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                       SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 10-K


(MARK ONE)

[X]   ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE
      ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 1998

                                       OR

[_]   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES
      EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM _________ TO _______

                         COMMISSION FILE NUMBER: 0-8898
                         MIDCOAST ENERGY RESOURCES, INC.
               (Exact Name of Registrant as Specified in its Charter)


          NEVADA                                        76-0378638
(State or Other Jurisdiction  of                     (I.R.S. Employer
Incorporation  or Organization)                    Identification  No.)

    1100 LOUISIANA, SUITE 2950
          HOUSTON, TEXAS                                          77002
(Address of Principal Executive Offices)                        (Zip Code)

         REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: (713) 650-8900

           SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:

       TITLE OF EACH CLASS          NAME OF EACH EXCHANGE ON WHICH REGISTERED
   ---------------------------      -----------------------------------------
          Common Stock,                     American Stock Exchange
     Par Value $.01 Per Share   


           SECURITIES REGISTERED UNDER SECTION 12(G) OF THE ACT: NONE

     Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
during the preceding 12 months (or for such shorter period that registrant was
required to file such reports), and (2)has been subject to such filing
requirements for the past 90 days.

                      Yes [X]                    No [ ]

     Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES OF
THE REGISTRANT.

     Aggregate market value of the voting stock (which consists soley of shares
of common stock) held by non-affiliates of the registrant as of March 15, 1999,
computed by reference to the closing sale price of the registrant's common stock
on the American Stock Exchange on such date: $92,662,757.

     Common Stock, par value $.01 per share. Shares outstanding on March 15,
1999 was 7,149,513.

                       DOCUMENTS INCORPORATED BY REFERENCE

     List hereunder the following documents if incorporated by reference and the
Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is
incorporated: Portions of Midcoast Energy Resouces, Inc. definitive Proxy
Statement for the 1999 Annual Meeting of Shareholders, to be filed not later
than 120 days after the end of the fiscal year covered by this report, are
incorporated by reference into Part III.

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<PAGE>


                               TABLE OF CONTENTS


                                     PART I


   ITEM 1.    BUSINESS.....................................................3
   ITEM 2.    PROPERTIES..................................................14
   ITEM 3.    LEGAL PROCEEDINGS...........................................14
   ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.........14


                                   PART II

   ITEM 5.    MARKET FOR THE REGISTRANT'S COMMON EQUITY AND
              RELATED SHAREHOLDER MATTERS.................................14
   ITEM 6.    SELECTED FINANCIAL DATA.....................................15
   ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
              CONDITION AND RESULTS OF OPERATIONS.........................16
   ITEM 7A.   QUANTATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK....25
   ITEM 8.    FINANCIAL STATEMENTS........................................27
   ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
              ACCOUNTING AND FINANCIAL DISCLOSURE.........................51



                                   PART III

   ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT..........51
   ITEM 11.   EXECUTIVE COMPENSATION......................................51
   ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL 
              OWNERS AND MANAGEMENT.......................................51
   ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS..............51



                                      PART IV


   ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, 
             AND REPORTS ON FORM 8-K.....................................51



                                       2
<PAGE>


                                       PART I

ITEM 1. BUSINESS.

GENERAL

     Midcoast Energy Resources, Inc., its subsidiaries and affiliated companies
(referred to collectively as the "Company" or "Midcoast") is primarily engaged
in the transportation, gathering, processing and marketing of natural gas and
other petroleum products. As of December 31, 1998, the Company owns and operates
two interstate transmission pipeline systems, one intrastate transmission
system, 20 end-user systems and 28 gathering systems representing over 2,300
miles of pipeline with an aggregate daily throughput capacity of over 1.9
billion cubic feet ("Bcf") of gas per day. The Company's principal business
consists of providing transportation services through its pipelines to both
end-users and natural gas producers, providing natural gas marketing services to
these customers and processing natural gas. In connection with these services,
the Company acquires and constructs pipelines to meet these customers needs. The
Company's principal assets are located in the Gulf Coast area.

     Midcoast was incorporated as a Nevada corporation in 1992. Midcoast leases
its principal executive offices at 1100 Louisiana, Suite 2950, Houston, Texas
77002, and its telephone number is (713) 650-8900. Midcoast also owns or leases
other regional offices in Alabama, Louisiana, Mississippi and Texas.

BUSINESS GROWTH STRATEGY

      The Company's principal business strategy is to increase its earnings and
cash flow by focusing on accretive acquisitions, improving the profitability of
existing systems and pursuing new pipeline, processing and treating construction
opportunities. The Company implements its strategy through the following steps:

ACCRETIVE ACQUISITIONS:

      The Company seeks to acquire natural gas or crude oil transmission,
end-user, gathering and processing systems which offer the opportunity for
operational synergies, cost savings and the potential for increased utilization
or expansion of the system. In doing so, the Company focuses on systems in its
core geographic areas of operation where it believes such additional systems
will enhance the overall profitability of Midcoast. The Company will also pursue
acquisition opportunities in other areas that are located in proximity to
geographic areas where demand for natural gas is growing, or where drilling
activity is expected to increase.

IMPROVING PROFITABILITY OF EXISTING SYSTEMS:

      After a system is acquired or constructed, the Company begins an
aggressive marketing effort to fully utilize the system's capacity. As part of
this process, the Company focuses on providing quality service to its existing
customers while seeking out new customers. Many of the Company's existing
pipeline and processing systems were designed with excess throughput capacity
that provide the Company with opportunities to increase throughput with little
incremental capital cost and to provide higher-margin "swing" sales during
periods of increased gas demand. The Company focuses on marketing its system
capacity directly to end-users to supply their natural gas needs and to
producers to provide a means to collect and aggregate their oil and gas
production for sale. In addition, the Company strives to realize cost savings
through the elimination of duplicative efforts achieved through the
implementation of efficiency targeted projects.

CONSTRUCTION OPPORTUNITIES:

      Finally, the Company seeks opportunities for the construction of new
pipeline facilities to meet new or increased demand for pipeline transportation
services. These can include new end-user pipelines and the construction of
gathering pipelines and/or processing facilities in areas of new production.


                                       3

<PAGE>

SIGNIFICANT ACQUISITIONS AND CONSTRUCTION

      Since the first quarter of 1996, the Company has acquired ownership of or
interests in 39 pipelines including four natural gas processing plants for an
aggregate cost of over $141 million. The following is a summary of the Company's
significant acquisition and construction activities.

THE MIT ACQUISITION

      Consistent with the Company's 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 million in contingent deferred
payments (the "MIT Acquisition"). These operations include (i) a 295 mile
interstate transmission pipeline located in northern Alabama, Mississippi and
southern Tennessee which transports natural gas to industrial and municipal
customers (the "MIT System"), (ii) a 38 mile and a one mile pipeline in northern
Alabama which primarily serve two large industrial customers (the "Champion
System" and "Monsanto System," respectively and (iii) a natural gas marketing
company which was subsequently merged into Midcoast Marketing Inc. ("MMI").

THE MIDLA ACQUISITION

      In October 1997, the Company completed its merger of Republic Gas Partners
L.L.C. ("Republic"), which owned Mid Louisiana Gas Company ("MLGC"), Mid
Louisiana Gas Transmission Company ("MLGT") and Mid Louisiana Marketing Company
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.

      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 Rogue Expansion"). The Company has estimated the total cost of the
project to be approximately $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.

ANADARKO ACQUISITION

      In September 1998, Midcoast Gas Services, Inc. ("MGSI"), a wholly owned
subsidiary of Midcoast, 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").

      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 is comprised of over 696 miles of pipeline with an average throughput of
157 Mmcf/day and a total capacity of 345 Mmcf/day ("Anadarko System"). The
system gathers gas from approximately 250 wells and includes a 40 Mmcf/day
natural gas processing facility ("Hobart Plant"), 11 compressor stations with a
total of over 14,000 horsepower and interconnections with eight major interstate
and intrastate pipeline systems.

      The Company expanded the Anadarko System in December 1998 with the
acquisition of the Mendota system from Seagull Energy Corporation for $3.75
million. The Mendota system, which was interconnected with the Anadarko System,
included two processing facilities and 35 miles of gathering pipeline.


                                       4
<PAGE>

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 in the Notes to the Consolidated Financial Statements.

SEGMENTS

      Beginning in 1998, the Company segregated its business activities into
three segments: Transmission Pipelines, End-user Pipelines, and Gathering
Pipelines and Natural Gas Processing. These segments are analyzed independently
by management and derive revenue from different sources. For financial
information related to each segment, see Results of Operations, in Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations, as well as Note 14 Segment Data, in the Notes to the Consolidated
Financial Statements. Set forth below is a description of the principal business
activities conducted by each of the segments:

TRANSMISSION PIPELINES

      The Company's transmission pipelines primarily receive and deliver natural
gas to and from other pipelines, and secondarily sometimes involve end-user or
gathering functions. Transportation fees are received by the Company for
transporting gas owned by other parties through the Company's pipeline systems.
The Company seeks to further expand its activities in this area through the
acquisition or construction of natural gas transmission pipelines in its core
geographic areas of operation where operational synergies and market
opportunities exist or in new geographic regions where there is increasing
demand for gas by municipal and industrial users. As of December 31, 1998, the
Company owns two interstate and one intrastate transmission pipelines.

END-USER PIPELINES

      The Company also contracts with industrial end-users, municipalities or
electrical generating facilities to provide natural gas and natural gas
transportation services to their facilities through interconnect gas pipelines
constructed or acquired by the Company. These pipelines provide a direct supply
of natural gas to new industrial facilities or to existing facilities as an
alternative to the local distribution company. The Company intends to continue
to pursue direct sales to these end-users who have the flexibility to negotiate
their gas purchase and transportation contracts as a result of industry
deregulation. Frequently, the Company is able to offer its end-user customers
rates lower than the customer's current energy supplier. The Company's contracts
with end-user customers typically provide for the payment of a transportation
fee by the customer based on the volume of natural gas transported through the
Company's pipeline. As of December 31, 1998, the Company owns 20 end-user
transmission pipelines.

GATHERING PIPELINES AND NATURAL GAS PROCESSING

      The Company's gathering systems typically consist of a network of
pipelines which collect natural gas or crude oil from points near producing
wells and transport it to larger pipelines for further transmission. Gathering
systems may include meters, separators, dehydration facilities and other
treating equipment owned by the Company or others. The Company derives revenues
from gathering systems by transporting natural gas or crude oil owned by others
through its pipelines for a transportation fee, by purchasing natural gas and
utilizing its pipelines to transport the natural gas to a customer in another
location where the natural gas is resold or, in certain instances, by purchasing
natural gas and arranging for the delivery and resale of an equivalent quantity
of natural gas to a customer not directly served by the Company's pipelines.
Transactions with customers not directly served by the Company's pipelines are
typically accomplished by entering into agreements whereby the Company exchanges
natural gas in its pipelines for natural gas in the pipelines of other
transmission companies. The Company intends to pursue the acquisition or
construction of additional gas gathering systems in or near its core geographic
operating areas and where drilling activity is expected to provide opportunities
for the expansion of gathering or processing facilities. As of December 31,
1998, the Company currently owns an interest in and operates 28 gathering
systems.

                                       5

<PAGE>

      The Company's natural gas processing revenues are realized from the
extraction and sale of natural gas liquids ("NGLs") as well as the sale of the
residual natural gas. These revenues occur under processing contracts with
producers of natural gas utilizing both a "percentage of proceeds" and
"keep-whole" basis. The contracts based on percentage of proceeds provide that
the Company receives a percentage of the NGLs and residual gas revenues as a fee
for processing the producer's gas. The keep-whole contracts require that the
Company reimburse the producers for the british thermal unit ("Btu") energy
equivalent of the NGLs and fuel removed from the natural gas as a result of
processing and the Company retains all revenues from the sale of the NGLs. Once
extracted, the NGLs are further fractionated in the Company's facilities into
products such as ethane, propane, butanes, natural gasoline and condensate, then
sold to various wholesalers along with raw sulfur from the Company's sulfur
recovery plant. The Company's 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. As of December 31, 1998, the Company
owned four processing plants with a capacity of 90 Mmbtu/day.

GAS MARKETING SERVICES ON SEGMENTS

      In addition, the Company provides natural gas marketing services to its
customers within each of the three segments. The Company's gas marketing
activities have been focused on the Company's systems with a strategic focus to
provide quality and consistent service to customers connected to the Company's
pipeline network. The Company's marketing activities include providing natural
gas supply and sales services to some of its end-user customers by purchasing
the natural gas supply from other marketers or pipeline affiliates and reselling
the natural gas to the end-user. The Company also purchases natural gas directly
from well operators on many of the Company's gathering systems and resells the
natural gas to other marketers or pipeline affiliates. Many of the contracts
pertaining to the Company's gas marketing activities are month-to-month spot
market transactions with numerous gas suppliers or producers in the industry.
The Company also offers other gas services to some of its customers including
management of capacity release and gas balancing.

      Typically, the Company purchases natural gas at a price determined by
prevailing market conditions. Simultaneous with the purchase of natural gas by
the Company, the Company generally resells natural gas at a higher price under a
sales contract which is comparable in its terms to the purchase contract,
including any price escalation provisions. In most instances, natural gas
marketing is characterized by small margins since there are numerous companies
of greatly varying size and financial capacity who compete with the Company in
the marketing of natural gas. The profitability of the natural gas marketing
operations of the Company depends in large part on the ability of the Company's
management to assess and respond to changing market conditions in negotiating
these natural gas purchase and sale agreements. As a consequence of the increase
in competition in the industry and volatility of natural gas prices there has
been a reluctance of end-users to enter into long-term purchase contracts.
Moreover, consumers have shown an increased willingness to switch fuels between
gas and alternate fuels in response to relative price fluctuations in the
market. The inability of management to respond appropriately in changing market
conditions could have a negative effect on the Company's profitability.
Accordingly, historical operating income associated with this revenue stream has
varied depending on market conditions. The Company's gas marketing activities,
which utilize third party pipelines, also exposes the Company to economic risk
resulting from imbalances or nominated volume discrepancies which can result
either in penalties having a negative impact on earnings or a transaction gain,
depending on how and when imbalances are corrected. The Company believes the
marketing of natural gas is an important complement to its transportation
services.


                                       6
<PAGE>

MAJOR CUSTOMERS

      The Company's principal customers are industrial end-users,
municipalities, resellers and producers of natural gas. The Company typically
enters into one to five year transportation agreements, which may also include
provisions regarding guaranteed minimum volumes and price reductions after the
customer meets certain transportation commitments. The Company also enters into
marketing agreements with many of its customers related to gas supply and other
services. For its Federal Energy Regulatory Commission ("FERC") regulated
entities, the Company enters into firm and interruptible transportation
contracts using the tariff rates approved by FERC. In certain situations, the
Company has offered discounts from its tariffs in response to specific market
conditions.

      For 1998, there were no customers that represented in excess of 10% of the
Company's gross margin. For 1997, Champion International Corporation
("Champion") and Entergy Gulf States, Inc. ("Entergy") each contributed in
excess of 10% of the Company's gross margin on a pro forma basis. Gross margin
is defined as revenues less related direct costs and expenses. The agreement
with Champion, which expires in 2004, provides for 26 Mmcf/day of firm
transportation and a rate reduction of 41% in the event that Champion meets a
minimum transportation volume, which is expected to occur in 2000 based on
Champion's current usage. The agreements with Entergy expire in 2000 and 1999
for marketing and transportation services, respectively. The marketing agreement
provides for volumes which range from 15,000 Mmbtu's to 110,000 Mmbtu's/day. The
transportation agreement provides for volumes which range from 25,000 Mmbtu's to
100,000 Mmbtu's/day. Both agreements include annual evergreen language after the
expiration of the primary term.

COMPETITION

      The Transmission Pipeline, End-user Pipeline and Gathering Pipeline and
Natural Gas Processing segments are highly competitive. In marketing natural
gas, the Company has numerous competitors, including marketing affiliates of
interstate pipelines, major integrated oil companies, and local and national
natural gas gatherers, brokers and marketers of widely varying sizes, financial
resources and experience. Many of these competitors, particularly those
affiliated with major integrated oil and interstate and intrastate pipeline
companies, have financial resources substantially greater than those available
to the Company. Local utilities and distributors of natural gas are, in some
cases, engaged directly, and through affiliates, in marketing activities that
compete with the Company. Some of the Company's contracts are month-to-month
arrangements and as such, these agreements are affected by competitive factors
at the time of the sale.

      The Company competes against other companies for supplies of natural gas
and for customers. Competition for natural gas supplies is primarily based on
efficiency, reliability, availability of transportation and the ability to offer
a competitive price for natural gas. Competition for customers is primarily
based upon reliability and price of deliverable natural gas. For customers that
have the capability of using alternative fuels, such as oil and coal, the
Company also competes against companies capable of providing these alternative
fuels at a competitive price.

NATURAL GAS SUPPLY

      The Company's transmission and end-user pipelines have connections with
major interstate and intrastate pipelines which management believes have
supplies of natural gas in excess of the volumes required for these systems.
However, these purchase contracts may be affected by factors beyond both the
Company's and the gas suppliers' control such as capacity constraints and
temporary regional supply shortages. With regard to its gathering systems,
supply risks include other parties having control over the drilling of new
wells, inability of wells to deliver gas at required pipeline quality and
pressure, and depletion of reserves. The future performance of the Company will
depend to a great extent on the throughput levels achieved by the Company with
respect to its existing pipelines and the pipelines acquired or constructed by
it in the future. In order to maintain the throughput on its gathering systems
at current levels, the Company must access new natural gas supplies to offset
the natural decline in reserves as such supplies are produced. In connection
with the construction and acquisition of its gathering systems, evaluations were
made of well and reservoir data furnished by producers to determine the
availability of natural gas supply for the systems. Based on those evaluations,
it is management's belief that there should be adequate natural gas supply for
the Company to recoup its investment with an adequate rate of return. As such,
management does not routinely obtain independent evaluation of reserves
dedicated to its systems due to the cost of such evaluations. Accordingly, the
Company does not have estimates of total reserves dedicated to its systems or
the anticipated life of such producing reserves.


                                       7
<PAGE>

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

      The Company's operations of the MIT and MIDLA Systems constitute the
operations of a "natural gas company", as defined in the NGA. As such, they 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 authorization issued under the NGA and pursuant to the NGPA.
The FERC regulates the interstate transportation and certain sales of natural
gas, including among other things, rates and charges allowed natural gas
companies, extensions and abandonment of facilities and service, rates of
depreciation and amortization and certain accounting methods.

      Pipeline rates for MIT and MIDLA must be filed with and approved by the
FERC and 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, 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 which 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.

INTRASTATE PIPELINE REGULATION

      The Company's intrastate pipeline operations are generally not subject to
regulation by the FERC, but are subject to regulation by various agencies of the
states in which the Company operates. The Magnolia System is subject to the
jurisdiction of the FERC with respect to the transportation rates under Section
311. Under Section 311, an intrastate pipeline can provide transportation
service "on behalf of" any interstate pipeline or local distribution company
without prior FERC authorization. Specifically, the FERC adopted a so-called
transport or title standard requiring that for purposes of interstate
transportation under Section 311, the on behalf of entity must either (1) have
physical custody of or (2) hold title to the gas at some point during the
transaction. Section 311 service must be provided without undue discrimination
or preference and is subject to certain FERC filing and reporting requirements.
The Champion and Monsanto Systems are regulated by the Alabama Public Service
Commission ("APSC"). The rates for transportation to customers on these two
systems are determined by negotiated contracts which are approved by the APSC.
The Company's operations in Texas are subject to the Texas Gas Utility
Regulatory Act, as implemented by the Texas Railroad Commission (the "TRC").
Generally, the TRC is vested with authority to ensure that rates charged for
natural gas sales and transportation services are just and reasonable. The
Company must also make filings with the TRC for all new and increased rates. The
Company's intrastate systems in Louisiana are subject to the regulations of the
Office of Conservation, Pipeline Division of the Department of Natural Resources
("Commission"). As in other states, this agency possesses the authority to
review and authorize transactions of those entities under its jurisdiction. This
may include, but not be limited to the construction, acquisition, abandonment
and interconnection of physical facilities and issues regarding transportation
rates and contract pricing. The Company currently conducts no transportation for
others through its Louisiana facilities and therefore, remains regulated only on
issues governing the construction or abandonment of physical facilities and
contract pricing only to the extent that no claims of "unjust" treatment are
received by the Commission. As in the case of potential federal regulatory
changes, there can be no assurances that state regulatory measures will not
adversely affect the Company's business and financial condition. In such events,
the states' regulatory authorities could temporarily suspend or hinder
operations in a particular state, depending on the authority's view of its
jurisdiction.


                                       8

<PAGE>

GATHERING OPERATIONS REGULATION

      The NGA exempts gas gathering facilities from the direct jurisdiction of
the FERC. The Company believes that its gathering facilities and operations meet
the current tests that the FERC uses to grant non-jurisdictional gathering
facility status. Some of the recent cases applying these tests in a manner
favorable to the determination of the Company's 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 the
Company believes the current definitions create non-jurisdictional status for
the Company's gathering facilities, no assurance is available that such
facilities will not, in the future, be classified as regulated transmission
facilities and thus, the rates, terms, and conditions of the services rendered
by those facilities would become subject to regulation by the FERC.

      No state in which the Company operates currently regulates gathering fees.
Although the Company is not aware that any state in which it operates a natural
gas gathering system is likely to begin regulation of the Company's natural gas
gathering activities and fees, new or increased state regulation has been
adopted or proposed in other natural gas producing states and there can be no
assurance that such regulation will not be proposed or adopted in states where
the Company conducts gathering activities or that the Company will not expand
into or acquire operations in a state where such regulations could be imposed.

ENVIRONMENTAL AND SAFETY MATTERS

      The Company's activities in connection with the operation and construction
of pipelines and other facilities for transporting, processing, treating, or
storing natural gas and other products are subject to environmental and safety
regulation by numerous federal, state and local authorities. This can include
ongoing oversight regulation as well as requirements for construction or other
permits and clearances that must be granted in connection with new projects or
expansions. Regulatory requirements can increase the cost of planning,
designing, initial installation and operation of such facilities. Sanctions for
violation of these requirements include a variety of civil and criminal
enforcement measures including assessment of monetary penalties, assessment and
remediation requirements and injunctions as to future compliance. The following
is a discussion of certain environmental and safety concerns related to the
Company. It is not intended to constitute a complete discussion of the various
federal, state and local statutes, rules, regulations, or orders to which the
Company's operations may be subject.


                                       9
<PAGE>

      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, the Company, without regard to fault, could incur liability
under the Comprehensive Environmental Response, Compensation, and Liability Act
of 1980, as amended, or state counterparts, in connection with the disposal or
other releases of hazardous substances, including those arising out of
historical operations conducted by the Company's predecessors. Further, the
recent trend in environmental legislation and regulations is toward stricter
standards, and this will likely continue in the future.

      Environmental laws and regulations may also require the acquisition of a
permit before certain activities may be conducted by the Company. Further, these
laws and regulations may limit or prohibit activities on certain lands lying
within wilderness areas, wetlands, areas providing habitat for certain species
which have been identified as "endangered" or "threatened" or other protected
areas. The Company is also subject to other federal, state and local laws
covering the handling, storage or discharge of materials used by the Company, or
otherwise relating to protection of the environment, safety and health. As an
employer, the Company is required to maintain a workplace free of recognized
hazards likely to cause death or serious injury and to comply with specific
safety standards.

      The Company will make expenditures in connection with environmental
matters as part of its normal operations and capital expenditures and the
possibility exists that stricter laws, regulations or enforcement policies could
significantly increase the Company's compliance costs and the cost of any
remediation which may become necessary. There is inherent risk of the incurrence
of environmental costs and liabilities in the Company's business due to its
handling of oil, gas and petroleum products, historical industry waste disposal
practices and prior use of gas flow meters containing mercury. There can be no
assurance that material environmental costs and liabilities will not be incurred
by the Company. Management believes, based on its current knowledge, that the
Company has obtained and is in current compliance with all necessary and
material permits and that the Company is in substantial compliance with
applicable material environmental and safety regulations. Further, the Company
maintains insurance coverages that it believes are customary in the industry,
although there can be no assurance that the Company's environmental impairment
insurance will provide sufficient coverage in the event an environmental claim
is made against the Company (See "Insurance"). The Company is not aware of any
existing environmental or safety claims that would have a material impact upon
its financial position or results of operations.



                                       10
<PAGE>

PIPELINE SYSTEMS

      As of December 31, 1998, the Company owns an interest in and operates 51
pipelines. Two interstate transmission pipelines, one intrastate transmission
pipelines, twenty end-user pipelines and twenty-eight gathering pipelines. The
majority of these pipelines are situated strategically in the Company's core
Gulf Coast operating area. Certain information concerning the Company's
pipelines is summarized in the following table:

<TABLE>
<CAPTION>

------------------------------------------------------------------------------------------------------------
                       Date of
                       Acquisition                                            Average             Daily
                       or                                                     Daily               Volume
                       initial                                   Length      Volume(2)          Capacity(2)
Pipeline System(1)     operations       Location                 in miles    (Mmbtu/Day)         (Mmbtu/Day)
------------------------------------------------------------------------------------------------------------
                                                       
TRANSMISSION PIPELINES:

<S>                 <C>       <C>                             <C>             <C>               <C>    
   Magnolia              09/95     Central AL                      111.0           28,447            120,000
   MIT                   05/97     Selmer, TN to Huntsville, AL    295.3          101,884            200,000
   MIDLA                 10/97     Monroe, LA to Baton Rouge, LA   404.6           78,092            190,000
                         
END-USER PIPELINES:      
   Burnett               12/89     Burnet Co., TX                    1.3              666              3,000
   Turkey Creek          01/91     Fort Bend Co., TX                15.6              816              5,000
   OC Kansas             06/91     Wyandotte Co., KS                 1.0            2,817              6,500
   Augusta               07/93     Butler Co., KS                    0.5              407              5,000
   Westlake              11/93     Calcasieu Parish, LA              1.3           14,209             50,000
   Quindaro              11/94     Wyandotte Co., KS                 3.1            1,309             60,000
   OC Albany             12/94     Albany Co., NY                    0.5            1,335              3,000
   Guadalupe (3)         02/96     Culberson Co., TX                 6.1              297             10,000
   Roane County (4)      08/96     Roane Co., TN                     2.1            1,440              5,000
   South Fulton          09/96     Obion Co., TN                     2.6               -- (5)          1,200
   Salt Creek (3)        09/96     Kent & Scurry Cos., TX           39.1            5,437             20,000
   Cuero                 10/96     DeWitt Co., TX                    5.4               83              2,000
   STEC                  10/96     Victoria Co., TX                  4.0              843             10,000
   Falfurrias            01/97     Brooks Co., TX                     -- (6)          219              8,000
   Monsanto              05/97     Morgan Co., AL                    1.0            4,432             20,000
   Champion              05/97     Lawerence & Colbert Cos., AL     38.0           23,313             50,000
   Crown Vantage         10/97     West Feliciana Parish, LA         2.5            8,489             32,800
   Farmlands             10/97     Grant Parish, LA                  4.3           31,434             62,000
   Baton Rouge           10/97     E. Baton Rouge Parish, LA        33.2           26,384             80,000
   Creole                06/98     Orleans Parish, LA               44.0           32,181            115,000
                                                                                          
GATHERING PIPELINES AND NATURAL GAS PROCESSING:

   Zmeskal               06/94     Victoria Co., TX                   -- (6)          141              3,000
   Cook Inlet                                                                                      
    Gas(4)               07/94     Cook Inlet, AK                    2.7              216             15,000
   Cook Inlet                                                                                      
     Oil(4)              07/94     Cook Inlet, AK                    2.7           17,141 (7)        120,000 (7)
   Foss                  12/94     Custer Co., OK                    4.1              344              5,000
   Flores (8)            01/96     Starr Co., TX                     9.9            1,474              5,000
   Chapa (3)             02/96     Live Oak Co., TX                 20.7            1,117             50,000
   Guerra (3)            02/96     Webb & Duval Cos., TX             8.4            6,485             50,000
   Loma Novia (3)        02/96     Duval & McMullen Cos., TX        15.2            6,178             25,000
   Detroit               05/96     Lamar Co., AL                    16.5               32              3,000
   Fayette               05/96     Fayette Co., AL                  62.8            1,170             10,000
   Greenwood                                                                                       
    Springs              05/96     Monroe Co., MS                    7.9              127              5,000
   Happy Hill            05/96     Fayette Co., AL                   5.5               71              3,000
   Heidlberg Koch        05/96     Jasper Co., MS                    1.0              136              3,000
   Heidlberg TGP         05/96     Jasper Co., MS                    3.5              920              2,500
   Millbrook             05/96     Wilkinson Co., MS                 8.9              223              5,000
   Sizemore              05/96     Lamar Co., AL                     1.0               10              3,000
   Chapparal             10/96     Monroe Co., MS                    9.6              495              3,000
   Harmony (9)           10/96     Central MS                      155.4            5,328             20,000
   Minnie Bock           11/96     Nueces Co., TX                   14.0            2,898             10,000
   Port                  11/96     Nueces Co., TX                    1.5              978              5,000
   Rowden                11/96     Duval Co., TX                     1.0               23              3,000
   Raymond (10)          03/97     Central KS                      120.0              531              5,000
   T33                   10/97     Offshore LA                       3.9           13,898             24,000
   T51                   10/97     Offshore LA                       4.7           18,126             72,000
   Texana (11)           04/98     Central TX                       46.0            4,488             15,000
   Anadarko/                                                                                  
    Mendota(9)      08/98     OK and TX Panhandle             731.0          157,829            345,000
   Hatcher          08/98     Robert Co., TX                    8.0              894              5,000
   Tynan            12/98     Bee & Live Oak Cos., TX          24.5            1,031             30,000
                                                            -------          -------          ---------
Totals                                                      2,306.9          606,838          1,903,000
                                                            =======          =======          =========

</TABLE>

                                                   (FOOTNOTES ON FOLLOWING PAGE)

                                       11

<PAGE>

----------

(1)  Unless otherwise indicated, all systems are 100% owned and operated by the
     Company and inactive systems owned by the Company 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 the Creole, Anadarko/Mendota, Hatcher and
     Tynan 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 the Company
     owns a 70% interest, and is operated by the Company.

(4)  This system is owned and operated by a third-party and the Company receives
     throughput charges from this system.

(5)  The Company receives a monthly fee on this system which is owned and
     operated by a third party.

(6)  This system is less than a quarter-mile in length.

(7)  Volume has been converted from barrels of oil to equivalent Mmbtu's of gas
     using one barrel of oil to six Mmbtu's.

(8)  This system is owned by Starr County Gathering System, a Joint Venture in
     which the Company owns a 60% interest, and is operated by the Company.

(9)  These gathering systems include natural gas processing facilities.

(10) The Company owns approximately 66% of this system, and is operated by the
     Company.

(11) This system is owned by Texana Gas Pipeline Company, in which the Company
     owns a 50% interest, and is operated by the Company.


                                       12

<PAGE>


OIL AND GAS PROPERTIES

      The Company owns several non-operated working interests in producing and
non-producing oil and gas properties. For the year ended December 31, 1998,
revenues from the Company's oil and gas properties were less than 1% of its
total revenues, and for the same period the Company's oil and gas properties
represented less than 1% of its total assets. Although it is not expected to
become a major line of business for the Company, management expects that
acquisition and ownership of non-operated oil and gas interests will remain a
facet of the Company's business for the foreseeable future.

TITLE TO PROPERTIES

      The Company, as part of its pipeline construction process, must obtain
certain right-of-way agreements from landowners whose property the proposed
pipeline will cross. The terms and cost of these agreements can vary greatly due
to a number of factors. In addition, as part of its acquisition process, the
Company will typically evaluate the underlying right-of-way agreements for the
particular pipeline to be acquired to determine that the pipeline owner has met
all terms and conditions of the underlying right-of-way agreements and that the
agreements are still in full force and effect. The Company typically relies upon
outside service organizations to review the right-of-way agreements and to make
suggestions to the seller as to any curative work required before closing. The
Company typically does not receive a title opinion or title policy as to these
right-of-way agreements due to the complexity of the records and expense.

      Occasionally, the Company may seek to initiate condemnation proceedings
where permitted under state law to obtain a right-of-way necessary for pipeline
construction projects. The Company believes that this process is consistent with
standards in the pipeline industry and that it holds good title to its pipeline
systems, subject only to defects which the Company believes are not material to
the ownership of its properties or results of operations. Substantially all of
the Company's pipeline systems are pledged to secure borrowings under the
Company's credit facility. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Capital Resources and
Liquidity".

INSURANCE

      The Company's operations are subject to many hazards inherent in the
natural gas transmission industry. The Company maintains insurance coverage for
its operations and properties considered to be customary in the industry. There
can be no assurance, however that the Company's insurance coverage will be
available or adequate for any particular risk or loss or that the Company will
be able to maintain adequate insurance in the future at rates it considers
reasonable. Although, management believes that the Company's assets are
adequately covered by insurance, a substantial uninsured loss could have a
material adverse impact on the Company and its financial position.

EMPLOYEES AND CONTRACT SERVICE ORGANIZATIONS

      The Company had 149 full-time employees on December 31, 1998. The Company
has arrangements with other unaffiliated independent pipeline operating
companies who service and operate the Company's extensive field operations and
provide for emergency response measures. The Company is not a party to any
collective bargaining agreements. There have been no significant labor disputes
in the past.

FORWARD LOOKING STATEMENTS

      See "Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations - Disclosure Regarding Forward Looking Statements" for
a discussion of forward looking statements contained above and elsewhere in this
Report.


                                       12
<PAGE>
ITEM 2. PROPERTIES

      See "Item 1. Business" for a discussion of properties and locations.

ITEM 3. LEGAL PROCEEDINGS

      The Company is currently involved in certain litigation. Management
believes that all such litigation arose in the ordinary course of business and
that costs of settlements or judgments arising from such suits will not have a
material adverse effect on the Company's consolidated financial position or
results of operations.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

      The Company did not submit any matters during the fourth quarter to a vote
of security holders.


                                      PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED SHAREHOLDER
        MATTERS

MARKET INFORMATION

    The Company's Common Stock began trading August 9, 1996 on the American
Stock Exchange ("AMEX") under the symbol "MRS". The following table sets forth
the high and low sales prices for the Company's Common Stock for the period from
January 1, 1997 to December 31, 1998.

                                                           Dividends
                                                           Paid per
                            High(1)          Low(1)          Share
                            -------          ------          -----
   1998

First Quarter               19.00           14.72             .06
Second Quarter              18.70           15.09             .06
Third Quarter               18.95           13.30             .06
Fourth Quarter              17.41           13.41             .06

   1997

First Quarter               12.72            7.45             .06
Second Quarter              12.64            9.91             .06
Third Quarter               16.50           11.64             .06
Fourth Quarter              20.36           14.19             .06


----------
(1)  All prices and dividends per share have been adjusted to reflect the 10%
     stock dividend declared on February 3, 1998 and paid on March 2, 1998 to
     shareholders of record on February 13, 1998 ("Stock Dividend"), as well as
     the five-for-four stock split declared on February 1, 1999, and paid on
     March 1, 1999, to shareholders of record on February 11, 1999 ("Stock
     Split").


    On March 15, 1999, the closing price for the Common Stock, as reported by
the AMEX, was $17.75 per share. As of March 15, 1999, there were 333 holders of
record of Common Stock. The Company believes that there are substantially more
beneficial holders of Common Stock.

DIVIDEND POLICY

    Holders of Common Stock are entitled to receive cash dividends out of
Company funds legally available subject to the qualification that dividends need
not be declared or paid by the Board of Directors ("Board") if to do so would be
in violation of laws or restrictions under contractual arrangements (including
credit agreements) to which the Company is or may hereafter become a party. The
Board declared the Company's initial Common Stock dividend of $.06 per share on
August 16, 1996, which was paid on September 3, 1996, and the Company has
declared and paid a $.06 per share cash dividend on its Common Stock in each
successive quarter since that time.

    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. 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.

                                       14
<PAGE>


    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-Stock Dividend and post-Stock
Split basis.

    It is the Company's current policy to continue to pay a quarterly dividend;
however, the amount of future cash dividends, if any, will depend upon future
earnings, results of operations, capital requirements, covenants contained in
various financing agreements of the Company and its subsidiaries, the financial
condition of the Company and certain other factors. Accordingly, there can be no
assurances that dividends will be paid by the Company in the future. See "Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations - Capital Resources and Liquidity".

ITEM 6. SELECTED FINANCIAL DATA

    The following table sets forth, for the periods and at the dates indicated,
selected historical consolidated financial data for Midcoast. This financial
data has been derived from and should be read in conjunction with the
consolidated financial statements of Midcoast and notes thereto included in Part
II, Item 8.

<TABLE>
<CAPTION>


                                                                    YEAR ENDED DECEMBER 31,
                                              -----------------------------------------------------------------
                                                1998          1997           1996         1995           1994
                                                ----          ----           ----         ----           ----
                                                          (In thousands, except per share amounts)
<S>                                           <C>           <C>           <C>           <C>            <C>     
STATEMENT OF OPERATIONS DATA:
  Operating revenues                          $234,069      $112,744      $ 29,415      $ 15,622       $ 14,969
  Operating income (1)                          13,553         7,291         2,573         2,569            349
  Interest expense                               3,247         1,067           413           339            189
  Income before income taxes                    10,422         5,914         1,914         2,193            148
  Net income                                     9,113         5,764         1,914         2,193             27
  Net income (loss) applicable to common
     shareholders                                9,113         5,764         1,891         2,134            (32)

PER SHARE DATA:
  Net income (loss) per share
   applicable to common shareholders
    Basic                                     $   1.29      $   1.13      $    .73      $   1.08       $   (.02)
    Diluted                                   $   1.25      $   1.10      $    .73      $   1.08       $   (.02)

  Weighted average number of
   common shares outstanding
    Basic                                        7,074         5,115         2,593         1,980          1,913
    Diluted                                      7,298         5,251         2,598         1,980          1,913

  Cash dividends declared 
     per common share                         $    .24      $    .24      $    .06      $   --         $   --

OTHER DATA:

  Depreciation, depletion
   and amortization                           $  3,197      $  1,592      $    818      $    452       $    259
  General and administrative                     6,283         3,455         1,223           785            849
  Cash flow from operating activities           17,169         3,856         2,564         2,361           (515)


                                                                         DECEMBER 31,
                                              -----------------------------------------------------------------
                                                1998          1997           1996          1995            1994
                                                ----          ----           ----          ----            ----
                                                                         (In thousands)
BALANCE SHEET DATA:
  Working capital (deficit)                   $    989      $  1,888      $  1,135      $    (99)      $ (1,105)
  Property, plant and equipment, net           154,247        97,552        16,965         8,206          4,994
  Total assets                                 191,342       128,038        27,303        11,089          7,272
  Long-term debt, net of current portion        78,082        28,923         4,015         3,961          1,781
  Shareholders' equity                          66,284        61,451        13,593         4,157          2,007

----------
(1) Operating revenues less operating expenses.

</TABLE>


                                       15
<PAGE>



ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS.


    The following discussion of the historical financial condition and results
of operations of Midcoast should be read in conjunction with "Selected Financial
Data" contained in Part I, Item 6 and with the consolidated financial statements
and related notes thereto contained in Part II, Item 8.

GENERAL

    Since its formation, the Company has grown significantly as a result of the
construction and acquisition of new pipeline facilities. For the three year
period ended 1998, the Company acquired or constructed 39 pipelines for an
aggregate cost of over $141 million. See "Pipeline Systems". The Company
believes the historical results of operations do not fully reflect the operating
efficiencies and improvements that are expected to be achieved by integrating
the acquired and newly constructed pipeline systems. As the Company pursues its
growth strategy in the future, its financial position and results of operations
may fluctuate significantly from period to period.

    The Company's results of operations are determined primarily by the volumes
of gas transported, purchased and sold through its pipeline systems or processed
at its processing facilities. With the exception of the Company's natural gas
processing activities, which represents a small component of the Company's
overall earnings, the Company's revenues are derived from fee based sources. As
a result, the Company's earnings have little sensitivity to changes in commodity
prices. In addition, most of the Company's operating costs do not vary directly
with volume on existing systems, thus, increases or decreases in transportation
volumes generally have a direct effect on net income. The Company derives its
revenues from three primary sources: (i) transportation fees from pipeline
systems owned by the Company, (ii) the processing and treating of natural gas
and (iii) the marketing of natural gas.

    Transportation fees are received by the Company for transporting natural gas
or crude oil owned by other parties through the Company's pipeline systems.
Typically, the Company incurs very little incremental operating or
administrative overhead cost to transport gas through its pipeline systems,
thereby recognizing a substantial portion of incremental transportation revenues
as operating income.

    The Company's natural gas processing revenues are realized from the
extraction and sale of NGLs as well as the sale of the residual natural gas.
These revenues occur under processing contracts with producers of natural gas
utilizing both a "percentage of proceeds" and "keep-whole" basis. The contracts
based on percentage of proceeds provide that the Company receives a percentage
of the NGLs and residual gas revenues as a fee for processing the producer's
gas. The keep-whole contracts require that the Company reimburse the producers
for the Btu energy equivalent of the NGLs and fuel removed from the natural gas
as a result of processing and the Company retains all revenues from the sale of
the NGLs. The Company's 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.

      The Company's marketing revenues are realized through the purchase and
resale of natural gas to the Company's customers. Generally, gas marketing
activities will generate higher revenues and correspondingly higher expenses
than revenues and expenses associated with transportation activities, given the
same volumes of gas. This relationship exists because, unlike revenues derived
from transportation activities, gas marketing revenues and associated expenses
include the full commodity price of the natural gas acquired. The operating
income the Company recognizes from its gas marketing efforts is the difference
between the price at which the gas was purchased and the price at which it was
resold to the Company's customers. The Company's strategy is to focus its
marketing activities on Company owned pipelines. The Company's marketing
activities have historically varied greatly in response to market fluctuations.

      The Company has had quarter-to-quarter fluctuations in its financial
results in the past due to the fact that the Company's natural gas sales and
pipeline throughputs can be affected by changes in demand for natural gas
primarily because of the weather. In particular, demand on the Magnolia, MIT and
MIDLA Systems fluctuate due to weather variations because of the large municipal
and other seasonal customers which are served by the respective systems. As a
result, historically the winter months have generated more income than summer
months on these systems. There can be no assurances that the Company's efforts
to minimize such effects will have any impact on future quarter-to-quarter
fluctuations due to changes in demand resulting from variations in weather
conditions. Furthermore, future results could differ materially from historical
results due to a number of factors including but not limited to interruption or
cancellation of existing contracts, the impact of competitive products and
services, pricing of and demand for such products and services and the presence
of competitors with greater financial resources.


                                       16
<PAGE>

RESULTS OF OPERATIONS

      As indicated in the table provided in Part I. Pipeline Systems, the
Company has acquired or constructed numerous pipelines in the three-year period
ended December 31, 1998. These assets were acquired from numerous sellers, at
different periods throughout the year and all were accounted for under the
purchase method of accounting for business combinations and accordingly, the
results of operations for such acquisitions are included in the Company's
financial statements only from the applicable date of the acquisition. As a
consequence, the historical results of operations for the periods presented may
not be comparable.

      The Company adopted the provisions of SFAS No. 131, Disclosures about
Segments of an Enterprise and Related Information, effective January 1, 1998.
Accordingly, the Company has segregated its business activities into three
segments: Transmission Pipelines, End-user Pipelines, and Gathering Pipelines
and Natural Gas Processing.

      Consolidated gross margin for the year ended December 31, 1998, increased
88% to $22.6 million compared to $12.0 million in 1997. Consolidated gross
margin for the year ended December 31, 1997, was $7.7 million higher than for
the same period in 1996. Variations for each segment are discussed in the
segment results below.

SEGMENT RESULTS

      The following tables present certain data for each of the three operating
segments of Midcoast for the three years ended December 31, 1998. As previously
discussed, the Company provides natural gas marketing services to its customers.
For analysis purposes, the Company accounts for the marketing services by
recording the marketing activity on the operating segment where it occurs.
Therefore, the gross margin for each segment includes a transportation component
and a marketing component. The Company evaluates each of its segments on a gross
margin basis, which is defined as the revenues of the segment less related
direct costs and expenses of the segment and does not include depreciation,
interest or allocated corporate overhead. For further analysis on each segment
regarding identifiable assets, depreciation and corporate administrative
expenses, see Note 14 - Segment Data in the Notes to Consolidated Financial
Statements.



                                       17
<PAGE>

TRANSMISSION PIPELINES

                                          For the Year Ended December 31,
                                    ---------------------------------------
                                      1998            1997           1996
                                    --------        --------       --------
                                    (IN THOUSANDS, EXCEPT AMOUNTS PER MMBTU)

OPERATING REVENUES:
  Marketing                         $117,557        $ 61,275       $  6,586
  Transportation Fees                  6,387           3,512            979
                                    --------        --------       --------

        TOTAL OPERATING REVENUES     123,944          64,787          7,565
                                    --------        --------       --------

OPERATING EXPENSES:

  Cost of Natural Gas and
   Transportation Charges            106,330          57,332          6,468
  Operating Expenses                   4,383           1,592            301
                                    --------        --------       --------

        TOTAL OPERATING EXPENSES     110,713          58,924          6,769
                                    --------        --------       --------

        GROSS MARGIN                $ 13,231        $  5,863       $    796
                                    ========        ========       ========


VOLUME (in Mmbtu)
  Marketing                           48,538          22,454          2,759
  Transportation                      49,506          30,752          9,914
                                    --------        --------       --------

TOTAL VOLUME                          98,044          53,206         12,673
                                    ========        ========       ========


GROSS MARGIN per Mmbtu              $    .13        $    .11       $    .06



YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

      The Company's entrance into the regulated interstate pipeline business
began with the acquisition of the MIT System (June 1997) and the MIDLA System
(November 1997) which significantly enhanced the Company's 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 to a complete
year of operations, average daily demand transportation volume ("Average
Demand") increased on both systems in 1998. The MIT System's Average Demand
increased 19% to 158,000 Mmbtu in 1998 while the Midla System's Average Demand
increased 13% to 166,000 Mmbtu in 1998

YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996

      As discussed above, the addition of the MIT System in June 1997 and the
MIDLA System in November 1997 significantly impacted the transmission segment.
The dramatic increases to revenue and gross margin in 1997 as compared to 1996
can be attributed to the partial years inclusion of the operations of the two
acquisitions. However, a smaller portion of the increased gross margin in 1997
can be attributed to negotiating higher transportation rates from customers on
the Magnolia System.


                                       18
<PAGE>


END-USER PIPELINES

                                           For the Year Ended December 31,
                                         -----------------------------------
                                           1998         1997         1996
                                         -------      -------       -------
                                      (IN THOUSANDS, EXCEPT AMOUNTS PER MMBTU)

OPERATING REVENUES:
  Marketing                              $90,800      $33,862       $13,367
  End-User Transportation Fees             3,287        2,487         1,144
                                         -------      -------       -------

        TOTAL OPERATING REVENUES          94,087       36,349        14,511
                                         -------      -------       -------

OPERATING EXPENSES:

 Cost of Natural Gas and
  Transportation Charges                  88,822       32,673        13,011
 Operating Expenses                          224          208           106
                                         -------      -------       -------

        TOTAL OPERATING EXPENSES          89,046       32,881        13,117
                                         -------      -------       -------

        GROSS MARGIN                     $ 5,041      $ 3,468       $ 1,394
                                         =======      =======       =======


VOLUME (in Mmbtu)
  Marketing                               40,447       11,867         5,822
  Transportation                          20,415       12,415         6,682
                                         -------      -------       -------

TOTAL VOLUME                              60,862       24,282        12,504
                                         =======      =======       =======


GROSS MARGIN per Mmbtu                   $   .08      $   .14       $   .11


YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

      The Company's end-user segment experienced significant increases in
revenues and gross margin in 1998 compared to 1997, primarily due to 1998 having
the benefit of a complete year of operations of the Champion and Monsanto
Systems (acquired in the MIT Acquisition in June 1997) and Crown Vantage and
Farmlands Systems (acquired in the Midla Acquisition in November 1997). A new
marketing services contract to provide 25 Mmcf/day of marketing services
beginning January 1, 1998 to an industrial facility near Port Hudson, Louisiana
also contributed to the increase in 1998 over 1997.

      This trend of increasing revenues and gross margin is expected to continue
into 1999 as an additional 30 Mmcf/day of natural gas marketing services to a
new cogeneration facility near Baton Rouge began at the end of 1998.

      The Company's gross margin per Mmbtu declined in 1998 compared to 1997.
The decrease is attributable to an increase in marketing activities, which are
characterized by lower margins and higher volumes.

YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996

      The Company's 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 Monsanto System acquired in the MIT
Acquisition in June 1997 accounted for 75% of the increase. In addition, 1997
results included a full year of operations for several end-user pipeline
acquisitions made during 1996.


                                       19
<PAGE>


GATHERING PIPELINES AND NATURAL GAS PROCESSING


                                           For the Year Ended December 31,
                                         -----------------------------------
                                           1998          1997         1996
                                         -------       -------       -------
                                       (IN THOUSANDS, EXCEPT AMOUNTS PER MMBTU)

OPERATING REVENUES:
  Marketing                              $ 6,761       $ 5,597       $ 3,595
  Gathering Transportation Fees            3,732           693           825
  Processing Revenue                       5,107         4,956         2,460
                                         -------       -------       -------

        TOTAL OPERATING REVENUES          15,600        11,246         6,880
                                         -------       -------       -------

OPERATING EXPENSES:

  Cost of Natural Gas and
   Transportation Charges                  4,781         4,548         3,057
  Operating Expenses                       2,410           415           227
  Processing Costs                         4,052         3,566         1,443
                                         -------       -------       -------

        TOTAL OPERATING EXPENSES          11,243         8,529         4,727
                                         -------       -------       -------

        GROSS MARGIN                     $ 4,357       $ 2,717       $ 2,153
                                         =======       =======       =======


VOLUME (in Mmbtu)
  Marketing                                4,326         2,170           972
  Gathering                               48,136        13,603        15,635
  Processing                               2,544         1,850           799
                                         -------       -------       -------

TOTAL VOLUME                              55,006        17,623        17,406
                                         =======       =======       =======


GROSS MARGIN per Mmbtu                   $   .08       $   .15       $   .12


YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

      Revenues, gross margins and volumes increased substantially in 1998
compared to 1997 in the Gathering Pipelines and Natural Gas Processing business
segment.

      The significant increase in gathering activity in 1998 is attributable to
the Anadarko Acquisition that was effective in August 1998. Although the
Company's 1998 operations only included five months of activity from the
Anadarko System, it was responsible for 50% of the volumes gathered and
approximately $1 million of the gross margin earned in 1998. The Company has
been actively integrating the operations of the Anadarko System and expects to
create operational cost savings to be realized during the second half of 1999.

      Despite a 38% increase in the volume of gas processed through its
processing facilities, the Company's gross margin from processing activities
declined significantly in 1998 as compared to 1997. This was due to lower
processing spreads 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.

      Marketing volumes increased 99% in 1998 over 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 volumetric increases are
the result of various acquisitions.


                                       20
<PAGE>


      The Company expects that the volumes, revenues and gross margin of its
gathering and processing business segment will substantially increase 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 - Subsequent Events in the Notes to Consolidated Financial
Statements). There can be no assurance as to whether such improved operating
results will be realized or as to the timing or size of any profits to be
derived from such acquisitions. Factors that may affect the realization of
additional profits include changes in competition, production levels of natural
gas and potential 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 business 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 $132,000 in 1997 due
principally to throughput declines on the Company's pipeline investment in
Alaska. This decrease was more than offset by increased margins created from
marketing transactions on gathering pipelines acquired in the fourth quarter of
1996.

      The volumes and gross margin related to the Company's processing plant
increased in 1997 as a result of having a full year of operations. However, the
processing margins on a per unit basis were negatively impacted by lower
commodity prices in 1997 as compared to 1996. The Company's share of proceeds
from the sale of NGLs and the residue natural gas declines as the price of the
commodity declines. However, a $600,000 expansion of the Harmony Plant's
gathering pipeline in the fourth quarter of 1997 connected four new wells and
increased NGL sales and residue gas sales by approximately 11% and 5%,
respectively.

OTHER INCOME, COSTS AND EXPENSES

YEAR ENDED DECEMBER 31, 1998 COMPARED TO YEAR ENDED DECEMBER 31, 1997

      In 1998, the Company received revenues of $.4 million from its 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 received by the Company on
its Vealmoor Field properties.

      In 1998, the Company's depreciation, depletion and amortization increased
when compared to 1997 primarily due to increased depreciation on assets acquired
in the MIT, Midla and Anadarko Acquisitions. Collectively, these acquisitions
accounted for 105% of the increase of $1.6 million.

      The Company's general and administrative expenses in 1998 increased $2.8
million when compared to 1997 primarily due to the numerous acquisitions the
Company has made during 1997 and 1998. In addition, the increase can be
attributed to the Company's expansion of its infrastructure to allow for
continued growth.

      Interest expense for the year ended December 31, 1998 increased to $3.2
million, from $1.1 million in 1997. The Company was servicing an average of
$45.6 million in debt for the year ended December 31, 1998 as compared to $13.6
million in debt for the year ended December 31, 1997. The increased debt load in
1998 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. The additional expense
related to increased debt levels was mitigated by a reduction in the Company's
weighted average interest rate. The Company's weighted average interest rate was
7.11% and 7.83% for the year ended December 31, 1998 and 1997, respectively.

      The Company recognized annual operating income and net income in 1998 of
$13.6 million and $9.1 million, respectively, as compared to $7.3 million in
operating income and $5.8 million in net income for the year ended 1997. Basic
earnings per share ("EPS") increased 14% from $1.13 in 1997 to $1.29 in 1998.
The significant improvement in EPS is primarily attributable to the positive
impact of accretive acquisitions consummated during 1998 and 1997.

                                       21
<PAGE>


YEAR ENDED DECEMBER 31, 1997 COMPARED TO YEAR ENDED DECEMBER 31, 1996

      In 1997, the Company received revenues of $.3 million from its 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 the Company's Sun
Field properties.

      In 1997, the Company's depreciation, depletion and amortization increased
when compared to 1996 primarily due to increased depreciation on assets acquired
in the MIT and Midla Acquisitions. Collectively, these new acquisitions
accounted for 70% of the increase of $.7 million.

      In 1997, the Company's general and administrative expenses increased when
compared to 1996 primarily due to increased costs associated with the management
of the assets acquired in the MIT and Midla Acquisitions. Collectively, these
new acquisitions accounted for 94% of the increase of $2.2 million.

      In 1997, the Company's 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,
that was outstanding for November and December and used to finance the Midla
Acquisition.

      The Company recognized annual operating income and net income in 1997 of
$7.3 million and $5.8 million, respectively, as compared to $2.6 million in
operating income and $1.9 million in net income for the year ended 1996. Basic
EPS increased 55% from $0.73 in 1996 to $1.13 in 1997. The Company achieved the
increased EPS despite the dilutive effects of issuing additional shares in the
August 1996 and July 1997 common stock offerings. The significant improvement in
EPS is primarily attributable to the positive impact of accretive acquisitions
consummated during 1997.


INCOME TAXES

      As of December 31, 1998, 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 acquisition of Republic.

      For the year ended December 31, 1998, the Company 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 the Company's
income tax expense being lowered by approximately $1.1 million.


CAPITAL RESOURCES AND LIQUIDITY

      The Company had historically funded its capital requirements through cash
flow from operations and borrowings from affiliates and various commercial
lenders. However, the capital resources of the Company were significantly
improved with the equity infusion derived from its initial and secondary Common
Stock offerings in August 1996 and July 1997, respectively.

      The net proceeds of the Company's combined stock offerings contributed
approximately $42.1 million and significantly improved the Company's financial
flexibility. This increased flexibility has allowed the Company to pursue
acquisition and construction opportunities utilizing lower cost conventional
bank debt financing. These 1998 acquisition and construction projects increased
the Company's long term-debt to total capitalization ratio to 54% at December
31, 1998.


                                       22
<PAGE>


      As a result of significantly increased cash flows generated from its
numerous acquisitions, the Company has increased its borrowing availability
under its bank financing agreements with Bank One Texas, N.A. ("Bank One"). In
September 1998, the Company amended and restated its bank financing agreement
with 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
accrue interest at London Inter-bank Offer Rate ("LIBOR") plus 1.25% or the Bank
One base rate less .25%. 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 was established among
Bank One, CIBC Oppenheimer, Texas N.A. ("CIBC"), NationsBank Texas, N.A.
("NationsBank"), collectively the "Lenders" and the Company. The Company was
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 remained 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. The Company 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 and allow for Canadian dollar
denominated loans. In anticipation of a new acquisition in Canada, the committed
amount of 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 risk as the functional currency of a
newly formed Canadian subsidiary will be Canadian dollars. See Note 17 -
Subsequent Events in the Notes to Consolidated Financial Statements for
additional information.

      For the year ended December 31, 1998, the Company generated cash flow from
operating activities of approximately $17.2 and had approximately $47.0 million
available to the Company under its Credit Agreement. At December 31, 1998, the
Company had committed to making approximately $3.7 million in construction
related expenditures for 1999 - see "Construction", and an additional $7.5
million in acquisition related expenditures, as indicated in Note 6 -
Commitments and Contingencies, in the Notes to the Consolidated Financial
Statements. The Company believes that its Credit Agreements and funds provided
by operations will be sufficient for it to meet its operating cash needs for the
foreseeable future, and its projected capital expenditures of approximately $3.7
million. If funds under the Credit Agreements are not available to fund
acquisition and construction projects the Company would seek to obtain such
financing from the sale of equity securities or other debt financing. There can
be no assurances that any such financing will be available on terms acceptable
to the Company. Should sufficient capital not be available, the Company will not
be able to implement its growth strategy.


                                       23
<PAGE>

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 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.

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 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.

      The Company has completed the assessment of its computer software,
hardware and other systems, including embedded technology, relative to Y2K
compliance. Some of the Company's 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 the Company's computer software and
hardware systems. If the problems are not remedied timely, 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 the Company's
results of operation, liquidity and financial condition

      The Company is currently updating some of its software and hardware in
order to improve the timeliness and quality of its business information systems.
A by-product of these improvements includes the purchase of Y2K compliant
software and hardware that otherwise are not Y2K compliant today. Software and
hardware selection has been completed and implementation has begun with
anticipated completion dates ranging from December 1998 to June 1999. A budget
for updating computer software and hardware of approximately $1.0 million
dollars has been established of which $.75 million has been spent through
December 31, 1998. Based on a successful implementation of our Y2K plan, we do
not expect the Y2K issue to pose significant operational problems for the
Company's computer systems.

      The Company plans to complete its assessment of its key vendors, customers
and other third parties by June 30, 1999 in order to assess the impact such
third party Y2K issues will have, if any, on the Company's business operations.
The Company does not anticipate that any third parties' Y2K issues will
materially impact the Company's operations or financial results. With respect to
suppliers, the Company does not utilize any individual supplier in its
operations with whom interruptions for Y2K problems could have a material impact
on the Company's operations and financial results. In addition, there are
alternative suppliers with whom the Company anticipates that it would be able to
obtain sufficient quantities of products to continue to conduct its business.
Because the Company anticipates that it will complete its Y2K remediation
efforts in advance of December 31, 1999, it has not made any contingency plans
with respect to its operations and systems. However, a contingency plan will be
established by the third quarter of 1999 to address any unforeseen issues, or if
the planned improvements are not completed on schedule.

      The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention to comply 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 herein shall 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 the
Company's Common Stock, this disclosure is made for the SOLE PURPOSE of
communicating or disclosing information aimed at correcting, helping to correct
and/or avoid Year 2000 failures.

                                       24
<PAGE>


DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS

      This report includes "forward looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Exchange Act of 1934. All statements other than statements of historical fact
included in this report are forward looking statements. Such forward looking
statements include, without limitation, statements under "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Capital Resources and Liquidity" regarding Midcoast's estimate of the
sufficiency of existing capital resources, whether funds provided by operations
will be sufficient to meet its operational needs in the foreseeable future, and
its ability to utilize NOL carryforwards prior to their expiration. Although
Midcoast believes that the expectations reflected in such forward looking
statements are reasonable, it can give no assurance that such expectations
reflected in such forward looking statements will prove to be correct. The
ability to achieve Midcoast's expectations is contingent upon a number of
factors which include (i) timely approval of Midcoast's acquisition candidates
by appropriate governmental and regulatory agencies, (ii) the effect of any
current or future competition, (iii) retention of key personnel and (iv)
obtaining and timing of sufficient financing to fund operations and/or
construction or acquisition opportunities. Important factors that could cause
actual results to differ materially from the Company's expectations ("Cautionary
Statements") are disclosed in this report, including without limitation those
statements made in conjunction with the forward looking statements included in
this report. All subsequent written and oral forward looking statements
attributable to the Company or persons acting on its behalf are expressly
qualified in their entirety by the Cautionary Statements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

      The Company utilizes derivative financial instruments to manage market
risks associated with certain energy commodities and interest rates. According
to guidelines provided by the Board, the Company enters into exchange-traded
commodity futures, options and swap contracts to reduce the exposure to market
fluctuations in 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. More detailed information about these financial
instruments, as well as the strategies and policies for their use, are provided
in Note 13.- Financial Instruments and Price Risk Management Activities in the
Notes to Conolidated Financial Statements.

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 specified price and the actual price
of natural gas. The Company uses futures and swaps to manage margins on
offsetting fixed-price purchase or sales commitments for physical quantities of
natural gas. Options held to hedge risk provide the right, but not the
obligation, to buy or sell energy commodities at a fixed price. The Company
utilizes options to manage margins and to limit overall price risk exposure.
(See Note 13 - Financial Instruments and Price Risk Management Activities in the
Notes to Consolidated Financial Statements). As of December 31, 1998 and 1997,
the Company had a net unrealized loss on its various open commodity futures,
swaps and option contracts of $896,000 and $81,000, respectively. Utilizing the
sensitivity analysis method and assuming a hypothetical change in natural gas
prices of 10%, the Company would realize a net gain of $258,000 and $29,000 on
contracts held as of December 31, 1998 and 1997, respectively.


                                       25
<PAGE>

INTEREST RATE RISK

      The Company's debt financial instruments are sensitive to market
flucuations in interest rates. The interest rate swap agreements entered into by
the Company effectively convert $65 million of floating-rate debt to fixed-rate
debt (see Note 13 - Financial Instruments and Price Risk Management Activities
in the Notes to Consolidated Financial Statements). The Company makes payments
to counterparties at fixed rates and in return receives payments at floating
rates. The first swap agreement, which has a notional amount of $25 million, was
entered into in December 1997 and was subsequently transferred to another bank
in November 1998 and replaced with a new swap agreement which has an initial
term of two years through December 2000 but is extendible, at the bank's option,
for an additional 3 years. The second swap agreement, with a notional amount of
$40 million, was entered into in October 1998 and has an initial term of 3 years
through November 2001 but is extendible, at the bank's option, for an additional
2 years. Both transactions are recorded using accrual accounting. The table
below presents notional amounts and weighted average interest rates by expected
or contractual maturity dates. Notional amounts are used to calculate the
contractual payments to be exchanged under the swap agreement. The tabular
presentation related to the Company's interest rate risk is illustrated below
(in thousands):


<TABLE>
<CAPTION>

                                                          AS OF DECEMBER 31, 1998
                                                     EXPECTED FISCAL YEAR OF MATURITY
-----------------------------------------------------------------------------------------------------------------
                                                                                                      FAIR
                                        1999        2000        2001       2002         TOTAL         VALUE
-----------------------------------------------------------------------------------------------------------------
LIABILITIES:

<S>                                    <C>         <C>          <C>       <C>          <C>           <C>
Short term  borrowing  - variable
interest rate of 7.25% at
December 31, 1998                      $   754    $    --       $ --      $  --        $   754       $   754
-----------------------------------------------------------------------------------------------------------------
Long-term debt, including
current  portion -- variable
interest  rate of 6.16% at
December 31, 1998                      $   176     $    82      $ --      $78,000       $78,258      $78,258
-----------------------------------------------------------------------------------------------------------------

INTEREST RATE DERIVATIVES:
-----------------------------------------------------------------------------------------------------------------
Interest Rate Swap
-----------------------------------------------------------------------------------------------------------------
Variable to fixed rate -
notional amounts                       $  --        $25,000     $40,000   $  --          $65,000     $   461
-----------------------------------------------------------------------------------------------------------------
Average paid rate                       4.71%         4.71%        4.48%
-----------------------------------------------------------------------------------------------------------------
Average received rate (a)               5.02%         5.08%        5.27%
-----------------------------------------------------------------------------------------------------------------
Net cash flow effect                   $  202        $  236       $  319
-----------------------------------------------------------------------------------------------------------------
</TABLE>
(a) The variable rates presented are the average forward rates for the remaining
    term of each swap agreement.

                                       26
<PAGE>



ITEM 8. FINANCIAL STATEMENTS

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


<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
                                                             =========       =========

          LIABILITIES AND SHAREHOLDERS' EQUITY

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.


                                       28

<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.

                                       29


<PAGE>


                  MIDCOAST ENERGY RESOURCES INC., AND SUBSIDIARIES

                   CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
                         (In thousands, except share data)



<TABLE>
<CAPTION>
                                5%                                                                                       TOTAL
                            CUMULATIVE      COMMON      PAID-IN        ACCUMULATED     UNEARNED          TREASURY     SHAREHOLDERS'
                            PREFERRED
                              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.

                                       30

<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 in 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.

                                       31
<PAGE>


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.

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.

                                       32
<PAGE>


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:

      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


      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.

      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.

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.


                                       33
<PAGE>

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.


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.


                                       34
<PAGE>

      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.

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 Rogue 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.


                                       35
<PAGE>

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.

      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.

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.

      For further information regarding the Anadarko Acquisitions, refer to the
Company's Form 8-K and 8-KA filed on September 22, 1998 and November 20, 1998.

4.   DEBT OBLIGATIONS:

        At December 31, 1998 and 1997, the Company had outstanding debt
obligations as follows (in thousands):


                                                            December 31,
                                                      -----------------------
                                                       1998             1997
                                                      ------           ------

(a)  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)                               $  --            $   31

(b)  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                                    258               425

                                       36
<PAGE>


(c)  Revolving credit line with a bank under a 
     $100 million promissory note (see
     following discussion)                              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 (see following discussion)          754             700
                                                     ---------      ----------
Total debt                                              79,012          29,822

Less current portion                                      (930)           (899)
                                                     ---------      ----------

Total long-term debt                                 $  78,082      $   28,923
                                                     =========      ==========


      (a) In January 1996, Starr County, in which Midcoast owns a 60% interest
and acts as manager, obtained $175,000 from a bank lender to finance the
acquisition of a gas gathering pipeline. The loan was secured by the pipeline
and related contracts. The Note was retired in the first quarter of 1998.

      (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 provide 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.

                                       37
<PAGE>


      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).

  The aggregate maturities of long-term debt at December 31, 1998 are as
follows:

    AS OF DECEMBER 31,                           (In thousands)
    ------------------                           --------------
              1999                                  $   176
              2000                                       82
              2001                                      --
              2002                                   78,000
                                                    -------
              Total                                 $78,258
                                                    =======

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 Federal
Energy Regulatory Commission 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.

                                       38
<PAGE>


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 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 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).


                                       39
<PAGE>

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 were all 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.

      The tax effect of significant temporary differences representing deferred
tax assets and liabilities at December 31, 1998 and 1997, are as follows (in
thousands):

                                                         December 31,
                                                  -------------------------
                                                     1998           1997
                                                   --------       -------
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)
                                                  ========        =======

      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.


                                       40
<PAGE>

      A reconciliation of the provision for income taxes to the statutory United
States tax rate is as follows (in thousands):

                                          For The Year Ended December 31,
                                      --------------------------------------
                                        1998          1997           1996
                                        ----          ----           ----
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       $  --
                                      =======        =======       =======


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 Companies cash balances with banks exceeded FDIC
limits. At December 31, 1998 and 1997 the 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.


                                       41
<PAGE>

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.

      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:
                                                                WEIGHTED
                                           TOTAL SHARES      AVERAGE PRICE
                                           UNDER OPTION        PER SHARE
                                           --------------    ---------------

        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
                                             ========           ======
                                                       

                                       42
<PAGE>

      The following table summarizes information about fixed stock options
outstanding at December 31, 1998:

                   Options Outstanding                  Options Exercisable
--------------------------------------------------------------------------------
                            Weighted
                            Average
Range                      Remaining       Weighted                    Weighted
of                          Years of       Average                     Average
Exercise     Number        Contractual     Exercise       Number       Exercise
Prices     Outstanding       Life           Price       Exercisable      Price
--------------------------------------------------------------------------------
$ 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
          ----------------------------------------------------------------------

      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 Director are eligible to receive a NQO to purchase 5,000 shares of
Common Stock at the time of the Directors re-election to the Board, subject to
share availability. Options granted under the Director'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:


                                                       For The Year Ended
                                                          December 31,
                                                   ----------------------------
                                                       1998           1997
                                                   -------------   ------------
    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


                                       43
<PAGE>

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 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):

                                                          As of December 31,
                                                   ----------------------------
                                                       1998           1997
                                                   -------------   ------------
    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


                                       44
<PAGE>

   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.

      The following table presents certain financial information relating to the
Company's business segments (in thousands):

                                            For the Year Ended December 31,
                                           ---------------------------------
                                             1998        1997       1996
                                           ---------   ---------  ----------

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
                                           ========    ========   =======

                                       45
<PAGE>

      The identifiable assets of the Company, by segment, are as follows (in
thousands):

                                                  December 31,
                                        ---------------------------------
                                             1998              1997
                                         --------------   ---------------
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
                                         =========        =========


     The depreciation expense of the Company, by segment, is as follows (in
thousands):

                                             For the Year Ended December 31,
                                             --------------------------------
                                              1998       1997        1996
                                             --------   --------   ----------
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
                                             =======    =======    =======


15. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED):

                                                 Quarters Ended
                                -----------------------------------------------
                                   MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
                                    (In thousands, except per share amounts)

 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
                                                                  


                                       46
<PAGE>

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 

                                       47
<PAGE>
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
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 a NGLs, crude oil and CO2 transportation and marketing
company. DPI operates 43 NGL and crude oil trucks and trailers, a fleet of 40
pressurized railcars and in excess of 400,000 gallons of NGL storage facilities
and product treating and handling equipment. The acquisition was 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" and
6" 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.

                                       48
<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 14-2, 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


                                       49
<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           CHARGED                                                 BALANCE
                                    AT                TO COSTS            CHARGED                              AT END
                                    BEGINNING          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                                                                                    
account                              $  --            $  --             $   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.


                                       50


<PAGE>



ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

        None

                                    PART III

ITEM 10.  DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.

ITEM 11.  EXECUTIVE COMPENSATION.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

      Pursuant to instruction G(3) to Form 10-K, Items 10, 11, 12 and 13 are
omitted because the Company will file with the SEC a definitive proxy statement
(the "Proxy Statement") pursuant to regulation 14A under the Securities Exchange
Act of 1934 not later than 120 days after the close of the fiscal year. The
information required by such Items will be included in the Proxy Statement to be
filed in connection with the Company's annual meeting of shareholders scheduled
for May 17, 1999 and is hereby incorporated by reference.

                                     PART IV

ITEM 14.  EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.

     (A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:

     1.   Financial statements.

          All financial statements of Midcoast Energy Resources, Inc. and
          subsidiaries are included under Part II, Item 8 beginning on page 27
          of this Form 10-K.

     2.   Financial statement schedules and supplementary information required
          to be submitted.

      Schedule II - Valuation and qualifying accounts is included on page 50 of
      this Form 10-K.

     3.   An exhibit list is included on page 52 of this Form 10-K.

      (B) REPORTS ON FORM 8-K:

     A report on Form 8-KA was filed during the fourth quarter of 1998. Such
report was filed on November 20, 1998 as an amendment to the Form 8-K filed on
September 22, 1998. The amendment was filed to include the required audited
historical summary of revenue and direct operating expenses of the Anadarko Gas
Gathering System of El Paso Field Services Company for the year ended July 31,
1998. In addition, the unaudited Midcoast Pro Forma Statement of Operations for
the six months ended June 30, 1998 and for the year ended December 31, 1997 and
unaudited Pro Forma Balance Sheet at June 30, 1998 were included.


                                       51
<PAGE>


                         MIDCOAST ENERGY RESOURCES, INC.
                                  EXHIBIT LIST
                                DECEMBER 31, 1998


      Each exhibit identified below is filed as a part of this report. An
asterisk designates exhibits not incorporated by reference to a prior filing;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

EXHIBIT
NUMBER             DESCRIPTION OF EXHIBITS

2.1   Agreement for Sale and Purchase of Harmony Gas Processing Plant and
      Related Gathering System dated October 3, 1996, by and between Koch
      Hydrocarbon Company, a division of Koch Industries, Inc. and Midcoast
      Holdings No. One, Inc. (Incorporated by reference from Midcoast Form 8-K
      dated October 21, 1996, as Exhibit 2.1).

2.2   Stock Purchase Agreement dated March 18, 1997, by and between Midcoast
      Energy Resources, Inc. and Atrion Corporation. (Incorporated by reference
      from Midcoast Form 10-KSB for the fiscal year ended December 31, 1996, as
      Exhibit 2.7).

2.3   Agreement and Plan of Merger dated October 31, 1997 by and between
      Republic Gas Partners, LLC. And Midcoast Energy Resources, Inc.
      (Incorporated by reference from Midcoast Form 8-K dated November 13, 1997
      as Exhibit 2.2)

2.4   Purchase and Sale Agreement dated September 8, 1998, by and between El
      Paso Field Services Company, a Delaware corporation, and Midcoast Gas
      Services, Inc., a Delaware corporation. (Incorporated by reference from
      Midcoast Form 10-Q for the nine month period ended September 30, 1998, as
      Exhibit 2.8).

*2.5  Agreement and Plan of Merger dated March 11, 1999, by and between Dufour
      Petroleum, Inc., Flare L.L.C. Partners and Midcoast Energy Resources, Inc.

*2.6  Purchase and Sale Agreement dated March 23, 1999, by and between Probe
      Exploration Inc. and Midcoast Canada Operating Corporation.

3.1   Articles of Incorporation of Midcoast Energy Resources, Inc. (Incorporated
      by reference from Midcoast Form 10-KSB for the fiscal year ended December
      31, 1992).

3.2   Certificate of Amendment of Articles of Incorporation of Midcoast Energy
      Resources, Inc. (Incorporated by reference from Midcoast Registration
      Statement on Form SB-2 (No.
      333-4643) dated August 8, 1996).

3.3   Certificate of Amendment of Articles of Incorporation of Midcoast Energy
      Resources, Inc. dated May 15, 1998 (Incorporated by reference from
      Midcoast Form 10-Q for the six month period ended June 30, 1998 as Exhibit
      3.4).

*3.4  Certificate of Stock Split of Midcoast Energy Resources, Inc. dated
      February 24, 1999.

3.5   Bylaws of Midcoast Energy Resources, Inc. (Incorporated by reference from
      Midcoast Form 10-KSB for the fiscal year ended December 31, 1992).

4.1   Specimen Certificate for Shares of Common Stock, par value $.01 per share.
      (Incorporated by reference from Midcoast Registration Statement on Form
      SB-2 (No. 333-4643) dated August 8, 1996).

4.2   Representative's Warrants. (Incorporated by reference from Midcoast
      Registration Statement on Form SB-2 (No. 333-4643) dated August 8, 1996).

4.3   Voting Proxy Agreement dated August 5, 1996, by and between Midcoast
      Energy Resources, Inc., Stevens G. Herbst, Kenneth B. Holmes, Jr., Rainbow
      Investments Company and Texas Commerce Bank National Association.
      (Incorporated by reference from Midcoast Registration Statement on Form
      SB-2 (No. 333-4643) dated August 8, 1996).

4.4   Registration Rights Agreement dated August 5, 1996, by and between
      Midcoast Energy Resources, Inc. and Stevens G. Herbst. (Incorporated by
      reference from Midcoast Registration Statement on Form SB-2 (No. 333-4643)
      dated August 8, 1996).

                                       52
<PAGE>


4.5   Registration Rights Agreement dated August 5, 1996, by and between
      Midcoast Energy Resources, Inc. and Kenneth B. Holmes, Jr. (Incorporated
      by reference from Midcoast Registration Statement on Form SB-2 (No.
      333-4643) dated August 8, 1996).

4.6   Registration Rights Agreement dated August 5, 1996, by and between
      Midcoast Energy Resources, Inc. and Rainbow Investments Company.
      (Incorporated by reference from Midcoast Registration Statement on Form
      SB-2 (No. 333-4643) dated August 8, 1996).

4.7   Executive Severance Agreement by and between Midcoast Energy Resources,
      Inc. and Dan Tutcher, dated August 15, 1997. (Incorporated by reference
      from Form 10-K for the year ended December 31, 1997 as Exhibit 4.11)

4.8   Executive Severance Agreement by and between Midcoast Energy Resources,
      Inc. and I.J. Berthelot, II, dated August 15, 1997. (Incorporated by
      reference from Form 10-K for the year ended December 31, 1997 as Exhibit
      4.12)

4.9   Executive Severance Agreement by and between Midcoast Energy Resources,
      Inc. and Richard Robert, dated August 15, 1997. (Incorporated by reference
      from Form 10-K for the year ended December 31, 1997 as Exhibit 4.13)

4.10  Executive Severance Agreement by and between Midcoast Energy Resources,
      Inc. and Duane Herbst, dated August 15, 1997. (Incorporated by reference
      from Form 10-K for the year ended December 31, 1997 as Exhibit 4.14)

4.11  First Amendment to Voting/Proxy Agreement dated April 29, 1998 by and
      between Midcoast Energy Resources, Inc. and Steven G. Herbst, June Herbst,
      Kenneth Holmes, Jr., Dorothy C. Holmes and Rainbow Investments Company and
      Chase Bank of Texas. (Incorporated by reference from Form 10-Q for the
      three months ended March 31, 1998 as Exhibit 4.14)

10.1  Employment Agreement dated January 1, 1993, by and between Midcoast Energy
      Resources, Inc. and Dan C. Tutcher (Incorporated by reference from
      Midcoast Form 10-KSB for the fiscal year ended December 31, 1992).

10.2  Amendment to the Employment Agreement dated April 1, 1993, by and between
      Midcoast Energy Resources, Inc. and Dan C. Tutcher (Incorporated by
      reference from Midcoast Form 10-KSB for the fiscal year ended December 31,
      1993).

10.3  Amendment to Employment Agreement dated April 14, 1997, by and between
      Midcoast Energy Resources, Inc. and Dan Tutcher (Incorporated by reference
      from Midcoast Form 10-QSB for the three-month period ended March 31,
      1997).

10.4  Employment Agreement dated April 30, 1994, by and between Midcoast Energy
      Resources, Inc. and Richard A. Robert (Incorporated by reference from
      Midcoast Form 10-KSB for the fiscal year ended December 31, 1994).

10.5  Amendment to the Employment Agreement dated April 8, 1996, by and between
      Midcoast Energy Resources, Inc. and Richard A. Robert (Incorporated by
      reference from Midcoast Form 10-QSB for the three-month period ended March
      31, 1996).

10.6  Employment Agreement dated April 25, 1995, by and between Midcoast Energy
      Resources, Inc. and I.J. Berthelot, II (Incorporated by reference from
      Midcoast Form 10-KSB for the fiscal year ended December 31, 1995).

10.7  Amendment to Employment Agreement dated April 14, 1997, by and between
      Midcoast Energy Resources, Inc. and I.J. Berthelot, II (Incorporated by
      reference from Midcoast Form 10-QSB for the three-month period ended March
      31, 1997).

10.8  Amendment to Employment Agreement dated December 8, 1995, by and between
      Midcoast Energy Resources, Inc. and I.J. Berthelot, II (Incorporated by
      reference from Midcoast Form 10-KSB for the fiscal year ended December 31,
      1995).

10.9  Assignment of Net Revenue Interest dated July 1, 1994, by and between
      Texline Gas Company and Midcoast Energy Resources, Inc. (Incorporated by
      reference from Midcoast Form 10-KSB for the fiscal year ended December 31,
      1994).


                                       53
<PAGE>


10.10 Assignment of Net Revenue Interest dated July 1, 1994, by and between
      Rainbow Investments Co. and Midcoast Energy Resources, Inc. (Incorporated
      by reference from Midcoast Form 10-KSB for the fiscal year ended December
      31, 1994).

*10.11  Midcoast Energy Resources, Inc. 1996 Incentive Stock Plan, as amended on
        May 15, 1998.

10.12   Credit Agreement dated August 22, 1996, by and between Bank One, Texas
        N.A. and Midcoast Energy Resources, Inc., Magnolia Pipeline Corporation
        and H&W Pipeline Corporation. (Incorporated by reference from Midcoast
        Form 10-QSB for the nine-month period ended September 30, 1996).

10.13   Midcoast Energy Resources, Inc. 1997 Non-Employee Director Stock Option
        Plan (Incorporated by reference from Midcoast Form 10-QSB for the
        three-month period ended March 31, 1997).

10.14   Indemnity Agreement dated April 23, 1997 between Midcoast Energy
        Resources, Inc. and Richard A. Robert (Incorporated by reference from
        Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
        26, 1997).

10.15   Indemnity Agreement dated April 23, 1997 between Midcoast Energy
        Resources, Inc. and I.J. Berthelot, II. (Incorporated by reference from
        Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
        26, 1997). 10.16 Indemnity Agreement dated April 23, 1997 between
        Midcoast Energy Resources, Inc. and Richard N. Richards. (Incorporated
        by reference from Midcoast Registration Statement on Form S-1 (No.
        333-27885) dated June 26, 1997)

10.17   Indemnity Agreement dated April 23, 1997 between Midcoast Energy
        Resources, Inc. and Duane S. Herbst. (Incorporated by reference from
        Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
        26, 1997)

10.18   Indemnity Agreement dated April 23, 1997 between Midcoast Energy
        Resources, Inc. and Dan C. Tutcher. (Incorporated by reference from
        Midcoast Registration Statement on Form S-1 (No. 333-27885) dated June
        26, 1997)

10.19   First Amendment to Credit Agreement dated May 30, 1997 by and between
        Bank One, Texas N.A. and Midcoast Energy Resources, Inc., Magnolia
        Pipeline Corporation, H&W Pipeline Corporation, Magnolia Resources,
        Inc., Magnolia Gathering Inc., Midcoast Holdings No. One, Inc., Midcoast
        Gas Pipeline, Inc., Nugget Drilling Corporation, Midcoast Marketing,
        Inc., AlaTenn Energy Marketing Company, and Tennessee River Intrastate
        Gas Co. (Incorporated by reference from Midcoast Registration Statement
        on Form S-1 (No. 333-27885) dated June 26, 1997)

10.20   Second Amendment to Credit Agreement dated October 31, 1997 by and
        between Bank One, Texas N.A. and Midcoast Energy Resources, Inc.,
        Magnolia Pipeline Corporation, H&W Pipeline Corporation, Magnolia
        Resources, Inc., Magnolia Gathering Inc., Midcoast Holdings No. One,
        Inc., Midcoast Gas Pipeline, Inc., Nugget Drilling Corporation, Midcoast
        Marketing, Inc., AlaTenn Energy Marketing Company, Tennessee river
        Intrastate Gas Co., Mid Louisiana Gas Company, Mid Louisiana Gas
        Transmission Company and Midla Energy Services Company. (Incorporated by
        reference from Midcoast Form 8-K dated October 13, 1997).

10.21   First Amendment to Credit Agreement dated October 31, 1997 by and
        between Bank One, Texas N.A. and Midcoast Interstate Transmission, Inc.
        (f/k/a/ Alabama Tennessee Natural Gas Company). (Incorporated by
        reference from Midcoast Form 8-K dated October 13, 1997).

10.22   Third Amendment to Employment Agreement dated March 2, 1998 by and
        between Midcoast Energy Resources, Inc. and Dan Tutcher. (Incorporated
        by reference from Form 10-K/A dated February 2, 1999, for the fiscal
        year ended December 31, 1997).

10.23   Third Amendment to Employment Agreement dated March 18, 1998 by and
        between Midcoast Energy Resources, Inc. and I.J. Berthelot, II.
        (Incorporated by reference from Form 10-K/A dated February 2, 1999, for
        the fiscal year ended December 31, 1997).

                                       54
<PAGE>


10.24   Second Amendment to Employment Agreement dated March 18, 1998 by and
        between Midcoast Energy Resources, Inc. and Richard Robert.
        (Incorporated by reference from Form 10-K/A dated February 2, 1999, for
        the fiscal year ended December 31, 1997).

10.25   Amended and Restated Credit Agreement dated August 31, 1998, by and
        among Midcoast Energy Resources, Inc., and, Bank One Texas, N.A., CIBC
        Inc., and Nationsbank, N.A. (Incorporated by reference from Midcoast
        Form 10-Q for the nine month period ended September 30, 1998, as Exhibit
        10.30).

*10.26  First Amendment to the Amended and Restated Credit Agreement dated March
        12, 1999, by and among Midcoast Energy Resources, Inc., and, Bank One
        Texas, N.A., CIBC Inc., and Nationsbank, N.A.

*21.1   Schedule listing subsidiaries of Midcoast Energy Resources, Inc.

*23.1   Consent of independent accountants.

*27.1   Financial Data Schedule for the year ended December 31, 1998.


                                       55

<PAGE>
                                  Signatures

        In accordance with Section 13 or 15 (d) of the Securities and Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

     MIDCOAST ENERGY RESOURCES, INC.
     (Registrant)


BY:  /S/ DAN C. TUTCHER
     Dan C. Tutcher
     Chief Executive Officer


Date:  March 31, 1999


     In accordance with the Securities and Exchange Act of 1934, this report has
been signed by the following persons on behalf of the registrant and in the
capacities and on the dates indicated.


SIGNATURES                         CAPACITY IN WHICH SIGNED
----------                         ------------------------

/s/ DAN C. TUTCHER                 Chairman of the Board
(Dan C. Tutcher)                   Chief Executive Officer
Date:________________              and President


/s/ I. J. BERTHELOT, II            Executive Vice President, Chief Operating
(I. J. Berthelot, II)              Officer and Director
Date:________________


/s/ TED COLLINS, JR.               Director
(Ted Collins, Jr.)
Date:________________


/s/ CURTIS J. DUFOUR III.          Director
(Curtis J. Dufour, III.)
Date:________________


/s/ RICHARD N. RICHARDS            Director
(Richard N. Richards)
Date:________________


/s/ RICHARD A. ROBERT              Treasurer, Principal Financial Officer
(Richard A. Robert)                Principal Accounting Officer
Date:________________


/s/ BRUCE WITHERS                  Director
(Bruce Withers)
Date:________________