[ARTICLE]5
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 June 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 June 30,1999, there were outstanding 10,719,513 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
Bank One Bank One, Texas N.A.
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.
EPS Basic earnings per share.
FASB Financial Accounting Standards Board.
FERC Federal Energy Regulatory Commission.
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
Acquisition Systems.
MIT The May 1997 acquisition of the MIT and TRIGAS
Acquisition Systems.
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 June 30, 1999
[CAPTION]
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Page
Number
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PART I. FINANCIAL INFORMATION
Item 1. Unaudited Financial Statements
Consolidated Balance Sheets as of December 31, 1998
and June 30, 1999 3
Consolidated Statements of Operations for the three months
and six months ended June 30, 1998 and June 30, 1999 4
Consolidated Statement of Shareholders' Equity for
the six months ended June 30, 1999 5
Consolidated Statements of Cash Flows for the three months
and six months ended June 30, 1998 and June 30, 1999 6
Notes to Consolidated Financial Statements 7
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations. 9
PART II. OTHER INFORMATION 15
SIGNATURE 17
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
DECEMBER 31, JUNE 30,
ASSETS 1998 1999
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CURRENT ASSETS:
Cash and cash equivalents $ 200 $ 5,516
Accounts receivable, net of allowance of 33,020 50,331
$92 and $104 , respectively
Materials and supplies, at average cost 1,363 1,389
Total current assets 34,583 57,236
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities 150,041 188,041
Investment in transmission facilities 1,342 1,358
Natural gas processing facilities 4,917 11,113
Oil and gas properties, using the full- 1,383 1,383
cost method of accounting
Other property and equipment 2,872 3,293
160,555 205,188
ACCUMULATED DEPRECIATION, DEPLETION AND (6,308) (8,924)
AMORTIZATION
154,247 196,264
OTHER ASSETS, net of amortization 2,512 1,964
Total assets $191,342 $255,464
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued $32,540 $51,867
liabilities
Current portion of long-term debt 176 176
payable to banks
Short-term borrowing from bank 754 -
Other current liabilities 124 48
Total current liabilities 33,594 52,091
LONG TERM DEBT PAYABLE TO BANKS 78,082 63,421
OTHER LIABILITIES 2,024 2,078
DEFERRED INCOME TAXES 10,808 11,196
MINORITY INTEREST IN CONSOLIDATED 550 517
SUBSIDIARIES
COMMITMENTS AND CONTINGENCIES (Note 3)
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per
share; authorized 31,250,000 shares; 71 107
issued 7,149,513 and 10,719,513
shares, respectively (Note 2)
Paid in capital 80,955 135,612
Accumulated deficit (11,947) (7,183)
Unearned compensation (4) -
Less: Cost of 181,125 and 161,156 (2,791) (2,375)
treasury shares, respectively
Total shareholders' equity 66,284 126,161
Total liabilities and shareholders' $191,342 $255,464
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)
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For the Three Months For the Six Months
Ended Ended
June 30, June 30, June 30, June 30,
1998 1999 1998 1999
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Operating Revenues:
Sale of natural gas and $ 45,977 $ 74,387 $ 109,153 $ 149,442
other petroleum products
Transportation fees 2,325 5,556 5,301 10,198
Natural gas processing 1,007 3,213 2,106 5,107
and treating revenue
Other 218 301 295 774
Total operating revenues 49,527 83,457 116,855 165,521
OPERATING EXPENSES:
Cost of natural gas and 44,226 72,425 104,402 143,688
other petroleum products
Natural gas processing 742 2,880 1,465 4,901
and treating costs
Depreciation, depletion 695 1,534 1,388 2,943
and amortization
General and administrative 1,313 2,052 2,916 3,950
Total operating expenses 46,976 78,891 110,171 155,482
Operating income 2,551 4,566 6,684 10,039
NON-OPERATING ITEMS:
Interest expense (637) (1,373) (1,236) (2,876)
Minority interest in (40) 17 (42) (23)
consolidated subsidiaries
Other income (expense), net 95 (97) 127 (92)
INCOME BEFORE INCOME TAXES 1,969 3,113 5,533 7,048
PROVISION FOR INCOME TAXES
Current (21) (366) (91) (829)
Deferred (220) (171) (953) (388)
NET INCOME $ 1,728 $ 2,576 $ 4,489 $ 5,831
EARNINGS PER COMMON SHARE:
BASIC $ 0.24 $ 0.31 $ 0.63 $ 0.77
DILUTED $ 0.23 $ 0.31 $ 0.61 $ 0.75
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
BASIC 7,127,783 8,224,972 7,114,795 7,581,609 5 9
DILUTED 7,378,669 8,428,998 7,364,476 7,792,269
</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)
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TOTAL
COMMON PAID-IN ACCUMULATED UNEARNED TREASURY SHAREHOLDER'
STOCK CAPITAL DEFICIT COMPENSATION STOCK EQUITY
Balance, December 31,1997 $ 71 $ 80,681 $(19,283) $ (18) $ - $ 61,451
Shares issued or vested - - - 14 - 14
vested under Various stock-
based compensation
arrangements
Warrants exercised - 274 - - - 274
Net income - - 9,113 - - 9,113
Treasury stock purchased - - - - (2,791) (2,791)
purchased (181,125 shares)
Common stock dividends, - - (1,777) - - (1,777)
$.24 per share
Balance, December 31, 1998 $ 71 $ 80,955 $(11,947) $ (4) $ (2,791) $66,284
Net income - - 5,831 - - 5,831
Shares issued or vested
under various stock-
based Compensation - - - 4 - 4
arrangements
Sale of 3,570,000 shares 36 54,657 - - - 54,693
of common stock (Note 2)
Foreign currency translation - - (146) - - (146)
Treasury stock - - - - (2,406) (2,406)
purchased (143,750 shares)
Treasury stock issued in - - - - 2,822 2,822
issued in connection
with the DPI acquisition
(163,719 shares)
Common stock dividends, - - (921) - - (921)
$.12 per share
Balance, June 30,1999 $ 107 $135,612 $(7,183) $ - $ (2,375) $126,161
</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)
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For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 1,728 $ 2,576 $ 4,489 $ 5,831
Adjustments to arrive at net
cash provided (used) in
operating activities-
Depreciation, depletion and 695 1,534 1,388 2,943
amortization
Increase in deferred tax liability 757 171 757 388
Minority interest in consolidated 40 (17) 42 23
subsidiaries
Other 79 (15) 71 (36)
Changes in working capital accounts-
(Increase) Decrease in 9,962 (7,308) 10,539 (17,311)
accounts receivable
Increase in other current assets (626) (25) (463) (26)
Increase (Decrease) in accounts (7,743) 14,675 (12,388) 19,335
payable and accrued liabilities
Net cash provided by operating activities 4,892 11,591 4,435 11,147
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions (3,425) (1,799) (3,425) (30,390)
Capital expenditures (1,398) (6,799) (3,020) (11,748)
Other (625) 744 (754) 188
Net cash used in investing activities (5,448) (7,854) (7,199) (41,950)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings 6,506 30,319 18,739 120,370
Bank debt repayments (4,674) (84,298) (14,447) (135,785)
Purchase of treasury stock - (416) - (2,406)
Common stock offering (Note 2) - 54,693 - 54,693
Contributions from (distributions to) 880 (61) 850 168
joint venture partners
Dividends on common stock (458) (479) (871) (921)
Net cash provided (used) by 2,254 (242) 4,271 36,119
financing activities
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS 1,698 3,495 1,507 5,316
CASH AND CASH EQUIVALENTS, 117 2,021 308 200
beginning of period
CASH AND CASH EQUIVALENTS, $1,815 $5,516 $1,815 $5,516
end of period
CASH PAID FOR INTEREST $ 571 $1,611 $1,413 $4,249
CASH PAID FOR INCOME TAXES $ 36 $ 60 $ 137 $ 60
</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 $54.7 million, net of
issuance costs, were received by the Company. The proceeds were used to
repay bank debt.
3. ACQUISITIONS
CALMAR ACQUISITION
The Company purchased the Calmar system in Alberta, Canada from Probe
Exploration, Inc. ("Probe"). The total value of the transaction was
approximately $13.2 million (U.S.). The assets purchased include a 30
Mmcf per day amine sweetening plant, 30 miles of gas gathering pipeline
and approximately 4,000 horsepower of compression located near Edmonton,
Alberta. The Calmar system currently gathers and treats approximately 24
Mmcf per day of sour gas from 27 producing wells operated by Probe and
Courage Energy Inc. In conjunction with the purchase, Probe entered into
a gas gathering and treating agreement with us, including the long-term
dedication of Probe's reserves in the Leduc Field, a right of first
refusal agreement on new or existing midstream assets within a defined
390-square mile area of interest, and an assignment to us of an existing
third party gathering and treating agreement.
DPI AND FLARE ACQUISITIONS
The Company purchased two related companies, Flare 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
The Company purchased the Tinsley crude oil gathering pipeline for $5.2
million. The Tinsley system is located in Mississippi and consists of 60
miles of crude oil gathering pipeline, related truck and Mississippi
River barge loading facilities and 170,000 barrels of crude oil storage.
The acquisition was funded through the Company's existing credit
facility.
SEACREST ACQUISITION
The Company also completed the purchase of a 70% interest in SeaCrest for
$1.5 million, which in turn acquired seven active offshore natural gas
gathering pipelines. The gathering pipelines that SeaCrest acquired from
Koch Industries include seven active systems located offshore in the Gulf
of Mexico, south of Louisiana, and comprise approximately 81 miles of
pipeline. These systems gather gas from 23 offshore producing wells with
a current total throughput of approximately 49 Mmcf per day. The
acquisition was funded through the Company's existing credit facility.
4. COMMITMENTS AND CONTINGENCIES
EMPLOYMENT CONTRACTS
Certain executive officers of the Company have entered into employment
contracts, which through amendments provide for employment terms of
varying lengths the longest of which expires in April 2001. These
agreements may be terminated by mutual consent or at the option of the
Company for cause, death or disability. In the event termination is due
to death, disability or defined changes in the ownership of the Company,
the full amount of compensation remaining to be paid during the term of
the agreement will be paid to the employee or their estate, after
discounting at 12% to reflect the current value of unpaid amounts.
MIT CONTINGENCY
As part of the Company's 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
June 30, 1999, the Company has made one payment of $250,000 and has
accrued an additional $62,500 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 June
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 six month periods ended June 30 (in thousands, except per share
amounts):
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For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
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Basic:
Net income $ 1,728 $ 2,576 $ 4,489 $ 5,831
Average shares outstanding 7,128 8,225 7,115 7,582
Earnings per share - basic $ 0.24 $ 0.31 $ 0.63 $ 0.77
Diluted:
Net income $ 1,728 $ 2,576 $ 4,489 $ 5,831
Average shares outstanding 7,128 8,225 7,115 7,582
Dilutive effect of stock options 88 148 92 151
Dilutive effect of warrants 163 56 157 59
Average shares & equivalent shares 7,379 8,429 7,364 7,792
outstanding
Earnings per share - diluted $ 0.23 $ 0.31 $ 0.61 $ 0.75
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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):
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The identifiable assets of the Company, by segment, are as follows (in
thousands):
June 30,
1998 1999
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Property, Plant and Equipment
Transmission $ 90,071 $120,401
End-User 4,517 10,597
Gathering, Processing and Treating 11,519 73,074
Total Segment Assets 106,107 204,072
Corporate and other 455 1,116
Total Assets $106,562 $205,188
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For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
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Segment Revenues:
Transmission $25,717 $22,739 $67,028 $57,963
End-User 21,087 29,636 44,756 57,995
Gathering, Processing 2,505 30,781 4,776 48,789
and Treating
Total Segment Revenues 49,309 83,156 116,560 164,747
Segment Operating Income:
Transmission 1,875 2,088 5,749 5,985
End-User 1,051 1,733 2,343 3,080
Gathering, Processing 782 2,603 1,337 4,351
and Treating
Total Segment Operating Income 3,708 6,424 9,429 13,416
Corporate Administrative expenses (1,313) (2,052) (2,916) (3,950)
Interest expense (637) (1,373) (1,236) (2,876)
Other income (expense),net 211 114 256 458
Income before income taxes $ 1,969 $ 3,113 $ 5,533 $ 7,048
</TABLE>
The depreciation expense of the Company, by segment, is as follows (in
thousands):
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For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
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Depreciation Expense:
Transmission $ 391 $ 364 $ 781 $ 736
End-User 136 221 272 426
Gathering, Processing 106 842 211 1,579
and Treating
Total Segment Depreciation 633 1,427 1,264 2,741
Expense
Corporate and other 62 107 124 202
Total Depreciation Expense $ 695 $ 1,534 $ 1,388 $ 2,943
</TABLE>
7. NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED
The FASB issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities". This Statement establishes accounting and reporting
standards for derivative instruments, including certain derivative
instruments embedded in other contracts, (collectively referred to as
derivatives) and for hedging activities. This Statement is effective for
all fiscal quarters of fiscal years beginning after June 15, 1999.
Initial application of this Statement should be as of the beginning of an
entity's fiscal quarter; on that date, SFAS No. 133 will require the
Company to record all derivatives on the balance sheet at fair value.
Changes in derivative fair values will either be recognized in earnings
as offsets to the changes in fair value of related hedged assets,
liabilities and firm commitments or, for forecasted transactions,
deferred and recorded as a component of other shareholders' equity until
the hedged transactions occur and are recognized in earnings. The
ineffective portion of a hedging derivative's change in fair value will
be immediately recognized in earnings. The impact of SFAS 133 on the
Company's financial statements will depend on a variety of factors,
including future interpretative guidance from the FASB, the extent of the
Company's hedging activities, the types of hedging instruments used and
the effectiveness of such instruments. However, the Company does not
believe the effect of adopting SFAS 133 will be material to its financial
position.
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 1996, the
Company acquired 50 pipelines for an aggregate acquisition cost of over
$163 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 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 six-month periods ended June 30, 1998
and June 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>
For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing $24,415 $21,458 $63,729 $54,790
Transportation Fees 1,302 1,281 3,299 3,173
Total Operating Revenues 25,717 22,739 67,028 57,963
Operating Expenses:
Marketing Costs 22,421 18,908 58,296 49,058
Operating Expenses 1,030 1,379 2,202 2,184
Total Operating Expenses 23,451 20,287 60,498 51,242
Gross Margin $ 2,266 $ 2,452 $ 6,530 $ 6,721
Volume (in Mmbtu)
Marketing 10,518 9,471 26,866 25,784
Transportation 10,579 13,423 25,731 28,091
Total Volume 21,097 22,894 52,597 53,875
Gross Margin per Mmbtu $ 0.11 $ 0.11 $ 0.12 $ 0.12
</TABLE>
The Company's transmission segment experienced an 8% and 3% increase in
gross margin for the three and six months ended June 30, 1999,
respectively when compared to the equivalent period in 1998. This
increase was achieved as a result of the completion of a looping
expansion to the MIT system in December 1998, to serve increased demand
on the MIT system. 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>
For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing $ 20,292 $ 28,745 $ 43,197 $ 56,344
End-User Transportation Fees 795 891 1,559 1,651
Total Operating Revenues 21,087 29,636 44,756 57,995
Operating Expenses:
Marketing Costs 19,852 27,644 42,048 54,385
Operating Expenses 48 38 93 104
Total Operating Expenses 19,900 27,682 42,141 54,489
Gross Margin $ 1,187 $ 1,954 $ 2,615 $ 3,506
Volume (in Mmbtu)
Marketing 9,060 13,312 19,296 23,358
Transportation 4,555 4,127 9,438 10,139
Total Volume 13,615 17,439 28,734 33,497
Gross Margin per Mmbtu $ 0.09 $ 0.11 $ 0.09 $ 0.10
</TABLE>
The 65% and 34% improvement in gross margin for the three and six month
periods of 1999 as compared to 1998 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
Rogue, Louisiana. In addition, the Company's July 1998 Creole
acquisition also contributed strong margins during the periods in 1999
with no corresponding results in the prior period.
GATHERING PIPELINES AND NATURAL GAS PROCESSING AND TREATING
(In thousands, except gross margin per Mmbtu)
<TABLE>
For the Three Months Ended For the Six Months Ended
June 30, 1998 June 30, 1999 June 30, 1998 June 30, 1999
<S> <C> <C> <C> <C>
Operating Revenues:
Marketing $ 1,270 $ 24,184 $ 2,227 $ 38,308
Gathering Transportation 228 3,384 443 5,374
Fees
Processing and Treating 1,007 3,213 2,106 5,107
Revenues
Total Operating Revenues 2,505 30,781 4,776 48,789
Operating Expenses:
Marketing Costs 760 21,042 1,537 33,287
Operating Expenses 440 3,414 830 4,671
Processing and Treating Costs 417 2,880 861 4,901
Total Operating Expenses 1,617 27,336 3,228 42,859
Gross Margin $ 888 $ 3,445 $ 1,548 $ 5,930
Volume (in Mmbtu)
Marketing 1,536 9,320 1,997 14,445
Gathering 5,531 23,232 11,397 42,789
Processing and Treating 510 7,160 1,021 9,121
Total Volume 7,577 39,712 14,415 66,355
Gross Margin per Mmbtu $ 0.12 $ 0.09 $ 0.11 $ 0.09
</TABLE>
The gathering pipelines and natural gas processing and treating segment
reflected strong margin gains for the three and six month periods ended
June 30, 1998 as compared to the equivalent periods in 1997. Although
margins per Mmbtu declined for the segment as a whole, overall gross
margin improved due to a significant increase in volumes gathered,
processed and marketed during 1999.
Recent acquisitions and an 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 six month period ended June 30, 1999, the Company
received revenues of $.3 million and $.8 million, respectively from other
revenue sources as compared to $.2 million and $.3 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 six month period ended June 30, 1999, the Company's
depreciation, depletion and amortization increased to $1.5 million and
$2.9 million, respectively from $.7 million and $1.4 million when
compared to 1998. The increase is primarily due to increased
depreciation on assets acquired in the Anadarko, DPI\Flare and Calmar
Acquisitions. Collectively, these new acquisitions accounted for 75% and
70% of the increases of $.8 million and $1.5 million.
In the three and six month period ended June 30, 1999, the Company's
general and administrative expenses increased to $2.1 million and $4.0
million, respectively from $1.3 million and $2.9 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 six months ended June 30, 1999
increased to $1.4 million and $2.9 million, respectively from $.6 million
and $1.2 million in 1998. The Company was servicing an average of $96.3
million and $97.0 million in debt for the three and six months ended June
30, 1999 as compared to $31.6 million and $31.1 million in debt for the
three and six months ended June 30, 1998. The increased debt load 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 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 6.32%
and 6.50% for the three month and six-month period ended June 30, 1999 as
compared to 8.07% and 7.96% for the three month and six-month period
ended June 30, 1998.
The Company recognized net income for the three and six-month period
ended June 30, 1998 of $2.6 million and $5.8 million, respectively, as
compared to $1.8 million and $4.5 million for the equivalent period in
1998. Basic earnings per share ("EPS") for the three and six month
period ended June 30, 1999 increased 29% and 22%, respectively from $.24
and $.63 in 1998 to $.31 and $.77 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 $96.7 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 $94.4 million of pipeline systems.
The Company's long-term debt to total capitalization ratio decreased from
62% at March 31, 1999 to 33% at June 30, 1999. This was accomplished by
utilizing the $54.7 million in net proceeds from the May 1999 common
stock offering to reduce debt.
As a result of significantly increased cash flows generated from our
numerous acquisitions, in September 1998, the Company amended and
restated its bank financing agreement with Bank One. These amendments
increased our borrowing availability, modified our letter of credit
facility, established a credit sharing, extended the maturity two years
to August 2002, modified financial covenants, established waiver and
amendment approvals and changed the fee structure to include a decrease
in the interest rate on borrowings.
The amendments to the credit agreement increased our borrowing
availability from $80 million to $150 million (with an initial committed
amount of $100 million, which, as noted below, has subsequently been
increased to $125 million). The amended credit agreement provides
borrowing availability as follows: (i) up to a $15 million sublimit for
the issuance of standby and commercial letters of credit and (ii) the
difference between the $125 million and the used sublimit available as a
revolving credit facility. Effective September 8, 1998, at our option,
borrowings under the amended credit agreement accrue interest at LIBOR
plus 1.25% or the Bank One base rate.
Under the amended credit agreement, a credit sharing was established
among Bank One, CIBC Inc., and Bank of America, N.A. The Company was
subject to an initial facility fee of $.5 million, which represents all
fees due on borrowings up to $100 million. As the Company borrows funds
in excess of $100 million, a .15% fee will be imposed. The 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, 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 is in compliance with such financial
covenants at June 30, 1999.
In March 1999, we further amended the credit agreement to increase the
committed amount of borrowing availability and to allow for Canadian
dollar denominated loans. In anticipation of a new acquisition in Canada,
the Company increased the committed amount of borrowing availability
under the credit agreement from $100 million to $125 million. In
addition, because the functional currency of a newly formed Canadian
subsidiary will be Canadian dollars, the Company revised the credit
agreement to allow for loans in Canadian dollars in order to eliminate
foreign currency exchange risk.
For the six-months ended June 30, 1999, the Company generated cash flow
from operating activities before changes in working capital accounts of
approximately $9.1 million and had approximately $61.6 million available
under the credit agreement. At June 30, 1999, the Company had committed
to making approximately $6.9 million in construction related expenditures
for 1999. 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 $6.9 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 June 30, 1999, the Company had no unrealized
losses from such hedging contracts.
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%. 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 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 June 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 June 30, 1999, the
fair value of this interest rate swap through the initial termination
date was a net asset of $1.52 million.
The effect of these swap agreements was to lower interest expense by
$139,000 in the six-months ended June 30, 1999 and increase interest
expense by $33,000 in the six-months ended June 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 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 September 1999. A budget for updating computer software
and hardware of approximately $1.0 million dollars has been established
of which $.9 million has been spent through June 30, 1999. 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 September 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.
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 4. Submission of Matters to a Vote of Security Holders
The Company held its Annual Meeting of Shareholders on May 17, 1999.
Shareholders of record at the close of business on March 31, 1999 were
entitled to vote. The shareholders voted on nominations to elect six
Directors to the Board of Directors, a proposal to change the Company's
state of incorporation from Nevada to Texas, a proposal to amend the 1997
Non-Employee Director Stock Option Plan by increasing the number of
shares of common stock that could be issued under the incentive plan, and
a proposal to approve an Employee Stock Purchase Plan. For additional
information concerning the Annual Meeting of Shareholders please see the
Company's proxy statement dated April 19, 1999.
The Shareholders elected each of the six directors nominated for the
board of directors as follows:
<TABLE>
<S> <C> <C> <C>
Directors Votes For Votes Against Abstaining Broker No-Votes
Dan C. Tutcher 6,636,195 - 4,631
- -
I.J. Berthelot, II 6,636,173 - 4,653
- -
Richard N. Richards 6,636,173 - 4,653
- -
Ted Collins, Jr. 6,636,173 - 4,653
- -
Curtis J. Dufour III 6,636,173 - 4,653
- -
Bruce M. Withers 6,635,659 - 5,163
- -
</TABLE>
The shareholders approved the proposal to change the Company's state of
incorporation as follows:
<TABLE>
<S> <C> <C> <C> <C>
Votes For Against Abstaining Broker No-Votes
Articles of Incorporation 5,444,347 4,389 16,231 1,175,859
</TABLE>
The shareholders approved the proposal to amend to the 1997 Non-Employee
Director Stock Option Plan as follows:
<TABLE>
<S> <C> <C> <C> <C>
Votes For Votes Against Abstaining Broker No-Votes
Director Stock Option Plan 5,845,673 781,701 13,452
- -
The shareholders approved the proposal to approve the Company's Employee
Stock Purchase Plan as follows:
Votes For
Votes For Votes Against Abstaining Broker No-Votes
Employee Stock Purchase Plan 6,098,255 532,198 10,373 -
</TABLE>
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 second quarter of 1999. Such
report was filed on May 28, 1999 to report the sale of 3,370,000 shares
of common stock of the Company and 90,000 shares being sold by two
selling shareholders.
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: August 16, 1999
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<PERIOD-TYPE> 6 MONTHS
<FISCAL-YEAR-END> 12/31/99
<PERIOD-END> 06/30/99
<CASH> 5,516,000
<SECURITIES> 0
<RECEIVABLES> 50,331,000
<ALLOWANCES> 0
<INVENTORY> 1,389,000
<CURRENT-ASSETS> 57,236,000
<PP&E> 205,188,000
<DEPRECIATION> 8,924,000
<TOTAL-ASSETS> 255,464,000
<CURRENT-LIABLILITIES> 52,091,000
<BONDS> 0
<COMMON> 107,000
0
0
<OTHER-SE> 126,054,000
<TOTAL-LIABILITY-AND-EQUITY> 255,464,000
<SALES> 165,521,000
<TOTAL-REVENUES> 165,521,000
<CGS> 148,589,000
<TOTAL-COSTS> 155,482,000
<OTHER-EXPENSES> 115,000
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,876,000
<INCOME-PRETAX> 7,048,000
<INCOME-TAX> 1,217,000
<INCOME-CONTINUING> 5,831,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 5,831,000
<EPS-BASIC> .77
<EPS-DILUTED> .75
</TABLE>
