U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q/A
(Amendment No. 1)
[X] Quarterly Report Under Section 13 or 15(d) of
the Securities Exchange
Act of 1934 for the Quarterly Period Ended September 30, 1998
[ ] Transition Report Pursuant to Section 13 or
15(d) of the Securities
Exchange Act of 1934
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.
Incorporation or Organization) Employer
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
Indicate by check mark whether the registrant (1) has
filed all reports required to be filed by Section 13 or 15(d)
of the Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No _
On September 30, 1998, there were outstanding 5,719,665
shares of the Company's common stock, par value $.01 per share.
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF
OPERATIONS
The Company has grown significantly as a result of the
construction and acquisition of new pipeline facilities.
Since January of 1997, the Company acquired 16 pipelines
for an aggregate acquisition cost of over $111.9 million.
The Company believes the historical results of operations
do not fully reflect the operating efficiencies and
improvements that are expected to be achieved by
integrating the acquired 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. Most of the Company's operating
costs do not vary directly with volume on existing
systems, thus, increases or decreases in transportation
volumes on existing systems generally have a direct effect
on net income. Also, the addition of new pipeline systems
typically results in a larger percentage of revenues being
added to operating income as fixed overhead components are
allocated over more systems. The Company derives its
revenues from three primary sources: (i) transportation
fees from pipeline systems owned by the Company, (ii) the
processing and treating of natural gas and (iii) the
marketing of natural gas.
Transportation fees are received by the Company for
transporting gas owned by other parties through the
Company's pipeline systems. Typically, the Company incurs
very little incremental operating or administrative
overhead cost to transport gas through its pipeline
systems, thereby recognizing a substantial portion of
incremental transportation revenues as operating income.
The Company's natural gas processing revenues are realized
from the extraction and sale of 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 NGL and residual gas revenues as a fee
for processing the producers gas. The contracts based on
keep-whole provide that the Company is required to
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 NGL's. 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 operations can be
adversely affected by declines in NGL prices, declines in
gas throughput or increases in shrinkage or fuel costs.
The Company's gas marketing revenues are realized through
the purchase and resale of natural gas to the Company's
customers. Generally, gas-marketing activities will
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 includes the full commodity price of
the natural gas acquired. The operating income the Company
recognizes from its gas marketing efforts is the
difference between the price at which the gas was
purchased and the price at which it was resold to the
Company's customers. The Company's strategy is to focus
its marketing activities on Company owned pipelines. The
Company's marketing activities have historically varied
greatly in response to market fluctuations.
The Company has had quarter-to-quarter fluctuations in
its financial results in the past due to the fact that
the Company's natural gas sales and pipeline throughputs
can be affected by changes in demand for natural gas
primarily because of the weather. Although, historically,
quarter-to-quarter fluctuations resulting from weather
variations have not been significant, the acquisitions of
the Magnolia System, the MIT System and the MLGC System
have increased the impact that weather conditions have on
the Company's financial results. In particular, demand on
the Magnolia System, MIT System and MLGC System fluctuate
due to weather variations because of the large municipal
and other seasonal customers which are served by the
respective systems. As a result, historically the winter
months have generated more income than summer months on
these systems. There can be no assurances that the
Company's efforts to minimize such effects will have any
impact on future quarter-to-quarter fluctuations due to
changes in demand resulting from variations in weather
conditions. Furthermore, future results could differ
materially from historical results due to a number of
factors including but not limited to interruption or
cancellation of existing contracts, the impact of
competitive products and services, pricing of and demand
for such products and services and the presence of
competitors with greater financial resources.
The Company has also from time to time derived
significant income by capitalizing on opportunities in
the industry to sell its pipeline systems on favorable
terms as the Company receives offers for such systems
which are suited to another company's pipeline network.
Although no substantial divestitures are currently under
consideration, the Company will from time to time solicit
bids for selected properties which are no longer suited
to its business strategy.
RESULTS OF OPERATIONS
The following tables present certain data for major
operating units of Midcoast for the three and nine-month
periods ended September 30, 1997 and September 30, 1998.
A discussion follows which explains significant factors
that have affected Midcoast's operating results during
these periods. Gross margin for each of the units is
defined as the revenues of the unit less related direct
costs and expenses of the unit. As previously discussed,
the Company provides natural gas marketing services to
its customers. For analysis purposes, the Company
accounts for the marketing services by recording the
marketing activity on the operating unit where it occurs.
Therefore, the gross margin for each of the major
operating units include a transportation and marketing
component.
TRANSMISSION PIPELINES
(In thousands, except gross margin per Mmbtu)
<TABLE>
<CAPTION>
For the Three For the Nine
Months Ended Months Ended
September September September September
30,1997 30,1998 30,1997 30,1998
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Transportation Fees $ 856 $1,454 $ 1,835 $ 4,751
Marketing 13,660 21,862 23,359 85,591
Total operating revenues 14,516 23,316 25,194 90,342
OPERATING EXPENSES:
Cost of Natural Gas and 12,662 20,225 21,865 78,519
Transportation Charges
Operating Expenses 599 1,106 905 3,308
Total operating expenses 13,261 21,331 22,770 81,827
GROSS MARGIN $ 1,255 $ 1,985 $ 2,424 $ 8,515
VOLUME (in Mmbtu)
Transportation 9,146 11,459 16,703 37,190
Marketing 5,588 9,972 9,174 36,838
TOTAL VOLUME 14,734 21,431 25,877 74,028
GROSS MARGIN per Mmbtu $ .09 $ .09 $ .09 $ .12
</TABLE>
The Company's entrance into the regulated interstate
pipeline business began with the acquisition of the MIT
System (June 1997) and the MLGC System (November 1997)
which significantly enhanced the Company's transmission
pipeline operations in 1998. Significant increases in
revenues, sales volumes and gross margin are attributable
to full quarter and year-to-date operations of the MIT and
MLGC Systems. In the three and nine month periods ended
September 30, 1998, revenues increased 61% and 259%,
respectively on corresponding volume increases of 45% and
186%. For the same periods, gross margins increased by
58% and 251% to $1,985,000 and $8,515,000 from $1,255,000
and $2,424,000.
The gross margin per Mmbtu was affected by the inclusion
of the MIT System and the MLGC System during the 1998
periods. These systems are subject to seasonal margin
variations. The MIT System has a lower summer (April -
October) tariff rate than its winter (November - March)
tariff rate. The MLGC System allows customers to reduce
their demand capacity during the summer months.
The Company has succeeded in increasing contracted
transportation volumes on both the MIT System and MLGC
System since completing the acquisitions. Through the
completion of two successful open seasons, contracted
demand on the MIT System has increased by 28% for the
winter of 1998 which includes new long term transportation
agreements with the cities of Huntsville and Decatur,
Alabama. Construction of new pipeline facilities on the
MIT System is planned to accommodate the incremental
volumes generated by the new transportation contracts and
has received FERC approval. Contracted demand on the MLGC
System has increased due to the execution of a new 20
Mmcf/day gas transportation contract to service a new
cogeneration facility near Baton Rouge. Transportation
services under the new contract will commence upon the
completion of related construction of new facilities
expected in the fourth quarter of 1998.
END-USER PIPELINES
<TABLE>
<CAPTION>
(In thousands, except gross margin per Mmbtu)
For the Three For the Nine
Months Ended Months Ended
September September September September
30,1997 30,1998 30,1997 30,1997
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Transportation Fees $ 833 $ 897 $ 1,713 $ 2,456
Marketing 6,602 21,890 14,883 65,087
Total operating revenues 7,435 22,787 16,596 67,543
OPERATING EXPENSES:
Cost of Natural Gas and 6,494 21,590 14,331 63,638
Transportation Charges
Operating Expenses 75 48 163 141
Total operating expenses 6,569 21,638 14,494 63,779
GROSS MARGIN $ 866 $ 1,149 $ 2,102 $ 3,764
VOLUME (in Mmbtu)
Transportation 3,484 6,003 7,308 15,441
Marketing 2,672 10,293 5,938 29,589
TOTAL VOLUME 6,156 16,296 13,246 45,030
GROSS MARGIN per Mmbtu $ .14 $ .07 $ .16 $ .08
</TABLE>
The Company's end-user operating unit experienced
increases in sales volumes for the three and nine month
periods ended September 30, 1998, primarily due to the
full quarter and year-to-date operations of the
acquisitions of the TRIGAS Systems (June 1997) and MLGT
System (November 1997). As a result, in the three and
nine month periods ended September 30, 1998, revenues
increased 206% and 307%, and gross margin increased 33%
and 79%, respectively.
The Company's gross margin per Mmbtu declined for the
three and nine month periods ended September 30, 1998.
The decrease is attributable to an increase in marketing
activities which are characterized by lower margins and
higher volumes.
Since Midcoast's ownership of the MLGT System, new
marketing services contracts have been executed to provide
25 Mmcf/day of new marketing services beginning January 1,
1998 to an industrial facility near Port Hudson,
Louisiana, and an additional 40 Mmcf/day of natural gas
marketing services to a new cogeneration facility near
Baton Rouge by the end of 1998. The Company is currently
constructing a new high pressure end-user pipeline system
to service the new contracts. The new pipeline will allow
the Company to compete for potential new customers along
the industrial corridor of the Mississippi River requiring
natural gas at pressures previously not available through
the MLGT System.
<TABLE>
<CAPTION>
GATHERING PIPELINES AND NATURAL GAS PROCESSING
(In thousands, except gross margin per Mmbtu)
For the Three For the Nine
Months Ended Months Ended
September September September September
30,1997 30,1998 30,1997 30,1998
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Gathering Transportation Fees $ 147 $ 1,346 $ 504 $ 1,789
Processing Revenues 1,099 825 3,626 2,931
Marketing 1,266 1,979 4,017 4,206
Total operating revenues 2,512 4,150 8,147 8,926
OPERATING EXPENSES:
Cost of Natural Gas and 1,068 1,514 3,343 3,051
Transportation Charges
Processing cost 511 325 1,737 1,186
Operating Expenses 419 638 1,195 1,468
Total operating expenses 1,998 2,477 6,275 5,705
GROSS MARGIN $ 514 $ 1,673 $ 1,872 $ 3,221
VOLUME (in Mmbtu)
Gathering 3,177 16,568 9,483 27,965
Processing 428 468 1,383 1,489
Marketing 561 1,490 1,711 3,487
TOTAL VOLUME 4,166 18,526 12,577 32,941
GROSS MARGIN per Mmbtu $ .12 $ .09 $ .15 $ .10
</TABLE>
The gathering pipelines and natural gas processing
operating unit reflected mixed results for the three and
nine month periods ended September 30, 1998 as compared to
the equivalent periods in 1997. Although margins per
Mmbtu declined for the gathering, processing and marketing
units, overall gross margin improved due to increased
volumes gathered, processed and marketed during these
periods.
Gathering volumes increased 421% and 195% for the three
and nine-month periods ended September 30, 1998,
respectively. These volumetric increases are primarily
the result of the Company's acquisition of the Anadarko
System. Although the Anadarko System was operational for
only two-months in the quarter, it is responsible for 57%
and 34% of the volumes gathered for the three and nine
month periods ended September 30, 1998. In addition,
gathering volumes increases are associated with offshore
gathering systems acquired in the Midla Acquisition and
the Company's gathering line investment in Alaska.
Processing volumes increased 9% and 8% for the three and
nine-month periods ended September 30, 1998, respectively.
Weaker NGL pricing, however, mitigated the volume
increase, and therefore, the gross margins for 1998 were
comparable to the corresponding periods in 1997. The
future profitability of the Harmony Plant will be affected
by changes in commodity pricing of NGL and natural gas,
production curtailments, shut-in wells and also the
natural declines in the deliverability of the reservoirs
connected and dedicated to Midcoast's processing plant.
Marketing volumes increased 166% and 104%, for the three
and nine month periods ended September 30, 1998,
respectively. These volumetric increases are primarily
the result of the Texana Acquisition. The Texana system
accounted for 37% and 47% of the total marketing volumes
for the three and nine-month periods ended September 30,
1998, respectively.
The overall decline in gross margin per Mmbtu in 1998 is
primarily attributable to significant volumes gathered by
offshore pipelines acquired in the Midla Acquisition and
significant volumes marketed on the Texana System. These
systems receive a low rate on a per Mmbtu basis and were
not included in the 1997 periods.
OTHER INCOME, COSTS AND EXPENSES
In the three and nine month period ended September 30,
1998, the Company received revenues of $49,000 and
$374,000, respectively from its oil and gas properties as
compared to $60,000 and $212,000 over the same periods in
1997. The increase is primarily attributable to a one-
time settlement received by the Company on its Vealmoor
Field properties. Also, certain of Midcoast's oil and
gas properties in the Sun Field have been approved for
changes in well spacing and tertiary recovery by
depressurization. The Company believes these factors may
contribute to increased volumes and revenues for its oil
and gas properties.
In the three and nine month period ended September 30,
1998, the Company's depreciation, depletion and
amortization increased to $813,000 and $2,202,000,
respectively from $414,000 and $983,000 when compared to
1997. The increase is primarily due to increased
depreciation on assets acquired in the MIT and Midla
Acquisitions. Collectively, these new acquisitions
accounted for 54% and 57% of the increases of $399,000 and
$1,219,000.
In the three and nine month period ended September 30,
1998, the Company's general and administrative expenses
increased to $1,437,000 and $4,353,000, respectively from
$522,000 and $1,477,000 in 1997. The increase is
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 93% and 96% of the increase of $915,000 and
$2,876,000. In addition, the increase can be attributed
to the Company's expansion of its infrastructure to allow
for continued growth.
Interest expense for the three and nine months ended
September 30, 1998 increased to $807,000 and $2,043,000,
respectively from $184,000 and $680,000 in 1997. The
Company was servicing an average of $45.9 and $36.0
million in debt for the three and nine months ended
September 30, 1998 as compared to $8.5 and $10.8 million
in debt for the three and nine months ended September 30,
1997. The increased debt load in 1998 is primarily
associated with the Company's October 31, 1997 acquisition
of Republic and, its September 1998 acquisition of
Anadarko. 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 7.59% and 7.57% for the three
month and nine-month period ended September 30, 1998 as
compared to 8.66% and 8.40% for the three month and nine-
month period ended September 30, 1997.
The Company recognized net income for the three and nine-
month period ended September 30, 1998 of $1.6 million and
$6.0 million, respectively, as compared to $1.2 million
and $2.9 million for the equivalent period in 1997. Basic
earnings per share ("EPS") for the three and nine month
period ended September 30, 1998 increased 27% and 30%,
respectively from $.22 and $.82 in 1997 to $.28 and $1.07
in 1998. The Company achieved the increased EPS despite
the dilutive effects of issuing additional shares in the
July 1997 common stock offering. The significant
improvement in EPS is primarily attributable to the
positive impact of accretive acquisitions consummated
during 1997.
INCOME TAXES
As of December 31, 1997, the Company had net operating
loss ("NOL") carryforwards of approximately $17.0 million,
expiring in various amounts from 1998 through 2012. The
Company's predecessor and Republic generated these NOLs.
The ability of the Company to utilize the carryforwards is
dependent upon the Company generating sufficient taxable
income and will be affected by annual limitations
(currently estimated at approximately $4.9 million) on the
use of such carryforwards due to a change in shareholder
control under the Internal Revenue Code triggered by the
Company's July 1997 common stock offering and the change
of ownership created by the acquisition of Republic. The
Company believes, however, that the limitation will not
materially impact the Company's ability to utilize the NOL
carryforwards prior to their expiration. Depending on
profitability, the limitation could result in the
Company's income tax expense to increase as compared to
previous years where no such limitation existed.
CAPITAL RESOURCES AND LIQUIDITY
In September 1998, the Company increased its borrowing
availability under its bank financing agreements with Bank
One Texas, N.A. ("Bank One"). Amendments to the credit
agreements (collectively the "Credit Agreements") 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 Agreements 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 Agreements 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 Agreements
will accrue interest at 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 Agreements have eliminated escalations
of the interest rate spread when borrowings exceed 50% of
the borrowing base.
Under the amended Credit Agreements, a credit sharing has
been established among Bank One, CIBC Oppenheimer, Texas
N.A., Nationsbank Texas, N.A., 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.
The Credit Agreements are secured by all accounts
receivable, contracts, the pledge of the stock of MIT,
MLGC and the pledge of the stock of Magnolia Pipeline
Corporation and a first lien security interest in the
Company's pipeline systems. The Credit Agreements contains
a number of customary covenants that require the Company
to maintain certain financial ratios, and limit the
Company's ability to incur additional indebtedness,
transfer or sell assets, create liens, or enter into a
merger or consolidation. Midcoast was in compliance with
such financial covenants at September 30, 1998.
For the nine months ended September 30, 1998, the Company
generated cash flow from operating activities of
approximately $7.5 million before changes in working
capital accounts and had approximately $79.2 million
available to the Company under its Credit Agreements. At
September 30, 1998, the Company had committed to making
approximately $8.2 million in capital expenditures for the
remainder of 1998. 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 $8.2 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.
RISK MANAGEMENT
According to guidelines provided by the Board, the Company
enters into exchange-traded commodity futures, options and
swap contracts to reduce the exposure to market
fluctuations in price and transportation costs of energy
commodities and is not to engage in speculative trading.
Approvals are required from senior management prior to the
execution of any financial derivative. The financial
derivatives have pricing terms indexed to both the New
York Mercantile Exchange and Kansas City Board of Trade.
The Company's market exposures arise from inventory
balances and fixed price purchase and sale commitments.
The Company uses the exchange-traded commodities to manage
and hedge price risk related to these market exposures.
Gas futures involve the buying and selling of natural gas
at a fixed price. Over-the-counter swap agreements
require the Company to receive or make payments based on
the difference between a specified price and the actual
price of natural gas. The Company uses futures and swaps
to manage margins on offsetting fixed-price purchase or
sales commitments for physical quantities of natural gas.
Options held to hedge risk provide the right, but not the
obligation, to buy or sell energy commodities at a fixed
price. The Company utilizes options to manage margins and
to limit overall price risk exposure.
YEAR 2000 COMPLIANCE
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
or 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 byproduct 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 $.5 million has been
spent through September 30, 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 March 31, 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.
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.
Signature
In accordance with the requirements of the Exchange Act, the
Registrant caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
MIDCOAST ENERGY RESOURCES, INC.
(Registrant)
BY: /s/ Richard A. Robert
Richard A. Robert
Principal Financial Officer
Treasurer
Principal Accounting Officer
Date: January 7, 1999
