10-K
are defined below:
Bbl................... 42 U.S. gallon barrel
Bcf................... Billion cubic feet
Board................. Board of Directors of Midcoast Energy Resources, Inc.
Btu................... British thermal unit
Common Stock......... Midcoast common stock, par value $.01 per share
Company............... Midcoast Energy Resources, Inc., its subsidiaries and
affiliated companies
CO2................... Carbon dioxide
DPI................... Dufour Petroleum, Inc., a wholly owned subsidiary of
Midcoast Energy Resources, Inc.
EBITDA................ Earnings Before Interest, Taxes, Depreciation and
Amortization
EPS................... Diluted earnings per share
FASB.................. Financial Accounting Standards Board
FERC.................. Federal Energy Regulatory Commission
KPC Acquisition...... The November 1999 acquisition of Kansas Pipeline
Company and MarGasCo
KPC System............ A 1,120 mile interstate transmission pipeline
LDC................... Local distribution company
LIBOR................. London Inter Bank Offering Rate
Mcf/day............... One Thousand cubic feet of gas per day
MCOC.................. Midcoast Canada Operating Corporation, a wholly owned
subsidiary of Midcoast Energy Resources, Inc.
Midcoast.............. Midcoast Energy Resources, Inc.
MIDLA Acquisition..... The October 1997 acquisition of the MLGC and MLGT
Systems
MIT Acquisition...... The May 1997 acquisition of the MIT and TRIGAS Systems
MIT System............ A 288-mile interstate transmission pipeline
MGSI.................. Midcoast Gas Services, Inc.
MLGC.................. Mid Louisiana Gas Company
MLGC System........... A 386-mile interstate transmission pipeline
MLGT.................. Mid Louisiana Gas Transmission Company
MLGT System........... A Louisiana intrastate pipeline
MMBtu................. Million British thermal units
MMcf/day.............. Million cubic feet of gas per day
MMI................... Midcoast Marketing Inc.
NGL................... Natural gas liquid
NOL................... Net operating loss
NYMEX................. New York Mercantile Exchange
Preferred Stock....... Midcoast preferred stock, par value $.01 per share
Republic.............. Republic Gas Partners L.L.C.
SeaCrest.............. SeaCrest Company, L.L.C., a 70% owned subsidiary of
Mid Louisiana Gas Transmission Company, which is
a wholly owned subsidiary of Midcoast Energy
Resources, Inc.
SIGCO................. Southern Industrial Gas Corporation
SFAS.................. Statement of Financial Accounting Standards
TRIGAS System......... Two end-user pipelines in northern Alabama
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PART I
ITEM 1. BUSINESS.
GENERAL
The Company, along with its subsidiaries and its affiliated companies, is
primarily engaged in the transportation, gathering, processing and marketing of
natural gas and other petroleum products. As of December 31, 1999, the Company
owned and operated three interstate transmission pipeline systems, one
intrastate transmission system, 35 end-user systems and 42 gathering systems
representing approximately 4,000 miles of pipeline with an aggregate daily
throughput capacity of over 3 Bcf of natural gas per day. Operations also
included gas processing and treating facilities and over 80 natural gas liquid
and crude oil tanks and rail cars. The Company's principal business consists of
providing transportation services 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 meet these customers' needs. The Company's principal
assets are located in the Gulf Coast and Mid-Continent areas.
The Company originally was incorporated as a Nevada corporation in 1992 and
subsequently reincorporated as a Texas corporation in 1999. The Company leases
its principal executive offices at 1100 Louisiana, Suite 2950, Houston, Texas
77002, and its telephone number is (713) 650-8900. The Company also owns or
leases other regional offices in Alabama, Kansas, Louisiana, Mississippi, Texas
and Alberta, Canada.
BUSINESS GROWTH STRATEGY
The Company's principal business strategy is to increase its earnings and
cash flow by focusing on accretive acquisitions, pursuing pipeline system and
processing facility construction and expansion opportunities and improving the
profitability of these systems through volume growth initiatives and cost
savings opportunities. The Company implements this strategy through the
following steps:
Accretive Acquisitions
The Company seeks to acquire natural gas or petroleum liquids transmission,
end-user and gathering pipeline systems and processing plants that offer the
opportunity for operational synergies and the potential for increased
utilization and expansion of the system. The Company targets systems in its core
geographic areas of operation in order to capitalize on existing infrastructure,
personnel and customer relationships to maximize system profitability. The
Company also seeks to acquire assets in other areas with growing demand for
natural gas or increasing drilling activity. These acquisitions enable the
Company to establish new core areas in which to build a regional presence. For
example, the Company purchased the Anadarko gas gathering system located in
Texas and Oklahoma in September 1998. The 696-mile natural gas gathering system
and processing plant are located in a prolific natural gas producing region and
established a new core geographic area for the Company. The Company quickly
strengthened its position in this area in December 1998 with the acquisition of
the 35-mile Mendota natural gas gathering system. This system, which included
another processing facility, was interconnected with the Anadarko system,
providing access to additional areas of natural gas production.
Construction and Expansion Opportunities
The Company leverages its existing infrastructure and customer relationships
by constructing systems to meet new or increased demand for pipeline
transportation services. These projects include expansion of existing systems
and construction of new pipeline or processing facilities. For example, earlier
this year the Company constructed new facilities near the southern end of the
MIDLA system to provide approximately 55 MMcf per day of high pressure natural
gas to two industrial customers. In November 1999, the Company agreed to
construct additional facilities for one of these customers to supply up to 80
MMcf per day of natural gas to their natural gas processing plants near Baton
Rouge, Louisiana.
Improving Existing System Profitability
After a system is acquired or constructed, the Company begins an aggressive
effort to market directly to both producers and end-users in order to fully
utilize the system's capacity. As part of this process, the Company focuses on
providing quality service to its existing customers while identifying new
customers. Many of the Company's existing pipeline and processing systems were
designed with excess throughput capacity that provides the Company with
opportunities to increase throughput with little incremental cost and to
facilitate higher margin "swing" sales during periods of increased natural gas
demand. For example, following the purchase of the MIT system in May 1997, the
Company had increased firm transportation volumes 29% to 170 MMcf per day by the
Spring of 1999 from 132 MMcf per day with
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minimal additional capital outlays. In addition, the Company generally seeks to
achieve administrative and operational efficiencies by capitalizing on the
geographic proximity of many of its systems.
SIGNIFICANT ACQUISITIONS
Since the first quarter of 1996, the Company has acquired ownership of, or
interests in, 73 pipelines including four natural gas processing plants for an
aggregate cost of approximately $369 million. The following is a summary of the
Company's significant acquisition activities:
The MIT Acquisition
In May 1997, the Company acquired the pipeline and energy services
operations of Atrion Corporation for cash consideration of $38.2 million and up
to $2 million in contingent deferred payments. These operations include (i) a
295-mile interstate transmission pipeline located in northern Alabama,
Mississippi and southern Tennessee which transports natural gas to industrial
and municipal customers, (ii) a 38-mile and a one-mile pipeline in northern
Alabama which primarily serve two large industrial customers and (iii) a natural
gas marketing company which was subsequently merged into MMI.
The MIDLA Acquisition
In October 1997, the Company completed its merger with Republic, which
owned MLGC, MLGT, and Mid Louisiana Marketing Company that was subsequently
merged into MMI. Consideration for the acquisition included $3.2 million in
cash, the assumption of approximately $19.1 million in bank indebtedness, the
issuance of 481,247 shares of the Company's common stock and warrants to acquire
171,880 shares of common stock. The assets acquired included (i) a 405-mile
interstate natural gas pipeline which runs from the Monroe gas field in northern
Louisiana, southward through Mississippi to Baton Rouge, Louisiana, (ii) three
end-user natural gas pipelines with a collective length of 40 miles and (iii)
two offshore lateral natural gas gathering pipelines with a collective length of
8.6 miles. These pipelines serve a number of large industrial and municipal
customers.
The Anadarko Acquisition
In September 1998, the Company purchased the Anadarko gas gathering system
from El Paso Energy Corporation. The pipeline system was purchased for cash
consideration of $35 million.
Under the agreement, MGSI acquired ownership and operation of the Anadarko
gas gathering system located in Beckham and Roger Mills counties, Oklahoma and
Hemphill, Roberts and Wheeler counties, Texas. The system is comprised of over
696 miles of pipeline with an average throughput of 157 MMcf/day and a total
capacity of 345 MMcf/day ("Anadarko System"). The system gathers gas from
approximately 250 wells and includes a 40 MMcf/day natural gas processing
facility ("Hobart Plant"), 11 compressor stations with a total of over 14,000
horsepower and interconnections with eight major interstate and intrastate
pipeline systems.
The Company expanded the Anadarko System in December 1998 with the
acquisition of the Mendota system from Seagull Energy Corporation for $3.75
million. The Mendota system, which was interconnected with the Anadarko System,
included two processing facilities and 35 miles of natural gas gathering
pipeline.
The Calmar Acquisition
In March 1999, the Company purchased the Calmar system in Alberta, Canada
from Probe Exploration, Inc. ("Probe"). The total value of the transaction was
approximately $13.2 million (U.S.). The assets purchased included a 30 MMcf/day
amine sweetening plant, 30 miles of gas gathering pipeline and approximately
4,000 horsepower of compression located near Edmonton, Alberta. The Calmar
system currently gathers and treats sour gas from wells operated by Probe and
Courage Energy Inc. In conjunction with the purchase, Probe entered into a gas
gathering and treating agreement with the Company, including the long-term
commitment of Probe's reserves in the Leduc Field, a right of first refusal
agreement on new or existing midstream assets within a defined 390-square mile
area of interest, and an assignment to the Company of an existing third party
gathering and treating agreement.
The Flare and DPI Acquisitions
In March 1999, the Company purchased two related companies, Flare and DPI.
The total value of the transaction was approximately $11.1 million and could
include future consideration should certain contingencies be met. The Flare and
DPI shareholders received cash consideration of approximately $3.2 million, the
Company assumed $5.5 million in debt and the DPI shareholders received 163,719
shares of
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the Company's common stock. Flare is a natural gas processing and treating
company whose principal assets include 27 mobile natural gas processing and
treating plants from which it earns revenues based on treating and processing
fees and/or a percentage of the NGL's produced. DPI is an NGL, crude oil and CO2
transportation and marketing company. DPI operates 43 NGL and crude oil trucks
and trailers, a fleet of 40 pressurized railcars and in excess of 400,000
gallons of NGL storage facilities and product treating and handling equipment.
The Tinsley Acquisition
In March 1999, the Company purchased the Tinsley crude oil gathering
pipeline for $5.2 million. The Tinsley system is located in Mississippi and
consists of 60 miles of crude oil gathering pipeline, related truck and
Mississippi River barge loading facilities and 170,000 barrels of crude oil
storage. The system transports approximately 5,000 barrels of crude oil per day
both directly from producing wells and from oil trucked to the pipeline.
The Kansas Pipeline Company Acquisition
In November 1999, the Company acquired KPC and other related entities for
approximately $195.2 million. KPC owns and operates a 1,120 mile regulated
interstate natural gas pipeline system. The system extends into two major
segments from northwestern and northeastern Oklahoma through Wichita into the
Kansas City metropolitan area. The system's two principal customers are
divisions of ONEOK, Inc. and Southern Union Company, which are the local
distribution companies for Wichita and Kansas City. KPC derives 97% of its gross
margin from a series of long-term transportation contracts with these two
principal customers. KPC is capable of delivering approximately 140 MMcf/day
and 21 MMcf/day of natural gas into the Kansas City and Wichita
marketplaces, respectively. KPC is one of only three pipeline systems currently
capable of delivering gas into the Kansas City metropolitan market.
In conjunction with the acquisition of KPC, the Company opted to terminate
a revenue sharing agreement with Management Resources Group, LLC by agreeing to
pay approximately $10.8 million on or before January 31, 2000. The full amount
was accrued as of December 31, 1999.
The Gloria Acquisition
In December 1999, the Company completed the acquisition of the Gloria
system from Koch Industries for cash consideration of approximately $6.1
million. The Gloria system is comprised of approximately 133 miles of pipeline
with a 1,650 horsepower compressor station and includes 51 miles of natural gas
gathering pipeline and 82 miles of transmission pipeline. The system gathers gas
from seven producing fields and also directly supplies natural gas to an
industrial customer and an LDC. The pipeline was part of Koch's interstate
system and FERC approval for the system's abandonment from interstate service
was received in October of 1999, which, following the expiration of the required
notice period, enabled us to proceed to close the Gloria system acquisition.
2000 Activity
In January 2000, the Company entered into a definitive purchase and sale
agreement to acquire the Manyberries Pipeline System ("MBPL") in Canada from
Triumph Energy Corporation for cash consideration of approximately $5.7 million
(U.S.), plus certain future contingent payments based on the actual throughput
volumes. MBPL consists of 90 miles of crude oil pipeline that originates at the
Manyberries Oil Field and terminates at an interconnection with the Milk River
Pipeline system in southeastern Alberta, Canada. Truck terminals, including the
Legend terminal, and a significant amount of crude oil storage also contribute
to the operations. The system has a design capacity of approximately 21,000
Bbl's/day and transports light sour crude oil from the Manyberries Oil Field, as
well as additional crude oil volumes from the Legend truck terminal. The
pipeline system is the only light gravity system in southern Alberta, and
current volumes are approximately 6,500 Bbl's/day. Closing is anticipated in the
second quarter of 2000, subject to receipt of the approvals, consents or other
authorizations required by the Investment Canada Act.
In March 2000, the Company acquired the Provost natural gas plant and
gathering system from NovaGas Canada LP, a division of TransCanada, for
approximately $4.9 million (U.S.). The Provost acquisition includes 80 miles of
natural gas gathering pipeline and a 15 MMcf/day sour gas processing plant and
sour gas injection well. The system is located in east-central Alberta, Canada
and is the only sour natural gas gathering and processing system in the area.
The system is connected to 21 oil tank batteries and primarily gathers the
associated sour natural gas production from approximately 900 wells in the
Provost area.
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SEGMENTS
Beginning in 1998, the Company segregated its business activities into
three segments: Transmission Pipelines, End-User Pipelines, and Gathering
Pipelines and Natural Gas Processing. These segments are analyzed independently
by management and derive revenue from different sources. For financial
information related to each segment, see Results of Operations in "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations," as well as "Note 16. Segment Data, in the Notes to the Consolidated
Financial Statements." Set forth below is a description of the principal
business activities conducted by each of the segments:
Transmission Pipelines
The Company's transmission pipelines primarily receive and deliver natural
gas to and from other pipelines, and secondarily involve 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 seeks
to further expand its activities in this area through the acquisition 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 natural gas by
municipal and industrial users. As of December 31, 1999, the Company owned three
interstate transmission pipelines and one intrastate transmission pipeline.
End-User Pipelines
The Company also contracts with industrial customers, municipalities or
electric generating facilities to provide natural gas and natural gas
transportation services to their facilities through interconnected gas pipelines
constructed or acquired by the Company. These pipelines provide a direct supply
of natural gas to new industrial facilities or to existing facilities as an
alternative to the local distribution company. The Company intends to continue
to pursue direct sales to these end-users who have the flexibility to negotiate
their natural gas purchase and transportation contracts as a result of industry
deregulation. Frequently, the Company is able to offer its end-user customer
lower rates 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. As of December 31, 1999, the Company
owned 35 end-user transmission pipelines.
Gathering Pipelines and Natural Gas Processing
The Company's gathering systems typically consist of a network of 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 natural gas
transmission companies. The Company intends to pursue the acquisition or
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. As of December 31,
1999, the Company owned an interest in and operated 42 gathering systems.
The Company's natural gas processing revenues are realized from the
extraction and sale of NGL's as well as the sale of the residual natural gas.
These revenues occur under processing contracts with producers of natural gas
utilizing both a "percentage of proceeds" and "keep-whole" basis. The contracts
based on percentage of proceeds provide that the Company receives a percentage
of the NGL's and residual gas revenues as a fee for processing the producer's
gas. The keep-whole contracts require that the Company reimburse the producers
for the Btu energy equivalent of the NGL's and fuel removed from the natural gas
as a result of processing and the Company retains all revenues from the sale of
the NGL's. Once extracted, the NGL's 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. The Company's processing margins can be
adversely affected by declines in NGL prices, declines in gas throughput, or
increases in shrinkage or fuel costs, and in the case of "keep-whole" contracts,
margins can be affected by rising natural gas prices. As of December 31, 1999,
the Company owned four processing and treating plants with a capacity of 100
MMBtu/day.
The Company also owns and operates 43 NGL and crude oil trucks and trailers
and a fleet of 40 pressurized railcars.
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Gas Marketing Services On Segments
In addition, the Company provides natural gas marketing services to its
customers within each of the three segments. The Company's natural gas marketing
activities have been focused on the Company's systems with a strategic focus to
provide quality and consistent service to customers connected to the Company's
pipeline network. 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 natural 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 some of its customers
including management of capacity release and gas balancing.
Typically, the Company purchases natural gas at a price determined by
prevailing 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 that 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 natural 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 natural gas marketing activities, which utilize third party pipelines,
also expose 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 three
to ten 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 natural gas supply and other
services. For its FERC regulated entities, the Company enters into firm and
interruptible transportation contracts using the tariff rates approved by FERC.
In certain situations, the Company has offered discounts from its tariffs in
response to specific market conditions.
For 1999 and 1998, there were no customers that represented greater than
10% of the Company's gross margin. For 1997, Champion International Corporation
and Entergy Gulf States, Inc. each contributed in excess of 10% of the Company's
gross margin.
COMPETITION
The Transmission Pipeline, End-user Pipeline, and Gathering Pipeline and
Natural Gas Processing segments 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 competitive factors
at the time of the sale.
The Company competes against other companies for supplies of natural gas
and for 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. 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.
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NATURAL GAS SUPPLY
The Company's transmission and end-user pipelines have connections with
major interstate and intrastate pipelines that management believes have 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 and temporary
regional supply shortages. With regard to its gathering systems, supply risks
include other parties having control over the drilling of new wells, the
inability of wells to deliver natural 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") and
the Natural Gas Policy Act of 1978 ("NGPA"), as well as various regulations
promulgated by the FERC.
Interstate Pipeline Regulation
Our operations of the MIT, MIDLA and the KPC systems constitute the
operations of a "natural gas company," as defined in the NGA. As such, these
operations are subject to the jurisdiction of the FERC. The interstate pipeline
operations of these systems are operated pursuant to certificates of public
convenience and necessity and other authorizations issued under the NGA and
pursuant to the NGPA. The FERC regulates the interstate transportation of 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.
Pipeline rates for the MIT, MIDLA and the KPC systems must be filed with
and approved by the FERC. They are regulated by the FERC on a cost-of-service
basis and must be deemed by the FERC to be "just and reasonable." The FERC may
suspend for up to five months the effectiveness of rate changes filed by the
pipeline, and/or permit a changed rate to go into effect subject to refund. The
FERC may require the pipeline to refund, with interest, all or any portion of
any increased amount collected under "subject to refund" rates that, in the
FERC's final determination, is found not to be just and reasonable. The FERC
may also investigate, either on its own motion or pursuant to protests by third
parties, the lawfulness of pipeline rates that are on file.
In April 1993, jurisdictional rates for the MIT system were increased 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 that the FERC
approved in December 1993. That agreement was amended in September 1996 to
eliminate the requirement that a new rate case be filed in September 1996 or any
year thereafter. As part of that agreement, rates on the MIT system were reduced
6% effective September 1996.
In June 1996, a decrease in the jurisdictional rates for the MIDLA system
was proposed from rates that had been in effect since 1990. This rate decrease
was agreed to in an uncontested settlement with MIDLA's customers and was
certified to the FERC by the presiding Administrative Law Judge in November
1996. Accordingly, the FERC approved the settlement by letter order dated March
28, 1997. As part of that agreement, MIDLA is not required to file a new rate
case.
The Kansas Pipeline Company Acquisition
The pipeline assets of KPC were held in three partnerships prior to May 11,
1998. KansOk Partnership owned intrastate pipelines whose rates were regulated
by state agencies or the FERC. Kansas Pipeline Partnership owned an intrastate
pipeline in Kansas whose rates were determined by the Kansas Corporation
Commission. Riverside Pipeline Company, L.P., owned interstate assets in Kansas,
Oklahoma and Missouri that connected the assets of the other two partnerships at
the state lines of Missouri, Kansas, or Oklahoma.
9
<PAGE>
Effective May 11, 1998, after more than two years of jurisdictional
proceedings before the FERC, the FERC asserted jurisdiction over the assets of
these three entities, which were combined into a single, FERC-regulated entity,
KPC. The new company's initial rates, by order of FERC, were approximately equal
to its then-existing rates. FERC also ordered the company to file a Section 4
Rate Case by September 10, 1999.
In accordance with the FERC's order, KPC filed a rate case pursuant
to Section 4 of the NGA on August 27, 1999 (FERC Docket No. RP99-485-000). KPC's
proposed rates reflect an annual revenue increase when compared to its initial
FERC-approved rates. The rates have been protested by KPC's two principal
customers and by the state public utility commissions that regulate them. On
September 30, 1999, the FERC issued an order that set KPC's proposed rates for
hearing and accepted and suspended the rates to be effective March 1, 2000,
subject to possible refund. The Section 4 rate case proceeding will determine
whether the rates proposed by KPC for interstate transportation of natural gas
are just and reasonable, and the extent to which KPC must refund all or any part
of the proposed rate increase that it charges to its customers prior to
approval. A procedural schedule in the case has been adopted by the Presiding
Administrative Law Judge. A hearing date is set for September 26, 2000.
Intrastate Pipeline Regulation
The Company's intrastate pipeline operations are generally not subject to
regulation by the FERC, but they are subject to regulation by various agencies
of the states in which we operate. The Magnolia and Gloria systems are subject
to the jurisdiction of the FERC with respect to the transportation rates under
NGPA Section 311. Under NGPA Section 311, an intrastate pipeline can provide
transportation service "on behalf of" any interstate pipeline or LDC served by
an interstate pipeline company without prior FERC authorization. Specifically,
the FERC adopted a so-called "transport" or "title" standard requiring that,
for purposes of interstate transportation under NGPA Section 311, the "on
behalf of entity" must either (i) have physical custody of or (ii) hold title to
the gas at some point during the transaction. NGPA Section 311 service must be
provided without undue discrimination or preference and is subject to certain
FERC filing and reporting requirements.
The end-user pipelines and the transmission pipelines not regulated by the
FERC are subject to the regulations of the state agencies of the states in which
they are located. Most states have agencies that possess the authority to review
and authorize transactions, construction, acquisition, abandonment and
interconnection of physical facilities. Some states also have state agencies
that regulate transportation rates and contract pricing to ensure their
reasonableness.
Gathering Pipeline 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 non-jurisdictional gathering
facility status. Some of the recent cases applying these tests in a manner
favorable to the determination of our non-jurisdictional status are still
subject to rehearing and appeal. In addition, the FERC's articulation and
application of the tests used to distinguish between jurisdictional pipelines
and non-jurisdictional gathering facilities have varied over time. While we
believe the current definitions create non-jurisdictional status for our
gathering facilities, no assurance is available that such facilities will not,
in the future, be classified as regulated transmission facilities. If such a
classification were to occur, the rates, terms and conditions of the services
rendered by those facilities would become subject to regulation by the FERC.
No state in which we operate currently regulates gathering fees. Although
we are not aware that any state in which we operate a natural gas gathering
system is likely to begin regulation of our 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 we conduct gathering activities
or that we will not expand into or acquire operations in a state where such
regulations could be imposed.
Canadian Pipeline Regulation
MCOC owns the Calmar system located in central Alberta, Canada.
Construction, operation and reclamation of the Calmar system are primarily
regulated by the Alberta Energy and Utilities Board ("EUB") and Alberta
Environmental Protection. Rates for gas processing and transportation through
the Calmar system are presently determined by negotiated contracts. Pursuant to
the Alberta Oil and Gas Conservation Act, R.S.A. 1980, c. O-5, an application
may be made to the EUB for an order declaring the Calmar system to be a common
processor, purchaser and/or carrier. In the event that (i) the EUB grants such
an order (with the approval of the Alberta Lieutenant Governor in Council) and
(ii) an agreement respecting rates and charges cannot be reached between the
applicant and MCOC, a subsequent application may then be made to the EUB to set
rates and charges for gas processing, purchase and/or transportation at the
Calmar system. The EUB also has the general authority pursuant to the Oil and
Gas Conservation Act and Alberta Pipeline Act, R.S.C. 1980, c. P-80, to conduct
an investigation into
10
<PAGE>
matters and questions involving gas plants and pipelines located within Alberta,
such as the Calmar system.
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, local and Canadian authorities. This
regulation can include ongoing oversight regulation as well as requirements for
construction or other permits and clearances that must be granted in connection
with new projects or expansions. 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 that relate to us. It is not intended to constitute a complete
discussion of the various federal, state, local and Canadian statutes, rules,
regulations or orders to which our operations may be subject.
In most instances, these regulatory requirements relate to the release of
substances into the environment and include measures to control water and air
pollution. Moreover, we could incur liability under the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980, as amended, or
state counterparts, regardless of our fault, in connection with the disposal or
other releases of hazardous substances, including those arising out of
historical operations conducted by our predecessors. Further, the recent trend
in environmental legislation and regulations is toward stricter standards, and
this trend will likely continue in the future.
Environmental laws and regulations may also require us to acquire a permit
before we may conduct certain activities. Further, these laws and regulations
may limit or prohibit activities on certain lands lying within wilderness areas,
wetlands, areas providing habitat for certain species that have been identified
as "endangered" or "threatened" or other protected areas. We are also subject to
other federal, state and local laws covering the handling, storage or discharge
of materials, and we are subject to laws that otherwise relate to the protection
of the environment, safety and health. As an employer, we are required to
maintain a workplace free of recognized hazards likely to cause death or serious
injury and to comply with specific safety standards.
We will make expenditures in connection with environmental matters as part
of our normal operations and capital expenditures. In addition, the possibility
exists that stricter laws, regulations or enforcement policies could
significantly increase our compliance costs and the cost of any remediation that
might become necessary. We are subject to an inherent risk of incurring
environmental costs and liabilities because of our handling of oil, natural gas
and petroleum products, historical industry waste disposal practices and prior
use of natural gas flow meters containing mercury. There can be no assurance
that we will not incur material environmental costs and liabilities. Management
believes, based on our current knowledge, that we have obtained and are in
current compliance with all necessary and material permits and that we are in
substantial compliance with applicable material environmental and safety
regulations. Further, we maintain insurance coverages that we believe are
customary in the industry; however, there can be no assurance that our
environmental impairment insurance will provide sufficient coverage in the event
an environmental claim is made against us. See "Business and Properties--
Insurance." We are not aware of any existing environmental or safety claims
that would have a material impact upon our financial position or results of
operations.
11
<PAGE>
PIPELINE SYSTEMS
As of December 31, 1999, the Company owned an interest in and operated 81
pipelines consisting of three interstate transmission pipelines, one intrastate
transmission pipeline, 35 end-user pipelines and 42 gathering pipelines. The
majority of these pipelines are situated strategically in the Company's core
operating areas. Certain information concerning the Company's pipelines is
summarized in the following table:
<TABLE>
<CAPTION>
DATE OF
ACQUISITION OR AVERAGE DAILY DAILY VOLUME
INITIAL LENGTH VOLUME (b) CAPACITY (b)
PIPELINE SYSTEM (a) OPERATIONS LOCATION IN MILES (MMBTU/DAY) (MMBTU/DAY)
- ---------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
TRANSMISSION PIPELINES:
MIDLA 10/97 Monroe, LA to Baton Rouge, LA 404.6 95,850 190,000
MIT 05/97 Selmer, TN to Huntsvile, AL 295.3 78,648 200,000
Kansas Pipeline 11/99 OK, KS, and MO 1,120.0 52,570 160,000
Magnolia 09/95 Central, AL 111.0 17,721 120,000
--------------------------------------------------------
Total Transmission (4 systems) 1,930.9 244,789 670,000
END-USER PIPELINES:
Baton Rouge 10/97 E. Baton Rouge Parish, LA 33.2 32,181 80,000
Champion 05/97 Lawerence & Colbert Cos., AL 38.0 25,000 50,000
Farmlands 10/97 Grant Parish, LA 4.3 22,059 62,000
Creole 06/98 Orleans Parish, LA 44.0 16,363 115,000
Crown Vantage 10/97 E. Baton Rouge Parish, LA 2.5 7,653 32,800
All Other (30 Systems) TX, KS, LA, NY, TN 86.2 36,571 301,622
--------------------------------------------------------
Total End-User (35 Systems) 208.2 139,827 641,422
GATHERING PIPELINES AND NATURAL GAS PROCESSING:
Anadarko/Mendota(d) 08/98 OK and TX Panhandle 731.0 157,755 345,000
Calmar (d) 03/99 Calgary, CA 30.0 16,930 26,000
T33 10/97 Offshore, LA 3.9 15,315 24,000
Cook Inlet -- Oil 07/94 Cook Inlet, AK 2.7 15,026 120,000
Gloria 12/99 South, LA 133.0 8,724 75,000
All Other Systems AK, TX, OK, AL, MS, LA, CA 905.7 154,519 1,393,500
(27 systems)(e)
--------------------------------------------------------
Total Gathering (42 systems) 1,806.3 368,269 1,983,500
--------------------------------------------------------
Total Pipelines (81 Systems) 3,945.4 752,885 3,294,922
========================================================
</TABLE>
- --------------------
(a) Unless otherwise indicated, all systems are 100% owned and operated by the
Company. Inactive systems owned by the Company are not included.
(b) All volume and capacity information is approximate. Average daily volumes
are based on total volumes transported during the twelve-month period ended
December 31, 1999, except systems that were acquired during 1999. For these
systems, the average daily volumes are based on total volumes transported
from the date of acquisition or initial operation through December 31,
1999.
(c) This system is owned by SeaCrest Company L.L.C., in which the Company owns
a 70% interest, and is operated by the Company.
(d) These gathering systems include natural gas processing and/or treating
facilities.
(e) This includes systems owned by Texana Gas Pipeline Company, in which the
Company owns a 50% interest and Pan Grande Pipeline LLC, in which the
Company owns a 70% interest.
OIL AND GAS PROPERTIES
The Company owned several non-operated working interests in producing and
non-producing oil and natural gas properties. For the year ended December 31,
1999, revenues from the Company's oil and natural gas properties were less than
1% of its total revenues, and for the same period the Company's oil and natural
gas properties represented less than 1% of its total assets.
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
12
<PAGE>
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. 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, however that the Company's insurance coverage will be
available or adequate for any particular risk or loss or that the Company will
be able to maintain adequate insurance in the future at rates it considers
reasonable. Although management believes that the Company's assets are
adequately covered by insurance, a substantial uninsured loss could have a
material adverse impact on the Company's financial position, results of
operations or cash flows.
EMPLOYEES AND CONTRACT SERVICE ORGANIZATIONS
The Company had 223 full-time employees on December 31, 1999. The Company
also had arrangements with other unaffiliated independent pipeline operating
companies to service and operate the Company's extensive field operations and
provide for emergency response measures. The Company is not a 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.
ITEM 2. PROPERTIES.
See "Item 1. Business" for a discussion of properties and locations.
ITEM 3. LEGAL PROCEEDINGS.
The Company is currently involved in certain litigation that arose in the
ordinary course of business. Except as otherwise disclosed in the KPC
acquisition discussion in the "Rate and Regulatory Matters" section, management
believes that all costs of settlements or judgments arising from such suits will
not have a material adverse effect on our consolidated financial position,
results of operations or cash flows.
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.
13
<PAGE>
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
MATTERS.
MARKET INFORMATION AND DIVIDEND POLICY
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
January 1, 1998 to December 31, 1999.
All prices and dividends per share below, and included elsewhere in this
10-K, have been adjusted to reflect the 10% stock dividend declared on February
3, 1998 and paid on March 2, 1998 to stockholders of record on February 13,
1998, as well as the five-for-four stock split declared on February 1, 1999, and
paid on March 1, 1999, to stockholders of record on February 11, 1999.
Dividends
High Low Paid per Share
---------- ---------- ---------------
1998
First Quarter $19.00 $14.72 $.058
Second Quarter 18.70 15.09 .064
Third Quarter 18.95 13.30 .064
Fourth Quarter 17.41 13.41 .064
1999
First Quarter $18.70 $15.50 $.064
Second Quarter 17.63 15.00 .070
Third Quarter 21.00 16.00 .070
Fourth Quarter 20.31 15.75 .070
On March 27, 2000, the closing price for the Common Stock, as reported by the
AMEX, was $16.25 per share. As of March 27, 2000, there were 319 holders of
record of common stock. The Company believes that there are substantially more
beneficial holders of Common Stock.
On February 3, 1998, the Board declared a 10% stock dividend to be paid March
2, 1998 to stockholders of record at the close of business on February 13, 1998.
No fractional shares were issued and stockholders 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 the stock dividend record date.
On February 1, 1999, the Board declared a five-for-four stock split to be
paid March 1, 1999 to stockholders of record at the close of business on
February 11, 1999. No fractional shares were issued, and stockholders 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 the stock split record date.
Holders of 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 if to do so would be in violation of laws or
restrictions under contractual arrangements (including credit agreements) to
which the Company is or may hereafter become a party.
It is the Company's current policy to continue to pay a quarterly dividend;
however, the amount of future cash dividends, if any, will depend upon future
earnings, results of operations, capital requirements, covenants contained in
various financing agreements of the Company and its subsidiaries, the financial
condition of the Company and certain other factors. Accordingly, there can be
no assurances that dividends will be paid by the Company in the future. See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations - Capital Resources and Liquidity".
14
<PAGE>
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,
-----------------------------------------------------------
1999 1998 1997 1996 1995
--------- --------- --------- -------- ---------
<S> <C> <C> <C> <C> <C>
(In thousands, except per share amounts)
STATEMENT OF OPERATIONS DATA:
Operating revenues $391,571 $234,069 $112,744 $29,415 $15,622
Operating income (1) 20,903 13,553 7,291 2,573 2,569
Interest expense 6,533 3,247 1,067 413 339
Income before income taxes 14,190 10,422 5,914 1,914 2,193
Net income 11,439 9,113 5,764 1,914 2,193
Net income applicable to common shareholders 11,439 9,113 5,764 1,891 2,134
PER SHARE DATA:
Net income per share applicable to common shareholders
Basic $ 1.25 $ 1.29 $ 1.13 $ .73 $ 1.08
Diluted $ 1.22 $ 1.25 $ 1.10 $ .73 $ 1.08
Weighted average number of common shares outstanding
Basic 9,176 7,074 5,115 2,593 1,980
Diluted 9,401 7,298 5,251 2,598 1,980
Cash dividends declared per common share $ .27 $ .25 $ .24 $ .06 $ -
OTHER DATA:
Depreciation, depletion and amortization $ 7,545 $ 3,197 $ 1,592 $ 818 $ 452
General and administrative 8,431 6,317 3,526 1,223 785
Cash flow from operating activities 16,699 17,169 3,856 2,564 2,361
DECEMBER 31,
-------------------------------------------------------
1999 1998 1997 1996 1995
-------- -------- -------- ------- -------
(In thousands)
BALANCE SHEET DATA:
Working capital (deficit) $ (1,539) $ 989 $ 1,888 $ 1,135 $ (99)
Property, plant and equipment, net 392,969 154,247 97,552 16,965 8,206
Total assets 478,372 191,342 128,038 27,303 11,089
Long-term debt, net of current portion 240,000 78,082 28,923 4,015 3,961
Shareholders' equity 160,677 66,284 61,451 13,593 4,157
(1) Operating revenues less operating expenses.
</TABLE>
15
<PAGE>
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. For the four year
period ended 1999, the Company acquired or constructed 73 pipelines for an
aggregate cost of approximately $369 million. 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 natural gas transported, purchased and sold through its pipeline systems or
processed at its processing facilities. With the exception of the Company's
natural gas processing activities, which represent a small component of the
Company's overall earnings, the Company's revenues are derived from fee based
sources. As a result, the Company's earnings have little sensitivity to changes
in commodity prices. In addition, most of the Company's operating costs do not
vary directly with volume on existing systems, thus, increases or decreases in
transportation volumes generally have a direct effect on net income. The Company
derives its revenues from three primary sources: (i) the marketing of natural
gas and other petroleum products, (ii) transportation fees from pipeline systems
owned by the Company the processing and treating of natural gas and (iii) the
processing and treating of natural gas.
The Company's marketing revenues are realized through the purchase and
resale of natural gas and other petroleum products to the Company's customers.
Generally, gas marketing activities will generate higher revenues and
correspondingly higher expenses than revenues and expenses associated with
transportation activities, given the same volumes of natural 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 natural 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.
Transportation fees are received by the Company for transporting natural gas
or crude oil owned by other parties through the Company's pipeline systems,
transport trucks and railcars. Typically, the Company incurs very little
incremental operating or administrative overhead cost to transport natural gas
through its pipeline assets, 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 NGL's as well as the sale of the residual natural gas.
These revenues occur under processing contracts with producers of natural gas
utilizing both a "percentage of proceeds" and "keep-whole" basis. The contracts
based on percentage of proceeds provide that the Company receives a percentage
of the NGL's and residual natural gas revenues as a fee for processing the
producer's gas. The keep-whole contracts require that the Company reimburse the
producers for the Btu energy equivalent of the NGL's and fuel removed from the
natural gas as a result of processing and the Company retains all revenues from
the sale of the NGL's. The Company's processing margins can be adversely
affected by declines in NGL's prices, declines in natural gas throughput, or
increases in shrinkage or fuel costs, and in the case of keep-whole contracts,
margins can be adversely affected affected by increases in natural gas prices.
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. In particular, demand on the Magnolia, MIT 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, the winter months have historically 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.
RESULTS OF OPERATIONS
The Company has acquired or constructed numerous pipelines in the four-year
period ended December 31, 1999. The purchased assets were acquired from numerous
sellers, at different periods throughout the year and all were accounted for
under the purchase method of accounting
16
<PAGE>
for business combinations and accordingly, the results of operations for such
acquisitions 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 Company adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective January 1, 1998.
Accordingly, the Company has segregated its business activities into three
segments: Transmission Pipelines, End-User Pipelines, and Gathering Pipelines
and Natural Gas Processing.
Consolidated gross margin for the year ended December 31, 1999, increased
66% to $37.6 million compared to $22.6 million in 1998. Consolidated gross
margin for the year ended December 31, 1998, was $10.6 million higher than for
the same period in 1997. Variations for each segment are discussed in the
segment results below.
SEGMENT RESULTS
The following tables present certain data for each of the three operating
segments of the Company for the three years in the period ended December 31,
1999. As previously discussed, the Company provides marketing services to its
customers. For analysis purposes, the Company accounts for the marketing
services by recording the marketing activity on the operating segment where it
occurs. Therefore, the gross margin for each segment includes a transportation
component and a marketing component. The Company evaluates each of its segments
on a gross margin basis, which is defined as the revenues of the segment less
related direct costs and expenses of the segment and does not include
depreciation, interest or allocated corporate overhead. For further analysis on
each segment regarding identifiable assets, depreciation and corporate
administrative expenses, see Note 16 - Segment Data in the Notes to Consolidated
Financial Statements.
TRANSMISSION PIPELINES
For the Year Ended December 31,
----------------------------------------------
1999 1998 1997
----------------------------------------------
(in thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $113,423 $111,924 $ 61,274
Transportation Fees 11,366 6,387 3,513
-------- -------- --------
TOTAL OPERATING REVENUES 124,789 118,311 64,787
-------- -------- --------
OPERATING EXPENSES:
Marketing Costs 99,726 100,889 57,333
Operating Expenses 5,975 4,383 1,592
-------- -------- --------
TOTAL OPERATING EXPENSES 105,701 105,272 58,925
-------- -------- --------
GROSS MARGIN $ 19,088 $ 13,039 $ 5,862
======== ======== ========
VOLUME (in MMBtu)
Marketing 47,900 47,649 22,454
Transportation 64,503 49,506 30,752
-------- -------- --------
TOTAL VOLUME 112,403 97,155 53,206
======== ======== ========
GROSS MARGIN per MMBtu $ .17 $ .13 $ .11
======== ======== ========
Year Ended December 31, 1999 compared to Year Ended December 31, 1998
Increases in transmission segment revenues were primarily due to increased
throughput volumes, increased transportation fees and the Company's acquisition
of KPC in November 1999. The increase in throughput volumes was primarily from
increased volumes on the MIT system and the additional volumes provided from the
KPC acquisition. Increased margins per MMBtu in marketing related activities
also contributed to the increase in segment earnings.
17
<PAGE>
Year Ended December 31, 1998 compared to Year Ended December 31, 1997
The Company's entrance into the regulated interstate pipeline business
began with the acquisition of the MIT system in June 1997 and the MIDLA system
in November 1997 which significantly enhanced the Company's transmission
pipeline operations in 1998. A complete year of operations in 1998 provided a
83% increase in revenues, an 83% increase in total volumes and a 122% increase
in gross margin when compared to the same period in 1997. In addition to a
complete year of operations, average daily demand transportation volume
("Average Demand") increased on both systems in 1998. The MIT system's Average
Demand increased 19% to 158,000 MMBtu in 1998 while the MIDLA system's Average
Demand increased 13% to 166,000 MMBtu in 1998
END-USER PIPELINES
For the Year Ended December 31,
---------------------------------------------------
1999 1998 1997
-------- -------- --------
(in thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $122,189 $96,433 $33,862
Transportation Fees 3,252 3,287 2,487
-------- ------- -------
TOTAL OPERATING REVENUES 125,441 99,720 36,349
-------- ------- -------
OPERATING EXPENSES:
Marketing Costs 117,242 94,263 32,673
Operating Expenses 345 224 208
-------- ------- -------
TOTAL OPERATING EXPENSES 117,587 94,487 32,881
-------- ------- -------
GROSS MARGIN $ 7,854 $ 5,233 $ 3,468
======== ======= =======
VOLUME (in MMBtu)
Marketing 49,513 41,336 11,867
Transportation 21,151 20,415 12,415
-------- ------- -------
TOTAL VOLUME 70,664 61,751 24,282
======== ======= =======
GROSS MARGIN per MMBtu $ .11 $ .08 $ .14
======== ======= =======
Year Ended December 31, 1999 compared to Year Ended December 31, 1998
The Company's end-user segment experienced significant increases in revenues
and gross margin in 1999 compared to 1998. These increases were primarily due to
the addition of a high-pressure pipeline system servicing a new cogeneration
facility near Baton Rouge, Louisiana and the additional earnings that were
achieved through the acquisition of SIGCO in June 1999. The high pressure
pipeline system was not fully optimized until the second half of 1999.
Year Ended December 31, 1998 compared to Year Ended December 31, 1997
The Company's end-user segment experienced significant increases in revenues
and gross margin in 1998 compared to 1997, primarily due to 1998 having the
benefit of a complete year of operations of the Champion and Monsanto systems
(acquired in the MIT Acquisition in June 1997) and Crown Vantage and Farmlands
systems (acquired in the MIDLA Acquisition in November 1997). A new marketing
services contract to provide 25 MMcf/day of marketing services beginning January
1, 1998 to an industrial facility near Port Hudson, Louisiana also contributed
to the increase in 1998 over 1997.
The Company's gross margin per MMBtu declined in 1998 as compared to 1997.
The decrease was attributable to an increase in marketing activities, which are
characterized by lower margins and higher volumes.
18
<PAGE>
GATHERING PIPELINES AND NATURAL GAS PROCESSING
For the Year Ended December 31,
---------------------------------------------
1999 1998 1997
--------------- --------------- -----------
(in thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $110,064 $ 6,761 $ 5,597
Transportation Fees 12,039 3,732 693
Processing and Treating Revenue 16,844 5,107 4,956
-------- ------- -------
TOTAL OPERATING REVENUES 138,947 15,600 11,246
-------- ------- -------
OPERATING EXPENSES:
Marketing Costs 104,528 4,781 4,548
Operating Expenses 11,263 2,410 415
Processing and Treating Costs 12,450 4,052 3,566
-------- ------- -------
TOTAL OPERATING EXPENSES 128,241 11,243 8,529
-------- ------- -------
GROSS MARGIN $ 10,706 $ 4,357 $ 2,717
======== ======= =======
VOLUME (in MMBtu)
Marketing 30,918 4,326 2,170
Transportation 96,567 48,136 13,603
Processing and Treating 11,552 2,544 1,850
-------- ------- -------
TOTAL VOLUME 139,037 55,006 17,623
======== ======= =======
GROSS MARGIN per MMBtu $ .08 $ .08 $ .15
======== ======= =======
Year Ended December 31, 1999 compared to Year Ended December 31, 1998
The Company's gathering and processing segment experienced significant
increases in revenues and gross margins in 1999 compared to 1998. These
increases were mostly attributable to a full year of Anadarko system
earnings and the Seacrest, Calmar and DPI/Flare acquisitions in March 1999.
Although marketing revenues increased over 1,500%, overall marketing margins
increased approximately 180% due to DPI's higher volume but lower margin
marketing business.
Year Ended December 31, 1998 compared to Year Ended December 31, 1997
Revenues, gross margins and volumes increased substantially in 1998
compared to 1997 in the Gathering Pipelines and Natural Gas Processing business
segment.
The significant increase in gathering activity in 1998 was attributable to
the Anadarko Acquisition that was effective in August 1998. Although the
Company's 1998 operations only included five months of activity from the
Anadarko system, it was responsible for 50% of the volumes gathered and
approximately $1 million of the gross margin earned in 1998.
Despite a 38% increase in the volume of natural gas processed through its
processing facilities, the Company's gross margin from processing activities
declined significantly in 1998 as compared to 1997. This decline was due to
lower processing spreads realized in 1998 as NGL commodity prices continued to
deteriorate throughout the year. The increase in processing volumes in 1998 was
attributable to the acquisition of the Hobart processing plant in the Anadarko
Acquisition in August 1998.
19
<PAGE>
Marketing volumes increased 99% in 1998 over 1997. These volumetric
increases were the result of various acquisitions. Collectively, two
acquisitions accounted for 90% of the increase.
OTHER INCOME, COSTS AND EXPENSES
Year Ended December 31, 1999 Compared to Year Ended December 31, 1998
Other revenues for the year ended December 31, 1999 increased to $2.4
million from $0.4 million in 1998. The increase was primarily attributable to
income earned by Flare on processing and treating plant construction projects.
Depreciation, depletion and amortization for the year ended December 31,
1999 increased to $7.5 million from $3.2 million in 1998. This increase was
primarily due to increased depreciation on assets acquired in the KPC, Anadarko,
DPI/Flare and Calmar acquisitions.
General and administrative expenses for the year ended December 31, 1999
increased to $8.4 million from $6.3 million in 1998. The increase was due to
increased costs associated with the management of the assets acquired in the
KPC, Anadarko, DPI/Flare and Calmar acquisitions. General and administrative
expenses, as a percentage of gross margin, decreased 6% from 28% in 1998 to 22%
in 1999.
Interest expense for the year ended December 31, 1999 increased to $6.5
million, from $3.2 million in 1998. The Company was servicing an average of
$110.5 million in debt for the year ended December 31, 1999 as compared to $45.6
million in debt for the year ended December 31, 1998. The increased debt level
in 1999 was primarily associated with the debt used to finance the Company's KPC
acquisition in November 1999 as well as its DPI/Flare and Calmar acquisitions in
March 1999. The additional expense related to increased debt levels was
mitigated by a reduction in the Company's weighted average interest rate. The
Company's weighted average interest rate was 6.37% and 7.11% for the years ended
December 31, 1999 and 1998, respectively.
During the fourth quarter of fiscal 1999, the Company recorded a pre-tax
unusual charge totaling $2.7 million ($2.2 million after tax) related to the
streamlining efforts announced in November 1999. The charge primarily relates
to the severance and benefits of approximately 50 employees who were involuntary
terminated. The Company anticipates savings from reduced employee cost and more
streamlined operating and business processes. At December 31, 1999, an accrued
liability of $1.8 million related to the severance charges was included in
"Accounts payable and accrued liabilities" on the consolidated balance sheet.
Thirty-three of these employees were still employed with the Company at December
31, 1999. The final severance will be paid in April 2002.
The Company had an extraordinary charge of $0.6 million for the year ended
December 31, 1999 incurred in connection with the write-down of deferred
financing charges as a result of amending the Company's credit facility.
Operating income, excluding the unusual charge, for the year ended December
31, 1999 increased to $23.6 million from $13.6 million in 1998.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
In 1998, the Company received revenues of $0.4 million from its oil and
natural gas properties as compared to $0.3 million over the same period in 1997.
The increase was primarily attributable to a one-time settlement received by the
Company on its Vealmoor Field properties.
In 1998, the Company's depreciation, depletion and amortization increased
when compared to 1997 primarily due to increased depreciation on assets acquired
in the MIT, MIDLA and Anadarko Acquisitions. Collectively, these acquisitions
accounted for 105% of the increase of $1.6 million.
The Company's general and administrative expenses in 1998 increased $2.8
million when compared to 1997 primarily due to the numerous acquisitions the
Company made during 1997 and 1998. In addition, the increase was attributed to
the Company's expansion of its infrastructure to allow for continued growth.
Interest expense for the year ended December 31, 1998 increased to $3.2
million, from $1.1 million in 1997. The Company was servicing an average of
$45.6 million in debt for the year ended December 31, 1998 as compared to $13.6
million in debt for the year ended December 31, 1997. The increased debt load
in 1998 was primarily associated with the debt used to finance the MIDLA
Acquisition being outstanding for a full year as compared to only two months in
1997. In addition, $35 million of additional debt associated with the Anadarko
Acquisition was outstanding for four months in 1998. The additional expense
related to increased debt levels was mitigated by a reduction in
20
<PAGE>
the Company's weighted average interest rate. The Company's weighted average
interest rate was 7.11% and 7.83% for the years ended December 31, 1998 and
1997, respectively.
The Company recognized annual operating income and net income in 1998 of
$13.6 million and $9.1 million, respectively, as compared to $7.3 million in
operating income and $5.8 million in net income for the year ended 1997. EPS
increased 14% from $1.10 in 1997 to $1.25 in 1998. The significant improvement
in EPS is primarily attributable to the positive impact of accretive
acquisitions consummated during 1998 and 1997.
INCOME TAXES
As of December 31, 1999, the Company has NOL carryforwards of approximately
$10.3 million, expiring in various amounts from 2003 through 2018. These loss
carryforwards were generated by companies acquired by Midcoast. 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 $5.2 million) on the use of such carryforwards due to a
change in shareholder control under section 382 of 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 and DPI.
The valuation allowance declined $2.1 million during the year ended
December 31, 1999. The decline was the net result of current year utilization of
net operating losses to offset taxable income and the removal of $581,000 of
valuation allowance related to net operating losses that are more likely than
not to be utilized in the future.
CAPITAL RESOURCES AND LIQUIDITY
Since 1996, the Company has acquired approximately $368.9 million of
pipeline systems. Capital requirements have been funded through equity
infusions from common stock offerings, borrowings from various commercial banks
and cash flow from operations.
The Company has raised net proceeds of approximately $128 million in four
common stock offerings since being listed on the American Stock Exchange in
August 1996. These capital infusions and the stability of our cash flow has
allowed the Company the financial flexibility to utilize lower cost conventional
bank debt financing to fund a large part of its growth. The Company's long-term
debt to total capitalization ratio increased from 54% at December 31, 1998 to
60% at December 31, 1999.
In November 1999 and again in March 2000, the Company amended and restated
its bank financing agreement under the certain Amended and Restated Credit
Agreement dated August 31, 1998. The amendments added additional banks to the
syndicate, increased our borrowing availability, modified our letter of credit
facility, extended the maturity five years to November 2004, modified financial
covenants, established waiver and amendment approvals and changed the method to
determine the interest rate to be charged.
The amendments to the credit agreement increased our borrowing availability
from $125 million to $335 million, with a provision to increase up to $400
million. The amended credit agreement provides borrowing availability as
follows: (i) up to a $25 million sublimit for the issuance of standby and
commercial letters of credit and (ii) the difference between the $335 million
and the used sublimit available as a revolving credit facility. At the option of
the Company, borrowings under the amended credit agreement accrue interest at
LIBOR plus an applicable margin or the higher of the Bank of America prime rate
or the Federal Funds rate plus an applicable margin.
The applicable margin percentage to be added to the interest rate is based
on the Company's debt to total capitalization ratio at the end of each fiscal
quarter. The Company is charged a margin between 1.0% and 2.0% as the Company's
total debt to total capitalization ratio ranges from under 40% and over 65%,
respectively. The Company's borrowings are currently being charged at the
margin of 1.75%. The Company was also subject to an arrangement fee, agency
fee, underwriting fee, unused fee and commitment fee totaling $1.2 million.
Additionally, the Company is subject to an annual administrative agency fee of
$35,000.
The credit agreement is secured by all accounts receivable, contracts, and
the pledge of all of our subsidiaries' stock and a first lien security interest
in our pipeline systems. It also contains a number of customary covenants that
require us to maintain certain financial ratios and limit our ability to incur
additional indebtedness, transfer or sell assets, create liens, or enter into a
merger or consolidation. The Company is required to comply with more stringent
debt to capitalization and EBITDA to interest ratios by June 30, 2000.
Subsequent to the amendment in March 2000, the Company has approximately $73
million of available capacity under its credit agreement.
For the year ended December 31, 1999, the Company generated cash flow from
operating activities of approximately $16.7 million.
21
<PAGE>
Currently, the Company has committed to making approximately $4.9 million in
construction related expenditures in 2000. The Company believes that its credit
agreement and funds provided by operations will be sufficient to meet its
operating cash needs for the foreseeable future and its projected capital
expenditures, other than acquisitions.
If sufficient funds under the credit agreement are not available to fund
acquisition and construction projects, the Company would seek to obtain such
financing from 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 growth strategy in as aggressive a manner as currently
planned.
RECENT ACCOUNTING PRONOUNCEMENT
The FASB issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities". This Statement establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, (collectively referred to as derivatives) and for
hedging activities. SFAS No. 133 will require the Company to record all
derivatives on the balance sheet at fair value. Changes in derivative fair
values will either be recognized in earnings as offsets to the changes in fair
value of related hedged assets, liabilities and firm commitments or, for
forecasted transactions, deferred and recorded as a component of other
shareholders' equity until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a hedging derivative's change in fair
value will be immediately recognized in earnings. The impact of SFAS No. 133 on
the Company's financial statements will depend on a variety of factors,
including future interpretative guidance from the FASB, the extent of the
Company's hedging activities, the types of hedging instruments used and the
effectiveness of such instruments. The standard was amended by SFAS No. 137 in
June 1999. The amendment defers the effective date of SFAS No. 133 to fiscal
years beginning after June 15, 2000. The Company is currently evaluating the
effects of this pronouncement.
ENVIRONMENTAL AND SAFETY MATTERS
Our 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, local and Canadian authorities. This
regulation can include ongoing oversight regulation as well as requirements for
construction or other permits and clearances that must be granted in connection
with new projects or expansions. 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 that
relate to us. It is not intended to constitute a complete discussion of the
various federal, state, local and Canadian statutes, rules, regulations, or
orders to which our operations may be subject.
In most instances, these regulatory requirements relate to the release of
substances into the environment and include measures to control water and air
pollution. Moreover, we could incur liability under the Comprehensive
Environmental Response, Compensation, and Liability Act of 1980, as amended, or
state counterparts, regardless of our fault, in connection with the disposal or
other releases of hazardous substances, including those arising out of
historical operations conducted by our predecessors. Further, the recent trend
in environmental legislation and regulations is toward stricter standards, and
this trend will likely continue in the future.
Environmental laws and regulations may also require us to acquire a permit
before we may conduct certain activities. Further, these laws and regulations
may limit or prohibit activities on certain lands lying within wilderness areas,
wetlands, areas providing habitat for certain species that have been identified
as "endangered" or "threatened" or other protected areas. We are also
subject to other federal, state and local laws covering the handling, storage or
discharge of materials, and we are subject to laws that otherwise relate to the
protection of the environment, safety and health. As an employer, we are
required to maintain a workplace free of recognized hazards likely to cause
death or serious injury and to comply with specific safety standards.
We will make expenditures in connection with environmental matters as part
of our normal operations and capital expenditures. In addition, the possibility
exists that stricter laws, regulations or enforcement policies could
significantly increase our compliance costs and the cost of any remediation that
might become necessary. We are subject to an inherent risk of incurring
environmental costs and liabilities because of our 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 we will
not incur material environmental costs and liabilities. Management believes,
based on our current knowledge, that we have obtained and are in current
compliance with all necessary and material permits and that we are in
substantial compliance with applicable material environmental and safety
regulations. Further, we maintain insurance coverages that we
22
<PAGE>
believe are customary in the industry; however, there can be no assurance that
our environmental impairment insurance will provide sufficient coverage in the
event an environmental claim is made against us. See "Business and Properties--
Insurance." We are not aware of any existing environmental or safety claims
that would have a material impact upon our financial position or results of
operations.
YEAR 2000
The Company completed all phases of the Year 2000 Program relative to
computer systems and technology infrastructure considered essential to the
Company's business prior to the event. The year 2000 event passed without
significant incident. The Company's contingency plans are designed to minimize
any disruptions or other adverse effects resulting from unexpected
incompatibilities regarding core systems and business applications and to
facilitate the early identification and remediation of system problems that
manifest themselves after December 31, 1999. To date, no significant items have
been identified. The Company continues to assess, test and remediate business
application and technology infrastructure that were previously determined to be
other than essential to core business operations. The extent of these activities
is very insignificant to the Company's overall business. Aggregate costs
expended for the Year 2000 Project totaled approximately $1.0 million.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This Form 10-K contains forward-looking statements within the meaning of
Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. All statements other than statements of historical fact
included in and incorporated by reference into this Form 10-K are
forward-looking statements. These 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
the Company's estimate of the sufficiency of existing capital resources, whether
funds provided by operations will be insufficient to meet its operational needs
in the foreseeable future, and its ability to use NOL carryforwards prior to
their expiration. Although, we believe that the expectations reflected in these
forward looking statements are reasonable, we can not give any assurance that
such expectations reflected in these forward looking statements will prove to
have been correct.
When used in this Form 10-K, the words "expect", "anticipate", "intend",
"plan", "believe", "seek", "estimate", and similar expressions are intended to
identify forward-looking statements, although not all forward-looking statements
contain these identifying words. Because these forward-looking statements
involve risks and uncertainties, actual results could differ materially from
those expressed or implied by these forward-looking statements for a number of
important reasons, including those discussed under "Management's Discussion and
Analysis of Financial Condition and Results of Operations", and elsewhere in
this Form 10-K.
You should read these statements carefully because they discuss our
expectations about our future performance, contain projections of our future
operating results or our future financial condition, or state other "forward-
looking" information. Before you invest in our common stock, you should be aware
that the occurrence of any of the events described in "Risk Factors" in the
Prospectus Supplement, dated December 6, 1999 and elsewhere in this Form 10-K
could substantially harm our business, results of operations and financial
condition and that upon the occurrence of any of these events, the trading price
of our common stock could decline, and you could lose all or part of your
investment.
We cannot guarantee any future results, levels of activity, performance or
achievements. Except as required by law, we undertake no obligation to update
any of the forward-looking statements in this Form 10-K after the date of this
Form 10-K.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest rates. 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 the price of energy commodities and fluctuations in interest
rates. The Company does not engage in speculative trading. Approvals are
required from senior management prior to the execution of any financial
derivative.
COMMODITY PRICE RISK
The Company's commodity price risk exposure arises from inventory balances
and fixed price purchase and sale commitments. The Company uses exchange-traded
commodity futures contracts, options and swap contracts to manage and hedge
price risk related to these market exposures. These futures and options
contracts have pricing terms indexed to the NYMEX.
23
<PAGE>
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 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 11 - Financial Instruments
and Price Risk Management Activities in the Notes to Consolidated Financial
Statements). As of December 31, 1999 and 1998, the Company had net unrealized
losses on its various open commodity futures, swaps and option contracts of
$1,139,000 and $896,000, respectively. The tabular presentation related to the
Company's commodity price risk is illustrated below (in thousands, except for
price per MMBtu amounts):
As of December 31, 1999
Expected Fiscal Year of Maturity
-----------------------------------------
2000 Fair Value
------------------ --------------------
Swap Contracts:
Contract Volumes (MMBtu) 5,045 -
Weighted Average Price (Per MMBtu) $ 2.11 $ -
Contract Amount $10,635 $9,608
Futures Contracts:
Contract Volumes (MMBtu) 930 -
Weighted Average Price (Per MMBtu) $ 2.47 $ -
Contract Amount $ 2,295 $2,183
INTEREST RATE RISK
The Company's debt financial instruments are sensitive to market
fluctuations in interest rates. The interest rate swap agreements entered into
by the Company effectively convert $65 million of floating-rate debt to fixed-
rate debt (see Note 11 - Financial Instruments and Price Risk Management
Activities in the Notes to Consolidated Financial Statements). The Company
makes payments to counterparties at fixed rates and in return receives payments
at floating rates. The first swap agreement, which has a notional amount of $25
million, was entered into in December 1997. It was subsequently transferred to
another bank in November 1998 and replaced with a new swap agreement which has
an initial term of two years through December 2000 but is extendible, at the
bank's option, for an additional three years. The second swap agreement, with a
notional amount of $40 million, was entered into in October 1998 and has an
initial term of three years through November 2001 but is extendible, at the
bank's option, for an additional two years. Both transactions are recorded using
accrual accounting. The table below presents notional amounts and weighted
average interest rates by expected or contractual maturity dates. Notional
amounts are used to calculate the contractual payments to be exchanged under the
contract. The tabular presentation related to the Company's interest rate risk
is illustrated below (in thousands, except for interest rates):
<TABLE>
<CAPTION>
As of December 31, 1999
Expected Fiscal Year of Maturity
--------------------------------------------------------------------
2000 2001 2002 2003 2004 Total Fair Value
------- ------- ---- ---- -------- -------- ----------
<S> <C> <C> <C> <C> <C> <C> <C>
Liabilities:
Long-term debt, including current portion -
variable interest rate of 8.17% at
December 31, 1999 $ 71 - - - $240,000 $240,071 $240,071
Interest Rate Derivatives:
Interest rate swaps, variable to fixed rate -
notional amounts $25,000 $40,000 - - - $ 65,000 $ 976
Average interest rate 4.71% 4.48%
Average received rate 6.58% 6.99%
Net cash flow effect $ 1,211 $ 1,007
</TABLE>
24
<PAGE>
ITEM 8. FINANCIAL STATEMENTS.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
of Midcoast Energy Resources, Inc.:
In our opinion, the accompanying consolidated balance sheet and the related
consolidated statements of operations, comprehensive income, shareholders'
equity and cash flows present fairly, in all material respects, the financial
position of Midcoast Energy Resources, Inc. and its subsidiaries at December 31,
1999 and the results of their operations and their cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audit. We conducted our audit of these statements in
accordance with auditing standards generally accepted in the United States,
which require that we plan and perform the audit to obtain reasonable assurance
about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for the opinion expressed above.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 10, 2000
25
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Board of Directors and Shareholders
Midcoast Energy Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheet of Midcoast
Energy Resources, Inc. and subsidiaries as of December 31, 1998, and the related
consolidated statements of operations, shareholders' equity and cash flows for
each of the years in the two year period ended December 31, 1998. 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, 1998, and the
results of their operations and their cash flows for each of the years in the
two year period ended December 31, 1998, in conformity with generally accepted
accounting principles.
HEIN + ASSOCIATES LLP
Houston, Texas
March 18, 1999
26
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
December 31,
-------------------------------
1999 1998
------------- -------------
<S> <C> <C>
ASSETS
------
Current Assets:
Cash and cash equivalents $ 2,345 $ 200
Accounts and notes receivable, net of allowance of $1,484 and $92, respectively 55,189 33,020
Other current assets 4,905 1,363
------------- -------------
Total Current Assets 62,439 34,583
------------- -------------
Property, Plant and Equipment, net 392,969 154,247
Other Assets 22,964 2,512
------------- -------------
Total Assets $478,372 $191,342
============= =============
LIABILITIES AND SHAREHOLDERS' EQUITY
------------------------------------
Current Liabilities:
Accounts payable and accrued liabilities $ 63,901 $ 32,540
Current portion of long-term debt 71 930
Other current liabilities 6 124
------------- -------------
Total Current Liabilities 63,978 33,594
------------- -------------
Long-term Debt 240,000 78,082
Other Liabilities 2,147 2,024
Deferred Income Taxes 11,034 10,808
Commitments and Contingencies - -
Minority Interest in Consolidated Subsidiaries 536 550
Shareholders' Equity:
Common stock, par value $.01 per share; authorized 31,250,000 shares; issued
12,721,980 and 7,149,513 shares, respectively 127 71
Paid-in capital 165,964 80,955
Accumulated deficit (2,915) (11,947)
Unearned compensation - (4)
Accumulated other comprehensive income 71 -
Treasury stock (at cost), 161,156 and 181,125 treasury shares, respectively (2,570) (2,791)
------------- -------------
Total Shareholders' Equity 160,677 66,284
------------- -------------
Total Liabilities and Shareholders' Equity $478,372 $191,342
============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
27
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share and share data)
<TABLE>
<CAPTION>
For the Year Ended December 31,
--------------------------------------------
1999 1998 1997
---------- ---------- ----------
<S> <C> <C> <C>
Operating Revenues:
Energy marketing revenue $ 345,676 $ 215,118 $ 100,733
Transportation fees 26,657 13,406 6,693
Natural gas processing and treating revenue 16,844 5,107 4,956
Other 2,394 438 362
---------- ---------- ----------
Total operating revenues 391,571 234,069 112,744
---------- ---------- ----------
Operating Expenses:
Energy marketing expenses 339,079 206,950 96,769
Natural gas processing and treating costs 12,450 4,052 3,566
Other operating expenses 478 - -
Depreciation, depletion and amortization 7,545 3,197 1,592
General and administrative 8,431 6,317 3,526
Unusual charge 2,685 - -
---------- ---------- ----------
Total operating expenses 370,668 220,516 105,453
---------- ---------- ----------
Operating income 20,903 13,553 7,291
Non-Operating Items:
Interest expense (6,533) (3,247) (1,067)
Minority interest in consolidated subsidiaries (43) (58) (222)
Other income (expense), net (137) 174 (88)
---------- ---------- ----------
Total non-operating items (6,713) (3,131) (1,377)
---------- ---------- ----------
Income before income taxes and extraordinary item 14,190 10,422 5,914
Provision for income taxes:
Current (1,833) (114) (150)
Deferred (336) (1,195) -
---------- ---------- ----------
Income before extraordinary item 12,021 9,113 5,764
Extraordinary item, net of income tax provision of $300 (582) - -
---------- ---------- ----------
Net Income $ 11,439 $ 9,113 $ 5,764
========== ========== ==========
Earnings per common share:
Basic
Income before extraordinary item $ 1.31 $1.29 $ 1.13
Extraordinary Item (.06) - -
---------- ---------- ----------
Net Income $ 1.25 $1.29 $ 1.13
========== ========== ==========
Diluted
Income before extraordinary item $ 1.28 $1.25 $ 1.10
Extraordinary Item (.06) - -
---------- ---------- ----------
Net Income $ 1.22 $1.25 $ 1.10
========== ========== ==========
Weighted Average Number of Common Shares Outstanding:
Basic 9,176,201 7,074,372 5,115,169
========== ========== ==========
Diluted 9,400,754 7,298,345 5,251,456
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
28
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------
1999 1998 1997
---------------- ---------------- -----------------
<S> <C> <C> <C>
Net income.......................................... $11,439 $9,113 $5,764
Foreign currency translation adjustment............. 71 - -
------- ------ ------
Comprehensive income................................ $11,510 $9,113 $5,764
======= ====== ======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
29
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS' EQUITY
(In thousands, except per share data)
<TABLE>
<CAPTION>
Accumulated
Common Stock Other Treasury Stock Total
------------------ Paid-in Accumulated Unearned Comprehensive ---------------- Shareholders'
Shares Amount Capital Deficit Compensation Income Shares Amount Equity
--------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
BALANCE, DECEMBER 31, 1996 3,130 $ 32 $ 26,935 $(13,284) $(90) $ - - $ - $ 13,593
Net Income - - - 5,764 - - - - 5,764
Shares issued or vested
under various stock-based
compensation arrangements - - - - 72 - - - 72
10% Stock Dividend
(645 shares) 645 6 10,555 (10,565) - - - - (4)
Sale of 2,894 shares of
common stock 2,894 29 34,024 - - - - - 34,053
Common stock warrants issued in
conjunction with the MIDLA
Acquisition 481 4 9,167 - - - - - 9,171
Common Stock Dividends, $.24
per share - - - (1,198) - - - - (1,198)
------ ---- --------- --------- ----- --- ------ ---- --- --------
BALANCE, DECEMBER 31, 1997 7,150 $ 71 $ 80,681 $(19,283) $(18) $ - - $ - $ 61,451
Net Income - - - 9,113 - - - - 9,113
Shares issued or vested under
various stock-based
compensation arrangements - - - - 14 - - - 14
Warrants Exercised - - 274 - - - - - 274
Treasury Stock Purchased
(181 shares) - - - - - - (181) (2,791) (2,791)
Common Stock Dividends,
$.25 per share - - - (1,777) - - - - (1,777)
------ ---- --------- --------- ----- --- ------ ------- ---------
BALANCE, DECEMBER 31, 1998 7,150 $ 71 $ 80,955 $(11,947) $ (4) $ - (181) $(2,791) $ 66,284
Net Income - - - 11,439 - - - - 11,439
Shares issued or vested under
various stock-based
compensation arrangements - - - - 4 - - - 4
Stock options exercised - - 42 - - - - - 42
Sale of 3,572 shares of
common stock 3,572 36 54,547 - - - - - 54,583
Sale of 2,000 shares of
common stock 2,000 20 30,225 - - - - - 30,245
Treasury Stock Purchased
(144 shares) - - - - - - (144) (2,406) (2,406)
Treasury Stock issued in
connection with the DPI
Acquisition (164 shares) - - 195 - - - 164 2,627 2,822
Foreign currency translation
adjustment - - - - - 71 - - 71
Common Stock Dividends,
$.27 per share - - - (2,407) - - - - (2,407)
------ ---- -------- --------- ----- --- ------ ------- ---------
BALANCE, DECEMBER 31, 1999 12,722 $127 $165,964 $ (2,915) $ - $71 (161) $(2,570) $160,677
====== ==== ======== ======== ===== === ===== ======= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
30
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Year Ended December 31,
---------------------------------------
1999 1998 1997
---------- ---------- --------
<S> <C> <C> <C>
Cash Flows from Operating Activities:
Net income $ 11,439 $ 9,113 $ 5,764
Adjustments to arrive at net cash provided by operating activities -
Depreciation, depletion and amortization 7,545 3,197 1,592
Deferred income taxes 336 1,195 -
Recognition of deferred income (76) (83) (83)
Minority interest in consolidated subsidiaries 43 58 222
Extraordinary charge, net of tax 582 - -
Other (96) - 69
Changes in working capital accounts:
Increase in accounts receivable (11,396) (4,498) (12,022)
Increase in other current assets 186 (138) (933)
Increase in accounts payable and accrued liabilities 8,136 8,325 9,247
---------- ---------- --------
Net cash provided by operating activities 16,699 17,169 3,856
---------- ---------- --------
Cash Flows from Investing Activities:
Acquisitions, net of cash acquired (238,104) (52,076) (60,778)
Capital expenditures (16,562) (7,816) (1,410)
Net receipts from (advances to) equity investee 368 (724) -
Other - (695) (309)
---------- ---------- --------
Net cash used by investing activities (254,298) (61,311) (62,497)
---------- ---------- --------
Cash Flows from Financing Activities:
Bank debt borrowings 194,658 89,159 65,321
Bank debt repayments (33,599) (39,969) (39,891)
Net proceeds from equity offerings 84,870 - 34,053
Financing costs (1,372) (588) (504)
Treasury stock purchases (2,406) (2,791) -
Dividends on common stock (2,407) (1,777) (1,198)
---------- ---------- --------
Net cash provided by financing activities 239,744 44,034 57,781
---------- ---------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 2,145 (108) (860)
----------- ---------- -------
Cash and Cash Equivalents, beginning of year 200 308 1,168
----------- ---------- --------
Cash and Cash Equivalents, end of year $ 2,345 $ 200 $ 308
=========== ========== ========
Supplemental Disclosures:
Cash Paid for Interest $ 7,357 $ 2,135 $ 706
=========== ========== ========
Cash Paid for Income Taxes $ 460 $ 311 $ 241
=========== ========== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
31
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BUSINESS:
The Company was formed on May 11, 1992, as a Nevada corporation and in
September 1992, through a merger accounted for as a pooling of interest, became
the successor to Nugget Oil Corporation. The Company was reincorporated as a
Texas corporation in 1999.
The Company is primarily engaged in the transportation, gathering,
processing and marketing of natural gas and other petroleum products. As of
December 31, 1999, the Company owned and operated three interstate transmission
pipeline systems, one intrastate transmission system, 35 end-user systems and 42
gathering systems representing approximately 4,000 miles of pipeline with an
aggregate daily throughput capacity of over 3.0 Bcf of natural gas per day.
Operations also included natural gas processing and treating facilities and over
80 natural gas liquid and crude oil tanks and rail cars. The Company's
principal business consisted of providing transportation services 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 meet customer needs. The
Company's principal assets are located in the Gulf Coast and Mid-Continent
areas.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
Basis of Presentation and Principles of Consolidation
The accompanying consolidated financial statements include the accounts of
all majority-owned, controlled subsidiaries of the Company after the elimination
of all significant intercompany accounts and transactions. The equity method
of accounting is used for investments in affiliates where the Company owns fifty
percent or less and is not deemed to have significant control. The financial
statements for previous periods include certain reclassifications that were made
to conform to the current year presentation. Such reclassifications have no
impact on reported net income or shareholders' equity.
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 reported amounts of
assets, liabilities, revenues and expenses and disclosure of contingent assets
and liabilities that exist at the date of the financial statements. Actual
results could differ from those estimates.
Cash and Cash Equivalents
The Company considers short-term, highly liquid investments that have an
original maturity of three months or less at the time of purchase to be cash
equivalents.
Gas Imbalances
In the course of providing 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 natural 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. Natural gas imbalances
were not material as of December 31, 1999 and 1998.
Inventories
Inventories consist primarily of materials and supplies, natural gas and
liquid petroleum products. Inventories of materials and supplies utilized for
ongoing replacements and expansions are carried at average cost and are reviewed
regularly and adjusted to their net realizable value. The natural gas and liquid
petroleum products are carried at fair value, which approximates average cost.
Inventories are included in "Other Current Assets" on the consolidated balance
sheets.
Regulated Pipelines
MIT, MLGC and KPC are subject to the provisions of SFAS No. 71, "Accounting
for the Effects of Certain Types of Regulation."
32
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory assets represent probable future revenue to MIT, MLGC and KPC
associated with certain costs which will be recovered from customers through the
regulatory, or the rate making process. Regulatory assets are included in "Other
Assets" on the consolidated balances sheets.
The 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,
MLGC and KPC.
Property, Plant and Equipment
Interstate and intrastate natural gas transmission, distribution and
processing facilities and other equipment are stated at cost and depreciated by
the straight-line method at rates based on the following estimated useful lives
of the assets:
<TABLE>
<S> <C> <C>
Interstate natural gas transmission facilities 15 - 66 Years
Intrastate natural gas transmission facilities 15 - 60 Years
Pipeline right-of-ways 17 Years
Natural gas processing facilities 30 Years
Other property and equipment 3 - 10 Years
</TABLE>
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 operations 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. Major
additions, replacements and improvements 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 that include a
significant portion of the total remaining reserves.
Impairment of Long-Lived Assets
In accordance with FASB Statement No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," the Company
recognizes impairment losses for long-lived assets used in operations when
indicators of impairment are present and the undiscounted cash flows estimated
to be generated by those assets are less than the assets' carrying amount.
During the first quarter of 1999, the Company wrote down, by approximately
$145,000, a certain pipeline system to salvage value. The amount is included in
"Depreciation, depletion and amortization" in the Consolidated Statement of
Operations.
Goodwill
Goodwill, representing the excess cost of purchased subsidiaries over the
fair value of net assets acquired, is amortized using the straight-line method
over 20 years.
Treasury Stock
Treasury stock is accounted for using the cost method and is shown as a
reduction to shareholders' equity in the consolidated balance sheets. Treasury
stock sold or issued is valued on a weighted average basis.
Employee Stock Based Compensation
In 1997, the Company adopted FASB Statement No. 123, "Accounting for
Stock-Based Compensation" ("SFAS 123"). Under SFAS 123, the Company is
permitted to either record expenses for stock options and other stock-based
employee compensation plans
33
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
based on their fair value at the date of grant or to continue to apply
Accounting Principles Board Opinion No. 25 ("APB 25") and recognize compensation
expense, if any, based on the intrinsic value of the equity instrument at the
measurement date. The Company elected to continue following APB 25; therefore,
no compensation expense has been recognized because the exercise price of
employee stock options equals the market price of the underlying stock on the
date of grant.
Revenue Recognition
Customers are invoiced and the related revenue is recorded as natural gas
and other petroleum products are delivered. Oil and natural gas revenue from
the Company's interests in producing wells is recognized as oil and natural gas
is produced from those wells. Revenue from renovated and manufactured equipment
sales is recognized at the time of sale.
Income Taxes
Income taxes are based on income reported for tax return purposes along
with a provision for deferred income taxes. Deferred income taxes are provided
to reflect the tax consequences in future years of differences between the
financial statement and tax bases of assets and liabilities at each year-end.
Tax credits are accounted for under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
Deferred tax assets are reduced by a valuation allowance when, based upon
management's estimates, it is more likely than not that a portion of the
deferred tax asset will not be realized in a future period. The estimates
utilized in the recognition of deferred tax assets are subject to revision in
future periods based on new facts or circumstances.
Hedging Activities
It is the Company'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 transaction
cannot be completed, the Company will periodically enter into financial
instruments to reduce its exposure to commodity price risk. The Company 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 the NYMEX futures contract. Gains or
losses on hedging activities are deferred until the physical transaction occurs.
Gains or losses relating to financial derivatives terminated prior to maturity
are recognized currently in income. See "Note 11. Financial Instruments and
Price Risk Management Activities" for information on unrealized losses, notional
amounts and notional contracts at December 31, 1999.
Recent Accounting Pronouncement
The FASB issued SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities". This Statement establishes accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, (collectively referred to as derivatives) and for
hedging activities. SFAS No. 133 will require the Company to record all
derivatives on the balance sheet at fair value. Changes in derivative fair
values will either be recognized in earnings as offsets to the changes in fair
value of related hedged assets, liabilities and firm commitments or, for
forecasted transactions, deferred and recorded as a component of other
shareholders' equity until the hedged transactions occur and are recognized in
earnings. The ineffective portion of a hedging derivative's change in fair
value will be immediately recognized in earnings. The impact of SFAS 133 on the
Company's financial statements will depend on a variety of factors, including
future interpretative guidance from the FASB, the extent of the Company's
hedging activities, the types of hedging instruments used and the effectiveness
of such instruments. The standard was amended by SFAS No. 137 in June 1999.
The amendment defers the effective date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. The Company is currently evaluating the effects
of this pronouncement.
3. ACQUISITIONS
The MIT Acquisition
In May 1997, the Company acquired the pipeline and energy services
operations from Atrion Corporation for cash consideration of $38.2 million and
up to $2 million in contingent deferred payments. The MIT operations include (i)
a 295-mile interstate transmission pipeline located in northern Alabama,
Mississippi and southern Tennessee which transports natural gas to industrial
and municipal customers, (ii) a 38-mile and a one mile pipeline in northern
Alabama which primarily serve two large industrial customers and (iii) a natural
gas marketing company which was subsequently merged into MMI. The acquisition
was funded through the Company's existing credit facility.
The MIDLA Acquisition
34
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In October 1997, the Company completed its merger with Republic, which
owned MLGC, MLGT, and Mid Louisiana Marketing Company that was subsequently
merged into MMI. Consideration for the acquisition included $3.2 million in
cash, the assumption of approximately $19.1 million in bank indebtedness, the
issuance of 481,247 shares of the Company's common stock and the issuance of
warrants to acquire 171,880 shares of common stock. The assets acquired included
(i) a 405-mile interstate natural gas pipeline which runs from the Monroe gas
field in northern Louisiana, southward through Mississippi to Baton Rouge,
Louisiana, (ii) three end-user natural gas pipelines with a collective length of
40 miles and (iii) two offshore lateral natural gas gathering pipelines with a
collective length of 8.6 miles. These pipelines serve a number of large
industrial and municipal customers. The acquisition was funded through the
Company's existing Credit Facility.
The Anadarko Acquisition
In September 1998, MGSI purchased the Anadarko gas gathering system from El
Paso Field Services Company, a business unit of El Paso Energy Corporation. The
pipeline system was purchased for cash consideration of $35 million. The
acquisition was financed through the Company's existing credit facility.
Under the agreement, MGSI acquired ownership and operation of the Anadarko
gas gathering system located in Beckham and Roger Mills counties, Oklahoma and
Hemphill, Roberts and Wheeler counties, Texas. The system was comprised of over
696 miles of pipeline with an average throughput of 157 MMcf/day and a total
capacity of 345 MMcf/day. The system gathers natural gas from approximately 250
wells and includes a 40 MMcf/day natural gas processing facility, 11 compressor
stations and interconnections with eight major interstate and intrastate
pipeline systems.
The Company expanded the Anadarko system in December 1998 with the
acquisition of the Mendota system from Seagull Energy Corporation for $3.75
million. The Mendota system, which was interconnected with the Anadarko System,
includes two processing facilities and 35 miles of gathering pipeline.
The Calmar Acquisition
In March 1999, the Company purchased the Calmar system in Alberta, Canada
from Probe. The total value of the transaction was approximately $13.2 million
(U.S.). The assets purchased include a 30 MMcf per day amine sweetening plant,
30 miles of gas gathering pipeline and approximately 4,000 horsepower of
compression located near Edmonton, Alberta. The Calmar system currently gathers
and treats sour natural gas from wells operated by Probe and Courage Energy Inc.
In conjunction with the purchase, Probe entered into a natural gas gathering and
treating agreement with the Company, including the long-term commitment of
Probe's reserves in the Leduc Field, a right of first refusal agreement on new
or existing midstream assets within a defined 390-square mile area of interest,
and an assignment to the Company of an existing third party gathering and
treating agreement. The acquisition was funded through the Company's existing
credit facility.
The Flare and DPI Acquisitions
In March 1999, the Company purchased two related companies, Flare and DPI.
The total value of the transaction was approximately $11.1 million and could
include future consideration should certain contingencies be met. The Flare and
DPI shareholders received cash consideration of approximately $3.2 million, the
Company assumed $5.5 million in debt and the DPI shareholders received 163,719
shares of the Company's common stock. Flare is a natural gas processing and
treating company whose principal assets include 27 mobile natural gas
processing and treating plants from which it earns revenues based on treating
and processing fees and/or a percentage of the NGL's produced. DPI is an NGL,
crude oil and CO2 transportation and marketing company. DPI operates 43 NGL and
crude oil trucks and trailers, a fleet of 40 pressurized railcars and in excess
of 400,000 gallons of NGL storage facilities and product treating and handling
equipment. The acquisition was funded through the Company's existing Credit
Facility.
The Tinsley Acquisition
In March 1999, the Company purchased the Tinsley crude oil gathering
pipeline for $5.2 million. The Tinsley system is located in Mississippi and
consists of 60 miles of crude oil gathering pipeline, related truck and
Mississippi River barge loading facilities and 170,000 barrels of crude oil
storage. The system transports approximately 5,000 barrels of crude oil per day
both directly from producing wells and from oil trucked to the pipeline. The
acquisition was funded through the Company's existing credit facility.
The Kansas Pipeline Company Acquisition
In November 1999, the Company acquired KPC and other related entities for
approximately $195.2 million. KPC owns and operates a 1,120 mile regulated
interstate natural gas pipeline system. The system extends into two major
segments from northwestern and
35
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
northeastern Oklahoma through Wichita and into the Kansas City metropolitan
area. The system's two principal customers are divisions of ONEOK, Inc. and
Southern Union Company, which are the local distribution companies for Wichita
and Kansas City. KPC derives 97% of its gross margin from a series of long-term
transportation contracts with these two principal customers. KPC is capable of
delivering approximately 140 MMcf per day and 21 MMcf per day of natural gas
into the Kansas City and Wichita marketplaces, respectively. KPC is one of only
three pipeline systems currently capable of delivering gas into the Kansas City
metropolitan market. The acquisition was funded through the Company's existing
credit facility.
In conjunction with the acquisition of KPC, the Company opted to terminate
a revenue sharing agreement with Management Resources Group, LLC by agreeing to
pay approximately $10.8 million on or before January 31, 2000. The full amount
was accrued as of December 31, 1999.
The Gloria Acquisition
In December 1999, the Company acquired the Gloria system from Koch
Industries for a total price of approximately $6.1 million. The Gloria system is
comprised of approximately 133 miles of pipeline with a 1,650 horsepower
compressor station, and includes 51 miles of gathering pipeline and 82 miles of
transmission pipeline. The system gathers gas from seven producing fields and
also directly supplies natural gas to an industrial customer and an LDC in the
area. The pipeline was part of Koch's interstate system and FERC approval for
the system's abandonment from interstate service was received in October of
1999, which, following the expiration of the required notice period, enabled us
to proceed to close the Gloria system acquisition. The acquisition was funded
by a common stock offering in December 1999.
Pro Forma Information
The following summarized unaudited Pro Forma Consolidated Income Statement
information for the twelve months ended December 31, 1999 and 1998 assumes the
Company's acquisition of DPI/Flare, Calmar, SeaCrest, SIGCO, KPC and Gloria had
occurred as of January 1, 1998. The unaudited Pro Forma financial results have
been prepared for comparative purposes only and may not be indicative of results
that would have occurred if the Company had acquired these assets on January 1,
1998 or results which will be attained in the future. Amounts presented below
are in thousands, except for per share amounts:
<TABLE>
<CAPTION>
Pro Forma
Twelve Months Ended
December 31,
---------------------
Income Statement 1999 1998
---------------- ---------- ---------
(Unaudited)
<S> <C> <C>
Revenues $471,794 $425,841
Operating Income 32,779 39,129
Net Income before Extraordinary charge 12,865 17,357
Net Income 12,283 17,357
Net Income per share before extraordinary charge, diluted $ 1.37 $ 2.38
Net Income per share, diluted $ 1.31 $ 2.38
</TABLE>
The Company utilized the purchase method of accounting to record all of
its acquisitions. At the acquisition date, the respective assets and
liabilities acquired were recorded at their estimated fair values. Any excess
of the purchase price over fair value was allocated to goodwill. With the
exception of the DPI/Flare acquisition, no goodwill arose from these
transactions.
In connection with its current year acquisition activity, the Company
acquired certain assets and liabilities to include approximately $229.8 million
in property, plant and equipment, $35.4 million in other noncash assets and
$24.3 million in assumed liabilities. Furthermore, the Company issued
approximately $2.8 million of treasury stock as consideration.
4. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment consisted of the following (in
thousands):
<TABLE>
<CAPTION>
December 31,
----------------------
1999 1998
-------- ---------
<S> <C> <C>
Property, Plant, and Equipment:
Transmission............................................... $291,422 $ 75,537
End-user................................................... 24,206 18,862
Gathering and processing................................... 77,109 53,401
Corporate & other.......................................... 1,948 4,255
Construction in progress................................... 12,200 8,500
-------- --------
406,885 160,555
Less accumulated depreciation................................. 13,916 6,308
-------- --------
Total property, plant, and equipment, net..................... $392,969 $154,247
======== ========
</TABLE>
Included in construction in progress is an allocation of interest incurred
during the period related to the Baton Rouge expansion. Interest capitalized for
the years ended December 31, 1999 and 1998 totaled $0.2 million and $0.1
million, respectively. No interest was capitalized in 1997.
36
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. OTHER ASSETS
Other assets are summarized as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------------
1999 1998
------- -------
<S> <C> <C>
Regulatory assets, net of accumulated amortization of $6,670 and $585 $16,455 $ 307
Goodwill, net of accumulated amortization of $109 4,031 -
Deferred financing costs, net of accumulated amortization of $46 and $156 1,326 1,049
Other 1,152 1,156
------- ------
$22,964 $2,512
======= ======
</TABLE>
6. ACCOUNTS PAYABLE AND ACCRUED LIABILITIES:
Accounts payable and accrued liabilities are summarized as follows (in
thousands):
<TABLE>
<CAPTION>
December 31,
----------------------
1999 1998
-------- --------
<S> <C> <C>
Trade accounts payable $28,068 $28,321
Accrued gas purchases payable 15,835 -
Accrued termination fee 10,750 -
Accrued interest 809 3,963
Accrued other 8,439 256
------- -------
$63,901 $32,540
======= =======
</TABLE>
7. LONG-TERM DEBT:
At December 31, 1999 and 1998, the Company had outstanding long-term debt
as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
-----------------------
1999 1998
-------- -------
<S> <C> <C> <C>
(a) Note payable by Pan Grande to a bank under a term loan $ 71 $ 258
bearing interest at the prime rate plus 1% (9.5% and
8.75% at December 31, 1999 and 1998, respectively),
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.
(b) Revolving credit line with a bank under a $100 million - 78,000
promissory note bearing interest at 7.5% at December
31, 1998 (see following discussion).
Revolving credit line with a bank for working capital - 754
needs under a $100 million promissory note bearing
interest at 7.5% at December 31, 1998
(c) Revolving credit line with a bank under a $265 million 240,000 -
promissory note bearing interest at 8.17% at December
31, 1999 (see following discussion).
-------- -------
Total debt 240,071 79,012
Less current portion (71) (930)
-------- -------
Total long-term debt $240,000 $78,082
======== =======
</TABLE>
37
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(a) In March 1996, Pan Grande, a joint venture owned 70% by the Company,
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, members of Pan Grande have guaranteed the loan in an amount equal
to their respective ownership interest.
(b) In August 1998, the Company amended and restated its bank financing
agreement (the "Credit Agreement") with Bank One. The Credit Agreement
increased the Company's borrowing availability, modified the Letter of Credit
facility, extended the maturity two years to August 2002, modified financial
covenants, established waiver and amendment approvals and changed the fee
structure to include a decrease on the interest rate on borrowings.
The Credit Agreement increased the Company's borrowing availability from
$80 million to $150 million (with an initial committed amount of $100 million).
Under the Credit Agreement, the credit facility was provided by Bank One,
CIBC Oppenheimer, Texas N.A. and Bank of America, collectively the "Lenders."
The Company was subject to an initial facility fee of $495,000 which represented
all fees due on borrowings up to $100 million. As funds in excess of $100
million are borrowed, a .15% fee will be imposed. The Company's commitment fee
remained at .375%. Additionally, the Company was subject to an annual
administrative agency fee of $35,000.
In March 1999, the Company further amended the credit agreement to increase
the committed amount of borrowing availability from $100 million to $125
million.
(c) In November 1999 and again in March 2000, the Company amended and
restated the Credit Agreement. The amendment to the Credit Agreement added
additional banks to the syndicate, increased our borrowing availability,
modified our letter of credit facility, extended the maturity five years to
November 2004, modified financial covenants, established waiver and amendment
approvals and changed the method to determine the interest rate to be charged.
The unamortized portion of previously capitalized financing costs were written
off and recorded as an extraordinary loss totaling $582,000, net of taxes of
$300,000, in the fourth quarter of 1999.
The amendment to the Credit Agreement increased the Company's borrowing
availability from $125 million to $335 million, with a provision to increase up
to $400 million. The amended Credit Agreement provides borrowing availability as
follows: (i) up to a $25 million sublimit for the issuance of standby and
commercial letters of credit and (ii) the difference between the $335 million
and the used sublimit available as a revolving credit facility. At the option of
the Company, borrowings under the amended Credit Agreement accrue interest at
LIBOR plus an applicable margin or the higher of the Bank of America prime rate
or the Federal Funds rate plus an applicable margin.
The applicable margin percentage to be added to the interest rate is based
on the Company's debt to total capitalization ratio at the end of each fiscal
quarter. The Company is charged a margin between 1.0% and 2.0% as the Company's
total debt to total capitalization ratio ranges from under 40% and over 65%,
respectively. The Company's borrowings are currently being charged at the
margin of 1.75%. In addition, the Company was subject to an arrangement fee,
agency fee, underwriting fee, unused fee and commitment fee totaling $1.2
million. Additionally, the Company is subject to an annual administrative agency
fee of $35,000.
The credit agreement is collateralized by all accounts receivable,
contracts, and the pledge of all of our subsidiaries' stock and a first lien
security interest in our pipeline systems. It also contains a number of
customary covenants that require the Company to maintain certain financial
ratios and limit our ability to incur additional indebtedness, transfer or sell
assets, create liens, or enter into a merger or consolidation.
The Company will be required to comply with more stringent debt to
capitalization and EBITDA to interest ratios by June 30, 2000. At March 29,
2000, the Company had approximately $94 million of available capacity under its
credit agreement.
In an effort to mitigate interest rate fluctuations exposure, the Company
has entered into interest rate swaps, under two separate swap agreements, with a
combined notional amount of $65 million (See Note 11 - Financial Instruments and
Price Risk Management Activities).
38
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The aggregate maturities of long-term debt at December 31, 1999 are as follows
(in thousands):
<TABLE>
<S> <C>
2000.................................................... $ 71
2001.................................................... -
2002.................................................... -
2003.................................................... -
2004.................................................... 240,000
--------
Total................................................... $240,071
========
</TABLE>
8. CAPITAL STOCK:
Common and Preferred Stock
In July 1997, approximately 3.2 million shares of the Company's common
stock were issued in a public offering registered under the Securities Act of
1933, as amended, at an offering price of $11.64. Proceeds of $34.6 million,
net of issuance costs, were used to repay borrowings on indebtedness incurred on
the MIT Acquisition.
In May 1998, the Board and the Company's shareholders approved a resolution
to amend the Articles of Incorporation to increase the number of authorized
shares of common stock, par value $.01 per share from 10 million to 25 million
shares and to authorize 5 million shares of preferred stock.
In connection with the five-for-four stock split discussed below, the
Company increased the authorized shares of common stock to 31.25 million shares.
In May 1999, the Company sold 3.57 million shares of its common stock at an
offering price of $16.31 per share. Proceeds of $54.5 million, net of issuance
costs, were used to pay down existing long-term debt.
In December 1999, the Company sold 2 million shares of its common stock at
an offering price of $16.06 per share. Proceeds of $30.2 million, net of
issuance costs, were used to repay existing long-term debt, complete the Gloria
system acquisition and provide working capital for general corporate purposes.
The Company has five million shares of preferred stock authorized, none of
which are outstanding as of December 31, 1999. The preferred stock may be
issued in multiple series with various terms, as authorized by the Board. The
Company has 12,721,980 shares of common stock issued and 12,560,824 shares of
common stock outstanding as of December 31, 1999.
Treasury Stock
From time to time, the Board has authorized the repurchase of the
Company's outstanding shares of common stock to be used for specific corporate
purposes. During 1999 and 1998, the Company repurchased 143,750 and 181,125
common shares, respectively, at a weighted-average price of $17.71 and $15.41
per share. As of December 31, 1999, and 1998, the Company held 161,156 and
181,125 shares of treasury stock, respectively. In March and June 1999, the
Company issued 140,574 and 23,145 shares of treasury stock, respectively, in
connection with the DPI/Flare acquisition.
Stock Dividends and Stock Splits
On February 3, 1998, the Board declared a ten percent stock dividend to be
paid to shareholders of record at the close of business on February 13, 1998
("Stock Dividend Record Date") on March 2, 1998. Shareholders of record
received one additional share for each ten shares held. 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 the Stock Dividend Record Date.
On February 1, 1999, the Board declared a five-for-four stock split to be
paid to shareholders of record at the close of business on February 11, 1999
("Stock Split Record Date") on March 1, 1999. 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 the Stock
Split Record Date.
39
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Warrants
In connection with the Company's August 1996 common stock offering, the
Company issued warrants in February 1996 to purchase 47,231 shares of the
Company's common stock at $5.71 per share. All of these warrants were exercised
in 1998.
Also in connection with the Company's August 1996 common stock offering,
the underwriters received warrants to acquire 137,500 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. As of
December 31, 1999, none of these warrants had been exercised.
In connection with the MIDLA Acquisition, the Company issued warrants to
acquire 171,880 shares of Common Stock at $15.82 per share. The securities
underlying these warrants are subject to demand and piggyback registration
rights and expire in October 2000. As of December 31, 1999, none of these
warrants had been exercised.
9. EMPLOYEE BENEFITS:
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 made a matching
contribution to the plan, which was recognized as compensation expense in the
year incurred, of approximately $305,000, $83,000 and $81,000 for the years
ended December 31, 1999, 1998 and 1997, respectively.
In October 1998, the Board approved an Employee Stock Purchase Plan
("ESPP"), which was subsequently approved by the Company's shareholders in May
1999. The purpose of the ESPP, as amended, is to permit Company employees to
purchase the Company's common stock on a monthly basis at a 15% discount from
the market price in order to attract and retain dedicated and reliable
employees. The maximum number of shares of the Company's common stock which
shall be reserved for sale under the ESPP, not including treasury shares or
shares purchased in the open market, shall be 100,000 shares. Through December
31, 1999, all shares purchased under the plan have been acquired on the open
market. The Company recognized $22,000 and $3,000 of compensation expense during
the years ended December 31, 1999 and 1998 related to the ESPP.
10. 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, 531,250 shares
of the Company's common stock are reserved for issuance. In February 2000, the
Compensation Committee approved an amendment to the Incentive Plan which
increased the shares reserved for issuance from 531,250 to 1,000,000, subject to
shareholder approval at the Company's 2000 annual shareholders meeting.
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.
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 exceptions, options may not be
exercised unless, at the time of the exercise, the optionee is in the service of
the Company. In general, options granted under the incentive plan vest at a rate
of one-fifth each year.
40
<PAGE>
MIDCOAST ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Transactions with regard to incentive stock options issued pursuant to the
Incentive Plan are as follows:
<TABLE>
<CAPTION>
Stock Options
-----------------------------------------------------------------------------
1999 1998 1997
-----------------------------------------------------------------------------
Number of Weighted Number of Weighted Number of Weighted
Shares Average Shares Average Shares Average
Underlying Exercise Underlying Exercise Underlying Exercise
Options Price Options Price Options Price
---------- ---------- ----------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C> <C>
Outstanding at beginning of the
year.............................. 441,814 $11.32 295,627 $ 8.65 - $ -
Granted.......................... 64,375 16.68 148,125 16.66 295,627 8.65
Exercised........................ (2,500) 16.80 (688) 7.64 - -
Forfeited/Repurchased............ (39,000) 17.14 (1,250) 16.80 - -
------- ------ ------- ------ ------- -----
Outstanding at end of year........ 464,689 $11.55 441,814 $11.32 295,627 $8.65
======= ====== ======= ====== ======= =====
Exercisable at end of
year............................ 152,289 $ 9.92 86,351 $ 9.24 - $8.65
======= ====== ======= ====== ======= =====
</TABLE>
The following table summarizes information about incentive stock options
outstanding as of December 31, 1999:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
---------------------------------------------------- ---------------------------------
Weighted Average
Number Remaining Years of Weighted Average Number Weighted Average
Exercise Prices Outstanding Contractual Life Exercise Price Exercisable Exercise Price
- ------------------ ----------- ------------------ ---------------- ------------- -----------------
<S> <C> <C> <C> <C> <C>
$ 7.64 140,939 7.10 $ 7.64 56,376 $ 7.64
8.40 78,375 2.10 8.40 31,350 8.40
10.50 72,875 7.42 10.50 41,938 10.50
15.40 14,375 8.74 15.40 2,875 15.40
16.56 59,375 9.60 16.56 - 16.56
16.60 3,125 8.92 16.60 625 16.60
16.80 95,625 8.29 16.80 19,125 16.80
------- ----- ------ ------- -------
464,689 6.93 $11.55 152,289 $ 9.92
------- ----- ------ ------- -------
</TABLE>
In April 1997, the Board adopted the Director's Plan, which was
subsequently approved by the Company's shareholders in May 1997. The Director's
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's Plan, 150,000 shares of the Company's common stock are reserved for
issuance.
The Director's 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's
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's
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 Directors 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's Plan are fully vested
upon issue and expire ten years after the date of the grant. As of December 31,
1999, 50,000 non-qualified stock options have been issued at option prices
ranging from $11.00 to $18.40 per share and all of these options were
exercisable as of that date at a weighted average price of $14.34 per share.
The fair value of each stock option granted is estimated on the date of
grant using the Black-Scholes option-pricing model with the following weighted-
average assumptions:
<TABLE>
<CAPTION>
ASSUMPTION: 1999 1998 1997
- ----------- --------- -------- ---------
<S> <C> <C> <C>
Expected Term in Years........................................ 6.35 6.60 6.57
Expected Volatility........................................... 33.04% 36.29% 36.29%
Expected Dividends............................................ 0.4% 0.4% 0.4%
Risk-Free Interest Rate....................................... 5.95% 5.59% 6.38%
</TABLE>
41
<PAGE>
MIDCOAST ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Black-Scholes weighted average fair value of all options granted under
both plans during 1999, 1998 and 1997 was $7.10, $7.54 and $4.09, respectively.
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 applying the provisions of SFAS No. 123, The Company's net
income and net income per common share for 1999, 1998 and 1997 would approximate
the pro forma amounts below (in thousands, except per share data):
<TABLE>
<CAPTION>
December 31, 1999 December 31, 1998 December 31, 1997
----------------------------- ------------------------- --------------------------
As Reported Pro Forma As Reported Pro Forma As Reported Pro Forma
----------------------------- ------------------------- --------------------------
<S> <C> <C> <C> <C> <C> <C>
Net income............................ $11,439 $11,121 $9,113 $8,317 $5,764 $5,686
Basic earnings per share.............. $ 1.25 $ 1.21 $ 1.29 $ 1.18 $ 1.13 $ 1.11
Diluted earnings per share............ $ 1.22 $ 1.18 $ 1.25 $ 1.14 $ 1.10 $ 1.08
</TABLE>
11. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES:
FAIR VALUE OF FINANCIAL INSTRUMENTS
As of December 31, 1999 and 1998, the carrying amounts of certain
financial instruments held by the Company, including cash, cash equivalents,
trade receivables and payables and short-term borrowings are representative of
fair value because of the short-term maturity of these instruments. The fair
value of long-term debt with variable interest rates approximates the carrying
value because of the variable nature of the debt's interest rate. The fair
value of all derivative financial instruments is the estimated amount at which
management believes the instruments could be liquidated over a reasonable period
of time, based on quoted market prices, current market conditions or other
estimates obtained from third-party brokers or dealers.
PRICE RISK MANAGEMENT ACTIVITIES
The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest rates. 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
fluctuations in interest rates. The Company does not engage in speculative
trading. Approvals are required from senior management prior to the execution
of any derivative transactions.
Commodity Price Risk:
The Company's commodity price risk exposure arises from inventory balances
and fixed price purchase and sale commitments. The Company uses exchange-traded
commodity futures contracts, options and swap contracts to manage and hedge
price risk related to these market exposures. These futures and options
contracts have pricing terms indexed to the NYMEX.
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 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.
42
<PAGE>
MIDCOAST ENERGY RESOURCES, INC
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The gains, losses and related costs of the financial instruments that
qualify as a hedge are not recognized until the underlying physical transaction
occurs. At December 31, 1999 and 1998, the Company had unrealized losses from
such hedging contracts of $1,139,000 and $896,000, respectively. The market
value, notional amount and notional contract quantity of open commodity futures,
options and swaps contracts used for hedging purposes were as follows (in
thousands):
<TABLE>
<CAPTION>
As of December 31,
----------------------
1999 1998
-------- -------
<S> <C> <C>
Market Value - Unrealized Loss:
Swap contracts $(1,027) $ (695)
Futures contracts (112) (178)
Options contracts - (23)
Notional Contract Amount:
Swap contracts $10,635 $11,729
Futures contracts 2,295 683
Options contracts - 23
Notional Contract Quantity (MMBtu):
Swap contracts 5,045 5,606
Futures contracts 930 270
Options contracts - 120
</TABLE>
Interest Rate Risk:
The Company's Credit Facility provides an option for the Company to borrow
funds at a variable interest rate of LIBOR plus an applicable margin based on
the Company's debt to total capitalization ratio. In an effort to mitigate
interest rate fluctuation exposure, the Company entered into interest rate swaps
under two separate swap agreements with a combined notional amount of $65
million dollars. The interest rate swap agreements entered into by the Company
effectively convert $65 million of floating-rate debt to fixed-rate debt.
The first interest rate swap agreement was entered into with Bank One in
December 1997. The swap agreement effectively established a fixed three-month
LIBOR interest rate setting of 6.02% for a two-year period on a notional amount
of $25 million. This swap agreement was subsequently transferred to Bank of
America in November 1998 and replaced with a new swap agreement. The new swap
agreement provides a fixed 5.09% three-month LIBOR interest rate to the Company
with a new two year termination date of December 2000 which may, however, be
extended through December 2003 at Bank of America's option on the last day of
the initial term. The variable three-month LIBOR rate is reset quarterly based
on the prevailing market rate and the Company is obligated to reimburse Bank of
America when the three-month LIBOR rate is reset below 5.09%. Conversely, Bank
of America is obligated to reimburse the Company when the three-month LIBOR rate
is reset above 5.09%. At December 31, 1999 and 1998, the fair value of this
interest rate swap through the initial termination date was a net asset of
approximately $303,000 and a net liability of approximately $20,000,
respectively.
The second interest rate swap agreement was entered into with CIBC in
October 1998. The swap agreement effectively established a fixed three-month
LIBOR interest rate setting of 4.475% for a three-year period on a notional
amount of $40 million. The agreement, however, may be extended an additional two
years through November 2003 at CIBC's option on the last day of the initial
term. The variable three-month LIBOR rate is reset quarterly based on the
prevailing market rate and the Company is obligated to reimburse CIBC when the
three-month LIBOR rate is reset below 4.475%. Conversely, CIBC is obligated to
reimburse the Company when the three-month LIBOR rate is reset above 4.475%. At
December 31, 1999 and 1998, the fair value of this interest rate swap through
the initial termination date was a net asset of approximately $1,279,000 and
$481,000, respectively.
The effect of these swap agreements was to lower interest expense by
$377,000 and $37,000 in 1999 and 1998, respectively, and increase interest
expense by $2,000 in 1997.
12. CONCENTRATION OF CREDIT RISK:
The Company derives revenue from commercial companies located in the United
States and Canada. Four of the Company's largest customers account for 11% or
approximately $6.0 million of the outstanding accounts receivable at December
31, 1999. 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 that it deems
doubtful of collection. At December 31, 1999 and 1998, $1,484,000 and $92,000,
respectively, was reserved as a provision for doubtful accounts.
43
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The change in market value of futures and option contracts requires daily
cash settlement in margin accounts with brokers. At December 31, 1999 and 1998,
the Company had $893,000 and $181,000, respectively, 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.
13. INCOME TAXES:
The Company has NOL carryforwards of approximately $10.3 million, expiring
in various amounts from 2003 through 2018. These loss carryforwards were
generated by the companies acquired by Midcoast. 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 $5.2 million) on the use of such carryforwards due to a change in shareholder
control under section 382 of the Internal Revenue Code triggered by the
Company's July 1997 Common Stock offering and the change of ownership created by
the MIDLA acquisition and DPI/Flare acquisition.
The tax effects of significant temporary differences representing deferred
tax assets and liabilities at December 31, 1999 and 1998, are as follows (in
thousands):
<TABLE>
<CAPTION>
December 31,
-----------------------
1999 1998
-------- --------
<S> <C> <C>
NOL carryforwards $ 3,510 $ 5,644
Alternative minimum tax credit 2,104 420
Valuation allowance (2,464) (4,554)
Financial net book value of assets
in excess of tax net book value of assets (14,184) (12,318)
-------- --------
Net deferred tax liabilities $(11,034) $(10,808)
======== ========
</TABLE>
The valuation allowance declined $2.1 million during the year ended
December 31, 1999. The decline was the net result of current year utilization
of net operating losses to offset taxable income and the removal of $581,000 of
valuation allowance related to net operating losses that are more likely than
not to be utilized in the future.
A reconciliation of the provision for income taxes to the statutory United
States tax rate is as follows (in thousands):
<TABLE>
<CAPTION>
For The Year Ended December 31,
----------------------------------
1999 1998 1997
-------- ------- -------
<S> <C> <C> <C>
Federal tax computed at statutory rate $ 4,832 $ 3,543 $ 1,960
Utilization of net operating loss carryforwards (1,989) (1,145) (1,810)
Reduction in valuation allowance (581) (1,089) -
Foreign jurisdiction tax rate difference (146) - -
Other 53 - -
------- ------- -------
Actual provision $ 2,169 $ 1,309 $ 150
======= ======= =======
</TABLE>
United States income taxes have not been provided on the cumulative
undistributed earnings, which totaled approximately $589,000 at December 31,
1999, of the Company's Canadian subsidiaries since it is the Company's intention
to reinvest such earnings indefinitely.
14. 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 December 2002. 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
44
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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
The Company incurred net lease expenses of $1.0 million, $0.2 million and
$0.1 million during the years ended 1999, 1998 and 1997. As of December 31,
1999, future minimum lease payments due under these leases are approximately
$1.1 million, $0.5 million, $0.1 million and $0.1 million for the years ended
December 31, 2000, 2001, 2002 and 2003, respectively.
MIT Acquisition Contingency
As part of the MIT acquisition, the Company has agreed to pay additional
contingent annual payments to Atrion, not to exceed $250,000 per year, which
will be treated as deferred purchase price adjustments. 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. As of December 31, 1999, the Company has made one payment of $250,000
and has accrued an additional $187,500 under the contingency.
MIDLA Acquisition 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, the Company would
be obligated to issue 137,500 warrants to Republic to acquire common stock at an
exercise price of $15.82 per share. In addition, concurrent with initial
expenditures on the project, the Company would incur a $1.2 million cash
obligation to Republic. At December 31, 1999, none of the provisions of this
contingency were met and the obligation expired.
DPI Acquisition Contingency
As part of the DPI acquisition, the Company agreed that in the event that
the Company approves long-term DPI or Flare projects and these projects are
placed under contract and in service, the Company would be obligated to pay the
DPI shareholders an additional consideration of up to $2.5 million. This
contingency expires on March 11, 2002.
15. EARNINGS PER SHARE:
Basic and diluted earnings per share amounts calculated in accordance with
SFAS No. 128, "Earnings Per Share," are presented below for the years ended
December 31 (in thousands, except per share amounts):
<TABLE>
<CAPTION>
1999 1998 1997
------------------------------------- --------------------------------- ------------------------------------
Net Average Shares Earnings Per Net Average Shares Earnings Per Net Average Shares Earnings Per
Income Outstanding Share Income Outstanding Share Income Outstanding Share
------------------------------------ ---------------------------------- -------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic $11,439 9,176 $1.25 $9,113 7,074 $1.29 $5,764 5,115 $1.13
Effect of dilutive
securities:
Stock options - 159 (.02) - 151 (.03) - 86 (.02)
Warrants - 66 (.01) - 73 (.01) - 50 (.01)
------- ----- ----- ------ ----- ----- ------ ----- ------
Diluted $11,439 9,401 $1.22 $9,113 7,298 $1.25 $5,764 5,251 $1.10
======= ===== ===== ====== ===== ===== ====== ===== =====
</TABLE>
16. SEGMENT DATA:
The Company conducts its business of transporting, gathering, processing
and marketing of natural gas and other petroleum products through three
reportable segments. The Company's operations are segregated into reportable
segments based on the type of business activity and type of customer served. The
Company's transmission pipelines primarily receive and deliver natural gas to
and from other pipelines, and secondarily, provide 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's
end-user pipelines provide natural gas and natural gas transportation services
to industrial customers, municipalities or electrical generating facilities
through interconnect gas pipelines constructed or acquired by the Company. These
pipelines provide a direct supply of natural gas to new industrial facilities or
to existing facilities as an alternative to the local distribution company. The
Company's gathering systems typically consist of a network of pipelines
45
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
which collect natural gas or crude oil from points near producing wells, process
the natural gas, and transport oil and natural gas to larger pipelines for
further transmission. The Company's natural gas processing revenues are realized
from the extraction and sale of NGL's as well as the sale of the residual
natural gas. All of the Company's segments have significant revenues from gas
marketing activities.
The Company evaluates performance based on profit or loss from operations
before income taxes and other income and expense items incidental to core
operations. Operating income for each segment includes total revenues less
operating expenses (including depreciation) and excludes corporate
administrative expenses, interest expense, interest income and income taxes.
For the year ended December 31, 1999, no customer represented in excess of 10%
of the total revenue of the Company. For the years ended December 31, 1998 and
1997, the Company derived 12% of total revenue from a transmission segment
customer. The accounting policies of the segments are the same as those
described in the summary of significant accounting policies (see Note 2).
<TABLE>
<CAPTION>
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1999
----------------------------------------------------------------------------------
TRANSMISSION END-USER GATHERING AND
PIPELINES PIPELINES PROCESSING OTHER TOTAL
----------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Revenues
Domestic........................ $124,789 $125,441 $136,805 $ 2,394 $389,429
Foreign......................... - - 2,142 - 2,142
-------- --------- -------- -------- --------
Total Revenues.................... 124,789 125,441 138,947 2,394 391,571
Gross Margin...................... 19,088 7,854 10,706 1,916 39,564
Depreciation and Amortization..... (2,417) (899) (3,621) (608) (7,545)
General & Administrative.......... - - - (8,431) (8,431)
Interest Expense.................. - - - (6,533) (6,533)
Other, net........................ - - - (2,865) (2,865)
-------- --------- -------- -------- --------
Income before income taxes and
extraordinary charge........... $ 16,671 $ 6,955 $ 7,085 $(16,521) $ 14,190
======== ========= ======== ======== ========
Assets
Domestic....................... $336,555 $ 29,949 $ 88,679 $ 9,821 $465,004
Foreign........................ - - 13,368 - 13,368
-------- --------- -------- -------- --------
Total Assets..................... $336,555 $ 29,949 $102,047 $ 9,821 $478,372
======== ========= ======== ======== ========
Capital Expenditures............. 2,524 5,858 4,579 3,601 16,562
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1998
----------------------------------------------------------------------------------
TRANSMISSION END-USER GATHERING AND
PIPELINES PIPELINES PROCESSING OTHER TOTAL
----------------------------------------------------------------------------------
(IN THOUSANDS)
Total Revenues (all from domestic
sources)....................... $118,311 $99,720 $15,600 $ 438 $234,069
Gross Margin...................... 13,039 5,233 4,357 438 23,067
Depreciation and Amortization..... (1,554) (532) (841) (270) (3,197)
General & Administrative.......... - - - (6,317) (6,317)
Interest Expense.................. - - - (3,247) (3,247)
Other, net........................ - - - 116 116
-------- ------- ------- ------- --------
Income before income taxes and
extraordinary charge............ $ 11,485 $ 4,701 $ 3,516 $(9,280) $ 10,422
======== ======= ======= ======= ========
Total Assets (all from domestic
sources)................ $121,498 $ 8,055 $53,246 $ 8,543 $191,342
======== ======= ======= ======= ========
Capital Expenditures.............. 1,648 6,168 - - 7,816
</TABLE>
46
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
AS OF OR FOR THE YEAR ENDED DECEMBER 31, 1997
----------------------------------------------------------------------------------
TRANSMISSION END-USER GATHERING AND
PIPELINES PIPELINES PROCESSING OTHER TOTAL
----------------------------------------------------------------------------------
(IN THOUSANDS)
<S> <C> <C> <C> <C> <C>
Total Revenues
(all from domestic sources)...... $ 64,787 $36,349 $11,246 $ 362 $112,744
Gross Margin.................. 5,862 3,468 2,717 362 12,409
Depreciation and Amortization.. (553) (421) (341) (277) (1,592)
General & Administrative....... - - - (3,526) (3,526)
Interest Expense............... - - - (1,067) (1,067)
Other, net..................... - - - (310) (310)
-------- ------- ------- ------- --------
Income before income taxes and
extraordinary charge.......... $ 5,309 $ 3,047 $ 2,376 $(4,818) $ 5,914
======== ======= ======= ======= ========
Total Assets (all from domestic
sources)...................... $104,479 $ 6,452 $ 9,863 $ 7,244 $128,038
======== ======= ======= ======= ========
Capital Expenditures........... 163 414 833 - 1,410
</TABLE>
17. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):
<TABLE>
<CAPTION>
Quarters Ended
------------------------------------------------
March 31 June 30 September 30 December 31
-------- -------- ------------ -----------
(In thousands, except per share amounts)
<S> <C> <C> <C> <C>
1999
Operating revenues................................. $82,064 $83,457 $101,844 $124,206
Operating income................................... 5,473 4,566 3,891 6,973
Net income before extraordinary item .............. 3,255 2,576 2,758 3,432
Net income......................................... 3,255 2,576 2,758 2,850
Basic earnings per share before extraordinary item. 0.47 0.31 0.26 0.31
Diluted earnings per share before extraordinary
item.............................................. 0.46 0.31 0.26 0.31
Basic earnings per share........................... 0.47 0.31 0.26 0.26
Diluted earnings per share......................... 0.46 0.31 0.26 0.26
1998
Operating revenues................................. $67,339 $49,545 $ 50,301 $ 66,884
Operating income................................... 4,134 2,551 2,589 4,279
Net income......................................... 2,761 1,728 1,580 3,044
Basic earnings per share........................... 0.39 0.24 0.22 0.44
Diluted earnings per share......................... 0.38 0.23 0.22 0.43
</TABLE>
18. UNUSUAL CHARGE
During the fourth quarter of fiscal 1999, the Company recorded a pre-tax
unusual charge totaling $2.7 million ($2.2 million after tax) related to
streamlining efforts announced in November 1999. The charge primarily relates to
the severance and benefits of approximately 50 employees who were involuntary
terminated. The Company anticipates savings from reduced employee cost and more
streamlined operating and business processes. At December 31, 1999, an accrued
liability of $1.8 million related to the severance charge was included in
"Accounts payable and accrued liabilities" on the consolidated balance sheet.
Thirty-three of these employees were still employed with the Company at December
31, 1999. The final severance charge will be paid in April 2002.
19. SUBSEQUENT EVENTS (UNAUDITED):
In January 2000, the Company entered into a definitive purchase and sale
agreement to acquire MBPL from Triumph Energy Corporation for cash
consideration of approximately $5.7 million (U.S.), plus certain future
contingent payments based on the actual throughput volumes. MBPL consists of 90
miles of crude oil pipeline that originates at the Manyberries Oil Field and
terminates at an interconnection with the Milk River Pipeline system in
southeast Alberta, Canada. Truck terminals, including the Legend terminal, and a
significant amount of crude oil storage also contribute to the operations. The
system has a design capacity of approximately 21,000 BBLs/day and transports
light sour crude oil from the Manyberries oil field, as well as additional crude
oil volumes from the Legend truck terminal. The pipeline system is the only
light gravity system in southern Alberta and current volumes are
47
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately 6,500 Bbls/day. Closing is anticipated in the second quarter of
2000, subject to receipt of the approvals, consents or other authorizations
required by the Investment Canada Act.
In March 2000, the Company acquired the Provost natural gas plant and
gathering system from NovaGas Canada LP, a division of TransCanada, for
approximately $4.9 million (U.S.). The Provost acquisition includes 80 miles of
natural gas gathering pipeline and a 15 MMcf/day sour gas processing plant and
sour gas injection well. The system is located in east-central Alberta, Canada
and is the only sour gas gathering and processing system in the area. The system
is connected to 21 oil tank batteries and primarily gathers the associated sour
gas production from approximately 900 wells in the Provost area. The acquisition
was funded through the Company's existing credit facility.
In March 2000, the Company amended the existing credit agreement to increase
the committed amount of borrowing availability from $265 million to $335
million.
48
<PAGE>
REPORT OF INDEPENDENT ACCOUNTANTS
ON FINANCIAL STATEMENT SCHEDULE
To the Board of Directors and Shareholders
of Midcoast Energy Resources, Inc.:
Our audit of the consolidated financial statements of Midcoast Energy Resources,
Inc. and its subsidiaries as of December 31, 1999 and for the year then ended
also included an audit of the financial statement schedule for the year ended
December 31, 1999, listed in Item 14(a)(2) of this Form 10-K. In our opinion,
this financial statement schedule presents fairly, in all material respects, the
information set forth therein for the year ended December 31, 1999, when read in
conjunction with the related consolidated financial statements.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 10, 2000
49
<PAGE>
INDEPENDENT AUDITOR'S REPORT ON SCHEDULE
Stockholders and Board of Directors
Midcoast Energy Resources, Inc.
Houston, Texas
We have audited the consolidated financial statements Midcoast Energy Resources,
Inc. and subsidiaries as of December 31, 1998, and for each of the years in the
two-year period ended December 31, 1998. Our audits for such years also
included the financial statement schedule of Midcoast Energy Resources, Inc. and
subsidiaries, listed in Item 14-2, for each of the years in the two-year period
ended December 31, 1998. This financial statement schedule, when considered in
relation to the basic financial statements taken as a whole, presents fairly in
all material respects the information set forth herein.
HEIN + ASSOCIATES LLP
Houston, Texas
March 18, 1999
50
<PAGE>
SCHEDULE II
MIDCOAST ENERGY RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DECEMBER 31, 1999, 1998, AND 1997
(IN THOUSANDS)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
- ------------------------------------------------- ------------------- -------------------------- ---------- ----------
Balance at Charged to Balance at
Beginning of Costs and Charged to End of
Description Period Expenses Other Accounts Deductions Period
- ------------------------------------------------ ------------------- ---------- --------------- ---------- ----------
<S> <C> <C> <C> <C> <C>
1999
Allowance for doubtful accounts............... $ 92 $ 12 $1,380 (h) $ - $1,484
Valuation allowance on deferred tax assets.... $4,554 $ (581)(c) $ 480 (g) $(1,989)(f) $2,464
1998
Allowance for doubtful accounts............... $ 494 $ - $ (309)(a) $ (93)(b) $ 92
Valuation allowance on deferred tax assets.... $4,581 $(1,089)(c) $2,207 (d)(e) $(1,145)(f) $4,554
1997
Allowance for doubtful account................ $ - $ - $ 494 (a) $ - $ 494
Valuation allowance on deferred tax assets.... $3,727 $ - $2,664 (d) $(1,810)(f) $4,581
</TABLE>
(a) Due to MIDLA Acquisition.
(b) Represents uncollectible accounts written off.
(c) Removal of valuation allowance on deferred tax assets that are more likely
than not to be utilized in the future.
(d) Adjustment of federal net operating loss carryforwards and related
valuation allowance to reconcile to federal income tax return.
(e) Valuation allowance on federal net operating loss carryforwards acquired in
connection with the MIDLA Acquisition.
(f) Represents utilization of federal net operating loss carryforwards.
(g) Valuation allowance on federal net operating loss carryforwards and
alternative minimum tax credits acquired in connection with the DPI
Acquisition.
(h) Due to KPC acquisition.
51
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
On October 11, 1999, PricewaterhouseCoopers LLP was engaged as independent
accountant to audit the financial statements of the Company for the year ended
December 31, 1999. In connection therewith, on October 11, 1999, the Company
and Hein & Associates LLP, the Company's prior principal independent accountant,
mutually agreed that Hein + Associates LLP would be replaced by
PricewaterhouseCoopers LLP as the Company's principal independent accountant.
The decision to replace Hein + Associates LLP and engage PricewaterhouseCoopers
LLP was approved by the Board of Directors of the Company.
The accounting firm of Hein + Associates LLP served as the independent
accountant for the Company from March 17, 1994 until dismissed by the Company on
October 11, 1999. Midcoast and Hein have not, in connection with the audit of
Midcoast's financial statements for each of the prior two years ended December
31, 1998 and December 31, 1997 or for any subsequent interim period prior to and
including October 11, 1999, had any disagreement on any matter of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedure, which disagreement, if not resolved to Hein's satisfaction, would
have caused Hein to make reference to the subject matter of the disagreement in
connection with its reports.
The reports of Hein on the Midcoast financial statements for the past two
fiscal years did not contain an adverse opinion or a disclaimer of opinion and
were not qualified or modified as to uncertainty, audit scope or accounting
principles. Midcoast had no relationship with PricewaterhouseCoopers LLP
required to be reported pursuant to Regulation S-K item 304 (a) (2) during the
two fiscal periods ended December 31, 1998 and December 31, 1997 or for any
subsequent interim period prior to and including October 11, 1999.
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 16, 1999 and is hereby incorporated by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FROM 8-K.
The following documents are filed as part of this report:
1. Financial Statements
The following consolidated financial statements of Midcoast Energy
Resources, Inc. and subsidiaries are included in Part II, Item 8 of
this Form 10-K.
Page
----
Reports of Independent Accountants................. 25
Consolidated Balance Sheets........................ 27
Consolidated Statements of Operations.............. 28
Consolidated Statements of Comprehensive Income.... 29
Consolidated Statements of Shareholders' Equity.... 30
Consolidated Statements of Cash Flows.............. 31
Notes to Consolidated Financial Statements......... 32
2. Financial statement schedules and supplementary information
required to be submitted.
Page
----
Schedule II - Valuation and qualifying accounts.... 57
Schedules other than that listed above are omitted
because they are not applicable
3. An exhibit list is included on page 54 of this Form 10-K.
52
<PAGE>
(B) REPORTS ON FORM 8-K:
An 8-K was filed on October 15, 1999 to report the change of independent
accountant from Hein + Associates LLP to PricewaterhouseCoopers LLP.
A report on Form 8-K was filed on November 19, 1999 to report the KPC
acquisition and the amendment to the existing credit agreement. A report on
Form 8-KA was filed on December 3, 1999 as an amendment to the Form 8-K filed on
November 19, 1999. The amendment was filed to include the required audited
historical summary of revenue and direct operating expenses of Kansas Pipeline
Company for the nine months ended September 30, 1999. In addition, the
unaudited Midcoast Pro Forma Statement of Operations for the nine months ended
September 30, 1999 and for the year ended December 31, 1998 and unaudited Pro
Forma Balance Sheet at September 30, 1999 were included.
A report on Form 8-K/A was filed on December 2, 1999 as an amendment to the
report on Form 8-K filed September 29, 1999 relating the Company's
reincorporation in Texas. The amendment was filed to include specific language
adopting the pre-reincorporation company's registration statement and under the
Securities Exchange Act of 1934 (1934 Act) such that the common stock of the
Company after the reincorporation would be deemed to be registered under the
1934 Act.
A report on Form 8-K was filed on December 10, 1999 to report the terms of
the Underwriting Agreement that the Company entered in connection with its
public offering of common stock, in which the agreement was included as an
exhibit to the report.
A report on Form 8-K was filed on December 14, 1999 to report the
streamlining of its operations.
53
<PAGE>
MIDCOAST ENERGY RESOURCES, INC.
EXHIBIT LIST
December 31, 1999
Each exhibit identified below is filed as a part of this report. An
asterisk designates exhibits not incorporated by reference to a prior filing;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.
Exhibit
Number DESCRIPTION OF EXHIBITS
- ------ -----------------------
2.1 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).
2.2 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).
2.3 Agreement and Plan of Merger dated October 31, 1997 by and between Republic
Gas Partners, LLC. And Midcoast Energy Resources, Inc. (Incorporated by
reference from Midcoast Form 8-K dated November 13, 1997 as Exhibit 2.2)
2.4 Purchase and Sale Agreement dated September 8, 1998, by and between El Paso
Field Services Company, a Delaware corporation, and Midcoast Gas Services,
Inc., a Delaware corporation. (Incorporated by reference from Midcoast Form
10-Q for the nine month period ended September 30, 1998, as Exhibit 2.8).
2.5 Agreement and Plan of Merger dated March 11, 1999, by and between Dufour
Petroleum, Inc., Flare L.L.C. Partners and Midcoast Energy Resources, Inc.
(Incorporated by reference from Midcoast Form 10-K for the fiscal year
ended December 31, 1998).
2.6 Purchase and Sale Agreement dated March 23, 1999, by and between Probe
Exploration Inc. and Midcoast Canada Operating Corporation. (Incorporated
by reference from Midcoast Form 10-K for the fiscal year ended December 31,
1998).
2.7 Asset Purchase Agreement dated November 9, 1999 by and between K-Pipe
Merger Corporation, Midcoast Energy Resources, Inc., Midcoast Kansas
Pipeline, Inc., and Midcoast Kansas General Partner, Inc. (Incorporated by
reference from Midcoast Form 8-K dated November 9, 1999 as Exhibit 2.4)
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 Certificate of Amendment of Articles of Incorporation of Midcoast Energy
Resources, Inc. dated May 15, 1998 (Incorporated by reference from Midcoast
Form 10-Q for the six month period ended June 30, 1998 as Exhibit 3.4).
3.4 Certificate of Stock Split of Midcoast Energy Resources, Inc. dated
February 24, 1999. (Incorporated by reference from Midcoast Form 10-K for
the fiscal year ended December 31, 1998).
3.5 Bylaws of Midcoast Energy Resources, Inc. (Incorporated by reference from
Midcoast Form 10-KSB for the fiscal year ended December 31, 1992)
3.6 Plan of Agreement of Merger between the Company and the Corporation dated
September 22, 1999. (Incorporated by reference from Midcoast Form 8-K dated
September 29, 1999, as Exhibit 2.1).
3.7 Amended and Restated Articles of Incorporation dated September 23, 1999.
(Incorporated by reference from Midcoast Form 8-K dated September 29, 1999,
as Exhibit 3.1).
3.8 Bylaws of the Texas Corporation dated September 22, 1999. (Incorporated by
reference from Midcoast Form 8-K dated September 29, 1999, as Exhibit 3.2).
4.1 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).
4.2 Representative's Warrants. (Incorporated by reference from Midcoast
Registration Statement on Form SB-2 (No. 333-4643) dated August 8, 1996).
54
<PAGE>
4.3 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).
4.4 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).
4.5 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).
4.6 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).
4.7 Executive Severance Agreement by and between Midcoast Energy Resources,
Inc. and Dan Tutcher, dated August 15, 1997. (Incorporated by reference
from Form 10-K for the year ended December 31, 1997 as Exhibit 4.11)
4.8 Executive Severance Agreement by and between Midcoast Energy Resources,
Inc. and I.J. Berthelot, II, dated August 15, 1997. (Incorporated by
reference from Form 10-K for the year ended December 31, 1997 as Exhibit
4.12)
4.9 Executive Severance Agreement by and between Midcoast Energy Resources,
Inc. and Richard Robert, dated August 15, 1997. (Incorporated by reference
from Form 10-K for the year ended December 31, 1997 as Exhibit 4.13)
4.10 Executive Severance Agreement by and between Midcoast Energy Resources,
Inc. and Duane Herbst, dated August 15, 1997. (Incorporated by reference
from Form 10-K for the year ended December 31, 1997 as Exhibit 4.14)
4.11 First Amendment to Voting/Proxy Agreement dated April 29, 1998 by and
between Midcoast Energy Resources, Inc. and Steven G. Herbst, June Herbst,
Kenneth Holmes, Jr., Dorothy C. Holmes and Rainbow Investments Company and
Chase Bank of Texas. (Incorporated by reference from Form 10-Q for the
three months ended March 31, 1998 as Exhibit 4.14)
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 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).
10.7 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).
10.8 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).
10.9 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).
55
<PAGE>
10.10 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).
10.11 Midcoast Energy Resources, Inc. 1996 Incentive Stock Plan, as amended on
May 15, 1998. (Incorporated by reference from Midcoast Form 10-K for the
fiscal year ended December 31, 1998).
10.12 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).
10.13 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).
10.14 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).
10.15 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).
10.16 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)
10.17 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)
10.18 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)
10.19 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)
10.20 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).
10.21 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).
10.22 Third Amendment to Employment Agreement dated March 2, 1998 by and
between Midcoast Energy Resources, Inc. and Dan Tutcher. (Incorporated by
reference from Form 10-K/A dated February 2, 1999, for the fiscal year
ended December 31, 1997).
10.23 Third Amendment to Employment Agreement dated March 18, 1998 by and
between Midcoast Energy Resources, Inc. and I.J. Berthelot, II.
(Incorporated by reference from Form 10-K/A dated February 2, 1999, for
the fiscal year ended December 31, 1997).
10.24 Second Amendment to Employment Agreement dated March 18, 1998 by and
between Midcoast Energy Resources, Inc. and Richard Robert. (Incorporated
by reference from Form 10-K/A dated February 2, 1999, for the fiscal year
ended December 31, 1997).
56
<PAGE>
10.25 Amended and Restated Credit Agreement dated August 31, 1998, by and
among Midcoast Energy Resources, Inc., and, Bank One Texas, N.A., CIBC
Inc., and Nationsbank, N.A. (Incorporated by reference from Midcoast
Form 10-Q for the nine month period ended September 30, 1998, as
Exhibit 10.30).
10.26 First Amendment to the Amended and Restated Credit Agreement dated
March 12, 1999, by and among Midcoast Energy Resources, Inc., and, Bank
One Texas, N.A., CIBC Inc., and Nationsbank, N.A. (Incorporated by
reference from Midcoast Form 10-K for the fiscal year ended December
31, 1998).
10.27 Amended and Restated Credit Agreement dated November 8, 1999, by and
between Midcoast Energy Resources, Inc., Bank of America, N.A.,
individually and as administrative agent, Bank One, N.A., individually
and as syndication agent, CIBC, Inc., individually and as documentation
agent, Banc of America Securities LLC, as lead arranger and book
manager, and certain other Lenders. (Incorporated by reference from
Midcoast Form 8-K dated November 9, 1999 as Exhibit 10.4)
*10.28 First Amendment to the Amended and Restated Credit Agreement dated
March 1, 2000, by and between Midcoast Energy Resources, Inc., Bank of
America, N.A., individually and as administrative agent, Bank One,
N.A., individually and as syndication agent, CIBC, Inc., individually
and as documentation agent, Banc of America Securities LLC, as lead
arranger and book manager, and certain other Lenders.
*21.1 Schedule listing subsidiaries of Midcoast Energy Resources, Inc.
*23.1 Consent of independent accountants, PricewaterhouseCoopers LLP
*23.2 Consent of independent accountants, Hein + Associates LLP
*27.1 Financial Data Schedule for the year ended December 31, 1999.
57
<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, 2000
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.
<TABLE>
<CAPTION>
<S> <C>
SIGNATURES CAPACITY IN WHICH SIGNED
/s/ DAN C. TUTCHER Chairman of the Board
(Dan C. Tutcher) Chief Executive Officer
Date: March 30, 2000 and President
/s/ I. J. BERTHELOT, II Executive Vice President, Chief Operating
(I. J. Berthelot, II) Officer and Director
Date: March 30, 2000
/s/ TED COLLINS, JR. Director
(Ted Collins, Jr.)
Date: March 30, 2000
/s/ CURTIS J. DUFOUR III. Director
(Curtis J. Dufour, III.)
Date: March 30, 2000
/s/ RICHARD N. RICHARDS Director
(Richard N. Richards)
Date: March 30, 2000
/s/ RICHARD A. ROBERT Treasurer, Principal Financial Officer
(Richard A. Robert) Principal Accounting Officer
Date: March 30, 2000
/s/ BRUCE WITHERS Director
(Bruce Withers)
Date: March 30, 2000
</TABLE>
58
<PAGE>
EXHIBIT 10.28
FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT
THIS FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT (herein
called the "Amendment") made as of March 1, 2000 by and among MIDCOAST ENERGY
RESOURCES, INC., a Texas corporation (herein called "Borrower"), BANK OF
AMERICA, N.A., individually and as administrative agent (in its agency capacity
herein called "Administrative Agent"), BANK ONE, NA, individually and as
syndication agent (in its agency capacity herein called "Syndication Agent"),
CIBC, INC., individually and as documentation agent (in its agency capacity
herein called "Documentation Agent"), the Lenders party to the Original
Agreement defined below ("Original Lenders"), and certain additional lenders as
new Lenders ("New Lenders"; the New Lenders and the Original Lenders
collectively called "Lenders"),
W I T N E S S E T H:
WHEREAS, Borrower, Administrative Agent, Syndication Agent, Documentation
Agent and Original Lenders entered into that certain Amended and Restated Credit
Agreement dated as of November 8, 1999 (as amended, supplemented, or restated
prior to the date hereof, the "Original Agreement"), for the purpose and
consideration therein expressed, whereby Original Lenders became obligated to
make loans to Borrower as therein provided; and
WHEREAS, Borrower, Administrative Agent, Syndication Agent, Documentation
Agent, Original Lenders and New Lenders desire to amend the Original Agreement
to (i) increase the Facility Amount to , (ii) provide for certain additional
lenders to become new Lenders, (iii) increase the LC Sublimit to $50,000,000,
(iv) eliminate the C$50,000,000 limit on Canadian Dollar advances, and (v) amend
various other provisions of the Original Agreement;
NOW, THEREFORE, in consideration of the premises and the mutual covenants
and agreements contained herein and in the Original Agreement, in consideration
of the loans which may hereafter be made by Lenders to Borrower, and for other
good and valuable consideration, the receipt and sufficiency of which are hereby
acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I - Definitions and References
Section 1.1 Terms Defined in the Original Agreement. Unless the context
otherwise requires or unless otherwise expressly defined herein, the terms
defined in the Original Agreement shall have the same meanings whenever used in
this Amendment.
Section 1.2 Other Defined Terms. Unless the context otherwise requires,
the following terms when used in this Amendment shall have the meanings assigned
to them in this Section 1.2.
"Amendment" means this First Amendment to Amended and Restated Credit
Agreement.
<PAGE>
"Amendment Documents" means this Amendment and the Consent and
Agreement.
"Assignment and Acceptance" means the Assignment and Acceptance
appended hereto as Exhibit "B".
"Consent and Agreement" means the Consent and Agreement appended
hereto as Exhibit "A".
"Credit Agreement" means the Original Agreement as amended hereby.
"Revised Schedule of Commitments and Commitment Percentages" means the
Revised Schedule of Commitments and Commitment Percentages appended hereto
as Schedule 1.
ARTICLE II - Amendments to Original Agreement
Section 2.1 Cover Page. The figure "$265,000,000" on the cover page of
the Original Agreement is hereby deleted and the figure "$335,000,000" is
substituted therefore and the phrase "(including up to $50,000,000 Canadian
Dollar Revolving Loan)" is hereby deleted.
Section 2.2 Defined Terms. (a) The definition of "Commitment" in
Section 1.1 of the Original Agreement is hereby amended in its entirety to read
as follows:
""Commitment" means initially the Dollar amount set forth opposite
such Lender's name on its signature page hereto, and on and after the first
and each successive assignment pursuant to Section 10.6(a), the Dollar
amount set forth opposite such Lender's name on the Revised Schedule of
Commitments and Commitment Percentages and as of the First Amendment
Effective Date, the Revised Schedule of Commitments and Commitment
Percentages appended as Schedule 1 to the First Amendment, as such
Commitment may be reduced pursuant to Section 2.1, increased (as determined
by such Lender in its sole and absolute discretion) pursuant to Section
2.14, or reduced or increased pursuant to Section 10.6."
(b) The definition of "Canadian Subsidiaries" in Section 1.1 of the
Original Agreement is hereby amended in its entirety to read as follows:
""Canadian Subsidiaries" means collectively MCCI, MCOC and any other
Subsidiary organized under the laws of Canada or any Province of Canada,
acquired or formed by a Restricted Person in compliance with the terms and
provisions of this Agreement, giving effect to such acquisition or
formation, and "Canadian Subsidiary" individually means any of the
foregoing."
(c) The definition of "Commitment Percentage" in Section 1.1 of the
Original Agreement is hereby amended in its entirety to read as follows:
2
<PAGE>
""Commitment Percentage" means initially the Commitment Percentage set
forth opposite such Lender's name on its signature page hereto, and on and
after the first and each successive assignment pursuant to Section 10.6(a),
the Commitment Percentage set forth opposite such Lender's name on the
Revised Schedule of Commitments and Commitment Percentages and on and after
the First Amendment Effective Date, the Commitment Percentage set forth
opposite such Lender's name on the Revised Schedule of Commitments and
Commitment Percentages appended as Schedule 1 to the First Amendment, as
such Commitment Percentage may be reduced pursuant to Section 2.1,
increased (as determined by such Lender in its sole and absolute
discretion) pursuant to Section 2.14, or reduced or increased pursuant to
Section 10.6."
(d) The definition of "Facility Amount" in Section 1.1 of the Original
Agreement is hereby amended in its entirety to read as follows:
""Facility Amount" means $335,000,000, subject to increase to
$400,000,000 pursuant to Section 2.14 and subject to reduction pursuant to
Section 2.1."
(e) The definition of "Indebtedness" in Section 1.1 of the Original
Agreement is hereby amended by deleting section (c) thereof and substituting the
following therefor:
"(c) Liabilities evidenced by a bond, debenture, note or similar
instrument and Liabilities arising in connection with the Permitted
Canadian Acquisition Indebtedness;"
(f) The definition of "LC Sublimit" in Section 1.1 of the Original
Agreement is hereby amended in its entirety to read as follows:
""LC Sublimit" means a Dollar Equivalent amount equal to $50,000,000.
(g) The definition of "Permitted Canadian Investments" in Section 1.1 of
the Original Agreement is hereby amended in its entirety to read as follows:
""Permitted Canadian Investments" means (without duplication) (a)
equity Investments by Restricted Persons in Canadian Subsidiaries; provided
that, after giving effect to the making by any Restricted Person of any
equity Investment in a Canadian Subsidiary, the sum of (i) the Dollar
Equivalent of the aggregate outstanding principal amount of all loans and
advances made by all Restricted Persons to the Canadian Subsidiaries, plus
(ii) the Dollar Equivalent of the aggregate amount of all equity
Investments made by all Restricted Persons in the Canadian Subsidiaries,
plus (iii) the Dollar Equivalent of the outstanding principal amount of the
Permitted Canadian Acquisition Indebtedness, would not exceed forty percent
(40%) of Borrower's Consolidated total assets, and (b) equity Investments
by Restricted Persons in an aggregate amount not to exceed the Dollar
Equivalent of $5,000,000 at any one time in non-Affiliate, non-Subsidiary
Canadian companies or
3
<PAGE>
partnerships engaged in the same or similar lines of business as Restricted
Persons are engaged in or other businesses reasonably related thereto."
(h) The definition of "Permitted Liens" in Section 1.1 of the Original
Agreement is hereby amended by amending subsection (h) of such definition in its
entirety to read as follows:
"(h) Liens securing the KPC Notes and Liens securing (or an agreement to
secure by Lien in the future) the Permitted Canadian Acquisition
Indebtedness, but in the case of the Permitted Canadian Acquisition
Indebtedness, such Liens can only encumber the specific assets acquired by
MCOC or the MCOC Acquisition Subsidiary with proceeds of that specific
Permitted Canadian Acquisition Indebtedness,"
(i) The definition of "Total Funded Debt" in Section 1.1 of the Original
Agreement is hereby amended by amending the first sentence of such definition in
its entirety to read as follows:
""Total Funded Debt" means, without duplication, all Indebtedness for
money borrowed including any subordinated indebtedness, the KPC Notes, the
Permitted Canadian Acquisition Indebtedness, purchase money mortgages,
lease obligations capitalized in accordance with GAAP, amounts outstanding
in respect of asset securitization vehicles, conditional sales contracts
and similar title retention debt instruments, including any current
maturities of such Indebtedness, plus the net present value of future
operating lease payments calculated using standard S&P methodology, plus
the redemption amount with respect to any redeemable preferred stock of
Borrower or any Subsidiary required to be redeemed within the next twelve
(12) months."
(j) The following definition of "Canadian Finance Subsidiary" is hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "Canadian Eurodollar Rate":
""Canadian Finance Subsidiary" means one or more wholly-owned
Subsidiaries of Borrower, which Subsidiaries shall be corporations
organized under the Business Corporation Act of the Province of Alberta or
another Canadian Province and which Subsidiaries will purchase Permitted
Canadian Acquisition Indebtedness from a Permitted Canadian Lender pursuant
to the corresponding Put/Call Agreement."
(k) The following definition of "Canadian Side Letter Agreement" is hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "Canadian Finance Subsidiary":
""Canadian Side Letter" means a letter agreement to be entered into
between the Administrative Agent and the Permitted Canadian Lender funding
any Permitted Canadian Acquisition Indebtedness providing that while such
Permitted Canadian
4
<PAGE>
Acquisition Indebtedness remains outstanding (i) the Permitted Canadian
Lender will not terminate the Put/Call Agreement without the prior written
consent of Administrative Agent, (ii) the Permitted Canadian Lender will
not amend, waive, modify or otherwise alter the terms of the Put/Call
Agreement, and (iii) the Permitted Canadian Lender will agree to perform
its contractual obligation under the "call" to sell such Permitted Canadian
Acquisition Indebtedness to Borrower upon Borrower's exercise of its "call
rights" even if for any reason the Put/Call Agreement had been breached or
might otherwise not have been enforceable."
(l) The following definition of "First Amendment" is hereby added to
Section 1.1 of the Original Agreement immediately following the definition of
"Federal Funds Rate":
"First Amendment" means the First Amendment to this Agreement."
(m) The following definition of "First Amendment Effective Date" is hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "First Amendment":
"First Amendment Effective Date" means the first date on which all of
the conditions precedent to the effectiveness of the First Amendment have
been satisfied or waived."
(n) The following definition of "MCCI" is hereby added to Section 1.1 of
the Original Agreement immediately following the definition of "Maximum Drawing
Amount":
"MCCI" means Midcoast Canada Capital, Inc., a corporation organized
under the Business Corporation Act of the Province of Alberta and wholly-
owned Subsidiary of Borrower, which Subsidiary may acquire Permitted
Canadian Acquisition Indebtedness from a Permitted Canadian Lender pursuant
to the corresponding Put/Call Agreement."
(o) The following definition of "MCOC" is hereby added to Section 1.1 of
the Original Agreement immediately following the definition of "MCCI":
"MCOC" means Midcoast Canada Operating Corporation, a corporation
organized under the Business Corporation Act of the Province of Alberta and
wholly-owned Subsidiary of Borrower, which Subsidiary may acquire certain
Canadian assets and finance or refinance such acquisition by incurring
Permitted Canadian Acquisition Indebtedness."
(p) The following definition of "MCOC Acquisition Subsidiary" is hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "MCOC":
"MCOC Acquisition Subsidiary" means one or more wholly-owned
Subsidiaries of Midcoast Canada Operating Corporation, which Subsidiaries
shall be corporations organized under the Business Corporation Act of the
Province of
5
<PAGE>
Alberta or another Canadian Province and which Subsidiaries will acquire
certain Canadian assets and finance or refinance such acquisition by
incurring Permitted Canadian Acquisition Indebtedness."
(q) The following definition of "1999 Canadian Financing Transaction" is
hereby added to Section 1.1 of the Original Agreement immediately following the
definition of "Net Worth":
""1999 Canadian Financing Transaction" means the C$15,187,500 term
loan from First Chicago NBD Bank, Canada to MCOC dated March 24, 1999 to
finance MCOC's acquisition of certain Canadian assets, which term loan was
repaid and is no longer outstanding."
(r) The following definition of "Permitted Canadian Acquisition
Indebtedness" is hereby added to Section 1.1 of the Original Agreement
immediately following the definition of "Percentage Share":
""Permitted Canadian Acquisition Indebtedness" means, at any time,
Indebtedness in Canadian Dollars for borrowed money:
(a) incurred by MCOC or an MCOC Acquisition Subsidiary;
(b) for the purpose of financing or refinancing MCOC's or such MCOC
Acquisition Subsidiary's acquisition of assets located in Canada;
(c) payable to one or more Permitted Canadian Lenders; and
(d) in an amount which does not exceed the lesser of:
(i) (1) the Facility Amount less (2) the Dollar Equivalent of the
Facility Usage plus (ii) the Dollar Equivalent of the amounts
outstanding determined pursuant to subsections (a) through (c) above;
and
(ii) $25,000,000;
provided, however, that after giving effect to such Permitted Canadian
Acquisition Indebtedness, the sum of (i) the Dollar Equivalent of the
outstanding principal amount of the Permitted Canadian Acquisition
Indebtedness, plus (ii) the Dollar Equivalent of the aggregate amount
of all equity Investments made by all Restricted Persons in the
Canadian Subsidiaries, plus (iii) the Dollar Equivalent of the
aggregate outstanding principal amount of all loans and advances made
by all Restricted Persons to the Canadian Subsidiaries, would not
exceed forty percent (40%) of Borrower's Consolidated total assets;
provided further, to constitute Permitted Canadian Acquisition
Indebtedness, such Indebtedness must be substantially similar in terms
and substance to the 1999 Canadian Financing
6
<PAGE>
Transaction, as determined by the Administrative Agent in its sole
discretion including, without limitation, such Indebtedness being
subject to a Put/Call Agreement in form and substance satisfactory to
the Administrative Agent; and provided further, to constitute
Permitted Canadian Acquisition Indebtedness, such Indebtedness must at
all times be subject to a Canadian Side Letter Agreement."
(s) The following definition of "Permitted Canadian Lenders" is hereby
added to Section 1.1 of the Original Agreement immediately following the
definition of "Permitted Canadian Investments":
""Permitted Canadian Lenders" means those Canadian banking Affiliates
of one or more Lenders who lend the Permitted Canadian Acquisition
Indebtedness and enter into a Put/Call Agreement and Canadian Side Letter
Agreement in connection therewith."
(t) The following definition of "Put/Call Agreement" is hereby added to
Section 1.1 of the Original Agreement immediately following the definition of
"Prior Credit Documents":
""Put/Call Agreement" means an agreement between the Permitted
Canadian Lender and Borrower pursuant to which the Permitted Canadian
Lender has the right to require that Borrower purchase the Permitted
Canadian Acquisition Indebtedness subject to such Put/Call Agreement and
Borrower has the right to require the Permitted Canadian Lender to sell to
Borrower the Permitted Canadian Acquisition Indebtedness subject to such
Put/Call Agreement."
Section 2.3. Amendments to Section 2.1. (a) The first and second
sentences of Section 2.1 of the Original Agreement are hereby amended in their
entirety to read as follows:
"Subject to the terms and conditions hereof, each Lender severally agrees
to make Loans to Borrower upon Borrower's request from time to time during
the Commitment Period; provided that (a) subject to Sections 3.3, 3.4 and
3.6, all Lenders are requested to make Loans of the same Type in accordance
with their respective Percentage Shares and as part of the same Borrowing,
(b) after giving effect to such Loans, the sum of (1) the Dollar Equivalent
of the Facility Usage plus (2) the Dollar Equivalent of the Permitted
Canadian Acquisition Indebtedness does not exceed the Facility Amount
determined as of the date on which the requested Loans are to be made, and
(c) after giving effect to such Loans, the Dollar Equivalent of such
Lender's Loans and Percentage Share of any LC Obligations does not exceed
such Lender's Commitment determined as of the date on which the requested
Loans are to be made. The aggregate amount of all Loans in any Borrowing
consisting of Base Rate Loans must be greater than or equal to $1,000,000
or must equal the remaining availability under the Facility Amount (or, if
any Permitted Canadian Acquisition Indebtedness is outstanding, the
remaining availability under the Facility Amount less the Permitted
Canadian Acquisition Indebtedness) and the aggregate
7
<PAGE>
amount of all Loans in any Borrowing consisting of Eurodollar Loans must be
greater than or equal to $3,000,000."
(b) The last sentence of Section 2.1 of the Original Agreement is hereby
amended in its entirety to read as follows:
"Borrower may, upon three (3) Business Days' prior written notice to
Administrative Agent, irrevocably cancel all or any portion of the Unused
Amount; provided, however, that Borrower may not cancel that portion of the
Unused Amount equal to the outstanding principal balance of the Permitted
Canadian Acquisition Indebtedness."
Section 2.4. Amendment to Section 2.3. The second sentence of Section
2.3 of the Original Agreement is hereby amended in its entirety to read as
follows:
"If any Dollar Loan is converted into a Canadian Dollar Loan, the amount of
the resulting Canadian Dollar Loan shall be equal to the Canadian Dollar
Equivalent of such converted Dollar Loan; and, if any Canadian Dollar Loan
is converted into a Dollar Loan, the amount of the resulting Dollar Loan
shall be equal to the Dollar Equivalent of such converted Canadian Dollar
Loan."
Section 2.5. Amendment to Section 2.7. Subsection 2.7(a) of the Original
Agreement is hereby amended in its entirety to read as follows:
"(a) If at any time the sum of (1) the Dollar Equivalent of the Facility
Usage plus (2) the Dollar Equivalent of the outstanding principal balance
of the Permitted Canadian Acquisition Indebtedness exceeds the Facility
Amount, Borrower shall immediately upon Administrative Agent's demand
prepay the principal of the Loans in an amount at least equal to such
excess."
Section 2.6. Amendment to Section 2.8. Subsection 2.8(a) of the Original
Agreement is hereby amended in its entirety to read as follows:
"(a) the sum of (1) the Dollar Equivalent of the Facility Usage plus (2)
the Dollar Equivalent of the outstanding principal balance of the Permitted
Canadian Acquisition Indebtedness does not exceed the Facility Amount at
such time;"
Section 2.7. Amendment to Section 2.13. The first sentence of Subsection
2.13(a) of the Original Agreement is hereby amended in its entirety to read as
follows:
"If, after the making of all mandatory prepayments required under Section
2.7, the outstanding LC Obligations exceed the Facility Amount (or, if any
Permitted Canadian Acquisition Indebtedness is outstanding, the outstanding
LC Obligations exceed the Facility Amount less the Dollar Equivalent of the
Permitted Canadian Acquisition Indebtedness), then in addition to
prepayment of the entire principal
8
<PAGE>
balance of the Loans Borrower will immediately pay to LC Issuer an amount
equal to such excess."
Section 2.8. Amendment to Section 6.2. Section 6.2 of the Original
Agreement is hereby amended by adding a new Subsection 6.2(g) thereto to read in
its entirety as follows:
"(g) Not less than five (5) Business Days before MCOC or an MCOC
Acquisition Subsidiary incurs any Permitted Canadian Acquisition
Indebtedness, the Borrower will furnish a certificate stating the amount
and terms of the Permitted Canadian Acquisition Indebtedness to be
incurred, identifying the Permitted Canadian Lender(s) providing such
Permitted Canadian Acquisition Indebtedness, identifying the assets to be
acquired and the identity of the seller and certifying that after giving
effect to such Indebtedness such Indebtedness will meet all of the
conditions for such Indebtedness specified in the definition of "Permitted
Canadian Acquisition Indebtedness."
Section 2.9. Amendment to Section 6.3. The second sentence of Subsection
6.3 of the Original Agreement is hereby amended in its entirety to read as
follows:
"Each Restricted Person will permit representatives appointed by
Administrative Agent (and after the occurrence and during the continuance
of an Event of Default, representatives appointed by any Lender) (including
independent accountants, auditors, agents, attorneys, appraisers and any
other Persons) upon reasonable notice to visit and inspect during normal
business hours any of such Restricted Person's property, including its
books of account, other books and records, and any facilities or other
business assets, and to make extra copies therefrom and photocopies and
photographs thereof, and to write down and record any information such
representatives obtain, and each Restricted Person shall permit
Administrative Agent or its representatives (and after the occurrence and
during the continuance of an Event of Default, any Lender or its
representatives) to investigate and verify the accuracy of the information
furnished to Administrative Agent or any Lender in connection with the Loan
Documents, the Acquisition Agreement, the Permitted Canadian Acquisition
Indebtedness and the KPC Notes and to discuss all such matters with its
officers, employees and representatives."
Section 2.10. Amendment to Article VI. Article VI of the Original
Agreement is hereby amended by adding a new Section 6.19 thereto to read in its
entirety as follows:
"Section 6.19 Exercise of Call Rights. In connection with the Put/Call
Agreement relating to any particular Permitted Canadian Acquisition
Indebtedness, Borrower shall, upon demand of Administrative Agent, with the
consent of Required Lenders, exercise Borrower's right to "call" such
Permitted Canadian Acquisition Indebtedness and compel the Permitted
Canadian Lender holding such Permitted Canadian Acquisition Indebtedness to
sell, assign, transfer and convey such Permitted
9
<PAGE>
Canadian Acquisition Indebtedness to Borrower pursuant to the terms of the
applicable Put/Call Agreement."
Section 2.11. Amendment to Section 7.1. Subsection 7.1(e) of the Original
Agreement is hereby amended in its entirety to read as follows:
"(e) inter-company Indebtedness (i) incurred by Borrower or any Guarantor
and payable to Borrower or another Guarantor, or (ii) incurred by a
Canadian Subsidiary and payable to Borrower, a Guarantor or another
Canadian Subsidiary, including any extensions, renewals and replacements of
any such inter-company Indebtedness; provided that the sum of (A) the
Dollar Equivalent of the aggregate outstanding principal amount of all
loans and advances made by Restricted Persons to Canadian Subsidiaries,
plus (B) the Dollar Equivalent of the aggregate amount of all equity
Investments made by Restricted Persons in Canadian Subsidiaries, plus (C)
the Dollar Equivalent of the outstanding principal balance of the Permitted
Canadian Acquisition Indebtedness does not exceed at any time during the
term of this Agreement forty percent (40%) of Borrower's Consolidated total
assets and Permitted Canadian Acquisition Indebtedness,"
Section 2.12. Amendment to Section 7.1. Subsection 7.1(i) of the Original
Agreement is hereby amended by deleting the word "and" after the word "hereof"
and a new subsection (k) is hereby added to Section 7.1 after the word "prices"
and before the period at the end of subsection (j) to read in its entirety as
follows:
"and (k) Permitted Canadian Acquisition Indebtedness."
Section 2.13. Amendment to Section 7.2. Subsection 7.2(f) of the Original
Agreement is hereby amended to read in its entirety as follows:
"(f) guarantees, including, without limitation, the Put/Call Agreement, by
a Restricted Person of Indebtedness of another Restricted Person permitted
under Section 7.1."
Section 2.14. Amendment to Section 7.6. Subsection 7.6(f) of the Original
Agreement is hereby amended in its entirety to read as follows:
"(f) without duplication of any amounts permitted pursuant to subsection
(c) of this Section, loans or advances made by a Restricted Person to a
Canadian Subsidiary; provided that, after giving effect to the making by
any Restricted Person of any loan or advance to a Canadian Subsidiary, the
sum of (A) the Dollar Equivalent of the aggregate outstanding principal
amount of all loans and advances made by Restricted Persons to the Canadian
Subsidiaries, plus (B) the Dollar Equivalent of the aggregate amount of all
equity Investments made by Restricted Persons in the Canadian Subsidiaries,
plus (C) the Dollar Equivalent of the outstanding principal balance of the
Permitted Canadian Acquisition Indebtedness does not exceed at any time
during
10
<PAGE>
the term of this Agreement forty percent (40%) of Borrower's Consolidated
total assets or"
Section 2.15. Amendment to Article VII. Article VII of the Original
Agreement is hereby amended by adding a new Section 7.18 thereto to read in its
entirety as follows:
"Section 7.18 Maintenance of Put/Call Agreement. Borrower shall not
terminate any Put/Call Agreement relating to any particular Permitted
Canadian Acquisition Indebtedness while such Permitted Canadian Acquisition
Indebtedness is outstanding and held by a Permitted Canadian Lender."
Section 2.16. Amendment to Article VII. Article VII of the Original
Agreement is hereby amended by adding a new Section 7.19 thereto to read in its
entirety as follows:
"Section 7.19 Refinancing Permitted Canadian Acquisition Indebtedness.
Borrower agrees that only MCCI or a Canadian Finance Subsidiary will
acquire from Permitted Canadian Lenders any Permitted Canadian Acquisition
Indebtedness and upon MCCI's or such Canadian Finance Subsidiary's
acquisition of any such Indebtedness MCCI or such Canadian Finance
Subsidiary shall not further sell, assign, transfer or convey such
Indebtedness or any evidence of such Indebtedness."
Section 2.17. Amendment to Section 10.16. Subsection 10.16 of the
Original Agreement is hereby amended by deleting the reference to the promissory
note in the original principal amount of "$20,000,000" and substituting
"$2,000,000" therefor.
ARTICLE III - Conditions of Effectiveness
Section 3.1. Effective Date. This Amendment shall become effective as of
the date first above written when, and only when, (i) Administrative Agent shall
have received, at Administrative Agent's office, a counterpart of this Amendment
executed and delivered by Borrower and each Lender, (ii) Administrative Agent
shall have additionally received the Consent and Agreement in the form attached
hereto executed by each of the Guarantors, and (iii) Administrative Agent shall
have additionally received the Assignment and Acceptance in the form attached
hereto executed by each of the parties thereto.
ARTICLE IV - Waiver of Notice
Section 4.1. Waiver of Notice Required Under Section 2.14. Each Lender
Party hereby waives the requirement that Borrower provide not less than thirty
(30) days' prior written notice to Administrative Agent of any requested
increase in the Facility Amount and agrees that this Amendment shall suffice as
such written notice.
ARTICLE V - Representations and Warranties
11
<PAGE>
Section 5.1. Representations and Warranties of Borrower. In order to
induce each Lender to enter into this Amendment, Borrower represents and
warrants to each Lender that:
(a) The representations and warranties contained in Article V of the
Original Agreement are true and correct at and as of the time of the
effectiveness hereof, except to the extent that the facts on which such
representations and warranties are based have been changed by the extension of
credit under the Credit Agreement and except as such representations and
warranties have been modified pursuant to this Amendment.
(b) Borrower is duly authorized to execute and deliver this Amendment and
is and will continue to be duly authorized to borrow monies and to perform its
obligations under the Credit Agreement. Borrower has duly taken all corporate
action necessary to authorize the execution and delivery of this Amendment and
to authorize the performance of the obligations of Borrower hereunder.
(c) The execution and delivery by Borrower of this Amendment, the
performance by Borrower of its obligations hereunder and the consummation of the
transactions contemplated hereby do not and will not conflict with any provision
of law, statute, rule or regulation or the certificate of incorporation or
bylaws of Borrower, or of any material agreement, judgment, license, order or
permit applicable to or binding upon Borrower, or result in the creation of (or
obligation to create) any lien, charge or encumbrance upon any assets or
properties of Borrower. Except for those which have been obtained, no consent,
approval, authorization or order of any court or governmental authority or third
party is required in connection with the execution and delivery by Borrower of
this Amendment or to consummate the transactions contemplated hereby.
(d) When duly executed and delivered, each of this Amendment and the
Original Agreement will be legal and binding obligations of Borrower,
enforceable in accordance with their terms, except as limited by bankruptcy,
insolvency or similar laws of general application relating to the enforcement of
creditors' rights and by equitable principles of general application.
ARTICLE VI - Miscellaneous
Section 6.1. Ratification of Agreements. The Original Agreement as
hereby amended is hereby ratified and confirmed in all respects. The Loan
Documents, as they may be amended or affected by the various Amendment
Documents, are hereby ratified and confirmed in all respects. Any reference to
the Credit Agreement in any Loan Document shall be deemed to be a reference to
the Original Agreement as hereby amended. The execution, delivery and
effectiveness of this Amendment shall not, except as expressly provided herein,
operate as a waiver of any right, power or remedy of Lenders under the Credit
Agreement, the Notes, or any other Loan Document nor constitute a waiver of any
provision of the Credit Agreement, the Notes or any other Loan Document.
Section 6.2. Survival of Agreements. All representations, warranties,
covenants and agreements of Borrower herein shall survive the execution and
delivery of this Amendment and the performance hereof including, without
limitation, the making or granting of the Loans, and shall
12
<PAGE>
further survive until all of the Obligations are paid in full. All statements
and agreements contained in any certificate or instrument delivered by Borrower
or any Restricted Person hereunder or under the Credit Agreement to any Lender
shall be deemed to constitute representations and warranties by, and/or
agreements and covenants of, Borrower under this Amendment and under the Credit
Agreement.
Section 6.3. Loan Documents. This Amendment is a Loan Document, and all
provisions in the Credit Agreement pertaining to Loan Documents apply hereto.
Section 6.4. Revised Commitments and Commitment Percentages. Each of the
Lenders agrees and acknowledges that upon the effectiveness of this Amendment,
the Commitment and Commitment Percentage of each Lender will be as set forth on
the Revised Schedule of Commitments and Commitment Percentages appended hereto
as Schedule 1.
Section 6.5. Governing Law. This Amendment shall be governed by and
construed in accordance with the laws of the State of Texas and any applicable
laws of the United States of America in all respects, including construction,
validity and performance.
Section 6.6. Counterparts; Fax. This Amendment may be separately
executed in counterparts and by the different parties hereto in separate
counterparts, each of which when so executed shall be deemed to constitute one
and the same Amendment. This Amendment and the other Amendment Documents may be
validly executed by facsimile or other electronic transmission.
THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS REPRESENT THE FINAL AGREEMENT
BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR,
CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS OF THE PARTIES. THERE ARE NO
UNWRITTEN ORAL AGREEMENTS OF THE PARTIES.
IN WITNESS WHEREOF, this Amendment is executed as of the date first above
written.
MIDCOAST ENERGY RESOURCES, INC.,
Borrower
By: _____________________________________
Richard A. Robert
Chief Financial Officer and Treasurer
BANK OF AMERICA, N.A.,
Administrative Agent, Lender and LC Issuer
Signature Page 1
13
<PAGE>
By: _____________________________________
Patrick M. Delaney
Managing Director
BANK ONE, NA,
Syndication Agent and Lender
By: _____________________________________
Name:
Title: Authorized Officer
CIBC INC.,
Documentation Agent and Lender
By: _____________________________________
Name:
Title:
FIRST UNION NATIONAL BANK,
Lender
By: _____________________________________
Name:
Title:
FLEET NATIONAL BANK,
Lender
By: _____________________________________
Name:
Title:
CREDIT AGRICOLE INDOSUEZ,
Lender
By: _____________________________________
Name:
Title:
By: _____________________________________
Name:
Title:
To Modcoast Energy Resources, Inc.
First Amendment
Signature Page 2
<PAGE>
SCOTIABANC INC.,
Lender
By: _____________________________________
Name:
Title:
PRUDENTIAL SECURITIES CREDIT CORP.,
Lender
By: _____________________________________
Name:
Title:
UMB OKLAHOMA BANK,
Lender
By: _____________________________________
Name:
Title:
MEESPIERSON CAPITAL CORP.
By: _____________________________________
Darrell W. Holley
Managing Director
By: _____________________________________
Christopher S. Parada
Vice President
TORONTO DOMINION (TEXAS), INC.
Lender
By: _____________________________________
Name:
Title:
To Modcoast Energy Resources, Inc.
First Amendment
Signature Page 3
<PAGE>
THE BANK OF TOKYO-MITSUBISHI, LTD.
Lender
By: _____________________________________
Name:
Title:
To Modcoast Energy Resources, Inc.
First Amendment
Signature Page 4
<PAGE>
SCHEDULE 1
Revised Schedule of Commitments and Commitment Percentages
Commitment and Commitment Percentage Lender
Commitment: $40,000,000 BANK OF AMERICA, N.A.,
Commitment Percentage: 12% Lender and LC Issuer
Percentage Share: 12%
Commitment: $40,000,000 BANK ONE, NA,
Commitment Percentage: 12% Syndication Agent and Lender
Percentage Share: 12%
Commitment: $40,000,000 CIBC, INC.
Commitment Percentage: 12% Documentation Agent and Lender
Percentage Share: 12%
Commitment: $40,000,000 FIRST UNION NATIONAL BANK,
Commitment Percentage: 12% Lender
Percentage Share: 12%
Commitment: $30,000,000 PRUDENTIAL SECURITIES CREDIT
Commitment Percentage: 9% CORP.
Percentage Share: 9% Lender
Commitment: $20,000,000 FLEET NATIONAL BANK
Commitment Percentage: 6% Lender
Percentage Share: 6%
Commitment: $20,000,000 CREDIT AGRICOLE INDOSUEZ,
Commitment Percentage: 6% Lender
Percentage Share: 6%
To Modcoast Energy Resources, Inc.
First Amendment
Schedule 1 Page 1
<PAGE>
Commitment: $30,000,000 SCOTIABANC INC.
Commitment Percentage: 9% Lender
Percentage Share: 9%
Commitment: $ 5,000,000 UMB OKLAHOMA BANK
Commitment Percentage: 1% Lender
Percentage Share: 1%
Commitment: $20,000,000 MEESPIERSON CAPITAL CORP.
Commitment Percentage: 6% Lender
Percentage Share: 6%
Commitment: $30,000,000 TORONTO DOMINION (TEXAS), INC.
Commitment Percentage: 9% Lender
Percentage Share: 9%
Commitment: $20,000,000 THE BANK OF TOKYO-MITSUBISHI,
Commitment Percentage: 6% LTD.
Percentage Share: 6% Lender
TOTAL COMMITMENT $335,000,000
To Midcoast Energy Resources, Inc.
First Amendment
Schedule 1 Page 2
<PAGE>
EXHIBIT "A"
TO
FIRST AMENDMENT
CONSENT AND AGREEMENT
Each of Creole Gas Pipeline Corporation, a Delaware corporation, Dufour
Petroleum, Inc. f/k/a DPI/Midcoast, Inc., a Mississippi corporation, H&W
Pipeline Corporation, an Alabama corporation, Kansas Pipeline Company, a Kansas
general partnership, Magnolia Gathering, Inc., an Alabama corporation, Magnolia
Pipeline Corporation, an Alabama corporation, Magnolia Resources, Inc., a
Mississippi corporation, MarGasCo Partnership, an Oklahoma general partnership,
Midcoast Energy Marketing, Inc., a Delaware corporation, Midcoast Gas Services,
Inc., a Delaware corporation, Midcoast Gas Pipeline, Inc., a Delaware
corporation, Midcoast Gas Pipeline, Inc., a Texas corporation, Midcoast Holdings
No. One, Inc., a Delaware corporation, Midcoast Interstate Transmission, Inc.,
an Alabama corporation, f/k/a Alabama Tennessee Natural Gas Co., Midcoast Kansas
General Partner, Inc., a Delaware corporation, Midcoast Kansas Pipeline, Inc., a
Delaware corporation, Midcoast Marketing, Inc., a Texas corporation, Mid Kansas
Partnership, a Kansas general partnership, Mid Louisiana Gas Company, a Delaware
corporation, Mid Louisiana Gas Transmission Company, a Delaware corporation,
Nugget Drilling Corporation, a Minnesota corporation, Riverside Pipeline
Company, L.P., a Kansas limited partnership, Southern Industrial Gas
Corporation, a Louisiana corporation, and Tennessee River Intrastate Gas
Company, Inc., an Alabama corporation, hereby consents to the provisions of this
Amendment and the transactions contemplated herein, and hereby ratifies and
confirms the Guaranty dated as of November 8, 1999 made by it for the benefit of
Lenders, and agrees that its obligations and covenants thereunder are unimpaired
hereby and shall remain in full force and effect.
IN WITNESS WHEREOF, each Guarantor has executed and delivered this Consent
and Agreement.
GUARANTORS:
MAGNOLIA PIPELINE CORPORATION
H&W PIPELINE CORPORATION
MAGNOLIA RESOURCES, INC.
MAGNOLIA GATHERING, INC.
MIDCOAST HOLDINGS NO. ONE, INC.
TENNESSEE RIVER INTRASTATE
GAS COMPANY, INC.
NUGGET DRILLING CORPORATION
MIDCOAST MARKETING, INC.
MID LOUISIANA GAS COMPANY
CREOLE GAS PIPELINE CORPORATION
MID LOUISIANA GAS TRANSMISSION
COMPANY
Exhibit A Page 1
<PAGE>
MIDCOAST INTERSTATE
TRANSMISSION, INC.
MIDCOAST GAS SERVICES, INC.,
MIDCOAST ENERGY MARKETING,
INC.
DUFOUR PETROLEUM, INC. fka
DPI/MIDCOAST, INC.
MIDCOAST GAS PIPELINE, INC.,
a Texas corporation
MIDCOAST GAS PIPELINE, INC.,
a Delaware corporation
SOUTHERN INDUSTRIAL GAS
CORPORATION
MIDCOAST KANSAS PIPELINE, INC.
MIDCOAST KANSAS GENERAL
PARTNER, INC.
By: ________________________________
Richard A. Robert
Treasurer
MID-KANSAS PARTNERSHIP
MARGASCO PARTNERSHIP
RIVERSIDE PIPELINE COMPANY, L.P.
KANSAS PIPELINE COMPANY
By: Midcoast Kansas General Partner, Inc.,
General Partner
By: ________________________________
Richard A. Robert
Treasurer
Exhibit A Page 2
<PAGE>
EXHIBIT "B"
TO
FIRST AMENDMENT
ASSIGNMENT AND ACCEPTANCE
Reference is made to the Credit Agreement dated as of November 8, 1999 (the
"Credit Agreement") among MIDCOAST ENERGY RESOURCES, INC., a Texas corporation
(the "Borrower"), the Lenders (as defined in the Credit Agreement), Bank One,
NA, as Syndication Agent, CIBC, Inc., as Documentation Agent, and Bank of
America, N.A., as Administrative Agent for the Lenders (the "Administrative
Agent"). Terms defined in the Credit Agreement are used herein with the same
meaning.
The "Assignor" and the "Assignee" referred to on Schedule 1 agree as
follows:
1. The Assignor hereby sells and assigns to the Assignee, without recourse and
without representation or warranty except as expressly set forth herein,
and the Assignee hereby purchases and assumes from the Assignor, an
interest in and to the Assignor's rights and obligations under the Credit
Agreement and the other Loan Documents as of the date hereof equal to the
percentage interest specified on Schedule 1 of all outstanding rights and
obligations under the Credit Agreement and the other Loan Documents. After
giving effect to such sale and assignment, the Assignee's Commitment,
Commitment Percentage, Percentage Share and the amount of the Loans owing
to the Assignee will be as set forth on Schedule 1.
2. The Assignor: represents and warrants that it is the legal and beneficial
owner of the interest being assigned by it hereunder and that such interest
is free and clear of any adverse claim; makes no representation or warranty
and assumes no responsibility with respect to any statements, warranties or
representations made in or in connection with the Loan Documents or the
execution, legality, validity, enforceability, genuineness, sufficiency or
value of the Loan Documents or any other instrument or document furnished
pursuant thereto; makes no representation or warranty and assumes no
responsibility with respect to the financial condition of any Restricted
Person or the performance or observance by any Restricted Person of any of
its obligations under the Loan Documents or any other instrument or
document furnished pursuant thereto; and attaches the Note held by the
Assignor and requests that Administrative Agent exchange such Note for new
Notes payable to the order of the Assignee in an amount equal to the
Commitment assumed by the Assignee pursuant hereto and to the Assignor in
an amount equal to the Commitment retained by the Assignor, if any, as
specified on Schedule 1.
3. The Assignee confirms that it has received a copy of the Credit Agreement,
together with copies of the financial statements referred to in Section 6.2
thereof and such other documents and information as it has deemed
appropriate to make its own credit analysis and decision to enter into this
Assignment and Acceptance; agrees that it will, independently and
To Midcoast Energy Resources, Inc.
First Amendment
Exhibit B Page 1
<PAGE>
without reliance upon Administrative Agent, the Assignor or any other
Lender and based on such documents and information as it shall deem
appropriate at the time, continue to make its own credit decisions in
taking or not taking action under the Credit Agreement; confirms that it is
an Eligible Transferee; appoints and authorizes Administrative Agent to
take such action as agent on its behalf and to exercise such powers and
discretion under the Credit Agreement as are delegated to Administrative
Agent by the terms thereof, together with such powers and discretion as are
reasonably incidental thereto; agrees that it will perform in accordance
with their terms all of the obligations that by the terms of the Credit
Agreement are required to be performed by it as a Lender; and attaches any
U.S. Internal Revenue Service or other forms required under Section
3.10(d).
4. Following the execution of this Assignment and Acceptance, it will be
delivered to Administrative Agent for acceptance and recording by
Administrative Agent. The effective date for this Assignment and Acceptance
(the "Effective Date") shall be the date of acceptance hereof by
Administrative Agent, unless otherwise specified on Schedule 1.
5. Upon such acceptance and recording by Administrative Agent, as of the
Effective Date, the Assignee shall be a party to the Credit Agreement and,
to the extent provided in this Assignment and Acceptance, have the rights
and obligations of a Lender thereunder and the Assignor shall, to the
extent provided in this Assignment and Acceptance, relinquish its rights
and be released from its obligations under the Credit Agreement.
6. Upon such acceptance and recording by Administrative Agent, from and after
the Effective Date, Administrative Agent shall make all payments under the
Credit Agreement and the Notes in respect of the interest assigned hereby
(including, without limitation, all payments of principal, interest and
Unused Fees with respect thereto) to the Assignee. The Assignor and
Assignee shall make all appropriate adjustments in payments under the
Credit Agreement and the Notes for periods prior to the Effective Date
directly between themselves.
7. This Assignment and Acceptance shall be governed by, and construed in
accordance with, the Laws of the State of Texas.
8. This Assignment and Acceptance may be executed in any number of
counterparts and by different parties hereto in separate counterparts, each
of which when so executed shall be deemed to be an original and all of
which taken together shall constitute one and the same agreement. Delivery
of an executed counterpart of Schedule 1 to this Assignment and Acceptance
by telecopier shall be effective as delivery of a manually executed
counterpart of this Assignment and Acceptance.
To Midcoast Energy Resources, Inc.
First Amendment
Exhibit B Page 2
<PAGE>
IN WITNESS WHEREOF, the Assignor and the Assignee have caused Schedule 1 to
this Assignment and Acceptance to be executed by their officers thereunto duly
authorized as of the date specified thereon.
BANK OF AMERICA, N.A.,
Assignor
By: __________________________________
Patrick M. Delaney
Managing Director
NEW LENDER,
Assignee
By: ___________________________________
Name:
Title:
To Midcoast Energy Resources, Inc.
First Amendment
Exhibit B Page 3
<PAGE>
SCHEDULE 1
to
ASSIGNMENT AND ACCEPTANCE
Commitment Percentage interest assigned: ________%
Assignee's Commitment: $_______
Aggregate outstanding principal amount
of Loans assigned: $_______
Principal amount of Note payable to
Assignee: $_______
Principal amount of Note payable to
Assignor: $_______
Effective Date (if other than date
of acceptance by Administrative Agent): *_______, 2000
BANK OF AMERICA, N.A.,
Assignor
By:_______________________________
Patrick M. Delaney
Managing Director
Dated: _____________________, 19__
NEW LENDER, as Assignee
By: ______________________________
Name:
Title:
Domestic Lending Office:
Eurodollar Lending Office:
* This date should be no earlier than five Business Days after the delivery
of this Assignment and Acceptance to Administrative Agent.
To Midcoast Energy Resources, Inc.
First Amendment
Exhibit B Page 4
<PAGE>
Accepted and Approved **
this ___ day of _________________, 2000
BANK OF AMERICA, N.A.,
as Administrative Agent
By: ______________________________
Patrick M. Delaney
Managing Director
Accepted and Approved **
this ___ day of ________________, 2000
BANK OF AMERICA, N.A.,
as LC Issuer
By: ______________________________
Patrick M. Delaney
Managing Director
Approved this ____ day
of _____________________________, 2000
MIDCOAST ENERGY RESOURCES, INC.
By: ______________________________ **
Name:
Title:
** Required if the Assignee is an Eligible Transferee solely by reason of
subsection (b) of the definition of "Eligible Transferee".
To Midcoast Energy Resources, Inc.
First Amendment
Exhibit B Page 5
<PAGE>
EXHIBIT 21.1
MIDCOAST ENERGY RESOURCES, INC AND SUBSIDIARIES
SUBSIDIARIES OF THE REGISTRANT
<TABLE>
<CAPTION>
Year of State of
Name Incorporation Incorporation Ownership
- ------------------------------------------------ ---------------------- ---------------------- ----------------
<S> <C> <C> <C>
Mid Louisiana Gas Company 1953 Delaware 100%
Creole Gas Pipeline Corporation 1962 Louisiana 100%
Midcoast Interstate Transmission, Inc. 1966 Alabama 100%
H&W Pipeline Corporation* 1976 Alabama 100%
Nugget Drilling Corporation* 1982 Minnesota 100%
Tennessee River Intrastate Gas Company, Inc. 1986 Alabama 100%
Mid Louisiana Gas Transmission 1987 Delaware 100%
Magnolia Pipeline Corporation 1989 Alabama 100%
Midcoast Marketing, Inc. 1991 Texas 100%
Midcoast Holdings No. One, Inc. 1993 Delaware 100%
Magnolia Resources, Inc. 1996 Mississippi 100%
Magnolia Gathering, Inc. 1996 Alabama 100%
Arcadia/Midcoast Pipeline of New York L.L.C. 1996 New York 50%
Midcoast Gas Pipeline, Inc. 1997 Texas 100%
Pan Grande Pipeline, L.L.C. 1996 Texas 70%
Starr County Gathering System - A Joint Venture N/A N/A 60%
Texana Gas Pipeline - A Joint Venture N/A N/A 50%
Midcoast Energy Marketing, Inc. 1998 Delaware 100%
Midcoast Gas Services, Inc. 1998 Delaware 100%
Midcoast Del Bajio S. de R.L. de C.V. 1998 Mexico 50%
Midcoast Canada Capital, Inc. 1999 Canada 100%
Midcoast Canada Operating Corporation 1999 Canada 100%
DPI/Midcoast, Inc. 1999 Mississippi 100%
Flare, LLC 1999 Alabama 100%
Nova Scotia Company 1999 Canada 100%
Alberta Limited Partnership 1999 Canada 1%
Midcoast Canada Energy Services, Inc. 1999 Canada 100%
Midcoasr Kansas Pipeline, Inc. 1999 Kansas 100%
Midcoast Kansas General Partner, Inc. 1999 Kansas 100%
MarGasCo Partnership 1999 Oklahoma 100%
Kansas Pipeline Company General Partnership 1999 Kansas 100%
Mid-Kansas General Partnership 1999 Kansas 100%
Riverside Pipeline Co. General Partnership 1999 Kansas 100%
* Presently Inactive
</TABLE>
<PAGE>
EXHIBIT 23.1
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (No. 333-70371) and Form S-8 (No. 333-33127) of Midcoast
Energy Resources, Inc. of our report dated March 10, 2000 relating to the
consolidated financial statements and financial statement schedule, which
appears in this Form 10-K.
PRICEWATERHOUSECOOPERS LLP
Houston, Texas
March 30, 2000
<PAGE>
EXHIBIT 23.2
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statements on Form S-3 (No. 333-70371) and Form S-8 (No. 333-33127) of Midcoast
Energy Resources, Inc. of our report dated March 18, 1999 relating to the
consolidated financial statements and financial statement schedules, which
appears in this Form 10-K.
HEIN + ASSOCIATES LLP
Houston, Texas
March 30, 2000
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> DEC-31-1999
<CASH> 2,345,000
<SECURITIES> 0
<RECEIVABLES> 55,189,000
<ALLOWANCES> 1,484,000
<INVENTORY> 1,409,000
<CURRENT-ASSETS> 62,439,000
<PP&E> 406,885,000
<DEPRECIATION> 13,916,000
<TOTAL-ASSETS> 478,372,000
<CURRENT-LIABILITIES> 63,978,000
<BONDS> 0
0
0
<COMMON> 127,000
<OTHER-SE> 160,550,000
<TOTAL-LIABILITY-AND-EQUITY> 478,372,000
<SALES> 391,571,000
<TOTAL-REVENUES> 391,571,000
<CGS> 339,079,000
<TOTAL-COSTS> 370,668,000
<OTHER-EXPENSES> 180,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 6,533,000
<INCOME-PRETAX> 14,190,000
<INCOME-TAX> 2,169,000
<INCOME-CONTINUING> 12,021,000
<DISCONTINUED> 0
<EXTRAORDINARY> 582,000
<CHANGES> 0
<NET-INCOME> 11,439,000
<EPS-BASIC> 1.25
<EPS-DILUTED> 1.22
</TABLE>
