<PAGE>
Filed Pursuant to Rule: 424(b)(5)
Registration No. 333-70371
PROSPECTUS SUPPLEMENT
(To prospectus dated February 3, 1999)
3,460,000 Shares
[LOGO OF MIDCOAST ENERGY RESOURCES, INC. APPEARS HERE]
Common Stock
-----------------
Midcoast Energy Resources, Inc. is selling 3,370,000 shares of common
stock, and certain of our stockholders named in this prospectus supplement are
selling 90,000 shares of common stock. We will not receive any of the proceeds
from the sale of shares by the selling stockholders.
The common stock trades on the American Stock Exchange under the symbol
"MRS." On May 24, 1999, the last sale price of our common stock as reported on
the American Stock Exchange was $16 5/16 per share.
Investing in the common stock involves risks that are described in the
"Risk Factors" section beginning on page S-8 of this prospectus supplement.
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<TABLE>
<CAPTION>
Per Share Total
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<S> <C> <C>
Public Offering Price............................. $16.3125 $56,441,250
Underwriting Discount............................. $.88 $3,044,800
Proceeds, before expenses, to Midcoast Energy
Resources........................................ $15.4325 $52,007,525
Proceeds to the selling stockholders.............. $15.4325 $1,388,925
</TABLE>
The underwriters may also purchase up to an additional 519,000 shares
from us at the public offering price, less the underwriting discount, within 30
days from the date of this prospectus supplement to cover over-allotments.
Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus supplement or the accompanying prospectus is truthful or
complete. Any representation to the contrary is a criminal offense.
The shares of common stock will be ready for delivery in New York, New
York on or about May 28, 1999.
-----------------
Merrill Lynch & Co.
CIBC World Markets
Prudential Securities
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The date of this prospectus supplement is May 24, 1999.
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[Map of our principal transmission pipelines, end-user pipelines, gathering
systems and processing plants located in Alabama, Louisiana, Mississippi,
Oklahoma and Texas]
[Four color map]
<PAGE>
TABLE OF CONTENTS
Prospectus Supplement
<TABLE>
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Page
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<S> <C>
Prospectus Supplement Summary............................................ S-2
Summary Historical Consolidated Financial and Operating Data............. S-6
Risk Factors............................................................. S-8
Forward-Looking Statements............................................... S-13
Use of Proceeds.......................................................... S-14
Price Range of Common Stock and Dividend Policy.......................... S-15
Capitalization........................................................... S-16
Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... S-17
Business and Properties.................................................. S-27
Management............................................................... S-39
Selling Stockholders..................................................... S-40
Underwriting............................................................. S-42
Legal Matters............................................................ S-44
Experts.................................................................. S-44
Index to Financial Statements............................................ F-1
Prospectus
<CAPTION>
Page
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<S> <C>
About This Prospectus.................................................... 2
Where You Can Find More Information...................................... 2
Incorporation of Certain Documents by Reference.......................... 3
Summary.................................................................. 4
Forward-Looking Statements............................................... 4
Use of Proceeds.......................................................... 5
Ratio of Earnings to Fixed Charges and Earnings to Fixed Charges and
Preferred Stock Dividends............................................... 5
Description of Debt Securities........................................... 5
Description of Capital Stock............................................. 11
Description of Warrants.................................................. 14
Selling Security Holders................................................. 16
Plan of Distribution..................................................... 16
Legal Matters............................................................ 17
Experts.................................................................. 18
</TABLE>
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You should rely only on the information contained or incorporated by
reference in this prospectus supplement and the accompanying prospectus. We
have not, and the underwriters have not, authorized any other person to provide
you with different information. We are not, and the underwriters are not,
making an offer to sell these securities in any jurisdiction where the offer or
sale is not permitted. You should assume that the information appearing in this
prospectus supplement is accurate as of the date on the front cover of this
prospectus supplement only. Our business, financial condition, results of
operations and prospects may have changed since that date. Information included
in the accompanying prospectus has not been updated or changed since the date
of the accompanying prospectus, including the effect of a five-for-four stock
split effected on March 1, 1999.
-----------------
This prospectus supplement and the accompanying prospectus contain
summaries of certain agreements entered into by us that have been filed as
exhibits to the registration statement related to or incorporated by reference
in this prospectus supplement and the accompanying prospectus. These summaries
do not purport to be complete and are subject to, and are qualified in their
entirety by reference to, the exhibits. You should refer to each exhibit for a
complete description of the matter involved.
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In this prospectus supplement, the "company," "Midcoast," "we," "us" and
"our" refer to Midcoast Energy Resources, Inc. and its subsidiaries. Volumes
expressed in cubic feet of natural gas may include quantities of petroleum
liquids. In such cases, petroleum liquids quantities have been converted to a
natural gas equivalent unit basis using a conversion ratio of 6,000 cubic feet
of natural gas to one barrel of petroleum liquids, consistent with industry
standards.
S-1
<PAGE>
PROSPECTUS SUPPLEMENT SUMMARY
We are a rapidly growing pipeline company engaged in the transportation,
gathering, processing and marketing of natural gas and other petroleum
products. We currently own and operate over 2,450 miles of pipeline, including
interstate and intrastate transmission pipelines, end-user pipelines and
gathering systems, with an aggregate daily throughput capacity of approximately
2.5 billion cubic feet of natural gas ("Bcf") per day. In addition, we have
four processing and treating plants with an aggregate throughput capacity of
approximately 100 million cubic feet of natural gas ("Mmcf") per day. Our
principal assets are located in Alabama, Louisiana, Mississippi, Oklahoma,
Texas and Canada.
Since 1996, we have grown significantly by acquiring or constructing 49
pipeline systems at an aggregate cost of over $161 million. As a result, our
average daily throughput increased to approximately 607 Mmcf per day as of
December 31, 1998 from approximately 110 Mmcf per day in 1996. In addition, our
EBITDA (as defined later) and net income increased to $16.9 million and $9.1
million, respectively, in 1998 from $3.1 million and $1.9 million,
respectively, in 1996.
We segregate our business activities into three principal segments:
. Transmission Pipelines. We own and operate two interstate and one
intrastate transmission pipelines. These systems primarily receive and
deliver natural gas to and from other pipelines and also serve end-user
or gathering functions. Our primary transmission systems, which were
acquired in 1997, are the MIT system, located principally in northern
Alabama along the Tennessee River Valley, and the Midla system, located
in Louisiana and Mississippi. Average daily natural gas transmission
volumes increased 84% to 269 Mmcf per day in 1998 from 146 Mmcf per day
in 1997. The Transmission Pipelines segment accounted for $13.2 million
or 57% of our gross margin in 1998.
. End-User Pipelines. We own and operate 20 end-user systems that provide a
direct supply of natural gas to industrial companies, municipalities or
electric generating facilities through interconnect gas pipelines that we
construct or acquire. Some of our end-user customers include Amoco
Chemical Company, Champion International Corporation, Exxon Chemical
Company, Georgia Pacific Corporation and Owens Corning Corporation. Our
average daily end-user volumes increased 149% to 167 Mmcf per day in 1998
from 67 Mmcf per day in 1997. The End-User Pipelines segment accounted
for $5.0 million or 22% of our gross margin in 1998.
. Gathering Pipelines and Natural Gas Processing. Our 36 gathering systems
typically consist of a network of pipelines that collect natural gas or
crude oil from points near producing wells and transport it to larger
pipelines for further transmission. Processing revenues are realized from
the extraction and sale of natural gas liquids ("NGLs") as well as the
sale of the residual gas. Our more significant gathering and processing
assets, which were acquired in 1998 and 1999, include our
Anadarko/Mendota system in the Texas Panhandle and western Oklahoma, the
Calmar system in Alberta, Canada, and Dufour Petroleum, Inc., an NGL,
crude oil and CO\\2\\ trucking and marketing company. Our average daily
gathering and processing volumes increased 215% to 151 Mmcf per day in
1998 from 48 Mmcf per day in 1997. The Gathering Pipelines and Natural
Gas Processing segment accounted for $4.4 million or 19% of our gross
margin in 1998.
We derive revenue from transportation fees for transporting natural gas
and petroleum liquids through our pipelines. In addition, we provide natural
gas marketing services to our customers within each of the three segments.
Although the majority of our business is transportation fee based, we do retain
some exposure to commodity prices in our processing business. This exposure
represents a relatively small proportion of our total gross margin but provides
us with modest upside potential if NGL prices continue to recover from recent
historical lows.
S-2
<PAGE>
Opportunities in Our Industry
The natural gas industry has undergone dramatic change over the past
decade largely due to a series of steps taken by the federal and state
governments to deregulate the industry and increase competition among industry
participants. These actions are causing a major restructuring of the
relationships between interstate pipeline companies, local distribution
companies ("LDCs") and their respective customers and have created
opportunities for us to compete for these customers. We believe that the
strategic location of our pipelines, our strong industry relationships and
lower cost structure relative to major interstate carriers and LDCs position us
well to continue to take advantage of this opportunity to expand our customer
base.
As the focus of deregulation has shifted to the electric generating
industry, there has been an increasing convergence of the natural gas and
electric industries. There is also a general trend toward the consolidation of
companies within the natural gas industry. These changes have prompted several
large mergers between and among electric utilities and diversified natural gas
companies. We believe that these combined companies will divest certain of
their natural gas transmission, gathering and processing assets either as a
result of antitrust divestiture requirements or for strategic purposes. As a
result, we believe that these divestitures will create considerable acquisition
opportunities for us and that our industry relationships position us well to
capitalize on these opportunities.
Business Strategy
Our principal business strategy is to increase our 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. We implement this strategy through the following steps:
. Accretive Acquisitions. We seek 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.
We target systems in our core geographic areas of operation in order to
capitalize on existing infrastructure, personnel and customer
relationships to maximize system profitability. We also seek to acquire
assets near areas with growing demand for natural gas or increasing
drilling activity. These acquisitions enable us to establish new core
areas in which to build a regional presence. For example, we purchased
the Anadarko gas gathering system located in Texas and Oklahoma in
September 1998. The 696-mile system and processing plant are located in a
prolific natural gas producing region and established a new core
geographic area for us. We quickly strengthened our position in this area
in December 1998 with the acquisition of the 35-mile Mendota 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. We leverage our 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. We have recently constructed new
facilities at a cost of approximately $10.0 million near the southern end
of the Midla system to interconnect other systems we had previously
acquired. This project will allow us to provide approximately 55 Mmcf per
day of high pressure natural gas to a Georgia Pacific Corporation plant
and to an Exxon Chemical Company cogeneration facility and allows us to
compete for additional end-user customers in the area.
. Improving Existing System Profitability. After a system is acquired or
constructed, we begin 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, we focus on providing quality service to our
existing
S-3
<PAGE>
customers while identifying new customers. Many of our existing pipeline
and processing systems were designed with excess throughput capacity that
provides us with opportunities to increase throughput with little
incremental cost and to facilitate higher margin "swing" sales during
periods of increased gas demand. For example, since the purchase of the
MIT system in May 1997, we have increased contracted firm transportation
volumes 29% to 170 Mmcf per day from 132 Mmcf per day. In addition, we
generally seek to achieve administrative and operational efficiencies by
capitalizing on the geographic proximity of many of our systems.
Recent Developments
Dividend Declared. Our board of directors has declared a $.07 per share
cash dividend on our common stock to be paid on June 1, 1999 to shareholders of
record on May 21, 1999. This represents a 9.4% increase in our quarterly
dividend, as adjusted for the five-for-four stock split effected on March 1,
1999. This dividend will not be paid to you in connection with shares you
purchase in the offering.
Recent Acquisitions. In March 1999, we completed several acquisitions
totaling $31.0 million, including the following two significant acquisitions:
Calmar System Acquisition. We purchased the Calmar system in Alberta,
Canada from Probe Exploration, Inc. for approximately $13.2 million (U.S.)
and entered into a gas gathering and treatment agreement with Probe,
including the long-term dedication of Probe's reserves in the supply area.
The assets purchased include a 30 Mmcf per day amine sweetening plant and
30 miles of gas gathering pipeline located near Edmonton, Alberta. The
Calmar system currently gathers and treats approximately 24 Mmcf per day of
sour gas from 27 producing wells operated by Probe and Courage Energy Inc.
This acquisition establishes a new core area for us in Canada where we
believe the environment is favorable for future expansion as other Canadian
production companies explore the option of selling their gathering and
processing assets in order to provide capital for future development of
their reserve base.
Dufour Petroleum and Flare Acquisitions. We acquired Flare, LLC and Dufour
Petroleum, Inc., whose operations are centered in our core geographic areas
along the Gulf Coast. The total value of the transaction was approximately
$11.1 million and could include future consideration should certain
contingencies be met. Flare is a natural gas processing and treating
company whose principal assets include 27 portable natural gas processing
and treating plants. Dufour Petroleum is an NGL, crude oil and CO\\2\\
transportation and marketing company. Dufour Petroleum 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. This acquisition provides us with a much stronger
presence and greater expertise in the NGL and crude oil markets.
Reincorporation in Texas. On May 17, 1999, our shareholders approved a
proposal at our annual meeting to change our state of incorporation from Nevada
to Texas. The effects of this proposal on our stockholders are described in our
proxy statement for the annual meeting, which is part of our Schedule 14A filed
with the SEC on April 19, 1999. The reincorporation will occur after completion
of the offering covered by this prospectus supplement.
S-4
<PAGE>
The Offering
<TABLE>
<S> <C>
Common stock offered by
Midcoast(1)...................... 3,370,000 shares
Common stock offered by selling
stockholders..................... 90,000 shares
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Total........................... 3,460,000 shares
Shares to be outstanding after the
offering(2)...................... 10,362,179 shares
Use of proceeds................... The net proceeds from the sale of the
common stock we are offering in this
prospectus supplement will be used to repay
bank indebtedness we have incurred in
connection with our recent acquisitions.
See "Use of Proceeds."
Dividend policy................... We intend to declare and pay quarterly cash
dividends of $.07 per share, depending upon
our financial results and action by our
board of directors.
Risk factors...................... See "Risk Factors" and the other
information included in this prospectus
supplement for a discussion of factors you
should carefully consider before deciding
to invest in shares of our common stock.
American Stock Exchange symbol.... "MRS"
</TABLE>
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(1) Excludes 519,000 shares of common stock that are subject to purchase from
us upon exercise of the underwriters' over-allotment option. See
"Underwriting."
(2) Based on the number of shares of common stock outstanding on March 31,
1999. It does not include (i) 137,500 shares of common stock that are
issuable upon exercise of outstanding warrants to purchase common stock
exercisable at $10.327 per share, (ii) 171,880 shares issuable upon
exercise of outstanding warrants to purchase common stock exercisable at
$15.818 per share and (iii) 480,564 shares of common stock reserved for
issuance upon the exercise of outstanding stock options under our stock
option plans.
S-5
<PAGE>
SUMMARY HISTORICAL CONSOLIDATED FINANCIAL AND OPERATING DATA
The summary historical consolidated financial and operating data as of and
for the fiscal years ended December 31, 1996, 1997 and 1998, and as of and for
the three months ended March 31, 1998 and 1999, set forth below are derived
from and should be read in conjunction with our consolidated financial
statements and accompanying notes contained in this prospectus supplement and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations."
<TABLE>
<CAPTION>
Three Months
Ended March 31,
Year Ended December 31, (unaudited)
--------------------------- -----------------
1996 1997 1998 1998 1999
------- -------- -------- ------- --------
(in thousands, except per share amounts)
<S> <C> <C> <C> <C> <C>
Statements of Operations
Data:
Operating revenues....... $29,415 $112,744 $234,069 $67,339 $ 82,064
Operating income......... 2,573 7,291 13,553 4,134 5,473
Interest expense......... 413 1,067 3,247 599 1,503
Income before income
taxes................... 1,914 5,914 10,422 3,564 3,935
Net income to common
shareholders............ 1,891 5,764 9,113 2,761 3,255
Per Share Data(1):
Earnings per common share
Basic.................. $ 0.73 $ 1.13 $ 1.29 $ 0.39 $ 0.47
Diluted................ 0.73 1.10 1.25 0.38 0.46
Weighted average number
of common shares
outstanding
Basic.................. 2,593 5,115 7,074 7,101 6,931
Diluted................ 2,598 5,251 7,298 7,350 7,148
Other Data:
Depreciation, depletion
and amortization........ $ 818 $ 1,592 $ 3,197 $ 693 $ 1,409
General and
administrative expense.. 1,223 3,455 6,283 1,603 1,928
EBITDA (2)............... 3,145 8,573 16,866 4,856 6,847
Cash flows from operating
activities.............. 2,564 3,856 17,169 (457) (444)
Cash flows from investing
activities.............. (8,842) (62,497) (60,587) (1,751) (34,096)
Cash flows from financing
activities.............. 7,340 57,781 43,310 2,017 36,361
Capital expenditures..... 1,028 1,410 7,816 (1,622) 4,949
Acquisitions, net of cash
acquired................ 8,363 60,778 52,076 -- 28,591
</TABLE>
<TABLE>
<CAPTION>
As of
As of December 31, March 31,
------------------------- 1999
1996 1997 1998 (unaudited)
------- -------- -------- -----------
(in thousands, except operating data)
<S> <C> <C> <C> <C>
Balance Sheet Data:
Working capital............. $ 1,135 $ 1,888 $ 989 $ 4,053
Property, plant and
equipment, net............. 16,965 97,552 154,247 188,960
Total assets................ 27,303 128,038 191,342 237,167
Long-term debt, net of
current portion............ 4,015 28,923 78,082 111,567
Shareholders' equity........ 13,593 61,451 66,284 69,549
Operating Data:
Miles of pipeline (3)....... 584 1,414 2,307 2,478
Number of operating systems:
Interstate transmission... 0 2 2 2
Intrastate transmission... 2 1 1 1
End-user.................. 17 21 20 20
Gathering................. 24 26 28 36
------- -------- -------- --------
Total operating
systems................ 43 50 51 59
======= ======== ======== ========
Average daily volume
(Mmcf/day) (4)(5).......... 110 401 607 819
Daily volume capacity
(Mmcf/day) (5)............. 694 1,353 1,903 2,482
</TABLE>
S-6
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(1) Gives effect to a 10% stock dividend paid on March 2, 1998 and a five-for-
four stock split effected on March 1, 1999.
(2) "EBITDA" represents net income before income taxes, net interest expense,
depreciation, depletion and amortization. EBITDA is not a measure of
financial performance under GAAP and may not be comparable to other
similarly titled measures used by other companies. Accordingly, it does not
represent net income or cash flows from operations as defined by GAAP and
does not necessarily indicate that cash flows will be sufficient to fund
cash needs. As a result, EBITDA should not be considered an alternative to
net income as an indicator of operating performance or to cash flows as a
measure of liquidity. We incur significant capital expenditures and incur
debt, primarily related to acquisitions, that are not reflected in EBITDA.
We have included information concerning EBITDA because we understand that
it is used by analysts and some investors as a relevant measure of
financial performance.
(3) Includes all of the miles of pipeline of the various active pipelines in
which we own an interest.
(4) Average daily volume information is approximate and is based on total
volumes transported during the twelve-month period, except for systems
acquired during that period, the average daily volumes of which are based
on total volumes transported from the date of acquisition or initial
operation through the end of the period.
(5) Transported oil volumes have been converted to a natural gas equivalent
unit basis using a conversion ratio of six thousand cubic feet ("Mcf") of
natural gas to one barrel ("Bbl") of oil, consistent with industry
standards.
S-7
<PAGE>
RISK FACTORS
You should carefully consider the following factors as well as the other
information contained in this prospectus supplement and the accompanying
prospectus. This prospectus supplement and the accompanying prospectus contain
certain forward-looking statements. Actual results could differ materially from
those projected in the forward-looking statements as a result of a number of
factors, including the risk factors set forth below and elsewhere in this
prospectus supplement and the accompanying prospectus.
Our Acquisition Strategy May Be Difficult to Maintain
One of our business strategies is to grow through acquisitions.
Implementing this strategy requires us to continue to identify attractive or
willing acquisition candidates and to acquire such candidates on economically
acceptable terms. However, there can be no assurance that we will continue to
be able to successfully identify and purchase attractive acquisition
candidates. Nor can we be assured of acquiring such candidates at a pace
necessary to maintain our current rate of growth. In addition, we cannot
guarantee that other companies will not also compete with us for acquisition
candidates at some future date. Future competitors may have greater financial
resources than us to finance acquisition opportunities and might be willing to
pay higher prices for the same acquisition opportunities. Such competition
could have the effect of increasing the price for acquisitions or reducing the
number of suitable acquisition candidates.
We Could Have Difficulty Integrating Our Acquisitions
If we are unable to manage growth effectively or to successfully
integrate new acquisitions into our existing operations, our business and our
financial results could be materially adversely affected. Pursuing our
acquisition strategy in the future could result in period-to-period
fluctuations in our financial position and results of operations. We could have
difficulty assimilating the acquired operations, including implementing common
information systems and standardizing certain operating and financial reporting
procedures. If we do not successfully integrate the acquired companies or
assets to common information systems and implement consistent overall business,
accounting and reporting controls, inconsistent operating and financial
practices could result among local operations. Such inconsistencies could
negate the benefits to be derived from a cohesive, efficient enterprise.
We have a limited operating history for a significant portion of our
operations. From January 1, 1996 to December 31, 1998, we have acquired or
constructed 40 pipeline systems, which collectively comprised $231 million or
99% of our revenues for the fiscal year ended December 31, 1998. In addition,
we acquired nine pipeline systems during the three month period ended March 31,
1999. Collectively, these 49 pipeline systems represented $177 million or 94%
of our net property, plant and equipment at March 31, 1999. We may experience
difficulties with customers, personnel or operations as we integrate our recent
acquisitions. If we are unable to successfully integrate any significant
acquisition, our results of operations and financial condition could be
materially adversely affected.
Our Rapid Growth Strains Our Resources
Our acquisition strategy and the resulting rapid growth strain our
existing resources. Our growth strategy is capital intensive, requiring us to
continue to invest in operational, financial and management information
systems. It also involves the reallocation of significant amounts of capital
from operating initiatives, such as capital improvements and expansions, to
acquisitions. We may, therefore, be at risk from a lack of capital resources in
key business areas. Our strategy also strains our human resources, placing
added emphasis on our ability to attract, retain, motivate and effectively
manage our employees. In addition, it can result in the diversion of corporate
management's attention from operating matters to acquisitions. These burdens on
our human resources could have a material adverse effect on our results.
S-8
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Our Acquisition Strategy Entails Uncertain Liabilities
There are uncertainties associated with our acquisition strategy. For
instance, there may be no assurance that we have discovered and identified all
acquisition liabilities, including liabilities arising from non-compliance with
governmental regulation and environmental laws by former owners for which we,
as the new owner, may be responsible. There could be an adverse impact on our
overall profitability if acquired companies or pipeline systems do not achieve
the financial results projected in our valuation models. Also, when we make an
acquisition, we might not anticipate some operating problems or legal
liabilities.
We May Have Difficulty Securing Additional Financing, and Our Activities May Be
Restricted by Debt Covenants
Our growth strategy is capital intensive and depends on our ability to
successfully acquire or construct additional pipeline systems. Our ability to
implement this strategy depends upon our ability to obtain financing for such
acquisitions and construction projects. To date, we have satisfied
substantially all of our working capital needs through cash flow from
operations, the public sale of common stock, borrowings under our existing
credit facilities and other short-term borrowings. Substantially all of our
assets are pledged to secure our credit facility. As of March 31, 1999, we had
approximately $117.4 million of outstanding indebtedness under the credit
facility which matures in August 2002, and approximately $8 million of
borrowing availability to us under the credit facility. On March 31, 1999, our
ratio of long-term debt to total capitalization (i.e., long-term debt divided
by the sum of long-term debt and shareholders' equity) was approximately 62%.
Our debt could adversely affect our ability to obtain additional financing for
working capital, acquisitions or other purposes.
Our bank limits the amount we can borrow. This determination is based on
the performance of our existing assets and on certain events, such as our
acquisition or disposition of assets. We have no current commitments or
arrangements for longer term financing beyond the maturity date of the credit
facility in 2002. Furthermore, there is no assurance that we will not need
additional funds to implement our growth strategy, or that any needed longer
term financing funds will be available, if at all, on acceptable terms. We will
need to refinance any balances due under our credit facility maturing on August
2002 if that facility is not renewed. If we are unable to refinance or raise
additional funds, it will have a material adverse effect on our operations. If
we raise funds by selling additional equity securities, your share ownership
will be diluted. The credit facility also contains a number of significant
covenants limiting our ability to, among other things, borrow additional money,
transfer or sell assets, create liens and enter into a merger or consolidation.
These covenants also require us to meet certain financial tests. If we are
unable to meet our debt service obligations or to comply with these covenants,
there would be a default under our existing debt agreements. Such a default, if
not waived, could result in acceleration of the repayment of our debt and have
a material adverse effect on our operations.
We Rely on Key Personnel
We believe that our ability to successfully implement our business
strategy and to operate profitably depends on the continued employment of our
senior management team led by Mr. Dan C. Tutcher. We have entered into
employment agreements with the senior management team that contain non-
competition provisions. Notwithstanding these agreements, we may not be able to
retain our senior management team and may not be able to enforce the non-
competition provisions in the employment agreements. If Mr. Tutcher or other
members of the senior management team become unable or unwilling to continue in
their present positions, our business and financial results could be materially
adversely affected.
We Are at Risk from Competition from Larger Competitors
Competition is intense in all of our markets. Some of our competitors
have greater financial resources and access to larger supplies of natural gas
than those available to us. These resources could
S-9
<PAGE>
allow those competitors to price their services more aggressively than we do,
which could hurt our profitability. In particular, Southern Natural Gas, Inc.
("Southern"), a subsidiary of Sonat Inc., has received an order from the
Federal Energy Regulatory Commission ("FERC") that authorizes the construction
of a 110-mile pipeline from Tuscaloosa, Alabama, to north Alabama to provide
gas to, among others, two municipal customers currently being served by us in
that geographic area. Construction on this pipeline has already begun although
numerous issues relating to the FERC order are currently on appeal. Those two
customers, accounting for approximately 10% or $2.4 million of our gross margin
as of December 31, 1998, have entered into a 20-year contract with Southern to
provide natural gas transportation services if the proposed pipeline is
completed. Because these contracts with Southern cover substantially all of the
current natural gas requirements of these two customers, if the pipeline is
completed, we will lose the firm transportation gas volumes to these customers
unless we are able to renew the contracts or obtain new customers prior to the
expiration of our contracts with these customers in 2003. If the pipeline is
completed, it may have a material adverse effect on our business and financial
results subsequent to 2003.
We Could Be Adversely Affected by Governmental Regulation
Our interstate pipeline systems are subject to many restrictions mandated
by the FERC. The restrictions are subject to change and could affect these
systems to various degrees. The significant interstate regulatory factors that
have affected or could affect these systems from time to time include the
following:
. inability to obtain timely FERC authorization for additional
allowable firm throughput or for rate increases;
. uncertainty of the effect of the industry's restructuring and
rate increases under FERC Order No. 636;
. attempts by large volume customers or gas suppliers to construct
gas facilities connecting to another pipeline or other source of
gas supply in order to bypass our systems; and
. uncertainties related to regulation of interstate pipelines that
supply distribution companies.
The construction, operation, maintenance and safety of our intrastate
pipelines are typically regulated by the state regulatory commissions with
jurisdictional authority, and our Calmar system is regulated by Canadian
authorities. It is possible that future state or Canadian regulatory measures
will adversely affect our intrastate or Canadian business and financial
results. In such events, the state's or Canada's regulatory authorities could
temporarily suspend or hinder operations in their particular jurisdiction.
Regulators at the state level have generally followed FERC's lead by allowing
increased competition behind LDCs; however, we cannot be assured that every
state will follow this practice.
Our Gas Marketing Operations Involve Market and Price Risks
As part of our gas marketing activities, we purchase natural gas at a
price determined by prevailing market conditions. Simultaneously with our
purchase of natural gas, we generally resell natural gas at a higher price
under a sales contract that is comparable in terms to our purchase contract,
including any price escalation provisions. In most instances, small margins are
characteristic of natural gas marketing because there are numerous companies of
greatly varying size and financial capacity who compete with us in the
marketing of natural gas. The profitability of our natural gas marketing
operations depends on the following factors:
. our responsiveness to changing markets and our ability to
negotiate natural gas purchase and sales agreements in changing
markets;
. reluctance by end-users to enter into long-term purchase
contracts;
. consumers' willingness to use other fuels when natural gas prices
get too high;
S-10
<PAGE>
. timing of imbalance or volume discrepancy corrections and their
impact on financial results; and
. the ability of our customers to make timely payment.
Our Results Are Affected by Fluctuations in Demand Due to Weather
We experience quarter-to-quarter fluctuations in our financial results
because our natural gas sales and pipeline throughputs are affected by changes
in demand for natural gas, primarily because of the weather. In particular,
demand on the Magnolia, MIT and Midla systems fluctuates due to weather
variations because of the large municipal and other seasonal customers that 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 our efforts to minimize such effects will have any
impact on future quarter-to-quarter fluctuations resulting from seasonal demand
patterns.
Our Profitability Is Affected by the Volatility of Natural Gas Liquids and
Natural Gas Prices
The profitability of our natural gas processing operations is affected by
volatility in prevailing NGL and natural gas prices. This business segment
contributed $2.7 million or 11.7% of our gross margin for the year ended
December 31, 1998. NGL and natural gas prices have been subject to significant
volatility in recent years in response to relatively minor changes in the
supply and demand for NGLs and natural gas, market uncertainty and a variety of
additional factors that are beyond our control. Our acquisitions of the
Anadarko system in September 1998, the Mendota system in December 1998, and
Flare in March 1999, which included additional natural gas processing
facilities, have increased our sensitivity to NGL and natural gas price
fluctuations.
We Are Subject to Liabilities and Costs Under Environmental Laws
Our operations are subject to federal, state and local laws and
regulations, including those relating to the protection of the environment,
natural resources, health and safety, waste management, and transportation of
hydrocarbons and chemicals. Sanctions for noncompliance may include
administrative, civil and criminal penalties, revocation of permits and
corrective action orders. Environmental laws have become more stringent over
the years. These laws sometimes apply retroactively. As a result of our
historical waste disposal practices and prior use of gas flow meters containing
mercury, we may incur material environmental costs and liabilities that may not
be covered by insurance. In addition, a party can be liable for environmental
damage without regard to that party's negligence or fault. Therefore, we could
have liability for the conduct of others, or for acts that were in compliance
with all applicable laws at the time we performed them. There also may be no
assurance that we have discovered and identified all acquisition liabilities,
including liabilities arising from non-compliance with governmental regulation
and environmental laws by former owners, and for which we, as the new owner,
may be responsible.
Our Operations Are Subject to Many Hazards and Operating Risks That May Not Be
Covered Fully by Insurance
Our operations are subject to many hazards. These hazards include:
. damage to pipelines, related equipment and surrounding properties
caused by hurricanes, floods, fires and other natural disasters;
. inadvertent damage from construction and farm equipment;
. leakage of natural gas and other hydrocarbons;
. fires and explosions; and
. other hazards, including those associated with sour gas, that
could also result in personal injury and loss of life, pollution
and suspension of operations.
S-11
<PAGE>
We have insurance to protect against many of these liabilities. This
insurance is capped at certain levels and does not provide coverage for all
liabilities. Our insurance may not be adequate to cover all losses or
liabilities that we might incur in our operations. Moreover, we may not be able
to maintain insurance at adequate levels or at reasonable rates. Particular
types of coverage may not be available in the future. Should catastrophic
conditions occur that interrupt delivery of gas for any reason, such occurrence
could have a material impact on the profitability of our operations.
We Could Be Adversely Affected by Inadequate Gas Supplies
If we are unable to maintain the throughput on our gathering systems at
current levels by accessing new natural gas supplies to offset the natural
decline in reserves, our business and financial results could be materially
adversely affected. We purchase substantially all of our natural gas on the
spot market. These purchase contracts may be affected by factors beyond our
control such as:
. capacity restraints;
. temporary regional supply shortages;
. third parties having control over the drilling of new wells;
. inability of wells to deliver gas at required pipeline quality and
pressure; and
. depletion of reserves.
There Is No Assurance We Will Continue to Declare Dividends in the Future
Our common stockholders may receive dividends out of legally available
funds if, and when, they are declared by our board of directors. Our current
policy is to declare quarterly cash dividends at a rate of $.07 per share of
common stock, as adjusted for stock splits and stock dividends. The amount of
future cash dividends, if any, will depend upon future earnings, results of
operations, capital requirements, covenants contained in our various financing
agreements, our financial condition and certain other factors. We cannot assure
you that dividends will be paid in the future.
Our Ability to Issue Preferred Stock May Make It Difficult for a Third Party to
Acquire Us
Certain provisions of our articles of incorporation could make it more
difficult for a third party to acquire control of us, even if a change in
control would be beneficial to our stockholders. The articles of incorporation
allow us to issue preferred stock without stockholder approval. Issuances of
preferred stock could make it difficult for a third party to acquire us.
Sales of Significant Amounts of Our Common Stock Could Adversely Affect Its
Market Price
The market price of our common stock could drop due to sales of a large
number of shares of our common stock or the perception that such sales could
occur. These factors could also make it more difficult to raise funds through
future offerings of common stock.
After this offering, approximately 10.4 million shares of our common
stock will be outstanding (approximately 10.9 million shares if the
underwriters' over-allotment option is exercised in full). Of these shares, the
3,460,000 shares sold in this offering (3,979,000 shares if the underwriters'
over-allotment option is exercised in full) will be freely tradeable without
restrictions under the Securities Act of 1933, as amended ("Securities Act"),
except for any shares purchased by "affiliates" of the company (as defined in
Rule 144 under the Securities Act). Our officers and directors and the selling
shareholders, have entered into lock-up agreements pursuant to which they have
agreed not to offer or sell any shares of common stock for a period of 180 days
after the date of this prospectus supplement without the prior written consent
of Merrill Lynch & Co., on behalf of the underwriters. Also, Merrill Lynch &
Co. may, at any time and without notice, waive the terms of these lock-up
agreements specified in the underwriting
S-12
<PAGE>
agreement. Upon expiration of this lock-up period, 2,102,603 shares may be sold
in the future subject to compliance with the volume limitations and other
restrictions of Rule 144. See "Underwriting."
Year 2000 Issues Could Affect Us
Like most other companies, we strive to ensure that our information
systems are able to recognize and process date-sensitive information properly
as the year 2000 approaches. Systems that do not properly recognize and process
this information could generate erroneous data or even fail. We are conducting
a review of our key computer systems and have identified a number of systems
that could be affected by the year 2000 issue. We are undertaking to upgrade
these systems to allow them to function properly. If these steps are not
completed successfully in a timely manner or if third parties with whom we do
business fail to sufficiently address their year 2000 issues, our business and
financial results could be adversely affected by disruptions in operations.
There Is a Limited Trading Market for Our Common Stock
Our common stock is traded on the American Stock Exchange. Average daily
trading volume for our common stock, as reported by the American Stock Exchange
for the first quarter of 1999, was approximately 17,457 shares. Despite the
possible increase in the number of shares of common stock to be publicly held
as a result of this offering, should additional equity be issued, we cannot
assure you that a more active trading market will develop. Because there is a
small public float in our common stock and it is thinly traded, sales of small
amounts of common stock in the public market could materially adversely affect
the market price for our common stock. If a more active market does not
develop, we may not be able to sell shares in the future promptly, for prices
that we deem appropriate, or perhaps at all.
FORWARD-LOOKING STATEMENTS
This prospectus supplement and the accompanying prospectus include
forward-looking statements. We have based these forward-looking statements on
our current expectations and projections about future events that are subject
to certain risks, uncertainties and assumptions about our company. These risks,
uncertainties and assumptions about our company, include, among other things:
. the successful implementation of our anticipated internal and
external growth strategies;
. our ability to integrate our current and future acquisitions;
. our ability to locate and acquire acquisition candidates on
economically acceptable terms;
. anticipated trends affecting our business;
. future expenditures for capital projects; and
. our ability to realize cost efficiencies.
Additional risks are described under "Risk Factors" beginning on page S-
8. We may not be required to publicly update or revise any forward-looking
statements, whether as a result of new information, future events or otherwise.
In light of these risks, uncertainties, and assumptions, the forward-looking
events discussed in this prospectus supplement and the accompanying prospectus
might not occur.
S-13
<PAGE>
USE OF PROCEEDS
We estimate our net proceeds from the sale of the 3,370,000 shares of
common stock we are offering to be approximately $51.6 million after deducting
underwriting discounts and offering expenses ($59.6 million if the underwriters
exercise their over-allotment option in full). We will not receive any proceeds
from the sale of common stock by the selling stockholders.
We will use the proceeds of this offering to pay down approximately $51.6
million of our $111.7 million of existing long-term indebtedness under our
credit facility. Our credit facility provides us borrowing availability in
United States and Canadian dollar denominated loans up to $150.0 million (with
a current committed amount of $125 million). The credit facility provides up to
a $15.0 million sublimit for the issuance of standby and commercial letters of
credit and the difference between the $125 million and the used sublimit
available as a revolving credit facility. Effective September 8, 1998, at our
option, borrowings under the credit facility accrue interest at the London
Interbank Offer Rate ("LIBOR") plus 1.25% or the Bank One Texas, N.A. ("Bank
One") base rate. The credit facility has a maturity date of August 31, 2002.
See "Management's Discussion and Analysis of Financial Condition and Results of
Operations--Capital Resources and Liquidity."
Following the reduction of the credit facility with the proceeds of this
offering, the outstanding long-term indebtedness under the credit facility will
be approximately $60.1 million ($52.1 million if the underwriters exercise
their over-allotment option in full). The outstanding indebtedness under the
credit facility is the result of our use of the facility to finance our recent
acquisitions. See "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Capital Resources and Liquidity."
S-14
<PAGE>
PRICE RANGE OF COMMON STOCK AND DIVIDEND POLICY
Our common stock began trading August 9, 1996 on the American Stock
Exchange under the symbol "MRS." The following table sets forth the high and
low sales prices for our common stock for the period from January 1, 1997 to
May 24, 1999.
<TABLE>
<CAPTION>
Price Range
-------------- Dividends Paid
High(1) Low(1) Per Share
------- ------ --------------
<S> <C> <C> <C>
1999:
Second Quarter (through May 24, 1999)....... $17.63 $15.00 $.070(2)
First Quarter............................... 18.69 15.38 .064
1998:
Fourth Quarter.............................. $17.41 $13.41 $.064
Third Quarter .............................. 18.95 13.30 .064
Second Quarter.............................. 18.70 15.09 .064
First Quarter............................... 19.00 14.72 .058
1997:
Fourth Quarter.............................. $20.36 $14.19 $.058
Third Quarter............................... 16.50 11.64 .058
Second Quarter.............................. 12.64 9.91 .058
First Quarter............................... 12.72 7.45 .058
</TABLE>
- --------
(1) All prices and dividends per share have been adjusted to reflect the 10%
stock dividend declared on February 3, 1998 and paid on March 2, 1998 to
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.
(2) On May 5, 1999, our Board of Directors increased the quarterly dividend
payable on our common stock from $.064 per share to $.070 per share. The
new dividend will be payable on June 1, 1999 to shareholders of record on
May 21, 1999.
On May 24, 1999, the closing price for the common stock, as reported by
the AMEX, was $16.3125 per share. As of May 21, 1999, there were approximately
330 holders of record of common stock.
Holders of our common stock are entitled to receive cash dividends out of
the funds we have legally available for that purpose. This entitlement is
subject to the qualification that our board need not declare or pay dividends
if to do so would be in violation of any laws or restrictions under contractual
arrangements (including credit agreements) to which we are or may hereafter
become a party.
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
effected on 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.
We have adjusted all presentations in this prospectus supplement to give
effect to the 1998 stock dividend and the 1999 stock split.
S-15
<PAGE>
CAPITALIZATION
The following table sets forth our capitalization as of March 31, 1999,
and our capitalization as adjusted for the offering and the application of the
net proceeds from the offering as described in the "Use of Proceeds" section
(assuming net proceeds to us of approximately $51.6 million and no exercise of
the underwriters' over-allotment option). You should read the following table
in conjunction with "Use of Proceeds," "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Capital Resources and
Liquidity," and the consolidated financial statements and the notes thereto
included in this prospectus supplement.
<TABLE>
<CAPTION>
As of March 31, 1999
---------------------
Actual As Adjusted
-------- -----------
(in thousands)
<S> <C> <C>
Long-Term Bank Debt (net of current maturities)(1)....... $111,567 $ 59,959
Shareholders' Equity:
Common stock, $.01 par value; 25,000,000 shares
authorized(2); 7,149,480 shares issued, 10,519,480
shares issued as adjusted(3).......................... 71 105
Paid-in capital........................................ 80,955 132,529
Accumulated deficit.................................... (9,134) (9,134)
Unearned compensation.................................. (4) (4)
Treasury stock (at cost), 157,301 shares at March 31,
1999.................................................. (2,339) (2,339)
-------- --------
Total shareholders' equity........................... 69,549 121,157
-------- --------
Total capitalization............................... $181,116 $181,116
======== ========
</TABLE>
- --------
(1) As of May 21, 1999, there was approximately $111.7 million in existing
long-term indebtedness under our credit facility.
(2) In connection with our five-for-four stock split declared on February 1,
1999, we filed a Certificate of Stock Split in March 1999 to increase the
authorized shares of our common stock to 31,250,000.
(3) Based on the number of shares of common stock outstanding on March 31,
1999. It does not include (i) 137,500 shares of common stock that are
issuable upon exercise of outstanding warrants to purchase common stock
exercisable at $10.327 per share, (ii) 171,880 shares issuable upon
exercise of outstanding warrants to purchase common stock exercisable at
$15.818 per share, (iii) 480,564 shares of common stock reserved for
issuance upon the exercise of outstanding stock options under our stock
option plans or (iv) the issuance of shares of common stock on exercise of
the over-allotment option granted to the underwriters.
S-16
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion of the historical financial condition and
results of our operations should be read in conjunction with "Selected
Historical Consolidated Financial and Operating Data" and with the consolidated
financial statements and related notes thereto contained in this prospectus
supplement.
General
Since our formation, we have grown significantly as a result of the
construction and acquisition of new pipeline systems. From January 1, 1996 to
March 31, 1999, we have acquired or constructed 49 pipelines for an aggregate
cost of over $161 million. See "Business and Properties--Acquisition and
Construction Activity." We believe the historical results of operations do not
fully reflect the operating efficiencies and improvements that we expect to
achieve by integrating the recently acquired and constructed pipeline systems.
As we pursue our growth strategy in the future, our financial position and
results of operations may fluctuate significantly from period to period.
Our results of operations are determined primarily by the volumes of gas
transported, purchased and sold through our pipeline systems or processed at
our processing facilities. With the exception of our natural gas processing
activities, which represent a small component of our overall earnings, our
revenues are derived from fee-based sources. As a result, our earnings have
little sensitivity to changes in commodity prices. In addition, most of our
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. We derive our revenues from three primary sources: (i)
transportation fees from our pipeline systems, (ii) processing and treating
natural gas and (iii) marketing natural gas and NGLs.
We receive transportation fees for transporting natural gas or petroleum
liquids owned by other parties through our pipeline systems. Typically, we
incur very little incremental operating or administrative overhead cost to
transport gas through our pipeline systems. We, therefore, recognize a
substantial portion of incremental transportation revenues as operating income.
We realize our natural gas processing revenues from the extraction and
sale of NGLs as well as the sale of the residual natural gas. We earn these
revenues under processing contracts with producers of natural gas on both a
"percentage of proceeds" and "keep-whole" basis. The contracts based on
"percentage of proceeds" provide that we receive a percentage of the NGLs and
residual gas revenues as a fee for processing the producer's gas. The "keep-
whole" contracts require that we reimburse the producers for the British
thermal unit ("Btu") energy equivalent of the NGLs and fuel we remove from the
natural gas as a result of processing, and we retain all revenues from the sale
of the NGLs. Our processing margins can be adversely affected by declines in
NGLs 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.
We realize our marketing revenues through the purchase and resale of
natural gas to our customers. Generally, given the same volumes of gas, gas
marketing activities will generate higher revenues and correspondingly higher
expenses than revenues and expenses associated with transportation activities.
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. The operating income we recognize from our
gas marketing efforts is the difference between the price at which we purchase
the gas and the price at which we resell to our customers. We have focused our
gas marketing activities on our systems with a strategic focus on providing
quality and consistent service to customers connected to our pipeline network.
Our marketing activities have historically varied greatly in response to market
fluctuations.
We experience quarter-to-quarter fluctuations in our financial results
because our natural gas sales and pipeline throughputs are affected by changes
in demand for natural gas, primarily because of
S-17
<PAGE>
the weather. In particular, demand on the Magnolia, MIT and Midla systems
fluctuates due to weather variations because of the large municipal and other
seasonal customers that 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 our efforts to minimize such
effects will have any impact on future quarter-to-quarter fluctuations because
of changes in demand resulting from variations in weather conditions.
Furthermore, future results could differ materially from historical results due
to a number of factors. These factors include, but are not limited to, the
interruption or cancellation of existing contracts, the impact of competitive
products and services, the pricing of and demand for such competitive products
and services and the presence of competitors with greater financial resources.
Results of Operations
We have acquired or constructed numerous pipelines since January 1996. We
acquired these assets from numerous sellers, at varying times of the year, and
all were accounted for under the purchase method of accounting for business
combinations. Accordingly, we include the results of operations for such
acquisitions in our financial statements only from the applicable closing date
of the acquisition. As a consequence, the historical results of operations for
the periods presented may not be comparable.
We have adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective January 1, 1998.
Accordingly, we have segregated our business activities into three segments:
Transmission Pipelines; End-User Pipelines; and Gathering Pipelines and Natural
Gas Processing.
Our consolidated gross margin for the year ended December 31, 1998,
increased 87% to $23.0 million compared to $12.3 million in 1997. Our
consolidated gross margin for the year ended December 31, 1997, was $7.7
million higher than for the same period in 1996. We discuss variations for each
segment in the segment results below.
Segment Results
The following tables present certain data for each of our three operating
segments for the three years ended December 31, 1998 and for the three months
ended March 31, 1998 and 1999. As we previously discussed, we provide marketing
services to our customers. For the purpose of analysis, we account 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. We evaluate each of our
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 14 in the notes to our consolidated
financial statements included in this prospectus supplement.
For financial reporting and contractual purposes, we generally measure
natural gas on an energy equivalent basis expressed in millions of Btu
("Mmbtu"). To convert an energy equivalent measurement to a volume measurement
expressed in Mcf, one Mmbtu approximates one Mcf of natural gas, consistent
with industry standards. Actual energy content of natural gas volumes may vary
considerably.
S-18
<PAGE>
Transmission Pipelines
<TABLE>
<CAPTION>
Three Months
For the Year Ended Ended March 31,
December 31, (Unaudited)
------------------------ ---------------
1996 1997 1998 1998 1999
------- ------- -------- ------- -------
(in thousands, except gross margin per
Mmbtu)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Marketing................... $ 6,586 $61,275 $117,557 $39,314 $34,107
Transportation Fees......... 979 3,512 6,387 1,997 1,917
------- ------- -------- ------- -------
Total Operating Revenues.. 7,565 64,787 123,944 41,311 36,024
------- ------- -------- ------- -------
Operating Expenses:
Cost of Natural Gas and
Transportation Charges..... 6,468 57,332 106,330 35,875 30,024
Operating Expenses.......... 301 1,592 4,383 1,172 1,085
------- ------- -------- ------- -------
Total Operating Expenses.. 6,769 58,924 110,713 37,047 31,109
------- ------- -------- ------- -------
Gross Margin.............. $ 796 $ 5,863 $ 13,231 $4,264 $ 4,915
======= ======= ======== ======= =======
Volume (in Mmbtu):
Marketing................... 2,759 22,454 48,538 16,348 16,313
Transportation.............. 9,914 30,752 49,506 15,152 14,668
------- ------- -------- ------- -------
Total Volume.............. 12,673 53,206 98,044 31,500 30,981
======= ======= ======== ======= =======
Gross Margin per Mmbtu.... $ .06 $ .11 $ .13 $ .14 $ .16
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998
Our Transmission Pipeline segment experienced a 15% increase in gross
margin for the three months ended March 31, 1999 when compared to the
equivalent three-month period ended March 31, 1998. This increase was achieved
despite a mild winter due to improved marketing margins on a per Mmbtu basis,
as well as a reduction in operating expense.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
Our entrance into the regulated interstate pipeline business began with
our acquisitions of the MIT system in May 1997 and the Midla system in October
1997. These acquisitions significantly enhanced our transmission pipeline
operations in 1998. A complete year of operations in 1998 provided a 91%
increase in revenues, an 84% increase in total volumes and a 126% increase in
gross margin when compared to the same period in 1997. In addition, average
daily demand transportation volume increased on both systems in 1998. The MIT
system's average daily demand transportation volume increased 19% to 158,000
Mmbtu in 1998 while the Midla system's increased 13% to 166,000 Mmbtu in 1998.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
As we discussed above, the addition of the MIT system in May 1997 and the
Midla system in October 1997 had a significant impact on the Transmission
Pipelines segment. The dramatic increases in revenue and gross margin in 1997
as compared to 1996 can be attributed to our inclusion of the partial years of
operations of the two acquisitions. However, a smaller portion of the increased
gross margin in 1997 can be attributed to our negotiating higher transportation
rates from customers on the Magnolia system.
S-19
<PAGE>
End-User Pipelines
<TABLE>
<CAPTION>
Three Months
For the Year Ended Ended March 31,
December 31, (Unaudited)
----------------------- ---------------
1996 1997 1998 1998 1999
------- ------- ------- ------- -------
(in thousands, except gross margin per
Mmbtu)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Marketing............................ $13,367 $33,862 $90,800 $22,905 $27,808
End-User Transportation Fees......... 1,144 2,487 3,287 764 739
------- ------- ------- ------- -------
Total Operating Revenues........... 14,511 36,349 94,087 23,669 28,547
------- ------- ------- ------- -------
Operating Expenses:
Cost of Natural Gas and
Transportation Charges.............. 13,011 32,673 88,822 22,196 26,722
Operating Expenses................... 106 208 224 45 100
------- ------- ------- ------- -------
Total Operating Expenses........... 13,117 32,881 89,046 22,241 26,822
------- ------- ------- ------- -------
Gross Margin....................... $ 1,394 $ 3,468 $ 5,041 $ 1,428 $ 1,725
======= ======= ======= ======= =======
Volume (in Mmbtu)
Marketing............................ 5,822 11,867 40,447 10,236 10,046
Transportation....................... 6,682 12,415 20,415 4,883 6,012
------- ------- ------- ------- -------
Total Volume....................... 12,504 24,282 60,862 15,119 16,058
======= ======= ======= ======= =======
Gross Margin per Mmbtu............. $ .11 $ .14 $ .08 $ .09 $ .11
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998
For the quarter ended March 31, 1999, the End-User segment gross margin
increased 21% over the same period in 1998. The increase is primarily
attributable to incremental gross margin created by the June 1998 Creole
pipeline acquisition, in addition to our providing new natural gas marketing
services to a new cogeneration facility near Baton Rouge, Louisiana.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
Our End-User Pipelines segment experienced significant increases in
revenues and gross margin in 1998 as compared to 1997. This increase was
primarily due to the fact that 1998 included a complete year of operations of
the Champion and Monsanto systems, which were acquired in the MIT acquisition
in May 1997, and the Crown Vantage and Farmlands systems, which were acquired
in the Midla acquisition in October 1997. A new marketing services contract to
provide 25 Mmcf per 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.
We expect this trend of increasing revenues and gross margin to continue
into 1999 because an additional 30 Mmcf per day of natural gas marketing
services to a new cogeneration facility near Baton Rouge, Louisiana, began at
the end of 1998.
Our gross margin per Mmbtu declined in 1998 compared to 1997. We
attribute this decrease to an increase in marketing activities, which increases
are characterized by lower margins and higher volumes.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
Our gross margin for the End-User Pipelines segment increased 149% from
$1.4 million in 1996 to $3.5 million in 1997. The results of operations of the
Champion system and the Monsanto system, which were acquired in the MIT
acquisition in May 1997, accounted for 69% of the increase. In addition, 1997
results included a full year of operations for several end-user pipeline
acquisitions made during 1996.
S-20
<PAGE>
Gathering Pipelines and Natural Gas Processing
<TABLE>
<CAPTION>
Three Months
Ended March
For the Year Ended 31,
December 31, (Unaudited)
----------------------- --------------
1996 1997 1998 1998 1999
------- ------- ------- ------ -------
(in thousands, except gross margin per
Mmbtu)
<S> <C> <C> <C> <C> <C>
Operating Revenues:
Marketing............................. $ 3,595 $ 5,597 $ 5,107 $ 957 $13,285
Gathering Transportation Fees......... 825 693 3,732 215 1,976
Processing Revenue.................... 2,460 4,956 6,761 1,099 1,893
------- ------- ------- ------ -------
Total Operating Revenues............ 6,880 11,246 15,600 2,271 17,154
------- ------- ------- ------ -------
Operating Expenses:
Cost of Natural Gas and Transportation
Charges.............................. 3,057 4,548 4,781 777 13,332
Operating Expenses.................... 227 415 2,410 390 1,009
Processing Costs...................... 1,443 3,566 4,052 444 982
------- ------- ------- ------ -------
Total Operating Expenses............ 4,727 8,529 11,243 1,611 15,323
------- ------- ------- ------ -------
Gross Margin........................ $ 2,153 $ 2,717 $ 4,357 $ 660 $ 1,831
======= ======= ======= ====== =======
Volume (in Mmbtu)
Marketing............................. 972 2,170 4,326 461 5,125
Gathering............................. 15,635 13,603 48,136 5,866 19,557
Processing............................ 799 1,850 2,544 511 1,961
------- ------- ------- ------ -------
Total Volume........................ 17,406 17,623 55,006 6,838 26,643
======= ======= ======= ====== =======
Gross Margin per Mmbtu.............. $ .12 $ .15 $ .08 $ .10 $ .07
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998
Significant increases in revenues, gross margin and volumes were realized
for the quarter ended March 31, 1999 compared to the quarter ended March 31,
1998. The significant increases are a result of our successful acquisition
strategy which has recently been focused on assets in this segment. As
discussed in Note 3 to the Consolidated Financial Statements, five acquisitions
in this segment were consummated in the first quarter of 1999, in addition to
the Anadarko and Mendota acquisitions in September and December 1998,
respectively.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
In the Gathering Pipelines and Natural Gas Processing segment, revenues,
gross margins and volumes increased substantially in 1998 as compared to 1997.
The significant increase in gathering activity in 1998 is attributable to
the Anadarko acquisition that was effective in August 1998. Although our 1998
operations only included five months of activity from the Anadarko system, that
system was responsible for 50% of the volumes gathered and approximately $1
million of the gross margin earned in 1998. We have been actively integrating
the operations of the Anadarko system and expect to create operational cost
savings we will realize during the second half of 1999.
Despite a 38% increase in the volume of gas processed through our
processing facilities, our gross margin from processing activities declined
significantly in 1998 as compared to 1997. This decline was due to the lower
processing spreads we realized in 1998 as NGL commodity prices continued to
deteriorate throughout the year. Processing margins in 1999 have shown signs of
improvement as NGL commodity prices have strengthened in response to rising
crude oil prices. The increase in processing volumes in 1998 is attributable to
the acquisition of the Hobart processing plant in the Anadarko acquisition in
August 1998.
S-21
<PAGE>
Marketing volumes increased 99% in 1998 as compared to 1997. Most
marketing activities are characterized by large volumes and low margins;
therefore, the significant increase in volumes during 1998 improved the gross
margin for the segment, but not to the same percentage magnitude. The increases
in volume are the result of various acquisitions.
We expect that the volumes, revenues and gross margin of our Gathering
Pipelines and Natural Gas Processing segment will increase substantially in
1999 as a result of the benefit of a complete year of operations from the
Anadarko system, as well as other acquisitions consummated subsequent to
December 31, 1998 (see Note 17 in the notes to our consolidated financial
statements included in this prospectus supplement). However, we cannot offer
any assurance as to whether we will realize such improved operating results or
as to the timing or size of any profits we might derive from such acquisitions.
Factors that may affect our realization of additional profits include changes
in competition, changes in production levels of natural gas and changes in the
regulatory environment affecting natural gas.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
The Gathering Pipelines and Natural Gas Processing segment reflected
mixed results in 1997 as compared to 1996. The gross margin for the operating
unit as a whole increased to $2.7 million in 1997 from $2.2 million in 1996.
Gathering transportation fees decreased by $.1 million in 1997 due principally
to throughput declines on our pipeline investment in Alaska. This decrease was
more than offset by increased margins created from marketing transactions on
gathering pipelines we acquired in the fourth quarter of 1996.
The volumes and gross margin related to our processing plant increased in
1997 as a result of having a full year of operations. However, the lower
commodity prices in 1997 as compared to 1996 had a negative impact on our
processing margins on a per unit basis. Our share of proceeds from the sale of
NGLs and the residue natural gas declines as the price of the commodity
declines. However, a $.6 million expansion of the Harmony plant's gathering
pipeline in the fourth quarter of 1997 connected four new wells and increased
NGL sales and residue gas sales by approximately 11% and 5%, respectively.
Other Income, Costs and Expenses
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31, 1998
In the three-month period ended March 31, 1999, we received $339,000 in
other revenues as compared to $88,000 over the same period in 1998. The
increase is primarily attributable to a sale of renovated equipment by our
Flare subsidiary.
In the three-month period ended March 31, 1999, our depreciation,
depletion and amortization increased to $1,409,000 from $693,000 when during
the same period in 1998. Of the $716,000 increase, 69% is attributable to
depreciation on the Anadarko, Flare, SeaCrest, Tinsley, and Dufour
acquisitions, which had no equivalent depreciation in 1998. In addition, 20% of
the increase is attributable to a one-time impairment on our H&W Pipeline, Inc.
assets recognized in the first quarter of 1999.
In the three-month period ended March 31, 1999, our general and
administrative expenses increased to $1,928,000 from $1,603,000 during the same
period in 1998. The increase is due to incremental overhead on newly acquired
assets in late 1998 and 1999 as well as increased staffing levels in 1999.
Interest expense for the three-month period ended March 31, 1999
increased to $1,503,000 from $599,000 during the same period in 1998. The
increased level of indebtedness in 1999 is primarily associated with our
September 1998 acquisition of Anadarko and March 1999 acquisition of Midcoast
Canada Operating Corporation. The additional expense related to increased debt
levels was mitigated by a reduction in our weighted average interest rate. Our
weighted average interest rate was 6.13% for the three-month period ended
March 31, 1999 as compared to 7.84% for the three-month period ended March 31,
1998.
S-22
<PAGE>
We recognized net income for the three-month period ended March 31, 1999
of $3.26 million as compared to $2.76 million for the equivalent period in
1998. Basic earnings per share for the three-month period ended March 31, 1999
increased 21% from $.39 to $.47 in 1999. The significant improvement in
earnings per share is attributable to a full quarter of operations of
acquisitions completed in 1998, and partial quarter operations of new
acquisitions in 1999.
Year Ended December 31, 1998 Compared to Year Ended December 31, 1997
In 1998, we received revenues of $.4 million from our oil and gas
properties as compared to $.3 million over the same period in 1997. The
increase is primarily attributable to a one-time settlement we received on our
Vealmoor Field properties.
In 1998, our 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 102% of the net increase of $1.6 million.
Our general and administrative expenses in 1998 increased $2.8 million
when compared to 1997 primarily due to the numerous acquisitions we have made
during 1997 and 1998. In addition, the increase can be attributed to our
expansion of our infrastructure to allow for continued growth.
Our interest expense for the year ended December 31, 1998 increased to
$3.2 million, from $1.1 million in 1997. We were 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 is 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. We mitigated the
additional expense related to increased debt levels by reducing our weighted
average interest rate. Our weighted average interest rate was 7.11% for the
year ended December 31, 1998 as compared to 7.83% for the year ended December
31, 1997.
We recognized annual operating income and net income in 1998 of $13.6
million and $9.1 million, respectively. This compares to $7.3 million in
operating income and $5.8 million in net income for the year ended 1997. Basic
earnings per share increased 14% from $1.13 in 1997 to $1.29 in 1998. The
significant improvement in earnings per share is primarily attributable to the
positive impact of the accretive acquisitions that we consummated during 1998
and 1997.
Year Ended December 31, 1997 Compared to Year Ended December 31, 1996
In 1997, we received revenues of $.3 million from our oil and gas
properties as compared to $.2 million over the same period in 1996. The
increase is primarily associated with a successful drilling program in our Sun
Field properties.
In 1997, our depreciation, depletion and amortization increased when
compared to 1996 primarily due to increased depreciation on assets acquired in
the MIT and Midla acquisitions. Collectively, these new acquisitions accounted
for 67% of the increase of $.8 million.
In 1997, our general and administrative expenses increased when compared
to 1996 primarily due to increased costs associated with the management of the
assets acquired in the MIT and Midla acquisitions. Collectively, these new
acquisitions accounted for 94% of the increase of $2.2 million.
In 1997, our interest expense increased 159% when compared to the year
ended 1996, from $.4 million to $1.1 million. The increase in 1997 is
associated with additional borrowings of approximately $37 million, which was
outstanding for one month and used to bridge finance the MIT acquisition prior
to an equity offering, and the addition of approximately $21.8 million in debt,
which was outstanding for November and December and was used to finance the
Midla acquisition.
S-23
<PAGE>
We recognized annual operating income and net income in 1997 of $7.3
million and $5.8 million, respectively, as compared to $2.6 million in
operating income and $1.9 million in net income for the year ended 1996. Basic
earnings per share increased 55% from $0.73 in 1996 to $1.13 in 1997. We
achieved the increased earnings per share despite the dilutive effects of
issuing additional shares in common stock offerings in August 1996 and July
1997. We attribute this significant improvement in earnings per share to the
positive impact of the accretive acquisitions we consummated during 1997.
Income Taxes
As of December 31, 1998, we have net operating loss carryforwards of
approximately $16.6 million, expiring in various amounts from 1999 through
2011. These loss carryforwards were generated by our predecessor and by
Republic Gas Partners, L.L.C. ("Republic"). Our ability to utilize the
carryforwards depends on our generating sufficient taxable income. It will also
be affected by annual limitations (currently estimated at $4.9 million) on the
use of such carryforwards. This limitation is due to a change in stockholder
control under the Internal Revenue Code that was triggered by our July 1997
common stock offering and the change of ownership created by the acquisition of
Republic.
For the year ended December 31, 1998, we removed a portion of the
valuation allowance related to net operating loss carryforwards that are more
likely than not to be utilized in the future. This resulted in our income tax
expense being lowered by approximately $1.1 million.
Capital Resources and Liquidity
We had historically funded our capital requirements through cash flow
from operations and borrowings from affiliates and various commercial lenders.
However, our capital resources were significantly improved with the equity
infusion derived from our initial and secondary common stock offerings in
August 1996 and July 1997, respectively.
The net proceeds of our combined stock offerings contributed
approximately $42.1 million and significantly improved our financial
flexibility. This increased flexibility has allowed us to pursue acquisition
and construction opportunities utilizing lower cost conventional bank debt
financing. During 1998 and to date in 1999, we have acquired or constructed
$83.1 million of pipeline systems. These acquisition and construction projects
increased our long-term debt to total capitalization ratio to 62% at March 31,
1999.
As a result of significantly increased cash flows generated from our
numerous acquisitions, in September 1998, we amended and restated our bank
financing agreement with Bank One. These amendments increased our borrowing
availability, modified our letter of credit facility, established a credit
sharing, 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 in the interest rate on borrowings.
The amendments to the credit agreement increased our borrowing
availability from $80 million to $150 million (with an initial committed amount
of $100 million, which, as noted below, has subsequently been increased to $125
million). The amended credit agreement provides borrowing availability as
follows: (i) up to a $15 million sublimit for the issuance of standby and
commercial letters of credit and (ii) the difference between the $100 million
and the used sublimit available as a revolving credit facility. Effective
September 8, 1998, at our option, borrowings under the amended credit agreement
accrue interest at LIBOR plus 1.25% or the Bank One base rate.
Under the amended credit agreement, a credit sharing was established
among Bank One, CIBC Inc., and Bank of America, N.A. We were subject to an
initial facility fee of $.5 million, which represents all fees due on
borrowings up to $100 million. As we borrow funds in excess of $100 million, a
.15% fee will be imposed. Our commitment fee remained at .375%. Additionally,
we are subject to an annual administrative agency fee of $35,000.
S-24
<PAGE>
In addition, the credit agreement is secured by all accounts receivable,
contracts, the pledge of all of our subsidiaries' stock and a first lien
security interest in our pipeline systems. The credit agreement 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. We were in
compliance with such financial covenants at March 31, 1999.
In March 1999, we further amended the credit agreement to increase the
committed amount of borrowing availability and to allow for Canadian dollar
denominated loans. In anticipation of a new acquisition in Canada, we increased
the committed amount of borrowing availability under the credit agreement from
$100 million to $125 million. In addition, because the functional currency of a
newly formed Canadian subsidiary will be Canadian dollars, we revised the
credit agreement to allow us the flexibility to borrow funds in Canadian
dollars in order to eliminate foreign currency exchange risk. See Note 17 in
the notes to our consolidated financial statements included in this prospectus
supplement for additional information.
For the year ended December 31, 1998, we generated cash flow from
operating activities of approximately $17.2 million and had approximately $47.0
million available to us under our credit agreement. At December 31, 1998, we
had committed to making approximately $3.7 million in construction related
expenditures for 1999 and an additional $7.5 million in acquisition related
expenditures, as indicated in Note 6 in the notes to our consolidated financial
statements included in this prospectus supplement. For the quarter ended March
31, 1999, the Company generated cash flow from operating activities before
changes in working capital accounts of approximately $4.9 million and had
approximately $7.6 million available under the credit agreement. At March 31,
1999, the Company had committed to make approximately $2.2 million in
construction related expenditures for 1999. We believe that our credit
agreement and funds provided by operations will be sufficient for us to meet
our operating cash needs for the foreseeable future and our projected capital
expenditures of approximately $2.2 million. If funds under the credit agreement
are not available to fund acquisition and construction projects, we 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 us. Should sufficient capital not be available, we will
not be able to implement our growth strategy as aggressively. Reducing our
outstanding indebtedness with the net proceeds of this offering will increase
our borrowing availability and should enable us to continue to pursue our
aggressive growth strategy.
Recent Accounting Pronouncements
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. This statement is effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. Initial application of this
statement should be as of the beginning of an entity's fiscal quarter; on that
date, SFAS No. 133 will require us to record all derivatives on the balance
sheet at fair value. We will either recognize changes in derivative fair values
in earnings as offsets to the changes in fair value of related hedged assets,
as liabilities and firm commitments or, for forecasted transactions, they will
be 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 our financial statements will
depend on a variety of factors. These include future interpretative guidance
from the FASB, the extent of our hedging activities, the types of hedging
instruments used and the effectiveness of such instruments. However, we do not
believe the effect of adopting SFAS 133 will be material to our financial
position.
Year 2000
The Year 2000 ("Y2K") issue is the result of computer programs being
written using two digits rather than four to define the applicable year. Any
programs that have time-sensitive software may recognize a date using "00" as
the year 1900 rather than the year 2000. This could result in major
S-25
<PAGE>
system failure or miscalculations. As a result, many companies may be forced to
upgrade or completely replace existing hardware and software in order to be Y2K
compliant.
We have completed the assessment of our computer software, hardware and
other systems, including embedded technology, relative to Y2K compliance. Some
of our older computer programs were written using two digits rather than four
to define the applicable year. As a result, the Y2K problem identified above
does impact some of our computer software and hardware systems. If the problems
are not remedied in a timely manner, this could cause disruptions of
operations, including, among other things, a temporary inability to process
transactions, send invoices, or engage in similar normal business activities.
Such disruption could materially and adversely affect our results of operation,
our liquidity and our financial condition.
We are currently updating some of our software and hardware in order to
improve the timeliness and quality of our business information systems. A by-
product of these improvements is the purchase of Y2K compliant software and
hardware for systems that otherwise are not Y2K compliant today. We have
completed software and hardware selection and have begun implementing our
systems update. We anticipate completion by June 1999. A budget for updating
computer software and hardware of approximately $1.0 million dollars has been
established. Approximately $.8 million has been spent through March 31, 1999.
Based on a successful implementation of our Y2K plan, we do not expect the Y2K
issue to pose significant operational problems for our computer systems.
We plan to complete an assessment of our key vendors, customers and other
third parties by June 30, 1999 to assess the impact such third party Y2K issues
might have on our business operations. We do not anticipate that any third
party's Y2K issues will materially impact our operations or financial results.
With respect to suppliers, we do not utilize any individual supplier in our
operations for which interruptions for Y2K problems could have a material
impact on our operations and financial results. In addition, there are
alternative suppliers from which we anticipate we would be able to obtain
sufficient quantities of products to continue to conduct our business. Because
we anticipate that we will complete our Y2K remediation efforts in advance of
December 31, 1999, we have not made any contingency plans with respect to our
operations and systems. However, a contingency plan will be established by the
third quarter of 1999 to address any unforeseen issues and to cover for the
contingency that the planned improvements are not completed on schedule.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention of complying fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat. 2386, signed into law
October 19, 1998. All statements made in this disclosure should be construed
within the confines of that Act. To the extent that any reader of the above
Year 2000 Readiness Disclosure is other than an investor or potential investor
in our common stock, this disclosure is made for the SOLE PURPOSE of
communicating or disclosing information aimed at correcting, helping to correct
and/or avoiding Year 2000 failures.
S-26
<PAGE>
BUSINESS AND PROPERTIES
We are a rapidly growing pipeline company engaged in the transportation,
gathering, processing and marketing of natural gas and other petroleum
products. We currently own and operate over 2,450 miles of pipeline, including
interstate and intrastate transmission pipelines, end-user pipelines and
gathering systems, with an aggregate daily throughput capacity of approximately
2.5 Bcf per day. In addition, we have four processing and treating plants with
an aggregate throughput capacity of approximately 100 Mmcf per day. Our
principal assets are located in Alabama, Louisiana, Mississippi, Oklahoma,
Texas and Canada.
Since 1996, we have grown significantly by acquiring or constructing 49
pipeline systems at an aggregate cost of over $161 million. As a result, our
average daily throughput increased to approximately 607 Mmcf per day as of
December 31, 1998 from approximately 110 Mmcf per day in 1996. In addition, our
EBITDA and net income increased to $16.9 million and $9.1 million,
respectively, in 1998 from $3.1 million and $1.9 million, respectively, in
1996.
We segregate our business activities into three principal segments:
. Transmission Pipelines. We own and operate two interstate and one
intrastate transmission pipelines. These systems primarily receive
and deliver natural gas to and from other pipelines and also serve
end-user or gathering functions. Our primary transmission systems,
which were acquired in 1997, are the MIT system, located
principally in northern Alabama along the Tennessee River Valley,
and the Midla system, located in Louisiana and Mississippi.
Average daily natural gas transmission volumes increased 84% to
269 Mmcf per day in 1998 from 146 Mmcf per day in 1997. The
Transmission Pipelines segment accounted for $13.2 million or 57%
of our gross margin in 1998.
. End-User Pipelines. We own and operate 20 end-user systems that
provide a direct supply of natural gas to industrial companies,
municipalities or electric generating facilities through
interconnect gas pipelines that we construct or acquire. Some of
our end-user customers include Amoco Chemical Company, Champion
International Corporation, Exxon Chemical Company, Georgia Pacific
Corporation and Owens Corning Corporation. Our average daily end-
user volumes increased 149% to 167 Mmcf per day in 1998 from 67
Mmcf per day in 1997. The End-User Pipelines segment accounted for
$5.0 million or 22% of our gross margin in 1998.
. Gathering Pipelines and Natural Gas Processing. Our 36 gathering
systems typically consist of a network of pipelines that collect
natural gas or crude oil from points near producing wells and
transport it to larger pipelines for further transmission.
Processing revenues are realized from the extraction and sale of
NGLs as well as the sale of the residual gas. Our more significant
gathering and processing assets, which were acquired in 1998 and
1999, include our Anadarko/Mendota system in the Texas Panhandle
and western Oklahoma, the Calmar system in Alberta, Canada, and
Dufour Petroleum, Inc. ("DPI"), an NGL, crude oil and CO\\2\\
trucking and marketing company. Our average daily gathering and
processing volumes increased 215% to 151 Mmcf per day in 1998 from
48 Mmcf per day in 1997. The Gathering Pipelines and Natural Gas
Processing segment accounted for $4.4 million or 19% of our gross
margin in 1998.
We derive revenue from transportation fees for transporting natural gas
and petroleum liquids through our pipelines. In addition, we provide natural
gas marketing services to our customers within each of the three segments.
Although the majority of our business is transportation fee based, we do retain
some exposure to commodity prices in our processing business. This exposure
represents a relatively small proportion of our total gross margin but provides
us with modest upside potential if NGL prices continue to recover from recent
historical lows.
S-27
<PAGE>
Opportunities in Our Industry
The natural gas industry has undergone dramatic change over the past
decade largely due to a series of steps taken by the federal and state
governments to deregulate the industry and increase competition among industry
participants. These actions are causing a major restructuring of the
relationships between interstate pipeline companies, LDCs and their respective
customers and have created opportunities for us to compete for these customers.
We believe that the strategic location of our pipelines, our strong industry
relationships and lower cost structure relative to major interstate carriers
and LDCs position us well to continue to take advantage of this opportunity to
expand our customer base.
As the focus of deregulation has shifted to the electric generating
industry, there has been an increasing convergence of the natural gas and
electric industries. There is also a general trend toward the consolidation of
companies within the natural gas industry. These changes have prompted several
large mergers between and among electric utilities and diversified natural gas
companies. We believe that these combined companies will divest certain of
their natural gas transmission, gathering and processing assets either as a
result of antitrust divestiture requirements or for strategic purposes. As a
result, we believe that these divestitures will create considerable acquisition
opportunities for us and that our industry relationships position us well to
capitalize on these opportunities.
Business Strategy
Our principal business strategy is to increase our 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. We implement this strategy through the following steps:
. Accretive Acquisitions. We seek 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. We target systems in our core
geographic areas of operation in order to capitalize on existing
infrastructure, personnel and customer relationships to maximize
system profitability. We also seek to acquire assets near areas
with growing demand for natural gas or increasing drilling
activity. These acquisitions enable us to establish new core areas
in which to build a regional presence. For example, we purchased
the Anadarko gas gathering system located in Texas and Oklahoma in
September 1998. The 696-mile system and processing plant are
located in a prolific natural gas producing region and established
a new core geographic area for us. We quickly strengthened our
position in this area in December 1998 with the acquisition of the
35-mile Mendota 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. We leverage our 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. We have
recently constructed new facilities at a cost of approximately
$10.0 million near the southern end of the Midla system to
interconnect other systems we had previously acquired. This
project will allow us to provide approximately 55 Mmcf per day of
high pressure natural gas to a Georgia Pacific Corporation plant
and to an Exxon Chemical Company cogeneration facility and allow
us to compete for additional end-user customers in the area.
. Improving Existing System Profitability. After a system is
acquired or constructed, we begin 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, we focus on
providing
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<PAGE>
quality service to our existing customers while identifying new
customers. Many of our existing pipeline and processing systems
were designed with excess throughput capacity that provides us
with opportunities to increase throughput with little incremental
cost and to facilitate higher margin "swing" sales during periods
of increased gas demand. For example, since the purchase of the
MIT system in May 1997, we have increased contracted firm
transportation volumes 29% to 170 Mmcf per day from 132 Mmcf per
day. In addition, we generally seek to achieve administrative and
operational efficiencies by capitalizing on the geographic
proximity of many of our systems.
Acquisition and Construction Activity
From January 1, 1996 through March 31, 1999, we have acquired ownership
of or interests in or constructed 49 pipelines, including four natural gas
processing plants, for an aggregate cost of over $161 million. The following
table summarizes certain information regarding our acquisition and
construction activities:
<TABLE>
<CAPTION>
1999
1996 1997 1998 (3 Mos.) Total
----- ----- ----- -------- -------
<S> <C> <C> <C> <C> <C>
Acquisition Expenditures (in millions)..... $ 8.4 $70.3 $52.1 $31.0 $ 161.8
Pipelines Acquired or Constructed:
Transmission Pipelines.................... -- 2 -- -- 2
End-User Pipelines........................ 6 6 1 -- 13
Gathering Pipelines....................... 17 3 5 9 34
----- ----- ----- ----- -------
Total Number.............................. 23 11 6 9 49
===== ===== ===== ===== =======
Total Miles............................... 402 907 854 171 2,334
Processing and Treating Facilities
Acquired.................................. 1 -- 2 1 4
</TABLE>
MIT Acquisition. Consistent with our business strategy, in May 1997,
Midcoast acquired the pipeline and energy services operations of Atrion
Corporation for cash consideration of $38.2 million and up to $2.0 million in
contingent deferred payments. These operations include (i) a 295-mile
interstate transmission pipeline located in northern Alabama, Mississippi and
southern Tennessee that transports natural gas to industrial and municipal
customers (the "MIT system"), (ii) the 38-mile Champion system and the one-
mile Monsanto system pipeline in northern Alabama which primarily serve these
two large industrial customers and (iii) a natural gas marketing company that
was subsequently merged into Midcoast Marketing Inc. ("MMI").
Midla Acquisition. In October 1997, we completed our acquisition of
Republic, which owned Mid Louisiana Gas Company, Mid Louisiana Gas
Transmission Company and Mid Louisiana Marketing Company, which 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, 481,247 shares of our common stock and warrants to acquire
171,880 shares of common stock. The assets acquired included (i) a 405-mile
interstate gas pipeline that runs from the Monroe gas field in northern
Louisiana, southward through Mississippi to Baton Rouge, Louisiana (the "Midla
system"), (ii) three end-user gas pipelines with a collective length of 40
miles and (iii) two offshore lateral gas pipelines with a collective length of
approximately nine miles. These pipelines serve a number of large industrial
and municipal customers.
As a result of agreements to provide a new source of high-pressure
natural gas for customers in and around the Port Hudson and Baton Rouge area,
we have acquired several pipeline systems and are constructing additional
contiguous pipelines to build the needed infrastructure to meet this demand.
We have estimated the total cost of the project to be approximately $10.0
million. At March 31, 1999, $7.8 million has been incurred in purchase and
construction costs. The remaining expenditures are expected to be incurred no
later than the second quarter of 1999.
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Anadarko Acquisition. In September 1998, we purchased the Anadarko gas
gathering system from a subsidiary of El Paso Energy Corporation. The pipeline
system was purchased for cash consideration of $35.0 million. Under the
agreement, we acquired ownership and operation of the Anadarko gas gathering
system located in Beckham and Roger Mills Counties in Oklahoma, and Hemphill,
Roberts and Wheeler Counties in Texas. The system is comprised of over 696
miles of pipeline and had an average throughput of 158 Mmcf per day from the
date of acquisition through December 31, 1998. The system gathers gas from
approximately 250 wells and includes a 40 Mmcf per day natural gas processing
facility, 11 compressor stations with a total of over 14,000 horsepower and
interconnections with eight major interstate and intrastate pipeline systems.
We expanded the Anadarko system in December 1998 with the acquisition of
the Mendota system from Seagull Energy Corporation for $3.8 million. The
Mendota system, which is interconnected with the Anadarko system, includes a
processing facility and 35 miles of gathering pipeline.
Gloria System and Bruni System Acquisitions. In December 1998, the
Company entered into separate definitive purchase and sales agreements with
Koch Industries to purchase the Gloria pipeline system in southeastern
Louisiana and the Bruni gathering system in south Texas for a combined total
price of $7.5 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 Bruni system is comprised
of 142 miles of pipeline. The system gathers gas from producing wells in the
south Texas region and also provides natural gas supply services to several
municipalities. Both pipelines are presently part of Koch's interstate system
and the FERC must approve the system's abandonment from interstate service and
sale before the transaction can be completed. We intend to operate both
pipelines as intrastate systems.
1999 Acquisitions. During the first quarter of 1999, we consummated $31.0
million in acquisitions as follows:
Calmar Acquisition. We 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
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 approximately 24 Mmcf per day of sour gas from 27 producing wells
operated by Probe and Courage Energy Inc. In conjunction with the
purchase, Probe entered into a gas gathering and treating agreement with
us, including the long-term dedication 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 us of an existing third party gathering and treating
agreement.
DPI and Flare Acquisitions. We purchased two related companies, Flare,
LLC ("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, we assumed
$5.5 million in debt, and the DPI shareholders received 140,574 shares
of our common stock. Flare is a natural gas processing and treating
company whose principal assets include 27 portable natural gas
processing and treating plants from which it earns revenues based on
treating and processing fees and/or a percentage of the NGLs produced.
DPI is an NGL, crude oil and CO\\2\\ 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.
Tinsley Acquisition. We 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.
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SeaCrest Acquisition. We also completed the purchase of a 70% interest
in SeaCrest Company LLC for $1.5 million, which in turn acquired seven
active offshore natural gas gathering pipelines. The gathering pipelines
that SeaCrest acquired from Koch Industries include seven active systems
located offshore in the Gulf of Mexico, south of Louisiana, and comprise
approximately 81 miles of pipeline. These systems gather gas from 23
offshore producing wells with a current total throughput of
approximately 49 Mmcf per day.
Operations
Segments. Beginning in 1998, we segregated our business activities into
three segments: Transmission Pipelines; End-User Pipelines; and Gathering
Pipelines and Natural Gas Processing. Our management analyzes these segments
independently. The segments derive revenue from different sources. For
financial information related to each segment, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Results of
Operations," as well as Note 14 in the notes to our consolidated financial
statements included in this prospectus supplement. Set forth below is a
description of the principal business activities conducted by each of the
segments.
Transmission Pipelines. Our transmission pipelines primarily receive
and deliver natural gas to and from other pipelines and secondarily serve
end-user or gathering functions. We receive transportation fees for
transporting gas owned by other parties through our pipeline systems. We
seek to further expand our activities in this area through the acquisition
or construction of natural gas transmission pipelines in our core geographic
areas of operation where operational synergies and market opportunities
exist or in new geographic regions where there is increasing demand for gas
by municipal and industrial users. As of March 31, 1999, we owned two
interstate and one intrastate transmission pipelines. The Transmission
Pipelines segment accounted for $13.2 million or 57% of our gross margin in
1998.
End-User Pipelines. We also contract with industrial end-users,
municipalities and electrical generating facilities to provide natural
gas and natural gas transportation services to their facilities through
interconnect gas pipelines that we construct or acquire. These pipelines
provide a direct supply of natural gas to new industrial facilities or
to existing facilities as an alternative to the LDCs. We intend to
continue to pursue direct sales to these end-users, which now have the
flexibility to negotiate their gas purchase and transportation contracts
as a result of industry deregulation. Frequently, we are able to offer
our end-user customers rates lower than the customer's current energy
supplier. Our contracts with end-user customers typically provide that
the customer pay a transportation fee based on the volume of natural gas
transported through our pipeline. As of March 31, 1999, we owned 20 end-
user pipelines. The End-User Pipelines segment accounted for $5.0
million or 22% of our gross margin in 1998.
Gathering Pipelines and Natural Gas Processing. Our gathering systems
typically consist of a network of pipelines that 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 us or others. We derive revenues from gathering systems by
transporting natural gas or crude oil owned by others through our
pipelines for a transportation fee, by purchasing natural gas and
utilizing our 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 our pipelines. We typically accomplish transactions
with customers not directly served by our pipelines by entering into
agreements whereby we exchange natural gas in our pipelines for natural
gas in the pipelines of other transmission companies. We intend to
pursue the acquisition or construction of additional gas gathering
systems in or near our core geographic operating areas and where
drilling activity is expected to provide opportunities for the expansion
of gathering or processing facilities. As of March 31, 1999, we owned an
interest in and operated 36 gathering systems. The Gathering Pipelines
and Natural Gas Processing segment accounted for $4.4 million or 19% of
our gross margin in 1998.
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We realize our natural gas processing revenues from the extraction and
sale of NGLs as well as the sale of the residual natural gas. We earn
these revenues 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 we receive a
percentage of the NGLs and residual gas revenues as a fee for processing
the producer's gas. The "keep-whole" contracts require that we reimburse
the producers for the Btu energy equivalent of the NGLs and fuel we
remove from the natural gas as a result of processing, and we retain all
revenues from the sale of the NGLs. Once extracted, the NGLs are further
separated in our facilities into products such as ethane, propane,
butanes, natural gasoline and condensate. These products are then sold
to various wholesalers along with raw sulfur from our sulfur recovery
plant. Our 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 March 31, 1999, we owned
four large capacity processing and/or treating plants and 27 smaller
portable processing plants.
Gas Marketing Services. In addition, we provide natural gas marketing
services to our customers within each of the three segments. We have focused
our gas marketing activities on our systems with a strategic focus on providing
quality and consistent service to customers connected to our pipeline network.
Our marketing activities include providing natural gas supply and sales
services to some of our end-user customers by purchasing the natural gas supply
from other marketers or pipeline affiliates and reselling the natural gas to
the end-user. We also purchase natural gas directly from well operators on many
of our gathering systems and resell the natural gas to other marketers or
pipeline affiliates. Many of the contracts pertaining to our gas marketing
activities are month-to-month, spot market transactions with numerous gas
suppliers or producers in the industry. We also offer other gas services to
some of our customers including management of capacity release and gas
balancing.
Typically, we purchase natural gas at a price determined by prevailing
market conditions. Simultaneously with our purchase of natural gas, we
generally resell natural gas at a higher price under a sales contract that is
comparable in terms to our purchase contract, including any price escalation
provisions. In most instances, small margins are characteristic of natural gas
marketing because there are numerous companies of greatly varying size and
financial capacity who compete with us in the marketing of natural gas. The
profitability of our natural gas marketing operations depends in large part on
the ability of our 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, end-users have been reluctant to enter into long-term
purchase contracts. Moreover, consumers have shown an increased willingness to
switch fuels between gas and alternate fuels in response to relative price
fluctuations in the market. The inability of management to respond
appropriately in changing market conditions could have a negative effect on our
profitability. Accordingly, historical operating income associated with this
revenue stream has varied depending on market conditions. The use of third-
party pipelines in our gas marketing activities also exposes us to economic
risk. This risk results from imbalances or nominated volume discrepancies,
which can result either in penalties having a negative impact on earnings or in
a transaction gain, depending on how and when imbalances are corrected. We
believe the marketing of natural gas is an important complement to our
transportation services.
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Pipeline Systems
As of March 31, 1999, we owned an interest in and operated 59 pipelines.
These include two interstate transmission pipelines, one intrastate
transmission pipeline, 20 end-user pipelines and 36 gathering pipelines. The
majority of these pipelines are situated strategically in our core Gulf Coast
operating area. Certain information concerning our pipelines is summarized in
the following table:
<TABLE>
<CAPTION>
Average Daily
Length Daily Volume
in Volume(2) Capacity(2)
Pipeline System(1) Location Miles (Mmbtu/Day) (Mmbtu/Day)
- ------------------------ ----------------------------- ------- ----------- -----------
<S> <C> <C> <C> <C>
TRANSMISSION PIPELINES:
Magnolia.............. Central AL 111.0 28,447 120,000
MIT................... Selmer, TN to Huntsville, AL 295.3 101,884 200,000
Midla................. Monroe, LA to Baton Rouge, LA 404.6 78,092 190,000
------- ------- ---------
Total Transmission (3
systems)............ 810.9 208,423 510,000
END-USER PIPELINES:
Creole................ Orleans Parish, LA 44.0 32,181 115,000
Farmlands............. Grant Parish, LA 4.3 31,434 62,000
Baton Rouge........... E. Baton Rouge Parish, LA 33.2 26,384 80,000
Champion.............. Lawrence & Colbert Cos., AL 38.0 23,313 50,000
Westlake.............. Calcasieu Parish, LA 1.3 14,209 50,000
Crown Vantage......... West Feliciana Parish, LA 2.5 8,489 32,800
Salt Creek(3)......... Kent & Scurry Cos., TX 39.1 5,437 20,000
Monsanto.............. Morgan Co., AL 1.0 4,432 20,000
OC Kansas............. Wyandotte Co., KS 1.0 2,817 6,500
Roane County(4)....... Roane Co., TN 2.1 1,440 5,000
All Other (10
systems)............. KS, NY, TN, TX 39.1 5,975 107,200
------- ------- ---------
Total End-User (20
systems)............ 205.6 156,111 548,500
GATHERING PIPELINES AND
NATURAL GAS PROCESSING:
Anadarko/Mendota(5)... OK & TX Panhandle 731.0 157,829 345,000
T51................... Offshore LA 4.7 18,126 72,000
Cook Inlet Oil(4)..... Cook Inlet, AK 2.7 17,141(6) 120,000(6)
T33................... Offshore LA 3.9 13,898 24,000
Guerra(3)............. Webb & Duval Cos., TX 8.4 6,485 50,000
Loma Novia(3)......... Duval & McMullen Cos., TX 15.2 6,178 25,000
Harmony(5)............ Central MS 155.4 5,328 20,000
Texana(7)............. South TX 46.0 4,488 15,000
Minnie Bock........... Nueces Co., TX 14.0 2,898 10,000
Calmar(5)............. Alberta, Canada 30.0 N/A(8) 30,000
SeaCrest (7 systems).. Offshore LA 81.3 N/A(8) 397,000
Tinsley............... Yazoo Co., MS 60.0 N/A(8) 180,000(6)
All Other (18
systems)............. AK, AL, KS, MS, OK, TX 309.1 9,792 135,500
------- ------- ---------
Total Gathering (36
systems)............ 1,461.7 242,163 1,423,500
Total Pipelines (59
systems)........... 2,478.2 606,697 2,482,000
======= ======= =========
</TABLE>
- --------
(1) Unless otherwise indicated, all systems are 100% owned and operated by us.
Inactive systems are not included.
(2) All volume and capacity information is approximate. Average daily volumes
are based on total volumes transported during the twelve-month period ended
December 31, 1998, except for systems that were acquired during 1998. For
these systems the average daily volumes are based on total volumes
transported from the date of acquisition or initial operation through
December 31, 1998.
(3) This system is owned by Pan Grande Pipeline L.L.C., in which we own a 70%
interest and which we operate.
(4) This system is owned and operated by a third-party. We receive throughput
charges from this system.
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(5) This gathering system includes natural gas processing and/or treating
facilities.
(6) Volume has been converted from barrels of oil to equivalent Mmbtu of gas
using one barrel to six Mmbtu consistent with industry standards.
(7) This system is owned by Texana Pipeline Company, in which we own a 50%
interest and which we operate.
(8) This system was acquired in March 1999; therefore, there were no applicable
volumes for the period shown.
Marketing and Competition
Major Customers. Our principal customers are industrial end-users,
municipalities, resellers of natural gas and producers of natural gas. We
typically enter into one- to five-year transportation agreements. These
agreements may also include provisions regarding guaranteed minimum volumes and
price reductions after the customer meets certain transportation commitments.
We also enter into marketing agreements with many of our customers that relate
to gas supply and other services. For our FERC regulated entities, we enter
into firm or interruptible transportation contracts, using the tariff rates
approved by FERC. In certain situations, we have offered discounts from our
tariffs in response to specific market conditions.
In 1998, there were no customers that represented in excess of 10% of our
gross margin. For 1997, Champion International Corporation and Entergy Gulf
States, Inc. each contributed in excess of 10% of our gross margin on a pro
forma basis. The agreement with Champion, which expires in 2004, provides for
26 Mmcf per day of firm transportation and a rate reduction of 41% in the event
that Champion meets a minimum transportation volume, which is expected to occur
in 2000 based on Champion's current usage. The agreements with Entergy for
marketing and transportation services expire in 2000 and 1999, respectively.
The marketing agreement provides for volumes that range from 15,000 Mmbtu to
110,000 Mmbtu per day. The transportation agreement provides for volumes that
range from 25,000 Mmbtu to 100,000 Mmbtu per day. Both agreements include
annual evergreen language after the expiration of the primary term.
Competition. Our business is highly competitive. In marketing natural
gas, we have 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 energy and interstate and intrastate pipeline companies, have
financial resources substantially greater than ours. Local utilities and
distributors of natural gas are, in some cases, engaged directly, and through
affiliates, in marketing activities that compete with us. Some of our contracts
are month-to-month arrangements, and, as such, these agreements are affected by
competitive factors at the time of the sale.
We compete against other companies for companies and assets to acquire,
supplies of natural gas and customers. In competing for acquisitions, we
compete against companies with greater resources that may be willing to pay
more for a given acquisition. Competition for companies and assets to acquire
is primarily based on the acquiring company's capital resources and its ability
to complete the acquisition in a timely manner. Competition for customers is
primarily based on efficiency, reliability, availability of transportation and
the ability to offer a competitive price for natural gas. Competition for end-
users is primarily based upon reliability and price of deliverable natural gas.
For customers that have the capability to use alternative fuels, such as oil
and coal, we also compete against companies capable of providing these
alternative fuels at a competitive price.
Natural Gas Supply. Our transmission and end-user pipelines have
connections with major interstate and intrastate pipelines that management
believes have access to natural gas volumes in excess of the volumes required
for these systems. However, these purchase contracts may be affected by factors
such as capacity constraints and temporary regional supply shortages beyond
both our and the gas
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suppliers' control. With regard to our gathering systems, supply risks include
third parties' control of the drilling of new wells, the inability of wells to
deliver gas at required pipeline quality and pressure, and the depletion of
reserves. Our future performance will depend, to a great extent, on the
throughput levels we achieve with respect to our existing pipelines and the
pipelines we acquire or construct in the future. In order to maintain the
throughput on our gathering systems at current levels, we must access new
natural gas supplies to offset the natural decline in reserves. In connection
with the construction and acquisition of our gathering systems, we made
evaluations of well and reservoir data furnished by producers to determine the
availability of natural gas supply for the systems. Based on those evaluations,
management believes that there should be adequate natural gas supply for us to
recoup our investment with an adequate rate of return. However, management does
not routinely obtain independent evaluation of reserves dedicated to our
systems because of the cost of such evaluations. Accordingly, we do not have
estimates of total reserves dedicated to our systems or the anticipated life of
such producing reserves.
Regulatory Matters
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 and Midla
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 and Midla systems must be filed with and
approved by the FERC. They are submitted as cost-based and have been deemed 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 also may 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
were 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.
Intrastate Pipeline Regulation. Our 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
system is 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
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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 (1) have physical custody of or (2) 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.
Canadian Pipeline Regulation. One of our subsidiaries, Midcoast Canada
Operating Corporation ("Midcoast Canada"), 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 Midcoast Canada, 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 matters
and questions involving gas plants and pipelines located within Alberta, such
as the Calmar system.
Gathering Operations Regulation. The NGA exempts gas gathering facilities
from the direct jurisdiction of the FERC. We believe that our 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.
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
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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 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.
Oil and Gas Properties
We own several non-operated working and overriding royalty interests in
producing and non-producing oil and gas properties. For the year ended December
31, 1998, revenues from our oil and gas properties were less than 1% of our
total revenues, and for the same period our oil and gas properties represented
less than 1% of our total assets. Although it is not expected to become a major
line of business for us, management expects that acquisition and ownership of
non-operated oil and gas interests will remain a facet of our business for the
foreseeable future.
Title to Properties
As part of our pipeline construction process, we must obtain certain
right-of-way agreements from landowners whose property the proposed pipeline
will cross. The terms and cost of these agreements can vary greatly due to a
number of factors. In addition, as part of our acquisition process, we 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. We typically rely upon outside
service organizations to review the right-of-way agreements and to make
suggestions to the seller as to
S-37
<PAGE>
any curative work required before closing. We typically do 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, we may seek to initiate condemnation proceedings where
permitted under state law to obtain a right-of-way necessary for pipeline
construction projects. We believe that this process is consistent with
standards in the pipeline industry. We believe that we hold good title to our
pipeline systems, subject only to defects which we believe are not material to
the ownership of our properties or results of operations. Substantially all of
our pipeline systems are pledged to secure borrowings under our credit
facility. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Capital Resources and Liquidity."
Insurance
Our operations are subject to many hazards inherent in the natural gas
transmission industry. We maintain insurance coverage for our operations and
properties at levels considered to be customary in the industry. There can be
no assurance, however, that our insurance coverage will be available or
adequate for any particular risk or loss or that we will be able to maintain
adequate insurance in the future at rates we consider reasonable. Although,
management believes that our assets are adequately covered by insurance, a
substantial uninsured loss could have a material adverse impact on us and our
financial position.
Legal Proceedings
We are currently involved in certain litigation that arose in the
ordinary course of business. 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 or results of operations.
Employees and Contract Service Organizations
We had 232 full-time employees on March 31, 1999. We have arrangements
with other unaffiliated independent pipeline operating companies that service
and operate our extensive field operations and provide for emergency response
measures. We are not a party to any collective bargaining agreements. There
have been no significant labor disputes in the past.
S-38
<PAGE>
MANAGEMENT
The following table sets forth certain information concerning our
directors and executive officers. Each director holds office until the first
annual meeting of stockholders is held after his election or until his
successor is elected or appointed and qualified.
Directors and Executive Officers
<TABLE>
<CAPTION>
Officer or
Name Age Position Director Since
- ------------------------ --- ------------------------------------------- --------------
<S> <C> <C> <C>
Dan C. Tutcher.......... 50 Chairman of the Board, President, and Chief 1992
Executive Officer
I. J. Berthelot, II..... 39 Executive Vice President, Chief Operating 1996
Officer and Director
Richard A. Robert....... 33 Chief Financial Officer and Treasurer 1996
Duane S. Herbst......... 35 Vice President of Corporate Affairs and 1992
Secretary
Ted Collins, Jr......... 60 Director 1997
Curtis J. Dufour, III... 49 Director 1999
Richard N. Richards..... 52 Director 1996
Bruce Withers........... 72 Director 1997
</TABLE>
Dan C. Tutcher has been Chairman of the Board, President and Chief
Executive Officer since our formation in 1992 and served as Treasurer from 1995
to 1996. Since 1989, Mr. Tutcher has also been President and Chief Executive
Officer of Magic Gas Corp., a Texas corporation controlled by Mr. Tutcher.
Prior to its merger into our company in 1992, Mr. Tutcher served as a Director
of Nugget Oil Corporation ("Nugget"), from 1990 to 1992. He also serves on the
Utilities Advisory Board of Cigna Corporation and on the board of the
Interstate Natural Gas Association of America. Mr. Tutcher holds a Bachelors of
Business Administration degree from Washburn University.
I. J. (Chip) Berthelot, II has been a Director since 1996 and serves as
Executive Vice President and Chief Operating Officer. Mr. Berthelot has been
with us since our formation in 1992. Mr. Berthelot joined our company as Chief
Engineer and became Vice President of Operations in 1995, Chief Operating
Officer in 1996 and Executive Vice President in 1997. From 1991 to 1992 he was
a gas contracts representative with Mitchell Energy and Development Co.
("Mitchell Energy"). He is a Professional Engineer, licensed in Texas, and
holds a Bachelors of Science degree in Petroleum and Natural Gas Engineering
from Texas A&I University.
Richard A. Robert is Chief Financial Officer and Treasurer and has been
with us since our formation in 1992. Mr. Robert joined our company as
Controller and became Chief Financial Officer and Treasurer in 1996. From 1988
to 1992 he was an audit associate in the energy audit division of Arthur
Andersen LLP. Mr. Robert is a certified public accountant and is a member of
the Texas Society of Certified Public Accountants. He holds a Bachelors of
Business Administration degree in Accounting from Southwest Texas State
University.
Duane S. Herbst has been Secretary of our company since its formation in
1992 and Vice President of Corporate Affairs since 1996. From April 1992 until
its merger with our company in September 1992, he held the office of President
of Nugget. Since 1989, he has been Vice President of Rainbow Investments
Company. He holds a Masters of Business Administration degree from the
University of Texas and a Bachelors of Science degree in Finance from Trinity
University.
Ted Collins, Jr. has been a Director since 1997. Mr. Collins has served
as President since 1988 of Collins & Ware, Inc., a private corporation active
in oil and gas exploration, production and property acquisition. He served as
President of Enron Oil & Gas Company from 1986 to 1988 and prior to that held
positions as President with HNG/Internorth Exploration Company and HNG Oil
Company as well as Executive Vice President of American Quasar Petroleum
Company. Mr. Collins also serves on the boards
S-39
<PAGE>
of Hanover Compressor Company, Queen Sand Resources, Inc. and Chaparral
Resources, Inc. He graduated from the University of Oklahoma with a Bachelors
of Science degree in Geological Engineering.
Curtis J. Dufour, III has been a Director since March 1999 and serves as
Chief Executive Officer of DPI/Midcoast, Inc., a wholly owned subsidiary of our
company. Prior to its merger with and into our company in 1999, Mr. Dufour
served as President of DPI from 1988 until 1997, and Chief Executive Officer
from 1996 until 1999. DPI was a private corporation engaged in the NGL
marketing and transportation business. Prior to forming DPI, Mr. Dufour served
as President of Choctaw Fuels, Inc., a company engaged in the marketing and
transportation of NGLs from 1978 until 1986. He graduated from the University
of Southern Mississippi with a Bachelor of Science degree in Marketing.
Richard (Dick) N. Richards has been a Director since 1996. Mr. Richards
is currently Director of New Reusable Systems for The Boeing Company. Prior to
1998, he had been with NASA where he served in several capacities since 1980.
Mr. Richards was an astronaut with NASA until 1995 and flew one mission as
pilot and commanded three other space shuttle missions. He also served as
Manager of Space Shuttle Program Integration and Mission Director of the third
Hubble Space Telescope Space Shuttle servicing mission. He holds a Bachelors of
Science degree in Chemical Engineering from the University of Missouri and a
Masters of Science in Aeronautical Systems from the University of West Florida.
Bruce Withers has served as Director since 1997. From August 1991 to
October 1996, Mr. Withers served as Chairman and Chief Executive Officer of
Trident NGL, Inc. and Vice Chairman of Dynegy, Inc., formerly NGC Corporation
("Dynegy"). Dynegy is an aggregator, processor, transporter and marketer of
energy products and services. Prior to joining Dynegy, Mr. Withers served as
President of the Transmission and Processing Division of Mitchell Energy for 17
years. Mitchell Energy is engaged through its subsidiaries in the exploration
for and production of oil and gas, natural gas processing and gas gathering and
transmission. He has also served as President and Chief Operating Officer of
Liquid Energy Corp. and Southwestern Gas Pipeline, two affiliates of Mitchell
Energy. Mr. Withers holds a Bachelors of Science degree in Petroleum and
Natural Gas Engineering from Texas A & I University.
SELLING STOCKHOLDERS
The following table sets forth certain information concerning the
beneficial ownership of common stock by the selling stockholders as of March
31, 1999 and as adjusted to reflect the sale of common stock by each selling
stockholder.
<TABLE>
<CAPTION>
Beneficial Ownership
Beneficial Ownership After this
Before this Offering Offering(1)
-------------------- --------------------
Shares of Shares to Shares of
Name and Address Common Stock Percent be Sold Common Stock Percent
- ---------------------------- ------------ ------- --------- ------------ -------
<S> <C> <C> <C> <C> <C>
Stevens G. Herbst........... 407,496 5.7% 40,000 367,496 3.5%
710 Buffalo, Suite 800
Corpus Christi, Texas 78401
Kenneth B. Holmes, Jr....... 143,387 2.0% 50,000 93,387 *
5210 N.W. Trail
Corpus Christi, Texas 78401
</TABLE>
- --------
* Denotes less than 1%.
(1) Assumes no exercise of underwriters' over-allotment.
S-40
<PAGE>
Stevens G. Herbst received total compensation of $88,566 from the Company
in 1998. This included salary and bonus of $63,250, matching contributions to
the Company's 401(k) Plan of $1,316 and payments under a non-compete agreement
of $24,000. In addition, Rainbow Investments Company, a company solely owned by
Mr. Herbst, received $2,606 under a net revenue interest agreement with us. Mr.
Herbst serves as an officer and director of our principal operating
subsidiaries.
Kenneth B. Holmes, Jr. was our vice president and a director from our
inception in 1992 until 1996 and treasurer from the same period until 1995.
In July 1996, Stevens G. Herbst, Kenneth B. Holmes, Jr. and we entered
into an irrevocable five-year voting proxy agreement. Pursuant to the voting
proxy agreement, all shares of our common stock owned of record and
beneficially by Messrs. Herbst and Holmes will be voted by the trust department
of a banking institution. Pursuant to this agreement, the appointed proxy
holder is empowered and authorized to represent Messrs. Herbst and Holmes and
to vote their shares in the same proportion as all other shares of our common
stock are voted which are held of record and beneficially by stockholders who
are not officers, directors, or affiliates of ours. Messrs. Herbst and Holmes
have retained the power to receive dividends and sell their shares.
Messrs. Herbst and Holmes each have certain piggyback registration rights
with regard to shares of our common stock held by them, so long as the voting
proxy agreement is in place, subject to certain limitations. Should the number
of shares to be registered in any underwritten offering be cut-back by the
underwriter in such registrations, the number of shares offered by both us and
Messrs. Herbst and Holmes will be reduced proportionately. We will bear the
expenses of such registrations of our common stock, except for any underwriting
discounts and commissions.
S-41
<PAGE>
UNDERWRITING
General
We intend to offer our common stock through a number of underwriters.
Merrill Lynch, Pierce, Fenner & Smith Incorporated, CIBC World Markets Corp.
and Prudential Securities Incorporated are acting as representatives of each of
the underwriters named below. Under the terms and conditions set forth in a
purchase agreement among our company, the selling stockholders and the
underwriters, we and the selling stockholders have agreed to sell to each of
the underwriters, and each of the underwriters has severally and not jointly
agreed to purchase from us and the selling stockholders, the number of shares
of our common stock set forth opposite its name below.
<TABLE>
<CAPTION>
Number of
Underwriter Shares
----------- ---------
<S> <C>
Merrill Lynch, Pierce, Fenner & Smith
Incorporated............................................. 1,012,000
CIBC World Markets Corp........................................... 1,012,000
Prudential Securities Incorporated................................ 1,012,000
Banc of America Securities LLC.................................... 72,000
A.G. Edwards & Sons, Inc.......................................... 72,000
Chatsworth Securities LLC......................................... 40,000
Coleman and Company Securities, Inc............................... 40,000
Dain Rauscher Wessels, a division of Dain Rauscher Incorporated... 40,000
Harris Webb & Garrison, Inc....................................... 40,000
Jefferies & Company, Inc.......................................... 40,000
Ladenburg Thalmann & Co. Inc...................................... 40,000
Petrie Parkman & Co., Inc......................................... 40,000
---------
Total........................................................ 3,460,000
=========
</TABLE>
In the purchase agreement, the several underwriters have agreed, under
the terms and conditions set forth in the agreement, to purchase all of the
shares of our common stock being sold under the agreement if any of the shares
of our common stock being sold are purchased. In the event of a default by an
underwriter, the purchase agreement provides that, in certain circumstances,
the purchase commitments of the nondefaulting underwriters may be increased or
the purchase agreement may be terminated.
We and the selling stockholders have agreed to indemnify the underwriters
against some liabilities, including liabilities under the Securities Act, or to
contribute to payments the underwriters may be required as a result of such
liabilities.
The shares of our common stock are being offered by the several
underwriters, subject to prior sale, when, as and if issued to and accepted by
them, subject to approval of certain legal matters by counsel for the
underwriters and other conditions. The underwriters reserve the right to
withdraw, cancel or modify the offer and to reject orders in whole or in part.
Commissions and Dividends
The representatives have advised us and the selling stockholders that the
underwriters propose initially to offer the shares of our common stock to the
public at the public offering price set forth on the cover page of this
prospectus supplement, and to certain dealers at such price less a concession
not in excess of $.50 per share of our common stock. The underwriters may
allow, and such dealers may reallow, a discount not in excess $.10 per share of
our common stock on sales to certain other dealers. After this offering, the
public offering price, concession and discount may be changed.
S-42
<PAGE>
The following table shows per share and total public offering price,
underwriting discount to be paid by us and the selling stockholders to the
underwriters and the proceeds before expenses to us and the selling
stockholders. This information is presented assuming either no exercise or full
exercise by the underwriters of their over-allotment options.
<TABLE>
<CAPTION>
Without With
Per Share Option Option
--------- ----------- -----------
<S> <C> <C> <C>
Public offering price.................... $16.3125 $56,441,250 $64,907,437
Underwriting discount.................... $.88 $3,044,800 $3,501,520
Proceeds, before expenses, to Midcoast
Energy Resources ....................... $15.4325 $52,007,525 $60,016,992
Proceeds to the selling stockholders..... $15.4325 $1,388,925 $1,388,925
</TABLE>
The expenses of the offering, exclusive of the underwriting discount, are
estimated at $400,000 and are payable by us.
Over-allotment Option
We have granted options to the underwriters, exercisable for 30 days
after the date of this prospectus supplement, to purchase up to an aggregate of
519,000 additional shares of our common stock at the public offering price set
forth on the cover page of this prospectus supplement, less the underwriting
discount. The underwriters may exercise these options solely to cover over-
allotments, if any, made on the sale of our common stock offered by this
prospectus supplement. To the extent that the underwriters exercise these
options, each underwriter will be obligated, subject to certain conditions, to
purchase a number of additional shares of our common stock from us
proportionate to the underwriter's initial amount reflected in the foregoing
table.
No Sales of Similar Securities
We, our executive officers, directors and one of our stockholders have
agreed, with certain exceptions, without the prior written consent of Merrill
Lynch on behalf of the underwriters, for a period of 180 days after the date of
this prospectus supplement, not to directly or indirectly:
. offer, pledge, sell, sell short, contract to sell, sell any option or
contract to purchase, purchase any option or contract to sell, grant any
option, right or warrant for the sale of, lend or otherwise dispose of or
transfer any shares of our common stock or securities convertible into or
exchangeable or exercisable for or repayable with our common stock,
whether now owned or thereafter acquired by the person executing the
agreement or with respect to which the person executing the agreement
thereafter acquires the power of disposition, or file a registration
statement under the Securities Act with respect to the foregoing or
. enter into any swap or other agreement that transfers, in whole or in
part, the economic consequence of ownership of our common stock whether
any such swap or transaction is to be settled by delivery of our common
stock or other securities, in cash or otherwise.
Price Stabilization, Short Positions and Penalty Bids
Until the distribution of our common stock offered by this prospectus
supplement is completed, rules of the Securities and Exchange Commission may
limit the ability of the underwriters and certain selling group members to bid
for a purchase our common stock. As an exception to these rules, the
representatives are permitted to engage in certain transactions that stabilize
the price of our common stock. Such transactions consist of bids or purchases
for the purpose of pegging, fixing or maintaining the price of our common
stock.
If the underwriters create a short position in our common stock in
connection with the offering, i.e., if they sell more shares of our common
stock than are set forth on the cover page of this prospectus supplement, the
representatives may reduce that short position by purchasing our common stock
in the open market. The representatives may also elect to reduce any short
position by increasing all or part of the over-allotment option described
above.
S-43
<PAGE>
The representatives may also impose a penalty bid on underwriters and
selling group members. This means that if the representatives purchase shares
in the open market to reduce the underwriters' short position or to stabilize
the price of our common stock, they may reclaim the amount of the selling
concession from the underwriters and selling group members who sold those
shares as part of the offering.
In general, purchases of a security for the purpose of stabilization or
to reduce a short position could cause the price of the security to be higher
than it might be in the absence of such purchases. The imposition of a penalty
bid might also have an effect on the price of our common stock to the extent it
discourages resales of our common stock.
Neither we, the selling stockholders nor any of the underwriters makes
any representation or prediction as to the direction or magnitude of any effect
that the transactions described above may have on the price of our common
stock. In addition, neither we, the selling stockholders nor any of the
underwriters makes any representation that the representatives will engage in
such transactions or that such transactions, once commenced, will not be
discontinued without notice.
LEGAL MATTERS
Certain legal matters relating to the validity of the common stock will
be passed upon by Porter & Hedges, L.L.P., Houston, Texas. Certain legal
matters related to this offering will be passed upon for the underwriters by
Andrews & Kurth L.L.P., Houston, Texas.
EXPERTS
Our consolidated financial statements as of December 31, 1998 and 1997
and for each of the three years in the period ended December 31, 1998 included
in this prospectus supplement have been audited by Hein + Associates LLP,
certified public accountants, as set forth in their report dated March 18,
1999, included in reliance upon the authority of said firm as experts in
accounting and auditing.
S-44
<PAGE>
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Section Page
- -------------------------------------------------------------------------- ----
<S> <C>
Midcoast Energy Resources, Inc.
Consolidated Financial Statements:
Independent Auditor's Report............................................ F-2
Consolidated Balance Sheets, December 31, 1997 and 1998................. F-3
Consolidated Statements of Operations for the Years Ended December 31,
1996, 1997 and 1998.................................................... F-4
Consolidated Statements of Shareholders' Equity for the Years Ended
December 31, 1996, 1997 and 1998....................................... F-5
Consolidated Statements of Cash Flows for the Years Ended December 31,
1996, 1997 and 1998.................................................... F-6
Notes to Consolidated Financial Statements.............................. F-7
Independent Auditor's Report on Schedule................................ F-26
Schedule II............................................................. F-27
Unaudited Condensed Consolidated Balance Sheets as of March 31, 1999.... F-28
Unaudited Condensed Consolidated Statements of Operations for the three
months ended March 31, 1998 and 1999................................... F-29
Unaudited Condensed Consolidated Statement of Shareholders Equity for
the three months ended March 31, 1999.................................. F-30
Unaudited Condensed Consolidated Statements of Cash Flows for the three
months ended March 31, 1998 and 1999................................... F-31
Notes to Unaudited Condensed Consolidated Financial Statements.......... F-32
</TABLE>
F-1
<PAGE>
INDEPENDENT AUDITOR'S REPORT
Board of Directors and Shareholders
Midcoast Energy Resources, Inc.
Houston, Texas
We have audited the accompanying consolidated balance sheets of Midcoast
Energy Resources, Inc., and subsidiaries, as of December 31, 1998 and 1997, and
the related consolidated statements of operations, shareholders' equity and
cash flows for each of the years in the three year period ended December 31,
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 1997, and
the results of their operations and their cash flows for each of the years in
the three year period ended December 31, 1998, in conformity with generally
accepted accounting principles.
HEIN + ASSOCIATES LLP
Houston, Texas
March 18, 1999
F-2
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
December 31,
------------------
1998 1997
-------- --------
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents................................ $ 200 $ 308
Accounts and notes receivable, net of allowance of $92
and $494, respectively.................................. 33,020 27,524
Materials and supplies, at average cost.................. 1,363 1,225
-------- --------
Total current assets................................... 34,583 29,057
-------- --------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities...................... 150,041 90,859
Investment in transmission facilities.................... 1,342 1,341
Natural gas processing facilities........................ 4,917 4,626
Oil and gas properties, using the full-cost method of
accounting.............................................. 1,383 1,344
Other property and equipment............................. 2,872 2,411
-------- --------
160,555 100,581
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION....... (6,308) (3,029)
-------- --------
154,247 97,552
OTHER ASSETS, net of amortization.......................... 2,512 1,429
-------- --------
Total assets........................................... $191,342 $128,038
======== ========
<CAPTION>
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts payable and accrued liabilities................. $ 32,540 $ 25,779
Current portion of long-term debt payable to banks....... 176 199
Short-term borrowing from bank........................... 754 700
Other current liabilities................................ 124 491
-------- --------
Total current liabilities.............................. 33,594 27,169
-------- --------
LONG-TERM DEBT PAYABLE TO BANKS............................ 78,082 28,923
OTHER LIABILITIES.......................................... 2,024 190
DEFERRED INCOME TAXES (Note 8)............................. 10,808 9,613
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES............. 550 692
COMMITMENTS AND CONTINGENCIES (Note 6)
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per share; authorized
25,000,000 shares; issued 7,149,513 and 7,101,663
shares, respectively.................................... 71 71
Paid-in capital.......................................... 80,955 80,681
Accumulated deficit...................................... (11,947) (19,283)
Unearned compensation.................................... (4) (18)
Treasury stock (at cost), 181,125 shares at December 31,
1998.................................................... (2,791) --
-------- --------
Total shareholders' equity............................. 66,284 61,451
-------- --------
Total liabilities and shareholders' equity............. $191,342 $128,038
======== ========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-3
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
<TABLE>
<CAPTION>
For the Year Ended December
31,
-------------------------------
1998 1997 1996
--------- --------- ---------
<S> <C> <C> <C>
OPERATING REVENUES:
Sale of natural gas........................ $ 213,464 $ 100,733 $ 23,547
Transportation fees........................ 13,406 6,693 2,948
Natural gas processing revenue............. 6,761 4,956 2,460
Other...................................... 438 362 460
--------- --------- ---------
Total operating revenues................. 234,069 112,744 29,415
--------- --------- ---------
OPERATING EXPENSES:
Cost of natural gas and transportation
charges................................... 206,950 96,769 23,169
Natural gas processing costs............... 4,052 3,566 1,443
Depreciation, depletion and amortization... 3,197 1,592 818
General and administrative................. 6,283 3,455 1,223
Other...................................... 34 71 189
--------- --------- ---------
Total operating expenses................. 220,516 105,453 26,842
--------- --------- ---------
Operating income......................... 13,553 7,291 2,573
NON-OPERATING ITEMS:
Interest expense........................... (3,247) (1,067) (413)
Minority interest in consolidated
subsidiaries.............................. (58) (222) (197)
Other income (expense), net................ 174 (88) (49)
--------- --------- ---------
Total non-operating items................ (3,131) (1,377) (659)
--------- --------- ---------
INCOME BEFORE INCOME TAXES................... 10,422 5,914 1,914
PROVISION FOR INCOME TAXES:
Current.................................... (114) (150) --
Deferred................................... (1,195) -- --
--------- --------- ---------
Net income............................... 9,113 5,764 1,914
5% CUMULATIVE PREFERRED STOCK DIVIDENDS...... -- -- (23)
--------- --------- ---------
NET INCOME TO COMMON SHAREHOLDERS............ $ 9,113 $ 5,764 $ 1,891
========= ========= =========
EARNINGS PER COMMON SHARE:
Basic...................................... $1.29 $1.13 $.73
========= ========= =========
Diluted.................................... $1.25 $1.10 $.73
========= ========= =========
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING:
Basic...................................... 7,074,372 5,115,169 2,592,694
========= ========= =========
Diluted.................................... 7,298,345 5,251,456 2,597,649
========= ========= =========
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-4
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(In thousands, except share data)
<TABLE>
<CAPTION>
5%
Cumulative
Preferred Common Paid-in Accumulated Unearned Treasury Shareholders'
Stock Stock Capital Deficit Compensation Stock Equity
---------- ------ ------- ----------- ------------ -------- -------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1995... $ 200 $19 $18,820 $(14,775) $(107) $ -- $ 4,157
Shares issued in conjunction
with a financing agreement
with an affiliate........... -- -- 6 -- -- -- 6
Shares issued or vested under
various stock-based
compensation arrangements... -- -- 39 -- 17 -- 56
Redemption of 200,000 shares
of 5% cumulative preferred
stock....................... (200) -- 82 -- -- -- (118)
Sale of 1,250,000 shares of
common stock................ -- 13 7,988 -- -- -- 8,001
Net income................... -- -- -- 1,914 -- -- 1,914
5% cumulative preferred stock
dividends................... -- -- -- (23) -- -- (23)
Common stock dividends, $.06
per share................... -- -- -- (400) -- -- (400)
----- --- ------- -------- ----- ------- -------
Balance, December 31, 1996... $ -- $32 $26,935 $(13,284) $ (90) $ -- $13,593
Shares issued or vested under
various stock-based
compensation arrangements... -- -- -- -- 72 -- 72
Sale of 2,893,750 shares of
common stock................ -- 29 34,024 -- -- -- 34,053
Common stock warrants issued
in conjunction with the
Midla acquisition........... -- 4 9,167 -- -- -- 9,171
10% stock dividend (645,375
shares)..................... -- 6 10,555 (10,565) -- -- (4)
Net income................... -- -- -- 5,764 -- -- 5,764
Common stock dividends, $.24
per share................... -- -- -- (1,198) -- -- (1,198)
----- --- ------- -------- ----- ------- -------
Balance, December 31, 1997... $ -- $71 $80,681 $(19,283) $ (18) $ -- $61,451
Shares issued or vested under
various stock-based
compensation arrangements... -- -- -- -- 14 -- 14
Warrants exercised........... -- -- 274 -- -- -- 274
Net income................... -- -- -- 9,113 -- -- 9,113
Treasury stock purchased..... -- -- -- -- -- (2,791) (2,791)
Common stock dividends, $.24
per share................... -- -- -- (1,777) -- -- (1,777)
----- --- ------- -------- ----- ------- -------
Balance, December 31, 1998... $ -- $71 $80,955 $(11,947) (4) $(2,791) $66,284
===== === ======= ======== ===== ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-5
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1998 1997 1996
-------- -------- -------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income applicable to common shareholders..... $ 9,113 $ 5,764 $ 1,891
Adjustments to arrive at net cash provided by
operating activities--
Depreciation, depletion and amortization........ 3,197 1,592 818
Deferred income taxes........................... 1,195 -- --
Recognition of deferred income.................. (83) (83) (83)
Gain on sale of operating pipeline.............. -- -- (81)
Minority interest in consolidated
subsidiaries................................... 58 222 197
Other........................................... -- 69 9
Changes in working capital accounts--
Increase in accounts receivable................ (4,498) (12,022) (6,575)
Increase in other current assets............... (138) (933) --
Increase in accounts payable and accrued
liabilities................................... 8,325 9,247 6,388
-------- -------- -------
Net cash provided by operating activities..... 17,169 3,856 2,564
-------- -------- -------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions, net of cash acquired............... (52,076) (60,778) (8,363)
Capital expenditures............................. (7,816) (1,410) (1,028)
Sale of operating pipelines...................... -- -- 212
Other............................................ (695) (309) 337
-------- -------- -------
Net cash used in investing activities......... (60,587) (62,497) (8,842)
-------- -------- -------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings............................. 89,159 65,321 9,288
Bank debt repayments............................. (39,969) (39,891) (8,389)
Net proceeds from equity offering................ -- 34,053 8,113
Proceeds from notes payable to shareholders and
affiliates...................................... -- -- 100
Repayments on notes payable to shareholders and
affiliates...................................... -- -- (1,134)
Advances to joint ventures....................... (724) -- --
Financing costs.................................. (588) (504) (120)
Treasury stock purchases......................... (2,791) -- --
Redemption of 5% cumulative preferred stock...... -- -- (118)
Dividends on common stock........................ (1,777) (1,198) (400)
-------- -------- -------
Net cash provided by financing activities..... 43,310 57,781 7,340
-------- -------- -------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS.................................. (108) (860) 1,062
-------- -------- -------
CASH AND CASH EQUIVALENTS, beginning of year...... 308 1,168 106
-------- -------- -------
CASH AND CASH EQUIVALENTS, end of year............ $ 200 $ 308 $ 1,168
======== ======== =======
SUPPLEMENTAL DISCLOSURES:
CASH PAID FOR INTEREST........................... $2,135 $706 $411
======== ======== =======
CASH PAID FOR INCOME TAXES....................... $311 $241 $40
======== ======== =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-6
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Background and Information:
Midcoast Energy Resources, Inc. ("Midcoast" or "the Company") was formed
on May 11, 1992, as a Nevada corporation and, in September 1992, became the
successor to Nugget Oil Corporation. The merger was accounted for as a pooling
of interests.
2. Summary of Significant Accounting Policies:
Basis of Presentation
The accompanying consolidated financial statements include the accounts
of the Company, all of its wholly owned subsidiaries and those subsidiaries in
which the Company owns a controlling interest or is in a control position. As
of December 31, 1998, the Company's wholly-owned subsidiaries include Magnolia
Pipeline Corporation, Magnolia Resources, Inc., Magnolia Gathering, Inc., H&W
Pipeline Corporation, Midcoast Holdings No. One, Inc., Midcoast Marketing, Inc.
("MMI"), Midcoast Gas Pipeline, Inc., Nugget Drilling Corporation, Midcoast
Interstate Transmission, Inc. ("MIT"), Tennessee River Interstate Gas Company,
Inc., Mid Louisiana Gas Company ("MLGC"), Mid Louisiana Gas Transmission
Company ("MLGT"), Creole Gas Pipeline Corporation, Midcoast Energy Marketing
Inc., Midcoast Gas Services, Inc. ("MGSI"), and Midcoast Del Bajio S. de R.L.
de C.V. The consolidated subsidiaries in which the Company owns a controlling
interest or is in a control position are Starr County Gathering System, a Joint
Venture ("Starr County"), Pan Grande Pipeline, L.L.C., a Texas limited
liability company ("Pan Grande"), and Arcadia/Midcoast Pipeline of New York,
L.L.C., a New York limited liability company. The Company does not own a
controlling interest in Texana Gas Pipeline Company; therefore, this investment
is accounted for under the equity method of accounting.
All significant intercompany transactions and balances have been
eliminated. Certain amounts for 1997 and 1996 have been reclassified in the
accompanying consolidated financial statements to conform to the current year
presentation. The number of shares and price per share amounts have been
restated for all periods presented to reflect the ten percent stock dividend in
March 1998 and the five-for-four stock split in March 1999 (see Note 7 --
Capital Stock).
Use of Estimates
The preparation of the Company's consolidated financial statements in
conformity with generally accepted accounting principles requires the Company's
management to make estimates and assumptions that effect the amounts reported
in these financial statements and accompanying notes. Actual results could
differ from those estimates.
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.
F-7
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Regulated Pipelines
MIT and MLGC are subject to the provisions of Statement of Financial
Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain
Types of Regulation." Regulatory assets represent probable future revenue to
MIT and MLGC associated with certain costs which will be recovered from
customers through the regulatory, or the rate making process. MIT and MLGC had
no material regulatory assets or liabilities as of December 31, 1998.
The Federal Energy Regulatory Commission ("FERC") regulates the
interstate transportation and certain sales of natural gas, including among
other things, rates and charges allowed natural gas companies, extensions and
abandonment of facilities and service, rates of depreciation and amortization
and certain accounting methods utilized by MIT and MLGC.
Property, Plant and Equipment
Interstate and intrastate natural gas transmission, distribution and
processing facilities and other equipment are 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>
Interstate natural gas transmission facilities................... 15--66.0 Years
Intrastate natural gas transmission facilities................... 15--60.0 Years
Pipeline right-of-ways........................................... 17.5 Years
Natural gas processing facilities................................ 30.0 Years
Other property and equipment..................................... 3--10.0 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"). Provisions for AFUDC are not material, and
accordingly, are not presented separately in the accompanying consolidated
statements of operations. Maintenance and repairs, including the cost of
renewals of minor items of property, are charged principally to expense as
incurred. Replacements of property (exclusive of minor items or property) are
charged to the appropriate property accounts. Upon retirement of a pipeline
plant asset, its cost is charged to accumulated depreciation together with the
cost of removal, less salvage value.
For all other non-regulated assets, repairs and maintenance are charged
to expense as incurred; renewals and betterments, including any direct labor,
are capitalized.
At December 31, 1998, the Company had $8.5 million in construction in
progress and for the year ended December 31, 1998 the Company capitalized
interest costs of $.1 million. No interest was capitalized in 1997 or 1996.
The Company accounts for its oil and gas production activities using the
full cost method. Under this method, 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.
Cash and Cash Equivalents
For purposes of the statement of cash flows, the Company considers short-
term, highly liquid investments that have an original maturity of three months
or less at the time of purchase to be cash equivalents.
F-8
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Transportation and Exchange Gas Imbalances
In the course of providing transportation and exchange services to
customers, natural gas pipelines may receive different quantities of gas from
shippers than the quantities delivered on behalf of those shippers. These
transactions result in transportation and exchange gas imbalance receivables
and payables that are settled through cash-out procedures specified in each
tariff or recovered or repaid through the receipt or delivery of gas in the
future. Such imbalances are recorded as current assets or current liabilities
on the balance sheet using the posted index prices of the applicable FERC-
approved tariffs, which approximate market rates. Transportation and exchange
gas imbalances were not material as of December 31, 1998 and 1997.
Deferred Contract Costs
Costs incurred to construct natural gas transmission facilities pursuant
to long-term natural gas sales or transportation contracts, which upon
completion of construction are assigned to the contracting party, are
capitalized as deferred contract costs and classified as "Other Assets" on the
consolidated balance sheet. These costs are amortized over the life of the
initial contract on a straight-line basis.
Hedging Activities
The Company's policy is 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. Midcoast uses
futures and options with maturities of eighteen months or less to hedge against
the volatility of the price of natural gas purchases and sales. The financial
derivatives have pricing terms indexed to both the New York Mercantile Exchange
("NYMEX") and Kansas City Board of Trade ("KBOT") futures contract. Derivatives
held for hedging activities are not recorded on the balance sheet. Derivative
settlements are recorded as a gain or loss in operating income and cash inflows
and outflows are recognized in operating cash flows as the settlements of the
transactions occur. For a further discussion of the Company's hedging
activities see Note 13--Financial Instruments and Price Risk Management
Activities.
Stock Issuance Costs
Direct costs incurred by the Company in connection with its offering of
securities (see Note 7--Capital Stock) were applied as a reduction of the
offering proceeds.
Revenue Recognition
Customers are invoiced and the related revenue is recorded as natural gas
deliveries are made. Pipeline sales are recognized upon closing the sale
transaction. Oil and gas revenue from the Company's interests in producing
wells is recognized as oil and gas is produced from those wells.
Impairment of Long-Lived Assets
In accordance with Financial Accounting Standards Board ("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. No impairment losses have
been recorded by the Company.
F-9
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 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.
Recent Accounting Pronouncements
The FASB issued SFAS No. 130, "Reporting Comprehensive Income" and SFAS
No. 131, "Disclosures About Segments of an Enterprise and Related Information".
SFAS No. 130 establishes standards for reporting and display of comprehensive
income, its components and accumulated balances. Comprehensive income is
defined to include all changes in equity except those resulting from
investments by owners and distribution to owners. Among other disclosures, SFAS
No. 130 requires that all items that are required to be recognized under
current accounting standards as components of comprehensive income be reported
in a financial statement that displays with the same prominence as other
financial statements. SFAS No. 131 supersedes SFAS No. 14, "Financial Reporting
for Segments of a Business Enterprise". SFAS No. 131 establishes standards on
the way that public companies report financial information about operating
segments in annual financial statements and requires reporting of selected
information about operating segments in interim financial statements issued to
the public. It also establishes standards for disclosures regarding products
and services, geographic areas and major customers. SFAS No. 131 defines
operating segments as components of a company about which separate financial
information is available that is evaluated regularly by the chief operating
decision maker in deciding how to allocate resources and in assessing
performance.
The Company has 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 segment, End-User Pipeline segment, and
Gathering Pipelines and Natural Gas Processing segment.
The FASB also 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. This Statement is effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. SFAS 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. However, the Company does not believe the
effect of adopting SFAS 133 will be material to its financial position.
F-10
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
3. Pipeline Acquisitions and Construction:
The MIT Acquisition
In May 1997, Midcoast acquired the pipeline and energy services
operations from Atrion Corporation ("Atrion") for cash consideration of $38.2
million and up to $2 million in contingent deferred payments (the "MIT
Acquisition"). The 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
(the "MIT System"), (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
initially funded through the Company's existing credit facility. Subsequently,
the proceeds from the Company's common stock offering in July 1997 were used to
retire the indebtedness incurred on the MIT Acquisition.
The MidLa Acquisition
In October 1997, the Company completed its merger of Republic Gas
Partners L.L.C. ("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, 481,247 shares of Midcoast common stock,
par value $.01 per share ("Common Stock"), and warrants to acquire 171,880
shares of Common Stock (the "Midla Acquisition"). The assets acquired included
(i) a 405 mile interstate gas pipeline which runs from the Monroe gas field in
northern Louisiana, southward through Mississippi to Baton Rouge, Louisiana
("Midla System"), (ii) three end-user gas pipelines with a collective length of
40.0 miles and (iii) two offshore lateral 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.
As a result of agreements to provide a new source of high-pressure
natural gas for customers in and around the Port Hudson and Baton Rouge area,
the Company has acquired several pipeline systems and is constructing
additional contiguous pipelines to build the needed infrastructure to meet this
demand (the "Baton Rouge Expansion"). The Company has estimated the total cost
of the project to be $10.0 million. At December 31, 1998, $6.3 million has been
incurred in purchase and construction costs. The remaining expenditures are
expected to be incurred no later than the second quarter of 1999 and will be
funded through the Company's 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
("Anadarko Acquisition"). 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 effective August 1,
1998. 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 ("Anadarko
System"). The system gathers 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.
F-11
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The Company's 1998 operating revenues, net income applicable to common
shareholders, and basic and diluted earnings per common share on an unaudited
pro forma basis are $240 million, $8.9 million, $1.26 and $1.22, respectively.
The Company's 1997 operating revenues, net income applicable to common
shareholders, and basic and diluted earnings per common share on an unaudited
pro forma basis are $140 million, $5.4 million, $1.06 and $1.04, respectively.
The pro forma amounts are based on estimates and assume the Anadarko
Acquisition and $35 million in debt financing occurred as of the beginning of
the respective years. The pro forma combined results presented are not
necessarily indicative of actual results that would have been achieved had the
acquisitions occurred at the beginning of 1998 or the beginning of 1997.
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.
For further information regarding the Anadarko Acquisition, refer to the
Company's Form 8-K and 8-KA filed on September 22, 1998 and November 20, 1998.
1999 Activity
During 1999, the Company has completed several acquisitions totaling
$32.3 million. These acquisitions include the purchase of a majority interest
in SeaCrest Company LLC, the Tinsley crude oil gathering system, the
acquisition of Dufour Petroleum Inc. and Flare, LLC. and the Calmar natural gas
gathering system and treating plant. For additional information, see Note 17--
Subsequent Events.
The Company utilized the purchase method of accounting to record all of
its acquisitions. No goodwill arose from these transactions.
4. Debt Obligations:
At December 31, 1998 and 1997, the Company had outstanding debt
obligations as follows (in thousands):
<TABLE>
<CAPTION>
December 31,
----------------
1998 1997
------- -------
<S> <C> <C>
Note payable by Starr County to a bank under a term loan
bearing interest at the prime rate plus 1%(8.75% at December
31, 1998)(a) ............................................... $ -- $ 31
Note payable by Pan Grande to a bank under a term loan
bearing interest at the prime rate plus 1% (8.75% at
December 31, 1998), 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)..................................................... 258 425
Revolving credit line with a bank under a $100 million
promissory note (see following discussion)(c)............... 78,000 28,666
Revolving credit line with a bank for working capital needs
under a $100 million promissory note bearing interest at the
prime rate less .25%(7.5% at December 31, 1998)............. 754 700
------- -------
Total debt................................................. 79,012 29,822
Less current portion......................................... (930) (899)
------- -------
Total long-term debt....................................... $78,082 $28,923
======= =======
</TABLE>
- --------
(a) In January 1996, Starr County, in which Midcoast owns a 60% interest and
acts as manager, obtained $175,000 from a bank lender to finance the
acquisition of a gas gathering pipeline. The loan was secured by the
pipeline and related contracts. The note was retired in the first quarter
of 1998.
F-12
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
(b) In March 1996, Pan Grande obtained $800,000 from a bank to partially
finance the acquisition of six pipelines. The loan is secured by the
pipelines and related contracts. Furthermore, members of Pan Grande have
guaranteed the loan in an amount equal to their respective ownership
interest.
(c) In September 1998, the Company amended and restated its bank financing
agreement with Bank One Texas, N.A. ("Bank One"). Amendments to the bank
financing agreement (the "Credit Agreement") were entered into which
increased the Company's borrowing availability, modified the Letter of
Credit facility, established a credit sharing, 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 amendments to the Credit Agreement increased the Company's borrowing
availability from $80.0 million to $150.0 million (with an initial committed
amount of $100 million). The amended Credit Agreement provides borrowing
availability as follows: (i) up to a $15.0 million sublimit for the issuance of
standby and commercial letters of credit and (ii) the difference between the
$100 million and the used sublimit available as a Revolver. Effective September
8, 1998, at the Company's option, borrowings under the amended Credit Agreement
will accrue interest at London Inter-bank Offer Rate ("LIBOR") plus 1.25% or
the Bank One base rate less .25%. These rates reflect a .25% reduction in both
the LIBOR and Bank One base rate option. Finally, the amended Credit Agreement
eliminated escalations of the interest rate spread when borrowings exceed 50%
of the borrowing base.
Under the amended Credit Agreement, a credit sharing has been established
among Bank One, CIBC Oppenheimer, Texas N.A. ("CIBC"), NationsBank Texas, N.A.
("NationsBank"), collectively the "Lenders" and the Company. The Company is
subject to an initial facility fee of $495,000 which represents 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 will remain at .375%.
Additionally, the Company is subject to an annual administrative agency fee of
$35,000.
In addition, the Credit Agreement is secured by all accounts receivable,
contracts, the pledge of all the Company's subsidiaries' stock and a first lien
security interest in the Company's pipeline systems. The Credit Agreement
contains a number of customary covenants that require the Company to maintain
certain financial ratios, and limit the Company's ability to incur additional
indebtedness, transfer or sell assets, create liens, or enter into a merger or
consolidation. Midcoast was in compliance with such financial covenants at
December 31, 1998.
In March 1999, the Company amended the Credit Agreement to increase the
committed amount of borrowing availability to $125 million and to allow for
Canadian dollar denominated loans. See Note 17--Subsequent Events for
additional information.
In an effort to mitigate interest rate fluctuations exposure, the Company
has entered into two separate swap agreements which effectively converts $65
million of floating rate debt to fixed rate debt (See Note 13--Financial
Instruments and Price Risk--Management Activities).
F-13
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The aggregate maturities of long-term debt at December 31, 1998 are as
follows:
<TABLE>
<CAPTION>
As of December 31, (In thousands)
------------------ -------------
<S> <C>
1999....................................................... $ 176
2000....................................................... 82
2001....................................................... --
2002....................................................... 78,000
-------
Total...................................................... $78,258
=======
</TABLE>
5. Related Party Transactions:
In April 1994, affiliates owned by former officers and directors of the
Company extended collateral needed to obtain long-term bank financing for the
Cook Inlet pipelines. The collateral was outstanding for a period of
approximately eight months at which point the Company replaced the loan with
another commercial lender and the collateral was released. In consideration for
extending the collateral on the initial loan, the Company assigned a five
percent net revenue interest on the net income derived from the Company's
investment in the oil and natural gas gathering pipelines near Cook Inlet,
Alaska. The five percent override on the net revenue interest became effective
in 1998, after all costs associated with the investment were recaptured by the
Company. As of December 31, 1998, approximately $2,600 has been paid under the
assignment of the net revenue interest to a related party.
6. Commitments and Contingencies:
Acquisition Contingency
In December 1998, the Company entered into separate definitive purchase
and sales agreements with Koch Gateway Pipeline Company ("Koch") to purchase
the Gloria pipeline system in southeastern Louisiana and the Bruni gathering
system in south Texas for a combined total price of $7,525,000. The Gloria
system is comprised of approximately 133 miles of gathering pipeline located in
south Louisiana. The system gathers gas from seven producing fields and also
directly supplies natural gas to an industrial customer and a local
distribution company in the area. The Bruni system is comprised of 142 miles of
gathering pipeline located in south Texas. The system gathers gas from
producing wells in the region and also provides natural gas supply services to
several municipalities. Both pipelines are presently part of Koch's interstate
system and the FERC must approve the system's abandonment from interstate
service and sale before the acquisition can be consummated.
Employment Contracts
Certain executive officers of the Company have entered into employment
contracts which, through amendments, provide for employment terms of varying
lengths the longest of which expires in April 2001. These agreements may be
terminated by mutual consent or at the option of the Company for cause, death
or disability. In the event termination is due to death, disability or defined
changes in the ownership of the Company, the full amount of compensation
remaining to be paid during the term of the agreement will be paid to the
employee or their estate, after discounting at 12% to reflect the current value
of unpaid amounts.
Leases
The Company incurred net lease expenses of $.3 million, $.1 million, and
$.1 million, during the years ended 1998, 1997 and 1996, respectively. As of
December 31, 1998, future minimum lease payments due under these leases are
approximately $.2 million, $.2 million, $.1 million and $.1 million for the
years ended December 31, 1999, 2000, 2001 and 2002, respectively.
F-14
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
MIT Acquisition Contingency
As part of the MIT Acquisition, the Company has agreed to pay additional
contingent annual payments to Atrion, which will be treated as deferred
purchase price adjustments, not to exceed $250,000 per year. The annual payment
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. At December 31, 1998, the Company has
accrued $187,500 as an additional purchase price adjustment.
Midla Acquisition Contingency
In conjunction with the Midla Acquisition, the Company agreed that if a
specific contract with a third party was executed prior to October 2, 1999,
which included specific provisions regarding price and throughputs, Midcoast
would be obligated to issue 137,500 warrants to the former owners of Republic
to acquire Midcoast 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 the former owners of Republic. As
of December 31, 1998, none of the provisions of this contingency have been met.
7. Capital Stock:
Common Stock
In August 1996, the Company sold 1,375,000 shares of its Common Stock at
an offering price of $7.27 per share. Proceeds of $8.8 million, net of issuance
costs, were received by the Company. The proceeds were used to repay
indebtedness with the remainder applied to acquisitions of pipelines and
related assets.
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 approximately $34
million, net of issuance costs, were received and used to repay borrowings on
indebtedness incurred on the MIT Acquisition.
In May 1998, the Board of Directors ("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 10,000,000 to 25,000,000 shares and to authorize 5,000,000 shares of
preferred stock, par value $.001 per share ("Preferred Stock").
The Company has five million shares of Preferred Stock authorized, none
of which are outstanding as of December 31, 1998. The preferred stock may be
issued in multiple series with various terms, as authorized by the Board. The
Company has 25 million shares of Common Stock authorized, of which 7,149,513
shares were issued and outstanding as of December 31, 1998. In connection with
the five-for-four stock split discussed below, the Company filed a Certificate
of Stock Split in March 1999 to increase the authorized shares of Common Stock
to 31.25 million shares.
Treasury Stock
In March 1998, the Board authorized the repurchase of the Company's
outstanding shares of Common Stock to be used for specific corporate purposes.
During 1998, the Company repurchased 181,125 common shares at a weighted-
average price of $15.41 per share. In March 1999, the Company issued 140,574
shares of treasury stock in connection with an acquisition (see Note 17--
Subsequent Events).
F-15
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
All presentations herein are made on a post-dividend and post-split
basis.
Warrants
In February 1996, the Company issued warrants to purchase 47,231 shares
of the Company's Common Stock at $5.71 per share, and all were exercised in
1998. These warrants were issued in connection with the Company's August 1996
Common Stock offering.
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, 1998, none of these warrants have 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, 1998, none of these
warrants have been exercised.
8. Income Taxes:
The Company has net operating loss ("NOL") carryforwards of approximately
$16.6 million, expiring in various amounts from 1999 through 2011. These loss
carryforwards were generated by the Company's predecessor and Republic. The
ability of the Company to utilize the carryforwards is dependent upon the
Company generating sufficient taxable income and will be affected by annual
limitations (currently estimated at $4.9 million) on the use of such
carryforwards due to a change in shareholder control under the Internal Revenue
Code triggered by the Company's July 1997 Common Stock offering and the change
of ownership created by the Midla Acquisition.
F-16
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The tax effect of significant temporary differences representing deferred
tax assets and liabilities at December 31, 1998 and 1997, are as follows (in
thousands):
<TABLE>
<CAPTION>
December 31,
------------------
1998 1997
-------- --------
<S> <C> <C>
NOL carryforwards.......................................... $ 5,644 $ 5,756
Investment tax credit carryforwards........................ -- 108
Alternative minimum tax credit............................. 420 94
Financial basis of assets in excess of tax basis........... (12,318) (10,990)
Valuation allowance........................................ (4,554) (4,581)
-------- --------
Net deferred tax liabilities............................. $(10,808) $ (9,613)
======== ========
</TABLE>
The valuation allowance declined $27,000 in the year ended December 31,
1998. The decline was the net result of current year utilization of net
operating losses to offset taxable income, the adjustment of the net operating
loss carryforward and related valuation allowance acquired in connection with
the 1997 merger with Republic, and the removal of $1.1 million 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,
-----------------------
1998 1997 1996
------- ------- -----
<S> <C> <C> <C>
Federal tax computed at statutory rate................. $ 3,543 $ 1,960 $ 643
Utilization of net operating loss carryforwards........ (1,145) (1,810) (643)
Reduction in valuation allowance....................... (1,089) -- --
------- ------- -----
Actual provision....................................... $ 1,309 $ 150 $ --
======= ======= =====
</TABLE>
9. Major Customers:
For the years ended December 31, 1998, 1997 and 1996, the Company derived
12% of total revenue from a new customer in 1998, 12% from a new customer in
1997, and 31% and 15% of total revenue from two customers in 1996.
10. Concentration of Credit Risk:
The Company derives revenue from commercial companies located in Alabama,
Alaska, Kansas, Louisiana, Mississippi, New York, Oklahoma, Tennessee and
Texas. Two of Midcoast's largest customers account for 15% or approximately
$5.1 million of the outstanding accounts receivable at December 31, 1998. These
accounts receivable were subsequently collected under normal credit terms and
the Company believes that future accounts receivable with these companies will
continue to be collected under normal credit terms based on previous
experience. The Company performs ongoing evaluations of its customers and
generally does not require collateral. The Company assesses its credit risk and
provides an allowance for doubtful accounts for any accounts that it deems
doubtful of collection. At December 31, 1998, $92,000 was reserved as a
provision for doubtful accounts.
The Company periodically maintains cash balances with banks exceeding the
amounts insured by the Federal Deposit Insurance Corporation ("FDIC"). As of
December 31, 1998, none of the Company's cash balances with banks exceeded FDIC
limits. At December 31, 1998 and 1997 the
F-17
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
Company had no cash or cash equivalents under repurchase agreements originated
by the Company's bank under an arrangement whereby collected balances held in
the Company's main operating account are invested overnight.
The derivative financial instruments utilized by the Company in its
hedging activities include NYMEX and KBOT futures and option contracts that are
guaranteed by their respective exchange and have nominal risk. The change in
market value of futures and option contracts requires daily cash settlement in
margin accounts with brokers. At December 31, 1998, the Company had $181,000 in
margin cash accounts to service these derivative financial instruments. Swap
contracts and most other over-the-counter instruments are generally settled at
the expiration of the contract term. The Company is exposed to credit risk in
the event of nonperformance by a counterparty. For each counterparty, the
Company analyzes its financial condition prior to entering into the agreement,
establishes credit limits and monitors the appropriateness of these limits on
an ongoing basis.
11. Employee Benefits:
The Company issued a total of 87,096 and 35,760 shares of Common Stock to
certain key employees in 1995 and 1996, respectively. Of the shares issued in
1996, 12,266 were issued in connection with employment agreements with certain
employees and vest in equal amounts over a three-year period. The shares were
valued at the estimated fair market value on the date of issuance. Compensation
expense is being recognized ratably over the vesting period.
In December 1996, the Company established a defined contribution 401(k)
Profit Sharing Plan for its employees. The plan provides participants a
mechanism for making contributions for retirement savings. Each participant may
contribute certain amounts of eligible compensation. The Company made a
matching contribution to the plan of approximately $83,000 and $81,000 for the
years ended December 31, 1998 and 1997, respectively.
In October 1998, the Board approved an Employee Stock Purchase Plan
("ESPP"), subject to shareholder approval at the Company's 1999 annual
shareholders meeting. The purpose of the ESPP, as amended, is to permit Company
employees to purchase Common Stock on a monthly basis at a 15% discount to 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,
1998, all shares purchased under the plan have been acquired on the open market
and the Company has recognized $3,000 of compensation expense in connection
with the ESPP.
12. Stock Option Plans:
The Company has two stock option plans: the 1996 Incentive Stock Plan
(the "Incentive Plan") and the 1997 Non-Employee Director Stock Option Plan
(the "Director's Plan").
In May 1996, the Board adopted the Incentive Plan, which was subsequently
approved by the Company's shareholders in May 1997. All employees, including
officers (whether or not directors) and consultants of the Company and its
subsidiaries are currently eligible to participate in the Incentive Plan.
Persons who are not in an employment or consulting relationship with the
Company or any of its subsidiaries, including non-employee directors, are not
eligible to participate in the Incentive Plan. Under the Incentive Plan, as
amended in May 1998, the Compensation Committee may grant incentive awards with
respect to a number of shares of Common Stock that in the aggregate do not
exceed 531,250 shares of Common Stock, subject to adjustment upon the
occurrence of certain recapitalizations of the Company.
F-18
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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.
Transactions with regard to incentive stock options issued pursuant to
the Plan are as follows:
<TABLE>
<CAPTION>
Weighted
Total Average
Shares Price
Under Per
Option Share
------- --------
<S> <C> <C>
Balance--January 1, 1997...................................... -- $ --
Granted....................................................... 295,627 8.65
Canceled/Forfeited............................................ -- --
Exercised..................................................... -- --
------- ------
Balance--December 31, 1997.................................... 295,627 $ 8.65
Granted....................................................... 148,125 16.66
Canceled/Forfeited............................................ (1,250) 16.80
Exercised..................................................... (688) 7.64
------- ------
Balance--December 31, 1998.................................... 441,814 $11.32
======= ======
</TABLE>
The following table summarizes information about fixed stock options
outstanding at December 31, 1998:
<TABLE>
<CAPTION>
Options Outstanding Options Exercisable
----------------------- --------------------
Weighted
Average
Remaining Weighted
Range of Years of Average Average
Exercise Number Contractual Exercise Number Exercise
Prices Outstanding Life Price Exercisable Price
-------- ----------- ----------- -------- ----------- --------
<S> <C> <C> <C> <C> <C>
$ 7.64 140,939 8.10 $ 7.64 28,188 $ 7.64
8.40 78,375 3.10 8.40 15,675 8.40
10.50 72,875 8.42 10.50 41,938 10.50
15.40 14,375 9.74 15.40 -- 15.40
16.60 3,125 9.92 16.60 -- 16.60
16.80 129,375 9.29 16.80 -- 16.80
19.36 2,750 8.81 19.36 550 19.36
------- ---- ------ ------ ------
441,814 7.69 $11.32 86,351 $ 9.24
------- ---- ------ ------ ------
</TABLE>
F-19
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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, 68,750 shares of the Company's Common Stock are reserved for
issuance. In February 1999, the Board approved an amendment to the Director
Plan which increased the shares reserved for issuance from 68,750 to 150,000
subject to shareholder approval.
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,
1998, 40,000 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 $13.71 per share.
The Company applies APB Opinion No. 25, "Accounting for Stock Issued to
Employees," and related Interpretations in accounting for its plans.
Accordingly, no compensation cost has been recognized for its stock option
plans. Had compensation expense for the Company's stock-based compensation
plans been determined based on the Black Scholes option pricing model with the
following assumptions used for grants: risk-free interest rates ranging from of
4.67% and 5.84%; expected volatility of 36.29%; expected life of 7 years for
employees and 2 years for directors; and a dividend yield of 0.4%, the
Company's net income and earnings per common share would have been decreased to
the pro forma amounts indicated below:
<TABLE>
<CAPTION>
For The Year Ended
December 31,
---------------------
1998 1997
---------- ----------
<S> <C> <C>
Net income:
As reported............................................ $9,113,018 $5,764,451
Pro forma.............................................. $8,316,584 $5,686,133
Earnings per common share (basic):
As reported............................................ $ 1.29 $ 1.13
Pro forma.............................................. $ 1.18 $ 1.11
Earnings per common share (diluted):
As reported............................................ $ 1.25 $ 1.10
Pro forma.............................................. $ 1.14 $ 1.08
</TABLE>
13. Financial Instruments and Price Risk Management Activities
Fair Value of Financial Instruments
As of December 31, 1998 and 1997, 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 is 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
F-20
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 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. The futures and
options contracts have pricing terms indexed to both the New York Mercantile
Exchange and Kansas City Board of Trade.
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 fixed price and the actual price of
natural gas. The Company uses futures and swaps to manage margins on offsetting
fixed-price purchase or sales commitments for physical quantities of natural
gas. Options held to hedge risk provide the right, but not the obligation, to
buy or sell energy commodities at a fixed price. The Company utilizes options
to manage margins and to limit overall price risk exposure.
The gains, losses and related costs of the financial instruments that
qualify as a hedge are not recognized until the underlying physical transaction
occurs. At December 31, 1998, the Company had unrealized losses from such
hedging contracts of $896,000. 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,
--------------
1998 1997
------- -----
<S> <C> <C>
Market Value -- Unrealized
Gain/(Loss):
Swap contracts................................................ $ (695) $ --
Futures contracts............................................. (178) (78)
Options contracts............................................. (23) (3)
Notional Contract Amount:
Swap contracts................................................ $11,729 $ --
Futures contracts............................................. 683 924
Options contracts............................................. 23 252
Notional Contract Quantity (Mmbtu):
Swap contracts................................................ 5,606 --
Futures contracts............................................. 270 390
Options contracts............................................. 120 1,320
</TABLE>
F-21
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 1.25% (See Note 4 --
Debt Obligations). In an effort to mitigate interest rate fluctuation exposure,
the Company has entered into $65 million dollars of interest rate swaps under
two separate swap agreements. 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 NationsBank
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 Midcoast with a new
two year termination date of December 2000 which may, however, be extended
through December 2003 at NationsBank'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 Midcoast is obligated to reimburse NationsBank when
the three-month LIBOR rate is reset below 5.09%. Conversely, NationsBank is
obligated to reimburse Midcoast when the three-month LIBOR rate is reset above
5.09%. At December 31, 1998, the fair value of this interest rate swap through
the initial termination date was a net liability of $20,000.
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 Midcoast is obligated to reimburse CIBC when the
three-month LIBOR rate is reset below 4.475%. Conversely, CIBC is obligated to
reimburse Midcoast when the three-month LIBOR rate is reset above 4.475%. At
December 31, 1998, the fair value of this interest rate swap through the
initial termination date was a net asset of $481,000.
The effect of these swap agreements was to lower interest expense by
$37,000 in 1998 and increase interest expense by $2,000 in 1997.
14. Segment Data:
The Company has three reportable segments that are primarily in the
business of transporting, gathering, processing and marketing of natural gas
and other petroleum products. The Company's assets are segregated into
reportable segments based on the type of business activity and type of customer
served on the Company's assets. 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. The accounting policies of the segments are the same as those described
in the summary of significant accounting policies.
F-22
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The following table presents certain financial information relating to
the Company's business segments (in thousands):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
---------------------------
1998 1997 1996
-------- -------- -------
<S> <C> <C> <C>
Segment Revenues:
Transmission..................................... $123,944 $ 64,787 $ 7,565
End-user......................................... 94,087 36,349 14,511
Gathering and processing......................... 15,600 11,246 6,880
-------- -------- -------
Total segment revenues......................... $233,631 $112,382 $28,956
======== ======== =======
Segment Operating Income:
Transmission..................................... $ 11,677 $ 5,310 $ 664
End-user......................................... 4,509 3,047 1,157
Gathering and processing......................... 3,516 2,376 1,738
-------- -------- -------
Total segment operating income................. 19,702 10,733 3,559
-------- -------- -------
Corporate administrative expenses.................. (6,283) (3,455) (1,223)
Interest expense................................... (3,247) (1,067) (413)
Other income (expense), net........................ 250 (297) (9)
-------- -------- -------
Income before income taxes......................... $ 10,422 $ 5,914 $ 1,914
======== ======== =======
</TABLE>
The identifiable assets of the Company, by segment, are as follows (in
thousands):
<TABLE>
<CAPTION>
December 31,
-----------------
1998 1997
-------- --------
<S> <C> <C>
Property, Plant, and Equipment:
Transmission............................................... $ 84,037 $ 75,287
End-user................................................... 18,862 12,917
Gathering and processing................................... 53,401 8,622
-------- --------
Total segment assets..................................... 156,300 96,826
Corporate & other.......................................... 4,255 3,755
-------- --------
Total assets............................................. $160,555 $100,581
======== ========
</TABLE>
The depreciation expense of the Company, by segment, is as follows (in
thousands):
<TABLE>
<CAPTION>
For the Year Ended
December 31,
------------------
1998 1997 1996
------ ------ ----
<S> <C> <C> <C>
Depreciation Expense:
Transmission.............................................. $1,554 $ 553 $132
End-user.................................................. 532 421 237
Gathering and processing.................................. 841 341 415
------ ------ ----
Total segment depreciation expense.......................... 2,927 1,315 784
Corporate & other......................................... 270 277 34
------ ------ ----
Total depreciation expense.............................. $3,197 $1,592 $818
====== ====== ====
</TABLE>
F-23
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
15. 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>
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 0.43
Diluted earnings per share............ 0.38 0.23 0.22 0.42
1997
Operating revenues.................... $12,964 $12,661 $24,523 $62,596
Operating income...................... 1,299 1,064 1,748 3,180
Net income............................ 1,132 623 1,182 2,827
Basic earnings per share.............. 0.33 0.18 0.18 0.41
Diluted earnings per share............ 0.33 0.18 0.17 0.39
</TABLE>
16. Earnings Per Share:
In March 1997, the FASB issued SFAS No. 128, "Earnings Per Share," which
establishes new guidelines for calculating earnings per share. The
pronouncement is effective for reporting periods ending after December 15,
1997. SFAS No. 128 requires companies to present both a basic and diluted
earnings per share amount on the face of the statement of operations and to
restate prior period earnings per share amounts to comply with this standard.
Basic and diluted earnings per share amounts calculated in accordance with SFAS
No. 128 are presented below for the years ended December 31 (in thousands,
except per share amounts):
<TABLE>
<CAPTION>
1998 1997 1996
--------------------------- --------------------------- ---------------------------
Average Earnings Average Earnings Average Earnings
Net Shares Per Net Shares Per Net Shares Per
Income Outstanding Share Income Outstanding Share Income Outstanding Share
------ ----------- -------- ------ ----------- -------- ------ ----------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Basic................... $9,113 7,074 $1.29 $5,764 5,115 $1.13 $1,891 2,593 $0.73
===== ===== =====
Effect of dilutive
securities:
Stock options.......... -- 151 -- 86 -- --
Warrants............... -- 73 -- 50 -- 5
------ ----- ------ ----- ------ -----
Diluted................. $9,113 7,298 $1.25 $5,764 5,251 $1.10 $1,891 2,598 $0.73
====== ===== ===== ====== ===== ===== ====== ===== =====
</TABLE>
17. Subsequent Events:
In January 1999, the Company filed a shelf registration statement
pursuant to which the Company may offer up to $200 million of common or
preferred equities and various forms of debt securities. Currently, no
securities have been sold under this shelf registration.
In March 1999, the Company acquired through merger two related companies,
Flare, LLC ("Flare") and Dufour Petroleum, Inc. ("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,
Midcoast assumed $5.5 million in debt, and the DPI shareholders received
140,574 shares of Common Stock. Flare is a natural gas processing and treating
company whose principal assets include 27 portable natural gas processing and
treating plants from which it earns revenues based on treating and processing
fees and/or a percentage of the natural gas liquids ("NGLs") produced. DPI is
an NGL, crude oil and CO\\2\\
F-24
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
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 financed through the Company's existing credit facility and
the issuance of Common Stock held in treasury.
In March 1999, the Company completed two separate acquisitions for a
combined $8.0 million in cash consideration. The acquisitions include the
purchase of the Tinsley crude oil gathering pipeline from Producers Pipeline
Corporation, as well as the purchase of a 70% interest in SeaCrest Company LLC
("SeaCrest"), which in turn acquired eight offshore natural gas gathering
pipelines. 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
gathering pipelines that SeaCrest acquired from Koch Industries Inc. include
eight separate systems located offshore in the Gulf of Mexico, south of
Louisiana, and comprise approximately 87 miles of pipeline. These systems
gather gas from 23 offshore producing wells with a current total throughput of
approximately 50 Mmcf/day. The Tinsley acquisition was financed through the
Company's existing credit facility, and the acquisition by Seacrest was
financed by Midcoast which borrowed from its existing credit facility.
In March 1999, Midcoast announced that its newly formed, wholly owned,
Midcoast Canada Operating Corporation ("MCOC") subsidiary purchased the Calmar
natural gas treating plant and gathering system in Alberta, Canada from Probe
Exploration Inc. ("Calmar Acquisition"). The total value of the transaction was
$20 million (Canadian) or approximately $13.2 million (U.S.). The assets
purchased include a 30,000 Mcf/day amine sweetening plant, 30 miles of 10 3/4
and 6 3/4 gas gathering pipeline and approximately 4,000 horsepower of
compression located near Edmonton, Alberta. The system currently gathers and
treats approximately 26,000 Mcf/day of sour gas from 27 producing wells
operated by Probe and Courage Energy Inc. In conjunction with the purchase,
Probe entered into a gas gathering and treating agreement with Midcoast,
including the long-term dedication 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 assignment to Midcoast of an
existing third party gathering and treating agreement. The acquisition was
financed through the Company's credit facility which was amended as discussed
below.
In March 1999, the Company amended the Credit Agreement to increase the
committed amount of borrowing availability and allow for Canadian dollar
denominated loans. In anticipation of the Calmar Acquisition described above,
the borrowing availability under the Credit Agreement was increased from $100
million to $125 million. In addition, the Credit Agreement was revised to allow
the Company the flexibility to borrow funds in Canadian dollars in order to
eliminate foreign currency exchange risks as the functional currency of the
MCOC subsidiary will be Canadian dollars.
F-25
<PAGE>
INDEPENDENT AUDITOR'S REPORT ON SCHEDULE
Shareholders 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 1997, and for each
of the years in the three-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-(a)2, for each of the years
in the three-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
F-26
<PAGE>
SCHEDULE II
MIDCOAST ENERGY RESOURCES, INC.
VALUATION AND QUALIFYING ACCOUNTS
Years Ended December 31, 1998, 1997 and 1996
(in thousands)
<TABLE>
<CAPTION>
Column A Column B Column C Column D Column E
Balance
Balance At Charged To Charged At End
Beginning Costs and To Other of
Description Of Period Expenses Accounts Deductions Period
- ------------------------ ---------- ---------- -------- ---------- --------
<S> <C> <C> <C> <C> <C>
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
accounts............... $ -- $ -- $ 494(a) $ -- $ 494
Valuation allowance on
deferred tax assets.... $3,727 $ -- $2,664(d) $(1,810)(f) $4,581
1996
Valuation allowance on
deferred tax assets.... $4,834 $ -- $ -- $(1,107)(f) $3,727
</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.
F-27
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
March 31,
1999
---------
<S> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.......................................... $ 2,021
Accounts receivable, net of allowance of $92....................... 43,023
Materials and supplies, at average cost............................ 1,364
--------
Total current assets............................................. 46,408
--------
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities................................ 180,792
Investment in transmission facilities.............................. 1,358
Natural gas processing facilities.................................. 10,090
Oil and gas properties, using the full-cost method of accounting... 1,383
Other property and equipment....................................... 2,976
--------
196,599
ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION................. (7,639)
--------
188,960
OTHER ASSETS, net of amortization.................................... 1,799
--------
Total assets..................................................... $237,167
========
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities........................... $ 36,277
Current portion of long-term debt payable to banks................. 176
Short-term borrowing from bank..................................... 5,833
Other current liabilities.......................................... 69
--------
Total current liabilities........................................ 42,355
--------
LONG-TERM DEBT PAYABLE TO BANKS...................................... 111,567
OTHER LIABILITIES.................................................... 2,078
DEFERRED INCOME TAXES................................................ 11,025
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES....................... 593
COMMITMENTS AND CONTINGENCIES (Note 4)
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value, 31,250,000 shares authorized,
7,149,513 shares issued at March 31, 1999 (Note 2)................ 71
Paid in capital.................................................... 80,955
Accumulated deficit................................................ (9,134)
Unearned compensation.............................................. (4)
Less: Cost of 181,125 and 157,301 treasury shares, respectively.... (2,339)
--------
Total shareholders' equity....................................... 69,549
--------
Total liabilities and shareholders' equity....................... $237,167
========
</TABLE>
The accompanying notes are an integral part of these financial statements.
F-28
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share data)
<TABLE>
<CAPTION>
For the Three Months Ended
----------------------------
March 31, March 31,
1998 1999
------------- -------------
<S> <C> <C>
OPERATING REVENUES:
Sale of natural gas and other petroleum
products..................................... $ 63,176 $ 75,200
Transportation fees........................... 2,976 4,632
Natural gas processing and treating revenue... 1,099 1,893
Other......................................... 88 339
------------- -------------
Total operating revenues.................... 67,339 82,064
------------- -------------
OPERATING EXPENSES:
Cost of natural gas and other petroleum
products..................................... 60,465 72,272
Natural gas processing and treating costs..... 444 982
Depreciation, depletion and amortization...... 693 1,409
General and administrative.................... 1,603 1,928
------------- -------------
Total operating expenses.................... 63,205 76,591
------------- -------------
OPERATING INCOME................................ 4,134 5,473
NON-OPERATING ITEMS:
Interest expense.............................. (599) (1,503)
Minority interest in consolidated
subsidiaries................................. (2) (40)
Other income (expense), net................... 31 5
------------- -------------
INCOME BEFORE INCOME TAXES...................... 3,564 3,935
PROVISION FOR INCOME TAXES
Current....................................... (70) (463)
Deferred...................................... (733) (217)
------------- -------------
NET INCOME...................................... $ 2,761 $ 3,255
============= =============
EARNINGS PER COMMON SHARE:
Basic......................................... $0.39 $.47
============= =============
Diluted....................................... $0.38 $.46
============= =============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES
OUTSTANDING:
Basic......................................... 7,101,663 6,931,098
============= =============
Diluted....................................... 7,350,138 7,148,391
============= =============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-29
<PAGE>
MIDCOAST ENERGY RESOURCES INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(In thousands, except share data)
<TABLE>
<CAPTION>
Total
Common Paid-in Accumulated Unearned Treasury Shareholders'
Stock Capital Deficit Compensation Stock Equity
- ------------------------ ------ ------- ----------- ------------ -------- -------------
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31,
1998................... $71 $80,955 $(11,947) $(4) $(2,791) $66,284
Net income.............. -- -- 3,255 -- -- 3,255
Treasury stock purchased
(116,750 shares)....... -- -- -- -- (1,990) (1,990)
Treasury stock issued in
connection with the DPI
acquisition (140,574
shares) (Note 3)....... -- -- -- -- 2,442 2,442
Common stock dividends,
$.06 per share......... -- -- (442) -- -- (442)
--- ------- -------- --- ------- -------
Balance, March 31,
1999................... $71 $80,955 $ (9,134) $(4) $(2,339) $69,549
=== ======= ======== === ======= =======
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-30
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Three Months Ended
----------------------------
March 31, March 31,
1998 1999
------------- -------------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income...................................... $ 2,761 $ 3,255
Adjustments to arrive at net cash provided
(used) in operating activities--
Depreciation, depletion and amortization....... 693 1,409
Deferred income taxes.......................... 733 217
Recognition of deferred income................. (21) (21)
Minority interest in consolidated
subsidiaries.................................. 2 40
Other.......................................... 13 --
Changes in working capital accounts--
(Increase) decrease in accounts receivable.... 577 (10,003)
(Increase) decrease in other current assets... 163 (1)
Increase (decrease) in accounts payable and
accrued liabilities.......................... (5,378) 4,660
------------ -------------
Net cash used by operating activities........ (457) (444)
------------ -------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions.................................... -- (28,591)
Capital expenditures............................ (1,622) (4,949)
Other........................................... (129) (556)
------------ -------------
Net cash used by investing activities........ (1,751) (34,096)
------------ -------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings............................ 12,233 90,051
Bank debt repayments............................ (9,773) (51,487)
Purchase of treasury stock...................... -- (1,990)
Advances to affiliates.......................... -- (610)
Receipts from affiliates........................ -- 839
Contributions from (distributions to) joint
venture partners............................... (30) --
Dividends on common stock....................... (413) (442)
------------ -------------
Net cash provided by financing activities.... 2,017 36,361
------------ -------------
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS..................................... (191) 1,821
CASH AND CASH EQUIVALENTS, beginning of period... 308 200
------------ -------------
CASH AND CASH EQUIVALENTS, end of period......... $ 117 $ 2,021
============ =============
CASH PAID FOR INTEREST........................... $ 842 $ 2,638
============ =============
CASH PAID FOR INCOME TAXES....................... $ 101 $ --
============ =============
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
F-31
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation
The accompanying unaudited financial information has been prepared by
Midcoast Energy Resources, Inc. ("Midcoast" or the "Company") in accordance
with the instructions to Form 10-Q. The unaudited information furnished
reflects all adjustments, all of which were of a normal recurring nature, which
are, in the opinion of the Company, necessary for a fair presentation of the
results for the interim periods presented. Although the Company believes that
the disclosures are adequate to make the information presented not misleading,
certain information and footnote disclosures, including significant accounting
policies, normally included in financial statements prepared in accordance with
generally accepted accounting principles have been condensed or omitted
pursuant to such rules and regulations. Certain reclassification entries were
made with regard to the Consolidated Financial Statements for the periods
presented in 1998 so that the presentation of the information is consistent
with reporting for the Consolidated Financial Statements in 1999. It is
suggested that the financial information be read in conjunction with the
financial statements and notes thereto included in the Company's Annual Report
on Form 10-K for the year ended December 31, 1998.
2. Capital Stock
In February 1999, the Company's board of directors announced a five-for-
four common stock split. The stock split was effective for shareholders of
record on February 11, 1999, and was distributed on March 1, 1999. No
fractional shares were issued as a result of the stock split 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 record date.
Net income per share, dividends per share and weighted average shares
outstanding have been retroactively restated to reflect the five-for-four stock
split.
3. Acquisitions
Calmar Acquisition
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 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 approximately 24 Mmcf per day of
sour gas from 27 producing wells operated by Probe and Courage Energy Inc. In
conjunction with the purchase, Probe entered into a gas gathering and treating
agreement with us, including the long-term dedication 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 us of an existing third party gathering and treating agreement.
DPI and Flare Acquisitions
The Company purchased two related companies, Flare, L.L.C. and Dufour
Petroleum, Inc. ("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, Midcoast assumed $5.5 million in
debt, and the DPI shareholders received 140,574 shares of our common stock.
Flare is a natural gas processing and treating company whose principal assets
include 27 portable natural gas processing and treating plants from which it
earns revenues based on treating and processing fees and/or a percentage of the
NGLs 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
F-32
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
facilities and product treating and handling equipment. The acquisition was
funded through the Company's existing credit facility.
Tinsley Acquisition
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 acquisition
was funded through the Company's existing credit facility.
Seacrest Acquisition
The Company also completed the purchase of a 70% interest in SeaCrest
Company, L.L.C. for $1.5 million, which in turn acquired seven active offshore
natural gas gathering pipelines. The gathering pipelines that SeaCrest acquired
from Koch Industries include seven active systems located offshore in the Gulf
of Mexico, south of Louisiana, and comprise approximately 81 miles of pipeline.
These systems gather gas from 23 offshore producing wells with a current total
throughput of approximately 49 Mmcf per day. The acquisition was funded through
the Company's existing credit facility.
4. Commitments and Contingencies
Employment Contracts
Certain executive officers of the Company have entered into employment
contracts, which through amendments provide for employment terms of varying
lengths the longest of which expires in April 2001. These agreements may be
terminated by mutual consent or at the option of the Company for cause, death
or disability. In the event termination is due to death, disability or defined
changes in the ownership of the Company, the full amount of compensation
remaining to be paid during the term of the agreement will be paid to the
employee or their estate, after discounting at 12% to reflect the current value
of unpaid amounts.
MIT Contingency
As part of the Company's acquisition of MIT, the Company has agreed to
pay additional contingent annual payments, which will be treated as deferred
purchase price adjustments, not to exceed $250,000 per year. The amount each
year is dependent upon revenues received by the Company from certain gas
transportation contracts. The contingency is due over an eight-year period
commencing April 1, 1998, and payable at the end of each anniversary date. The
Company is obligated to pay the lesser of 50% of the gross revenues received
under these contracts or $250,000. At March 31, 1999, the Company has accrued
$250,000 as an additional purchase price adjustment.
Midla Contingency
As a condition of the Midla acquisition, the Company agreed that if a
specific contract with a third party was executed prior to October 2, 1999,
which included specific provisions regarding price and throughputs, Midcoast
would be obligated to issue 137,500 warrants to acquire Midcoast common stock
at an exercise price of $15.82 per share to Republic. In addition, concurrent
with initial expenditures on the project, the Company would incur a $1.2
million cash obligation to Republic Gas Partners, L.L.C. At March 31, 1999,
none of the provisions of this contingency have been met.
F-33
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
5. EARNINGS PER SHARE
In March 1997, the FASB issued SFAS No. 128, entitled "Earnings Per
Share", which establishes new guidelines for calculating earnings per share.
The pronouncement is effective for reporting periods ending after December 31,
1997. SFAS No. 128 requires companies to present both a basic and diluted
earnings per share amount on the face of the statement of operations and to
restate prior period earnings per share amounts to comply with this standard.
Basic and diluted earnings per share amounts calculated in accordance with SFAS
No. 128 are presented below for the three-months ended March 31 (in thousands,
except per share amounts):
<TABLE>
<CAPTION>
For the Three Months Ended March 31,
-------------------------------------------------------
1998 1999
--------------------------- ---------------------------
Average Earnings Average Earnings
Net Shares Per Net Shares Per
Income Outstanding Share Income Outstanding Share
------ ----------- -------- ------ ----------- --------
<S> <C> <C> <C> <C> <C> <C>
Basic................... $2,761 7,102 $.39 $3,255 6,931 $.47
==== ====
Effect of dilutive
securities:
Stock options......... 153 207
Warrants.............. 95 10
------ ----- ------ -----
Diluted................. $2,761 7,350 $.38 $3,255 7,148 $.46
====== ===== ==== ====== ===== ====
</TABLE>
F-34
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
6. SEGMENT DATA
The Company has three reportable segments that are primarily in the
business of transporting; gathering, processing and treating; and marketing of
natural gas and other petroleum products. The Company's assets are segregated
into reportable segments based on the type of business activity and type of
customer served on the Company's assets. 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. The accounting policies of the segments are
the same as those described in the summary of significant accounting policies,
included in the Company's Annual Report on Form 10-K for the year ended
December 31, 1998. The following table presents certain financial information
relating to the Company's business segments (in thousands):
<TABLE>
<CAPTION>
For the Three
Months Ended
March 31,
----------------
1998 1999
------- -------
<S> <C> <C>
Segment Revenues:
Transmission................................................ $41,311 $36,024
End-User.................................................... 23,669 28,547
Gathering, Processing and Treating.......................... 2,271 17,154
------- -------
Total Segment Revenues........................................ $67,251 $81,725
======= =======
Segment Operating Income:
Transmission................................................ $ 3,874 $ 4,543
End-User.................................................... 1,292 1,520
Gathering, Processing and Treating.......................... 555 1,094
------- -------
Total Segment Operating Income................................ 5,721 7,157
------- -------
Corporate administrative expenses........................... (1,603) (1,928)
Interest expense............................................ (599) (1,503)
Other income (expense), net................................. 45 209
------- -------
Income Before Income Taxes.................................... $ 3,564 $ 3,935
======= =======
</TABLE>
The identifiable assets of the Company, by segment, are as follows (in
thousands):
<TABLE>
<CAPTION>
March 31,
-----------------
1998 1999
-------- --------
<S> <C> <C>
Property, Plant and Equipment
Transmission............................................... $ 85,774 $104,471
End-User................................................... 5,158 8,289
Gathering, Processing and Treating......................... 10,858 82,539
-------- --------
Total Segment Assets......................................... 101,790 195,299
Corporate and other........................................ 672 1,300
-------- --------
Total Assets................................................. $102,462 $196,599
======== ========
</TABLE>
F-35
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
The depreciation expense of the Company, by segment, is as follows (in
thousands):
<TABLE>
<CAPTION>
For the
Three
Months
Ended March
31,
-----------
1998 1999
---- ------
<S> <C> <C>
Depreciation Expense:
Transmission..................................................... $390 $ 372
End-User......................................................... 136 205
Gathering, Processing and Treating............................... 105 737
---- ------
Total Segment Depreciation Expense................................. 631 1,314
Corporate and other.............................................. 62 95
---- ------
Total Depreciation Expense......................................... $693 $1,409
==== ======
</TABLE>
7. NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED
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. This Statement is effective for all fiscal quarters of
fiscal years beginning after June 15, 1999. Initial application of this
Statement should be as of the beginning of an entity's fiscal quarter; on that
date, 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. However, the Company does not believe the effect of adopting SFAS
133 will be material to its financial position.
F-36
<PAGE>
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
3,460,000 Shares
[MIDCOAST LOGO]
Common Stock
------------------------------------
PROSPECTUS SUPPLEMENT
------------------------------------
Merrill Lynch & Co.
CIBC World Markets
Prudential Securities
May 24, 1999
- --------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
