U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] Quarterly Report Under Section 13 or 15(d) of the
Securities Exchange
Act of 1934 for the Quarterly Period Ended September 30, 1999
[ ] 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. 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
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 30,1999, there were outstanding 10,722,013
shares of the Company's common stock, par value $.01 per share.
GLOSSARY
The following abbreviations, acronyms, or defined terms used in
this Form10-Q are defined below:
DEFINITIONS
BOD Board of directors of Midcoast Energy Resources, Inc.
BTU British thermal unit.
Company Midcoast Energy Resources, Inc.
DPI Dufour Petroleum, Inc., a wholly owned subsidiary of
Midcoast Energy Resources, Inc.
EBITDA Earnings Before Interest, Taxes, Depreciation and Amortization.
EPS Basic earnings per share.
FASB Financial Accounting Standards Board.
FERC Federal Energy Regulatory Commission.
KPC The November 1999 acquisition of the Kansas Pipeline Company
Acquisition system.
KPC System A 1,120 mile interstate transmission pipeline.
LIBOR London Inter Bank Offering Rate.
Mcf/day Thousand cubic feet of gas (per day).
MCOC Midcoast Canada Operating Corporation, a wholly
owned subsidiary of Midcoast Energy Resources, Inc.
Midcoast Midcoast Energy Resources, Inc.
MIDLA The October 1997 acquisition of the MLGC and MLGT Systems.
Acquisition
MIT The May 1997 acquisition of the MIT and TRIGAS Systems.
Acquisition
MIT System A 288-mile interstate transmission pipeline.
MLGC System A 386-mile interstate transmission pipeline.
MLGT System A Louisiana intrastate pipeline.
Mmbtu Million british thermal units.
Mmcf/day Million cubic feet of gas (per day).
NGL's Natural Gas Liquids.
NOL Net operating losses.
SeaCrest SeaCrest Company, L.L.C., a 70% owned subsidiary of
Mid Louisiana Gas Transmission Company, which is a
wholly owned subsidiary of Midcoast Energy
Resources, Inc.
SFAS Statement of Financial Accounting Standards
TRIGAS Two end-user pipelines in Northern Alabama.
System
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
Quarterly Report on Form 10-Q for the
Quarter Ended September 30, 1999
Page
Number
PART I. FINANCIAL INFORMATION
Item 1. Unaudited Financial Statements
Consolidated Balance Sheets as of December 31, 1998
and September 30, 1999 3
Consolidated Statements of Operations for the three months
and nine months ended September 30, 1998 and
September 30, 1999 4
Consolidated Statement of Shareholders' Equity for the year
ended December 31, 1998 and the nine months ended
September 30, 1999 5
Consolidated Statements of Cash Flows for the three months
and nine months ended September 30, 1998 and
September 30, 1999 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 12
PART II. OTHER INFORMATION 21
SIGNATURE 22
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
<TABLE>
<CAPTION>
DECEMBER 31, SEPTEMBER 30,
1998 1999
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 200 $ 1,468
Accounts receivable, net of allowance of 33,020 48,597
$92 and $104 , respectively
Materials and supplies, at average cost 1,363 1,425
Total current assets 34,583 51,490
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities 150,041 192,041
Investment in transmission facilities 1,342 1,358
Natural gas processing facilities 4,917 11,115
Oil and gas properties, using the full- 1,383 1,383
cost method of accounting
Other property and equipment 2,872 6,329
160,555 212,226
ACCUMULATED DEPRECIATION, DEPLETION AND (6,308) (10,578)
AMORTIZATION
154,247 201,648
OTHER ASSETS, net of amortization 2,512 1,946
Total assets $ 191,342 $ 255,084
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued $ 32,540 $ 39,434
liabilities
Current portion of long-term debt 176 176
payable to banks
Short-term borrowing from bank 754 10,243
Other current liabilities 124 27
Total current liabilities 33,594 49,880
LONG TERM DEBT PAYABLE TO BANKS 78,082 63,395
OTHER LIABILITIES 2,024 2,078
DEFERRED INCOME TAXES 10,808 11,029
MINORITY INTEREST IN CONSOLIDATED 550 520
SUBSIDIARIES
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per
share; authorized 31,250,000 shares; 71 107
issued 7,149,513 and 10,722,013
shares, respectively (Note 2)
Paid in capital 80,955 135,544
Accumulated deficit (11,947) (5,094)
Unearned compensation (4) -
Less: Cost of 181,125 and 161,156 (2,791) (2,375)
treasury shares, respectively
Total shareholders' equity 66,284 128,182
Total liabilities and shareholders' $ 191,342 $ 255,084
equity
</TABLE>
The accompanying notes are an integral part of these financial
statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Energy marketing $ 45,732 $ 89,379 $ 154,885 $ 238,821
revenue
Transportation fees 3,695 6,677 8,995 16,875
Natural gas processing 825 5,269 2,931 10,376
and treating revenue
Other 49 519 374 1,293
Total operating revenues 50,301 101,844 167,185 267,365
OPERATING EXPENSES:
Energy marketing expenses 44,838 90,094 149,268 233,782
Natural gas processing 624 4,023 2,089 8,924
and treating costs
Depreciation, depletion 813 1,850 2,202 4,793
and amortization
General and administrative 1,437 1,986 4,353 5,936
Total operating expenses 47,712 97,953 157,912 253,435
Operating income 2,589 3,891 9,273 13,930
NON-OPERATING ITEMS:
Interest expense (807) (775) (2,043) (3,651)
Minority interest in (15) (5) (31) (28)
consolidated subsidiaries
Other income (expense),net 17 (23) 117 (115)
INCOME BEFORE INCOME TAXES 1,784 3,088 7,316 10,136
PROVISION FOR INCOME TAXES
Current (13) (497) (104) (1,326)
Deferred (191) 167 (1,143) (221)
NET INCOME $ 1,580 $ 2,758 $ 6,069 $ 8,589
EARNINGS PER COMMON
SHARE:
BASIC $ 0.22 $ 0.26 $ 0.85 $ 1.00
DILUTED $ 0.22 $ 0.26 $ 0.82 $ 0.98
WEIGHTED AVERAGE NUMBER
OF COMMON SHARES
OUTSTANDING:
BASIC 7,130,369 10,559,172 7,120,044 8,585,037
DILUTED 7,344,398 10,795,517 7,357,840 8,804,258
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MIDCOAST ENERGY RESOURCES INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(In thousands, except share data)
<TABLE>
<CAPTION>
TOTAL
COMMON PAID-IN ACCUMULATED UNEARNED TREASURY SHAREHOLDERS
STOCK CAPITAL DEFICIT COMPENSATION STOCK EQUITY
<S> <C> <C> <C> <C> <C> <C>
Balance, December 31, 1997 $ 71 $ 80,681 $ (19,283) $ (18) $ - $ 61,451
Shares issued or vested - - - 14 - 14
under Various stock-based
Compensation arrangements
Warrants exercised - 274 - - - 274
Net income - - 9,113 - - 9,113
Treasury stock purchased - - - - (2,791) (2,791)
(181,125 shares)
Common stock dividends,
$.24 per share - - (1,777) - - (1,777)
Balance, December 31, 1998 $ 71 $ 80,955 $ (11,947) $ (4) $ (2,791) $ 66,284
Net income - - 8,589 - - 8,589
Shares issued or vested
under Various stock-based
Compensation arrangements - - - 4 - 4
Stock options exercised - 42 - - - 42
Sale of 3,570,000 shares of 36 54,547 - - - 54,583
common stock (Note 2)
Foreign currency translation - - (68) - - (68)
Treasury stock purchased - - - - (2,406) (2,406)
(143,750 shares)
Treasury stock issued in - - - - 2,822 2,822
connection with the DPI
acquisition (163,719 shares)
Common stock dividends, - - (1,688) - - (1,688)
$.07 per share
Balance, Septmeber 30, 1999 $ 107 $ 135,544 $ (5,094) $ - $ (2,375) $ 128,182
(Unaudited)
</TABLE>
The accompanying notes are an integral part of these consolidated financial
statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
CASH FLOWS FROM
OPERATING ACTIVITIES:
Net income $ 1,580 $ 2,758 $ 6,069 $ 8,589
Adjustments to arrive at
net cash provided (used)
in Operating activities-
Depreciation, depletion 813 1,850 2,202 4,793
and amortization
Increase (Decrease) in 204 (167) 961 221
deferred tax liability
Minority interest in 15 5 57 28
consolidated subsidiaries
Other (71) 72 - 36
Changes in working
capital accounts-
(Increase) Decrease in (1,196) 2,164 9,343 (15,147)
accounts receivable
Increase in other (160) (212) (623) (238)
current assets
Increase (Decrease) in 1,854 (12,455) (10,535) 6,880
accounts payable and
accrued liabilities
Net cash provided (used) 3,039 (5,985) 7,474 5,162
by operating activities
CASH FLOWS FROM
INVESTING ACTIVITIES:
Acquisitions (37,600) (3,998) (41,025) (34,388)
Capital expenditures (1,321) (3,040) (4,341) (14,788)
Other (459) (385) (1,213) (197)
Net cash used in (39,380) (7,423) (46,579) (49,373)
investing activities
CASH FLOWS FROM
FINANCING ACTIVITIES:
Bank debt borrowings 45,955 10,243 64,694 130,613
Bank debt repayments (9,006) (26) (23,453) (135,811)
Purchase of treasury stock (891) - (891) (2,406)
Common stock offering - (110) - 54,583
(Note 2)
Contributions from (480) - 370 168
(distributions to) joint
venture partners
Dividends on common stock (456) (747) (1,327) (1,668)
Net cash provided by 35,122 9,360 39,393 45,479
financing activities
NET INCREASE (DECREASE)
IN CASH AND CASH EQUIVALENTS (1,219) (4,048) 288 1,268
CASH AND CASH EQUIVALENTS, 1,815 5,516 308 200
beginning of period
CASH AND CASH EQUIVALENTS, $ 596 $ 1,468 $ 596 $ 1,468
end of period
CASH PAID FOR INTEREST $ 640 $ 1,077 $ 2,053 $ 5,326
CASH PAID FOR INCOME TAXES $ 174 $ 250 $ 311 $ 310
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION
The accompanying unaudited financial information has been
prepared by Midcoast in accordance with the instructions to Form
10-Q. The unaudited information furnished reflects all
adjustments, all of which were of a normal recurring nature,
which are, in the opinion of the Company, necessary for a fair
presentation of the results for the interim periods presented.
Although the Company believes that the disclosures are adequate
to make the information presented not misleading, certain
information and footnote disclosures, including significant
accounting policies, normally included in financial statements
prepared in accordance with generally accepted accounting
principles have been condensed or omitted pursuant to such rules
and regulations. Certain reclassification entries were made with
regard to the Consolidated Financial Statements for the periods
presented in 1998 so that the presentation of the information is
consistent with reporting for the Consolidated Financial
Statements in 1999. It is suggested that the financial
information be read in conjunction with the financial statements
and notes thereto included in the Company's Annual Report on Form
10-K for the year ended December 31, 1998.
2. CAPITAL STOCK
In February 1999, the Company's BOD's announced a five-for-four
common stock split. The stock split was effective for
shareholders of record on February 11, 1999, and was distributed
on March 1, 1999. No fractional shares were issued as a result of
the stock split and stockholders entitled to a fractional share
received a cash payment equal to the market value of the
fractional share at the close of the market on the record date.
Net income per share, dividends per share and weighted average
shares outstanding have been retroactively restated to reflect
the five-for-four stock split.
In May 1999, the Company sold 3,570,000 shares of its Common
Stock at an offering price of $16.31 per share. Proceeds of
$54.6 million, net of issuance costs, were received by the
Company. The proceeds were used to repay bank debt.
3. ACQUISITIONS
CALMAR ACQUISITION
In March 1999, the Company purchased the Calmar system in
Alberta, Canada from Probe Exploration, Inc. ("Probe"). The total
value of the transaction was approximately $13.2 million (U.S.).
The assets purchased include a 30 Mmcf per day amine sweetening
plant, 30 miles of gas gathering pipeline and approximately 4,000
horsepower of compression located near Edmonton, Alberta. The
Calmar system currently gathers and sour gas from 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 an assignment to Midcoast
of an existing third party gathering and treating agreement. The
acquisition was funded through the Company's existing credit
facility.
DPI AND FLARE ACQUISITIONS
In March 1999, the Company purchased two related companies, Flare
and DPI. The total value of the transaction was approximately
$11.1 million and could include future consideration should
certain contingencies be met. The Flare and DPI shareholders
received cash consideration of approximately $3.2 million,
Midcoast assumed $5.5 million in debt, and the DPI shareholders
received 163,719 shares of our common stock. Flare is a natural
gas processing and treating company whose principal assets
include 27 portable natural gas processing and treating plants
from which it earns revenues based on treating and processing
fees and/or a percentage of the NGLs produced. DPI is an NGL,
crude oil and CO2 transportation and marketing company. DPI
operates 43 NGL and crude oil trucks and trailers, a fleet of 40
pressurized railcars and in excess of 400,000 gallons of NGL
storage facilities and product treating and handling equipment.
The acquisition was funded through the Company's existing credit
facility.
TINSLEY ACQUISITION
In March 1999, the Company purchased the Tinsley crude oil
gathering pipeline for $5.2 million. The Tinsley system is
located in Mississippi and consists of 60 miles of crude oil
gathering pipeline, related truck and Mississippi River barge
loading facilities and 170,000 barrels of crude oil storage. The
system transports approximately 5,000 barrels of crude oil per
day both directly from producing wells and from oil trucked to
the pipeline. The acquisition was funded through the Company's
existing credit facility.
SEACREST ACQUISITION
In March 1999, the Company completed the purchase of a 70%
interest in SeaCrest for $1.5 million, which in turn acquired
seven active offshore natural gas gathering pipelines. The
gathering pipelines that SeaCrest acquired from Koch Industries
include seven active systems located offshore in the Gulf of
Mexico, south of Louisiana, and comprise approximately 81 miles
of pipeline. These systems gather gas from 23 offshore producing
wells with a current total throughput of approximately 49 Mmcf
per day. The acquisition was funded through the Company's
existing credit facility.
SOUTHERN INDUSTRIAL GAS CORPORATION ACQUISITION
In June 1999, the Company purchased the Southern Industrial Gas
Corporation ("SIGCO") for $1.8 million and could include up to a
maximum of$0.8 million in future consideration should certain
contingencies be met. SIGCO owns and operates 15 short delivery
systems located in Louisiana and markets gas in Texas, Mississippi
and North Carolina. These systems provide natural gas supplies to
a number of end-user customers including three food processing
plants, seven asphalt plants, the city of Logansport, Louisiana and
Southern University in Baton Rouge, Louisiana. Together these
pipelines presently sell approximately 1.1 Bcf of natural gas annually.
The acquisition was funded through the Company's existing credit
facility.
4. COMMITMENTS AND CONTINGENCIES
EMPLOYMENT CONTRACTS
Certain executive officers of the Company have entered into
employment contracts, which through amendments provide for
employment terms of varying lengths the longest of which expires
in April 2001. These agreements may be terminated by mutual
consent or at the option of the Company for cause, death or
disability. In the event termination is due to death, disability
or defined changes in the ownership of the Company, the full
amount of compensation remaining to be paid during the term of
the agreement will be paid to the employee or their estate, after
discounting at 12% to reflect the current value of unpaid
amounts.
MIT CONTINGENCY
As part of the Company's MIT Acquisition, the Company has agreed
to pay additional contingent annual payments, which will be
treated as deferred purchase price adjustments, not to exceed
$250,000 per year. The amount each year is dependent upon
revenues received by the Company from certain gas transportation
contracts. The contingency is due over an eight-year period
commencing April 1, 1998 and payable at the end of each
anniversary date. The Company is obligated to pay the lesser of
50% of the gross revenues received under these contracts or
$250,000. As of September 30, 1999, the Company has made one
payment of $250,000 and has accrued an additional $125,000 under
the contingency.
MIDLA CONTINGENCY
As a condition of the Midla Acquisition, the Company agreed that
if a specific contract with a third party was executed prior to
October 2, 1999, which included specific provisions regarding
price and throughputs, Midcoast would be obligated to issue
137,500 warrants to acquire Midcoast common stock at an exercise
price of $15.82 per share to Republic. In addition, concurrent
with initial expenditures on the project, the Company would incur
a $1.2 million cash obligation to Republic. At September 30,
1999, none of the provisions of this contingency have been met.
5. EARNINGS PER SHARE
In March 1997, the FASB issued SFAS No. 128, entitled "Earnings
Per Share", which establishes new guidelines for calculating
earnings per share. The pronouncement is effective for reporting
periods ending after December 31, 1997. SFAS No. 128 requires
companies to present both a basic and diluted earnings per share
amount on the face of the statement of operations and to restate
prior period earnings per share amounts to comply with this
standard. Basic and diluted earnings per share amounts
calculated in accordance with SFAS No. 128 are presented below
for the three and nine month periods ended September 30 (in
thousands, except per share amounts):
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Basic:
Net income $ 1,580 $ 2,758 $ 6,069 $ 8,589
Average shares outstanding 7,130 10,559 7,120 8,585
Earnings per share - basic $ 0.22 $ 0.26 $ 0.85 $ 1.00
Diluted:
Net income $ 1,580 $ 2,758 $ 6,069 $ 8,589
Average shares outstanding 7,130 10,559 7,120 8,585
Dilutive effect of 152 165 156 156
stock options
Dilutive effect of warrants 62 72 82 63
Average shares & equivalent 7,344 10,796 7,358 8,804
shares outstanding
Earnings per share-diluted $ 0.22 $ 0.26 $ 0.82 $ 0.98
</TABLE>
6. SEGMENT DATA
The Company has three reportable segments that are primarily in
the business of transporting; gathering, processing and treating;
and marketing of natural gas and other petroleum products. The
Company's assets are segregated into reportable segments based on
the type of business activity and type of customer served on the
Company's assets. The Company evaluates performance based on
profit or loss from operations before income taxes and other
income and expense items incidental to core operations. Operating
income for each segment includes total revenues less operating
expenses (including depreciation) and excludes corporate
administrative expenses, interest expense, interest income and
income taxes. The accounting policies of the segments are the
same as those described in the summary of significant accounting
policies, included in the Company's Annual Report on Form 10-K
for the year ended December 31, 1998. The following table
presents certain financial information relating to the Company's
business segments (in thousands):
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Segment Revenues:
Transmission $ 21,518 $ 25,530 $ 84,709 $ 83,493
End-User 24,585 32,889 73,176 90,884
Gathering,Processing and Treating 4,150 42,906 8,926 91,695
Total Segment Revenues 50,253 101,325 166,811 266,072
Segment Operating Income:
Transmission 1,603 3,210 7,227 9,195
End-User 1,084 1,968 3,552 5,048
Gathering, Processing and Treating 1,371 302 2,708 4,653
Total Segment Operating Income 4,058 5,480 13,487 18,896
Corporate Administrative expenses (1,437) (1,987) (4,354) (5,936)
Interest expense (807) (775) (2,043) (3,651)
Other income (expense), net (30) 370 226 827
Income before income taxes $ 1,784 $ 3,088 $ 7,316 $ 10,136
The identifiable assets of the Company, by segment, are as
follows (in thousands):
September 30,
1998 1999
Property, Plant and Equipment
Transmission $ 91,477 $ 122,668
End-User 7,425 14,375
Gathering, Processing and Treating 46,684 73,457
Total Segment Assets 145,586 210,500
Corporate and other 486 1,726
Total Assets $ 146,072 $ 212,226
</TABLE>
The depreciation expense of the Company, by segment, is as
follows (in thousands):
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Depreciation Expense:
Transmission $ 315 $ 352 $ 1,096 $ 1,088
End-User 132 251 404 677
Gathering,Processing and Treating 302 1,126 513 2,705
Total Segment Depreciation Expense 749 1,729 2,013 4,470
Corporate and other 64 121 189 323
Total Depreciation Expense $ 813 $ 1,850 $ 2,202 $ 4,793
</TABLE>
7. NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED
The FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". This Statement establishes
accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other
contracts, (collectively referred to as derivatives) and for
hedging activities. This Statement was effective for all fiscal
quarters of all 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.
The FASB issued SFAS No. 137, "Accounting for Derivative and
Hedging Activities - Deferral of the Effective Date of SFAS No.
133". SFAS No. 137 defers the effective date of SFAS No. 133 to
all fiscal quarters of all fiscal years beginning after June 15,
2000. The Company has elected to defer the application of SFAS
No. 133 to all fiscal quarters of all fiscal years beginning
after June 15, 2000 in order to have more time to study and
understand this statement.
8. SUBSEQUENT EVENTS
NATURAL GAS GATHERING ACQUISITION
In October 1999, the SeaCrest Company L.L.C. announced the
acquisition of three natural gas gathering systems from El Paso
Offshore Gathering and Transmission Company. Cash consideration
of $2.1 million was paid. The pipeline systems, which are
located offshore near Freeport, Texas, include 78 miles of
gathering assets and an onshore liquids handling facility. The
three systems currently gather 60 million cubic feet of natural
gas per day. This acquisition was funded through the Company's
existing credit facility.
NATURAL GAS PROCESSING AGREEMENT
In November 1999, Mid Louisiana Gas Transmission Company, a
wholly owned subsidiary of the Company, announced that it had
entered into a natural gas processing agreement with Exxon
Company U.S.A., a division of Exxon Corporation. Under the terms
of the multi-year agreement, MLGT will construct an eight-mile
14" pipeline to supply up to 80 Mmcf/day of natural gas to the
Exxon Baton Rouge Gas Plant. Construction costs are estimated to
be $3.5 million and will be funded through the Company's existing
credit facility. The anticipated completion date is set for the
first quarter of 2000.
KANSAS PIPELINE COMPANY ACQUISITION
In November 1999, the Company announced the acquisition of Kansas
Pipeline Company ("KPC"), MarGasCo Partnership ("MarGasCo") and
other related entities. The acquisition includes the KPC owned
and operated 1,120 mile interstate gas pipeline system which
transports natural gas from Oklahoma and western Kansas to the
metropolitan Wichita and Kansas City markets. The KPC system
also includes three compressor stations with a total of 14,680
horsepower and has a capacity of approximately 160 Mmcf/day. KPC
has supply interconnections with the Transok, Panhandle Eastern,
and ANR pipeline systems.
MarGasCo is a non-regulated company, which primarily markets
natural gas off the KPC interstate pipeline system. Currently
MarGasCo markets gas to over 125 end-use customers in Kansas,
Missouri and Oklahoma.
Under the terms of the agreement, the Company paid cash
consideration of approximately $190 million, which includes
repayment of $68.4 million in existing KPC senior secured notes
and other indebtedness, and an $8.7 million prepayment penalty in
connection with the early retirement of debt. The Company
anticipates taking an extraordinary charge for the prepayment
penalty in the fourth quarter of 1999. The Company financed this
transaction by amending its existing credit facility (see below).
AMENDMENT TO EXISTING CREDIT AGREEMENT
In November 1999, the Company amended the existing Credit Agreement.
In anticipation of the KPC acquisition described above, the borrowing
availability under the Credit Agreement was increased from $125 million
to $265 million with an accordian feature up to $400 million.
For more information related to the amendments to the Credit Agreement,
please refer to the Capital Resources and Liquidity section in
the Management's Discussion and Analysis of Financial Condition
and Results of Operations below.
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. From
January 1, 1996 through September 30, 1999, the Company acquired
50 pipelines for an aggregate acquisition cost of over $161
million. In addition, the Company almost doubled its pipeline
asset base with the $190 million KPC acquisition in November
1999. 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 NGL trucking fees and (iii) the marketing of
natural gas and other petroleum products.
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 NGL's as well as the sale of the
residual natural gas. These revenues occur under processing
contracts with producers of natural gas utilizing both a
"percentage of proceeds" and "keep-whole" basis. The contracts
based on percentage of proceeds provide that the Company receives
a percentage of the NGL and residual gas revenues as a fee for
processing the producer's 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
NGL's are further fractionated in the Company's facilities into
products such as ethane, propane, butanes, natural gasoline and
condensate, then sold to various wholesalers along with raw
sulfur from the Company's sulfur recovery plant. The Company's
processing operations can be adversely affected by declines in
NGL prices, declines in gas throughput or increases in shrinkage
or fuel costs. The Company's NGL trucking revenues occur in the
transportation of crude oil and NGL's using pressurized tractor-
trailers and railcars.
The Company's marketing revenues are realized through the
purchase and resale of natural gas and other petroleum products
to the Company's customers. Generally, 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, marketing
revenues and associated expenses includes the full commodity
price of the natural gas and other petroleum product acquired.
The operating income the Company recognizes from its marketing
efforts is the difference between the price at which the gas and
other petroleum products 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
marketing 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
segments of Midcoast for the three-month and nine-month periods
ended September 30, 1998 and September 30, 1999. A discussion
follows which explains significant factors that have affected
Midcoast's operating results during these periods. Gross margin
for each of the segments 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. As previously discussed, the Company provides
marketing services to its customers. For analysis purposes, the
Company accounts for the marketing services by recording the
marketing activity on the operating segment where it occurs.
Therefore, the gross margin for each of the major operating
segments include transportation and marketing components.
TRANSMISSION PIPELINES
(In thousands, except gross margin per Mmbtu)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing Revenue $ 20,064 $ 24,234 $ 79,958 $ 79,024
Transportation Fees 1,454 1,296 4,751 4,469
Total Operating Revenues 21,518 25,530 84,709 83,493
Operating Expenses:
Marketing Costs 18,494 20,832 73,078 69,890
Operating Expenses 1,106 1,136 3,308 3,320
Total Operating Expenses 19,600 21,968 76,386 73,210
Gross Margin $ 1,918 $ 3,562 $ 8,323 $ 10,283
Volume (in Mmbtu):
Marketing 9,083 10,156 34,277 35,940
Transportation 11,459 12,782 37,190 40,873
Total Volume 20,542 22,938 71,467 76,813
Gross Margin per Mmbtu $ 0.09 $ 0.16 $ 0.12 $ 0.13
</TABLE>
The Company's transmission segment experienced an 86% and 24%
increase in gross margin for the three and nine-month periods
ended September 30, 1999, respectively when compared to the
equivalent period in 1998. This increase was achieved as a result
of the completion of the expansions to the MIT system in December
1998 and the MIDLA system in May 1999. The expansions were made to serve
increased demand on the systems due principly to industrial growth.
This increase was partially mitigated by a decline in margin on the
Magnolia system, which is dependent on certain pipeline basis
differentials which were not as favorable in 1999.
END-USER PIPELINES
(In thousands, except gross margin per Mmbtu)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing Revenue $ 23,688 $ 32,071 $ 70,720 $ 88,415
End-User Transportation Fees 897 818 2,456 2,469
Total Operating Revenues 24,585 32,889 73,176 90,884
Operating Expenses:
Marketing Costs 23,321 30,558 69,079 84,943
Operating Expenses 48 112 141 216
Total Operating Expenses 23,369 30,670 69,220 85,159
Gross Margin $ 1,216 $ 2,219 $ 3,956 $ 5,725
Volume (in Mmbtu):
Marketing 11,182 12,927 32,150 36,285
Transportation 6,003 5,304 15,441 15,443
Total Volume 17,185 18,231 47,591 51,728
Gross Margin per Mmbtu $ 0.07 $ 0.12 $ 0.08 $ 0.11
</TABLE>
The End-User pipeline segment experenced an 82% and 44% improvement
in gross margin for the three and nine-month periods ended
September 30, 1999, respectively as compared to the equivalent
period in 1998. The increase is primarily attributable to the
completion of a new high pressure pipeline system which is
servicing new marketing contracts related to a new cogeneration
facility near Baton Rouge, Louisiana. In addition, gross margin
was positively impacted by increased industrial demand on the
TRIGAS system and the Company's June 1999 Southern Industrial
Corporation acquisition.
GATHERING PIPELINES AND NATURAL GAS PROCESSING AND TREATING
(In thousands, except gross margin per Mmbtu)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
September 30, September 30, September 30, September 30,
1998 1999 1998 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing Revenue $ 1,979 $ 34,547 $ 4,206 $ 72,855
Gathering Transportation Fees 1,346 3,092 1,789 8,466
Processing and Treating Revenues 825 5,269 2,931 10,376
Total Operating Revenues 4,150 42,908 8,926 91,697
Operating Expenses:
Marketing Costs 1,514 33,274 3,051 66,561
Operating Expenses 638 4,183 1,468 8,854
Processing and Treating Costs 325 4,023 1,186 8,924
Total Operating Expenses 2,477 41,480 5,705 84,339
Gross Margin $ 1,673 $ 1,428 $ 3,221 $ 7,358
Volume (in Mmbtu):
Marketing 1,490 9,400 3,487 23,845
Gathering 16,568 23,609 27,965 66,398
Processing and Treating 468 3,063 1,489 7,104
Total Volume 18,526 36,072 32,941 97,347
Gross Margin per Mmbtu $ 0.09 $ 0.04 $ 0.10 $ 0.08
The gathering pipelines and natural gas processing and treating
segment reflected strong margin gains for the nine-month period
ended September 30, 1999 as compared to the equivalent period in
1998. Although margins per Mmbtu declined for the segment as a
whole, the overall gross margin improved due to a significant
increase in volumes gathered, processed and marketed during 1999.
In addition, gross margin results for the three months ended
September 30, 1999, were negatively impacted by a $700,000
imbalance charge recorded on the Anadarko system.
Recent acquisitions and to a lesser extent the improvement in NGL pricing have
significantly enhanced the profitability of this segment. The
most significant of the acquisitions include the Anadarko
acquisition in August 1998 and the Calmar, the DPI/Flare, and the
Seacrest acquisition in March of 1999.
OTHER INCOME, COSTS AND EXPENSES
In the three and nine-month periods ended September 30, 1999, the
Company received revenues of $.7 million and $1.4 million,
respectively from other revenue sources as compared to $.1
million and $.4 million over the same periods in 1998. The
increase is primarily attributable to income earned by a newly
acquired subsidiary on processing and treating plant construction
projects.
In the three and nine-month periods ended September 30, 1999, the
Company's depreciation, depletion and amortization increased to
$1.9 million and $4.8 million, respectively from $.8 million and
$2.2 million when compared to 1998. The increase is primarily
due to increased depreciation on assets acquired in the Anadarko,
DPI\Flare and Calmar Acquisitions.
In the three and nine-month periods ended September 30, 1999, the
Company's general and administrative expenses increased to $2.0
million and $5.9 million, respectively from $1.4 million and $4.4
million in 1998. The increase is due to increased costs
associated with the management of the assets acquired in the
Anadarko, DPI\Flare and Calmar Acquisitions. The increase
attributable to these new acquisitions was mitigated by a
reduction of costs associated with the Company's centralization
of functions from remote locations to the Houston office.
Interest expense for the three and nine-month periods ended
September 30, 1999 increased to $.8 million and $3.7 million,
respectively from $.8 million and $2.0 million in 1998. The
Company was servicing an average of $66.7 million and $86.9
million in debt for the three and nine months ended September 30,
1999 as compared to $45.9 million and $36.0 million in debt for
the three and nine months ended September 30, 1998. The
increased debt level in 1999 is primarily associated with the
Company's September 1998 acquisition of Anadarko as well as its
DPI\Flare and Calmar acquisitions which occurred in March 1999.
The additional expense related to increased debt levels was
mitigated by a reduction in the Company's weighted average
interest rate. The Company's weighted average interest rate was
6.33% and 6.28% for the three month and nine-month period ended
September 30, 1999 as compared to 7.59% and 7.57% for the three
month and nine-month period ended September 30, 1998.
The Company recognized net income for the three and nine-month
periods ended September 30, 1999 of $2.8 million and $8.6
million, respectively as compared to $1.6 million and $6.1
million for the equivalent period in 1998. Basic earnings per
share ("EPS") for the three and nine-month period ended September
30, 1999 increased 18% from $.22 and $.85 in 1998 to $.26 and
$1.0 in 1999. The Company achieved the increased EPS despite the
dilutive effects of issuing additional shares in the May 1999
common stock offering. The significant improvement in EPS is
primarily attributable to the positive impact of accretive
acquisitions consummated during 1998 and 1999.
INCOME TAXES
As of December 31, 1998, the Company had net operating loss
("NOL") carryforwards of approximately $16.6 million, expiring in
various amounts from 1999 through 2011. 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 Midla Acquisition.
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, our capital resources
were significantly improved with the equity infusion derived from
our initial and secondary common stock offerings in August 1996,
July 1997 and May 1999, respectively.
The net proceeds of our combined stock offerings contributed
approximately $96.6 million and significantly improved our
financial flexibility. This increased flexibility has allowed us
to pursue acquisition and construction opportunities utilizing
lower cost conventional bank debt financing. During 1998 and to
date in 1999, the Company has acquired or constructed $291.5
million of pipeline systems. The Company's long-term debt to
total capitalization ratio decreased from 62% at March 31, 1999
to 33% at September 30, 1999 and is currently at approximately
67% subsequent to the KPC Acquisition.
In November 1999, the Company amended and restated its bank
financing agreement under the certain Amended and Restated Credit
Agreement dated August 31, 1998. The amendments increased our
borrowing availability, modified our letter of credit facility,
extended the maturity five years to November 2004, modified
financial covenants, established waiver and amendment approvals
and changed the method to determine the interest rate to be
charged.
The amendments to the credit agreement increased our borrowing
availability from $125 million to $265 million, with an accordian
feature up to $400 million. The amended credit agreement provides
borrowing availability as follows: (i) up to a $25 million
sublimit for the issuance of standby and commercial letters of
credit and (ii) the difference between the $265 million and the
used sublimit available as a revolving credit facility. The
facility will provide for Canadian Dollar borrowings of up to
C$50 million. At the option of the Company, borrowings under the
amended credit agreement accrue interest at LIBOR plus an
applicable margin or the higher of the Bank of America prime rate
or the Federal Funds rate plus an applicable margin.
The applicable margin percentage to be added to the interest rate
is based on the Company's total debt to total capitalization
ratio at the end of each fiscal quarter. The Company is charged
a margin between 1.0% and 2.0% as the Company's total debt to
total capitalization ratio ranges from under 40% and over 65%,
respectively. As a result of the KPC acquisition and the
resulting increase in Midcoast's total debt to total
capitalization ratio to approximately 67%, Midcoast's borrowings
are currently being charged at the highest applicable margin of
2.0%.
At closing in November 1999, the Company was subject to an
arrangement fee, agency fee, underwriting fee and commitment fee
totaling $1.2 million. Additionally, the Company is subject to
an annual administrative agency fee of $35,000.
The credit agreement is secured by all accounts receivable,
contracts, and the pledge of all of our subsidiaries' stock and a
first lien security interest in our pipeline systems. The credit
agreement also contains a number of customary covenants that
require us to maintain certain financial ratios and limit our
ability to incur additional indebtedness, transfer or sell
assets, create liens, or enter into a merger or consolidation.
The Company was in compliance with such financial covenants at
September 30, 1999. However, the Company is required to comply
with more stringent covenant ratios on its debt to capitalization
and EBITDA to interest by June 30, 2000.
For the nine-months ended September 30, 1999, the Company
generated cash flow from operating activities before changes in
working capital accounts of approximately $13.7 million.
At September 30, 1999, the Company had committed to making
approximately $7.1 million in construction related expenditures.
The Company believes that its credit agreement and
funds provided by operations will be sufficient to meet its
operating cash needs for the foreseeable future and its projected
capital expenditures of approximately $7.1 million. If funds
under the credit agreement are not available to fund acquisition
and construction projects, the Company would seek to obtain such
financing from the sale of equity securities or other debt
financing. There can be no assurances that any such financing
will be available on terms acceptable to the Company. Should
sufficient capital not be available, the Company will not be able
to implement its growth strategy as aggressively.
RISK MANAGEMENT
The Company utilizes derivative financial instruments to manage
market risks associated with certain energy commodities and
interest rates. According to guidelines provided by the BOD, 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 September 30, 1999, the Company
had no unrealized losses from such hedging contracts.
Interest Rate Risk:
Prior to the amendment of the Credit Facility in November 1999,
the Company's Credit Facility provided an option for the Company
to borrow funds at a variable interest rate of LIBOR plus 1.25%.
In an effort to mitigate interest rate fluctuation exposure, the
Company entered into $65 million dollars of interest rate swaps
under two separate swap agreements. The interest rate swap
agreements 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 Nations Bank 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 September 30,
1999, the fair value of this interest rate swap through the
transferred termination date was a net liability of $.21 million.
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 September 30, 1999, the fair value of this interest rate swap
through the initial termination date was a net asset of $1.32
million.
The effect of these swap agreements was to lower interest expense
by $182,501 in the nine-months ended September 30, 1999 and
increase interest expense by $55,458 in the nine-months ended
September 30, 1998.
_______________________________
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 of operation, liquidity and financial
condition.
The Company has updated its software and hardware to comply with
Y2K. Software and hardware selection has been completed. A
budget for updating computer software and hardware of
approximately $1.0 million dollars was established of which $.9
million was spent through September 30, 1999. We do not expect
the Y2K issue to pose significant operational problems for the
Company's computer systems.
The Company has completed its assessment of its key vendors,
customers and other third parties 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. The Company has completed its Y2K remediation efforts
in advance of December 31, 1999. The Company has made
contingency plans with respect to its operations, systems and
unforeseen issues.
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.
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.
PART II. OTHER INFORMATION
ITEM 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBITS DESCRIPTION OF EXHIBITS
None
______
b. Reports on Form 8-K:
A report on Form 8-K was filed during the third quarter of 1999.
Such report was filed on September 29, 1999 to report the
reincorporation of the Company under the laws of the state of
Texas.
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: November 15, 1999
</TABLE>
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<CASH> 1,468,000
<SECURITIES> 0
<RECEIVABLES> 48,597,000
<ALLOWANCES> 0
<INVENTORY> 1,425,000
<CURRENT-ASSETS> 51,490,000
<PP&E> 212,226,000
<DEPRECIATION> (10,578,000)
<TOTAL-ASSETS> 255,084,000
<CURRENT-LIABILITIES> 49,880,000
<BONDS> 0
0
0
<COMMON> 107,000
<OTHER-SE> 128,075,000
<TOTAL-LIABILITY-AND-EQUITY> 255,084,000
<SALES> 267,365,000
<TOTAL-REVENUES> 267,365,000
<CGS> 242,706,000
<TOTAL-COSTS> 253,435,000
<OTHER-EXPENSES> 10,729,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> (3,651,000)
<INCOME-PRETAX> 10,136,000
<INCOME-TAX> 1,547,000
<INCOME-CONTINUING> 0
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 8,589,000
<EPS-BASIC> 1.00
<EPS-DILUTED> .98
</TABLE>
