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 March 31, 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 March 31,1999, there were outstanding 7,149,513 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.
Flare Flare, L.L.C., a wholly owned subsidiary of Midcoast
Energy Resources, Inc.
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 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 March 31, 1999
<TABLE>
<CAPTION>
<S> <C>
PART I. FINANCIAL INFORMATION Page Number
Item 1. Unaudited Financial Statements
Consolidated Balance Sheets as of December 31, 1998
and March 31, 1999. 4
Consolidated Statements of Operations for the
three months ended March 31, 1998 and March 31, 1999. 5
Consolidated Statement of Shareholders' Equity for
the three months ended March 31, 1999. 6
Consolidated Statements of Cash Flows for the three months
ended March 31, 1998 and March 31, 1999. 7
Notes to Consolidated Financial Statements. 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. 12
Item 3. Quantitative and Qualitative Disclosures About
Market Risk 20
PART II. OTHER INFORMATION 20
SIGNATURE 21
</TABLE>
<TABLE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share date)
<CAPTION>
<S> <C> <C>
DECEMBER 31, MARCH 31,
ASSETS 1998 1999
CURRENT ASSETS:
Cash and cash equivalents $ 200 $ 2,021
Accounts receivable, net of allowance of $92 33,020 43,023
Materials and supplies, at average cost 1,363 1,364
Total current assets 34,583 46,408
PROPERTY, PLANT AND EQUIPMENT, at cost:
Natural gas transmission facilities 150,041 180,792
Investment in transmission facilities 1,342 1,358
Natural gas processing facilities 4,917 10,090
Oil and gas properties, using the full- 1,383 1,383
cost method of accounting
Other property and equipment 2,872 2,976
160,555 196,599
ACCUMULATED DEPRECIATION, DEPLETION AND (6,308) (7,639)
AMORTIZATION
154,247 188,960
OTHER ASSETS, net of amortization 2,512 1,799
Total assets $191,342 $237,167
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $32,540 $36,277
Current portion of long-term debt 176 176
payable to banks
Short-term borrowing from bank 754 5,833
Other current liabilities 124 69
Total current liabilities 33,594 42,355
LONG TERM DEBT PAYABLE TO BANKS 78,082 111,567
OTHER LIABILITIES 2,024 2,078
DEFERRED INCOME TAXES 10,808 11,025
MINORITY INTEREST IN CONSOLIDATED 550 593
SUBSIDIARIES
COMMITMENTS AND CONTINGENCIES (Note 4)
SHAREHOLDERS' EQUITY:
Common stock, $.01 par value, 31,250,000
shares authorized, 7,149,513 shares issued
and outstanding at December 31, 1998 and 71 71
March 31, 1999, respectively (Note 2)
Paid in capital 80,955 80,955
Accumulated deficit (11,947) (9,134)
Unearned compensation (4) (4)
Less: Cost of 181,125 and 157,301 (2,791) (2,339)
treasury shares, respectively
Total shareholders' equity 66,284 69,549
Total liabilities and shareholders'equity $191,342 $237,167
</TABLE>
The accompanying notes are an integral part of these financial
statements.
<TABLE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
(In thousands, except per share data)
<CAPTION>
For the Three Months Ended
March 31, March 31,
1998 1999
<S> <C> <C>
OPERATING REVENUES:
Sale of natural gas and other petroleum products $ 63,176 $ 75,200
Transportation fees 2,976 4,632
Natural gas processing and treating revenue 1,099 1,893
Other 88 339
Total operating revenues 67,339 82,064
OPERATING EXPENSES:
Cost of natural gas and other petroleum products 60,465 72,272
Natural gas processing and treating costs 444 982
Depreciation, depletion and amortization 693 1,409
General and administrative 1,603 1,928
Total operating expenses 63,205 76,591
OPERATING INCOME 4,134 5,473
NON-OPERATING ITEMS:
Interest expense (599) (1,503)
Minority interest in consolidated subsidiaries (2) (40)
Other income (expense), net 31 5
INCOME BEFORE INCOME TAXES 3,564 3,935
PROVISION FOR INCOME TAXES
Current ( 70) (463)
Deferred (733) (217)
NET INCOME $ 2,761 $ 3,255
EARNINGS PER COMMON SHARE:
BASIC $ 0.39 $ .47
DILUTED $ 0.38 $ .46
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
BASIC 7,101,663 6,931,098
DILUTED 7,350,138 7,148,391
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MIDCOAST ENERGY RESOURCES INC., AND SUBSIDIARIES
<TABLE>
<CAPTION>
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS' EQUITY
(In thousands, except share data)
<S> <C> <C> <C> <C> <C> <C>
TOTAL
COMMON PAID-IN ACCUMULATED UNEARNED TREASURY SHAREHOLDERS'
STOCK CAPITAL DEFICIT COMPENSATION STOCK EQUITY
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, - - (1,777) - - (1,777)
$.24 per share
Balance, December 31, 1998 $ 71 $80,955 $(11,947) $ (4) $(2,791) $66,284
Net income - - 3,255 - - 3,255
Treasury stock purchased - - - - (1,990) (1,990)
(116,750 shares)
Treasury stock issued in - - - - 2,442 2,442
connection with the DPI
acquisition (140,574
shares) (Note 3)
Common stock dividends, - - (442) - - (442)
$.06 per share
Balance, March 31, 1999 $ 71 $80,955 $(9,134) $ (4) $(2,339) $ 69,549
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
<TABLE>
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<CAPTION>
For the Three Months Ended
March 31, March 31,
1998 1999
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 2,761 $ 3,255
Adjustments to arrive at net cash provided (used)
in operating activities -
Depreciation, depletion and amortization 693 1,409
Deferred income taxes 733 217
Recognition of deferred income (21) (21)
Minority interest in consolidated subsidiaries 2 40
Other 13 -
Changes in working capital accounts -
(Increase) decrease in accounts receivable 577 (10,003)
(Increase) decrease in other current assets 163 (1)
Increase (decrease) in accounts payable and (5,378) 4,660
accrued liabilities
Net cash used by operating activities (457) (444)
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions - (28,591)
Capital expenditures (1,622) (4,949)
Other (129) (556)
Net cash used by investing activities (1,751) (34,096)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings 12,233 90,051
Bank debt repayments (9,773) (51,487)
Purchase of treasury stock - (1,990)
Advances to affiliates - (610)
Receipts from affiliates - 839
Contributions from (distributions to) joint (30) -
venture partners
Dividends on common stock (413) (442)
Net cash provided by financing activities 2,017 36,361
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (191) 1,821
CASH AND CASH EQUIVALENTS,beginning of period 308 200
CASH AND CASH EQUIVALENTS, end of period $ 117 $ 2,021
CASH PAID FOR INTEREST $ 842 $ 2,638
CASH PAID FOR INCOME TAXES $ 101 $ -
</TABLE>
The accompanying notes are an integral part of these consolidated
financial statements.
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.
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
140,574 shares of our common stock. Flare is a natural gas
processing and treating company whose principal assets include 27
portable natural gas processing and treating plants from which it
earns revenues based on treating and processing fees and/or a
percentage of the NGLs produced. DPI is an NGL, crude oil and CO2
transportation and marketing company. DPI operates 43 NGL and
crude oil trucks and trailers, a fleet of 40 pressurized railcars
and in excess of 400,000 gallons of NGL storage 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. At March 31, 1999, the Company has accrued $250,000 as
an additional purchase price adjustment.
MIDLA CONTINGENCY
As a condition of the Midla Acquisition, the Company agreed that
if a specific contract with a third party was executed prior to
October 2, 1999, which included specific provisions regarding
price and throughputs, Midcoast would be obligated to issue
137,500 warrants to acquire Midcoast common stock at an exercise
price of $15.82 per share to Republic. In addition, concurrent
with initial expenditures on the project, the Company would incur
a $1.2 million cash obligation to Republic. At March 31, 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-months ended March 31 (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
For the three months ended March 31,
1998 1999
<S> <C> <C> <C> <C> <C> <C>
Average Average
Net Shares Earnings Net Shares Earnings
Income Outstanding Per Share Income Outstanding Per Share
Basic $2,761 7,102 $ .39 $3,255 6,931 $.47
Effect of dilutive securities:
Stock options 153 207
Warrants 95 10
Diluted $2,761 7,350 $ .38 $3,255 7,148 $.46
</TABLE>
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>
<S> <C> <C>
For the three months ended March 31,
1998 1999
Segment Revenues:
Transmission $ 41,311 $ 36,024
End-User 23,669 28,547
Gathering, Processing and Treating 2,271 17,154
Total Segment Revenues $ 67,251 $ 81,725
Segment Operating Income:
Transmission $ 3,874 $ 4,543
End-User 1,292 1,520
Gathering, Processing and Treating 555 1,094
Total Segment Operating Income 5,721 7,157
Corporate administrative expenses (1,603) (1,928)
Interest expense (599) (1,503)
Other income (expense), net 45 209
Income Before Income Taxes $ 3,564 $ 3,935
</TABLE>
The identifiable assets of the Company, by segment, are as
follows (in thousands):
<TABLE>
<CAPTION>
March 31,
1998 1999
<S> <C> <C>
Property, Plant and Equipment
Transmission $ 85,774 $104,471
End-User 5,158 8,289
Gathering, Processing and Treating 10,858 82,539
Total Segment Assets 101,790 195,299
Corporate and other 672 1,300
Total Assets $102,462 $196,599
</TABLE>
The depreciation expense of the Company, by segment, is as
follows (in thousands):
<TABLE>
<CAPTION>
For the three months ended March 31,
1998 1999
<S> <C> <C>
Depreciation Expense:
Transmission $ 390 $ 372
End-User 136 205
Gathering, Processing and Treating 105 737
Total Segment Depreciation Expense 631 1,314
Corporate and other 62 95
Total Depreciation Expense $ 693 $ 1,409
</TABLE>
7. NEW ACCOUNTING PRONOUNCEMENT NOT YET ADOPTED
The FASB issued SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities". This Statement establishes
accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other
contracts, (collectively referred to as derivatives) and for
hedging activities. This Statement is effective for all fiscal
quarters of fiscal years beginning after June 15, 1999. Initial
application of this Statement should be as of the beginning of an
entity's fiscal quarter; on that date, SFAS No. 133 will require
the Company to record all derivatives on the balance sheet at
fair value. Changes in derivative fair values will either be
recognized in earnings as offsets to the changes in fair value of
related hedged assets, liabilities and firm commitments or, for
forecasted transactions, deferred and recorded as a component of
other shareholders' equity until the hedged transactions occur
and are recognized in earnings. The ineffective portion of a
hedging derivative's change in fair value will be immediately
recognized in earnings. The impact of SFAS 133 on the Company's
financial statements will depend on a variety of factors,
including future interpretative guidance from the FASB, the
extent of the Company's hedging activities, the types of hedging
instruments used and the effectiveness of such instruments.
However, the Company does not believe the effect of adopting SFAS
133 will be material to its financial position.
8. SUBSEQUENT EVENTS
In May 1999, the Company announced that it intends to make a
public offering of 3,370,000 shares of its common stock under its
shelf registration statement declared effective on February 5, 1999.
Also it is anticipated that three selling shareholders will offer
an additional 130,000 shares. The offering is expected to close
in late May 1999.
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 49 pipelines for an
aggregate acquisition cost of over $161 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 producers gas. The contracts based on keep-whole
provide that the Company is required to reimburse the producers
for the BTU energy equivalent of the NGLs and fuel removed from
the natural gas as a result of processing and the Company retains
all revenues from the sale of the NGL's. Once extracted, the
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 periods ended March 31,
1998 and March 31, 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.
<TABLE>
<CAPTION>
TRANSMISSION PIPELINES
(In thousands, except gross margin per Mmbtu)
For the Three Months Ended
March 31,1998 March 31,1999
<S> <C> <C>
Operating Revenues:
Marketing $ 39,314 $ 34,107
Transportation Fees 1,997 1,917
Total Operating Revenues 41,311 36,024
Operating Expenses:
Marketing Costs 35,875 30,024
Operating Expenses 1,172 1,085
Total Operating Expenses 37,047 31,109
Gross Margin $ 4,264 $ 4,915
Volume (in Mmbtu)
Marketing 16,348 16,313
Transportation 15,152 14,668
Total Volume 31,500 30,981
Gross Margin per Mmbtu $ .14 $ .16
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31,
1998
The Company's Transmission segment experienced a 15% increase in gross margin
for the three-months ended March 31, 1999 when compared to the equivalent
three-month period ended March 31, 1998. This increase was achieved despite
a mild winter due to improved marketing margins on a per Mmbtu basis, as
well as a reduction in operating expense.
<TABLE>
<CAPTION>
END-USER PIPELINES
(In thousands, except gross margin per Mmbtu)
For the Three Months Ended
March 31, March 31,
1998 1999
<S> <C> <C>
Operating Revenues:
Marketing $22,905 $ 27,808
End-User Transportation 764 739
Fees
Total Operating Revenues 23,669 28,547
Operating Expenses:
Marketing Costs 22,196 26,722
Operating Expenses 45 100
Total Operating Expenses 22,241 26,822
Gross Margin $ 1,428 $ 1,725
Volume (in Mmbtu)
Marketing 10,236 10,046
Transportation 4,883 6,012
Total Volume 15,119 16,058
Gross Margin per Mmbtu $ .09 $ .11
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31,
1998
For the quarter ended March 31, 1999, the End-User segment gross margin
increased 21% over the same period in 1998. The increase is primarily
attributable to incremental gross margin created by the June 1998 Creole
pipeline acquisition, in addition to new natural gas marketing services to
a new cogeneration facility near Baton Rouge, Louisiana.
<TABLE>
<CAPTION>
GATHERING PIPELINES AND NATURAL GAS PROCESSING AND TREATING
(In thousands, except gross margin per Mmbtu)
For the Three Months Ended
March 31, March 31,
1998 1999
<S> <C> <C>
Operating Revenues:
Marketing $ 957 $ 13,285
Gathering Transportation Fees 215 1,976
Processing and Treating Revenues 1,099 1,893
Total Operating Revenues 2,271 17,154
Operating Expenses:
Marketing Costs 777 13,332
Operating Expenses 390 1,009
Processing and Treating Costs 444 982
Total Operating Expenses 1,611 15,323
Gross Margin $ 660 $ 1,831
Volume (in Mmbtu)
Marketing 461 5,125
Gathering 5,866 19,557
Processing and Treating 511 1,961
Total Volume 6,838 26,643
Gross Margin per Mmbtu $ .10 $ .07
</TABLE>
Quarter Ended March 31, 1999 Compared to Quarter Ended March 31,
1998
Significant increases in revenues, gross margin and volumes were realized
for the quarter ended March 31, 1999 compared to the quarter ended March 31,
1998. The significant increases are a result of the Company's successful
acquisition strategy which has recently been focused on assets in this
segment. As discussed in Note 3 to the Consolidated Financial Statements,
five acquisitions in this segment were consummated in the first quarter
of 1999, in addition to the Anadarko and Mendota acquisitions in September
and December 1998, respectively.
OTHER INCOME, COSTS AND EXPENSES
In the three months period ended March 31, 1999, the Company
received revenues of $339,000 in other revenues as compared to
$88,000 over the same period in 1998. The increase is primarily
attributable to a sale of renovated equipment by its Flare
subsidiary.
In the three month period ended March 31, 1999, the Company's
depreciation, depletion and amortization increased to $1,409,000
from $693,000 when compared to 1998. Of the $716,000 increase,
69% is attributable to depreciation on the Anadarko, Flare,
SeaCrest, Tinsley, and Dufour acquisitions, which had no
equivalent depreciation in 1998. In addition, 20% of the
increase is attributable to a one-time impairment on the
Company's H&W assets recognized in the quarter.
In the three months period ended March 31, 1999, the Company's
general and administrative expenses increased to $1,928,000 from
$1,603,000 in 1998. The increase is due to incremental overhead
on newly acquired assets in late 1998 and 1999 as well as
increased staffing levels in 1999.
Interest expense for the three months period ended March 31, 1999
increased to $1,503,000 from $599,000 in 1998. The increased
debt load in 1999 is primarily associated with the Company's
September 1998 acquisition of Anadarko and March 1999 acquisition
of MCOC. 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
6.13% for the three-month period ended March 31, 1999 as compared
to 7.72% for the three-month period ended March 31, 1998.
The Company recognized net income for the three-month period
ended March 31, 1999 of $3.26 million as compared to $2.76
million for the equivalent period in 1998. EPS for the three
month period ended March 31, 1999 increased 21% from $.39 to $.47
in 1999. The significant improvement in EPS is attributable full
quarter operations of acquisitions completed in 1998, and partial
quarter operations of new acquisitions in 1999.
INCOME TAXES
As of December 31, 1998, the Company had 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
and July 1997, respectively.
The net proceeds of our combined stock offerings contributed
approximately $42.1 million and significantly improved our
financial flexibility. This increased flexibility has allowed us
to pursue acquisition and construction opportunities utilizing
lower cost conventional bank debt financing. During 1998 and to
date in 1999, the Company has acquired or constructed $83.1
million of pipeline systems. These acquisition and construction
projects increased our long-term debt to total capitalization
ratio to 62% at March 31, 1999.
As a result of significantly increased cash flows generated from
our numerous acquisitions, in September 1998, the Company has
amended and restated our bank financing agreement with Bank One.
These amendments increased our borrowing availability, modified
our letter of credit facility, established a credit sharing,
extended the maturity two years to August 2002, modified
financial covenants, established waiver and amendment approvals
and changed the fee structure to include a decrease in the
interest rate on borrowings.
The amendments to the credit agreement increased our borrowing
availability from $80 million to $150 million (with an initial
committed amount of $100 million, which, as noted below, has
subsequently been increased to $125 million). The amended credit
agreement provides borrowing availability as follows: (i) up to a
$15 million sublimit for the issuance of standby and commercial
letters of credit and (ii) the difference between the $100
million and the used sublimit available as a revolving credit
facility. Effective September 8, 1998, at our option, borrowings
under the amended credit agreement accrue interest at LIBOR plus
1.25% or the Bank One base rate.
Under the amended credit agreement, a credit sharing was
established among Bank One, CIBC Inc., and Bank of America, N.A.
The Company is 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, 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 March 31, 1999.
In March 1999, we further amended the credit agreement to
increase the committed amount of borrowing availability and to
allow for Canadian dollar denominated loans. In anticipation of a
new acquisition in Canada, 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 flexibility to borrow funds in Canadian dollars in order to
eliminate foreign currency exchange risk.
For the quarter ended March 31, 1999, the Company generated cash
flow from operating activities before changes in working capital
accounts of approximately $4.9 million and had approximately
$7.6 million available under the credit agreement.
At March 31, 1999, the Company had committed to making
approximately $2.2 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 $2.2 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.
In May 1999, the Company announced that it intends to make a
public offering of 3,370,000 shares of its common stock under its
shelf registration statement declared effective on Feb. 5, 1999.
Also it is anticipated that three selling shareholders will offer
an additional 130,000 shares. The offering is expected to close
in late May 1999.
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 March 31, 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 March 31,
1999, the fair value of this interest rate swap through the
transferred termination date was a net liability of $75,000.
The second interest rate swap agreement was entered into with
CIBC in October 1998. The swap agreement effectively established
a fixed three-month LIBOR interest rate setting of 4.475% for a
three-year period on a notional amount of $40 million. The
agreement, however, may be extended an additional two years
through November 2003 at CIBC's option on the last day of the
initial term. The variable three-month LIBOR rate is reset
quarterly based on the prevailing market rate, and Midcoast is
obligated to reimburse CIBC when the three-month LIBOR rate is
reset below 4.475%. Conversely, CIBC is obligated to reimburse
Midcoast when the three-month LIBOR rate is reset above 4.475%.
At March 31, 1999, the fair value of this interest rate swap
through the initial termination date was a net asset of
$1,078,000.
The effect of these swap agreements was to lower interest expense
by $49,000 in the three-months ended March 31, 1999 and increase
interest expense by $12,000 in the three-months ended March 31,
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 June
1999. A budget for updating computer software and hardware of
approximately $1.0 million dollars has been established of which
$.8 million has been spent through March 31, 1999. Based on a
successful implementation of our Y2K plan, we do not expect the
Y2K issue to pose significant operational problems for the
Company's computer systems.
The Company plans to complete its assessment of its key vendors,
customers and other third parties by June 30, 1999 in order to
assess the impact such third party Y2K issues will have, if any,
on the Company's business operations. The Company does not
anticipate that any third parties' Y2K issues will materially
impact the Company's operations or financial results. With
respect to suppliers, the Company does not utilize any individual
supplier in its operations with whom interruptions for Y2K
problems could have a material impact on the Company's operations
and financial results. In addition, there are alternative
suppliers with whom the Company anticipates that it would be able
to obtain sufficient quantities of products to continue to
conduct its business. Because the Company anticipates that it
will complete its Y2K remediation efforts in advance of December
31, 1999, it has not made any contingency plans with respect to
its operations and systems. However, a contingency plan will be
established by the third quarter of 1999 to address any
unforeseen issues, or if the planned improvements are not
completed on schedule.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made
with the intention to comply fully with the Year 2000 Information
and Readiness Disclosure Act of 1998, Pub. L. No. 105-271, 112
Stat, 2386, signed into law October 19, 1998. All Statements made
herein shall be construed within the confines of that Act. To the
extent that any reader of the above Year 2000 Readiness
Disclosure is other than an investor or potential investor in the
Company's Common Stock, this disclosure is made for the SOLE
PURPOSE of communicating or disclosing information aimed at
correcting, helping to correct and/or avoid Year 2000 failures.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This report includes "forward looking statements" within the
meaning of Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Exchange Act of 1934. All statements
other than statements of historical fact included in this report
are forward looking statements. Such forward looking statements
include, without limitation, statements under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Capital Resources and Liquidity" regarding
Midcoast's estimate of the sufficiency of existing capital
resources, whether funds provided by operations will be
sufficient to meet its operational needs in the foreseeable
future, and its ability to utilize NOL carryforwards prior to
their expiration. Although Midcoast believes that the
expectations reflected in such forward looking statements are
reasonable, it can give no assurance that such expectations
reflected in such forward looking statements will prove to be
correct. The ability to achieve Midcoast's expectations is
contingent upon a number of factors which include (i) timely
approval of Midcoast's acquisition candidates by appropriate
governmental and regulatory agencies, (ii) the effect of any
current or future competition, (iii) retention of key personnel
and (iv) obtaining and timing of sufficient financing to fund
operations and/or construction or acquisition opportunities.
Important factors that could cause actual results to differ
materially from the Company's expectations ("Cautionary
Statements") are disclosed in this report, including without
limitation those statements made in conjunction with the forward
looking statements included in this report. All subsequent
written and oral forward looking statements attributable to the
Company or persons acting on its behalf are expressly qualified
in their entirety by the Cautionary Statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information contained in Item 3 updates, and should be read
in conjunction with, information set forth in Part II, Item 7A in
the Company's Annual Report on Form 10-K for the year ended
December 31, 1998, in addition to the interim consolidated
financial statements and accompanying notes presented in Items 1
and 2 of this Form 10-Q. There are no material changes in market
risks faced by the Company from those reported in the Company's
Annual Report on Form 10-K for the year ended December 31, 1998.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS - None.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS - None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES - None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS -
None.
ITEM 5. OTHER INFORMATION - None.
ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
EXHIBITS DESCRIPTION OF EXHIBITS
______
b. Reports on Form 8-K:
A report on Form 8-K was filed during the first quarter of 1999.
Such report was filed on February 26, 1999 as an Other Event, to
amend Registration Statements to include the effects of a five
for four stock split.
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: May 17, 1999
_______________________________
1Includes 339 other revenue, less 94 corporate depreciation
expense, 40 minority interest and 5 other
2Need to call (Nationsbank) 877-669-7369 for market value of SWAP
at 3/31/99
3Need to call Thomas Lee (CIBC) 212-885-4373 for market value of
SWAP at 3/31/99.
<TABLE> <S> <C>
<ARTICLE> 5
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-1999
<CASH> 2,021,000
<SECURITIES> 0
<RECEIVABLES> 43,023,000
<ALLOWANCES> 0
<INVENTORY> 1,364,000
<CURRENT-ASSETS> 46,408,000
<PP&E> 196,559,000
<DEPRECIATION> 7,639,000
<TOTAL-ASSETS> 237,167,000
<CURRENT-LIABILITIES> 42,355,000
<BONDS> 0
<COMMON> 71,000
0
0
<OTHER-SE> 69,478,000
<TOTAL-LIABILITY-AND-EQUITY> 237,167,000
<SALES> 82,064,000
<TOTAL-REVENUES> 82,064,000
<CGS> 73,254,000
<TOTAL-COSTS> 76,591,000
<OTHER-EXPENSES> (35,000)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 1,503,000
<INCOME-PRETAX> 3,935,000
<INCOME-TAX> 680,000
<INCOME-CONTINUING> 3,255,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 3,255,000
<EPS-PRIMARY> .47
<EPS-DILUTED> .46
</TABLE>
