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, 2000
[_] 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)
Texas 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 May 12, 2000, there were outstanding 12,498,005 shares of
the Company's common stock, par value $.01 per share.
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
TABLE OF CONTENTS
Caption
Page
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Glossary ii
Part I. Financial Information
Item 1. Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Balance Sheets as of
March 31, 2000 and December 31, 1999 1
Unaudited Condensed Consolidated Statements of Operations
for the three months ended March 31, 2000 and March 31, 1999 2
Unaudited Condensed Consolidated Statements of Comprehensive
Income for the three months ended March 31, 2000 and
March 31, 1999 3
Unaudited Condensed Consolidated Statement of Shareholders'
Equity for the three months ended March 31, 2000 4
Unaudited Condensed Consolidated Statements of Cash Flows
for the three months ended March 31, 2000 and March 31, 1999 5
Notes to Unaudited Condensed Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 11
Item 3. Quantitative and Qualitative Disclosures about Market
Risk 18
Part II. Other Information 20
Signature 21
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GLOSSARY
The following abbreviations, acronyms, or defined terms
used in this Form10-Q are defined below:
Bbl 42 U.S. gallon barrel
Board Board of directors of Midcoast Energy Resources,
Inc.
Btu British thermal unit
Common Stock Midcoast common stock, par value $.01 per share
Company Midcoast Energy Resources, Inc., its subsidiaries
and affiliated companies
DPI Dufour Petroleum, Inc., a wholly owned subsidiary of
Midcoast Energy Resources, Inc.
EBITDA Earnings Before Interest, Taxes, Depreciation and
Amortization
EPS Diluted earnings per share
FASB Financial Accounting Standards Board
KPC The November 1999 acquisition of Kansas Pipeline
Acquisition Company and MarGasCo
KPC System A 1,120-mile interstate transmission pipeline
LIBOR London Inter Bank Offering Rate
Mcf/day Thousand cubic feet of gas (per day)
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 Natural gas liquid
NOL Net operating loss
Republic Republic Gas Partners L.L.C.
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 System Two end-user pipelines in northern Alabama
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share data)
MARCH 31, 2000 DECEMBER 31, 1999
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and cash equivalents $ 2,749 $ 2,345
Accounts receivable, net of allowance of 57,472 55,189
$1,294 and $1,484, respectively
Other current assets 4,105 4,905
Total Current Assets 64,326 62,439
PROPERTY, PLANT AND EQUIPMENT, NET 398,814 392,969
OTHER ASSETS 23,236 22,964
Total Assets $486,376 $478,372
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable and accrued liabilities $ 65,948 $ 63,901
Current portion of long-term debt 22 71
payable to banks
Other current liabilities 6 6
Total Current Liabilities 65,976 63,978
LONG-TERM DEBT 241,000 240,000
OTHER LIABILITIES 2,196 2,147
DEFERRED INCOME TAXES 11,775 11,034
COMMITMENTS AND CONTINGENCIES - -
MINORITY INTEREST IN CONSOLIDATED 524 536
SUBSIDIARIES
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 31,250,000 shares; 127 127
issued 12,721,980
Paid-in capital 165,936 165,964
Retained earnings (accumulated deficit) 2,428 (2,915)
Accumulated other comprehensive income 63 71
Treasury stock (at cost), 227,856 and (3,649) (2,570)
161,156
Total Shareholders' Equity 164,905 160,677
Total Liabilities and Shareholders' Equity $486,376 $478,372
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
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MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
For the Three Months Ended
March 31, 2000 March 31, 1999
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OPERATING REVENUES:
Energy marketing revenue $129,032 $75,200
Transportation fees 14,677 4,632
Natural gas processing revenue 7,621 1,893
Other 422 339
Total operating revenues 151,752 82,064
OPERATING EXPENSES:
Energy marketing expenses 126,830 72,272
Natural gas processing costs 5,341 982
Depreciation, depletion and amortization 3,479 1,409
General and administrative 3,958 1,928
Total operating expenses 139,608 76,591
Operating income 12,144 5,473
NON-OPERATING ITEMS:
Interest expense (4,895) (1,503)
Minority interest in consolidated subsidiaries (18) (40)
Other income, net 60 5
INCOME BEFORE INCOME TAXES 7,291 3,935
PROVISION FOR INCOME TAXES:
Current (333) (463)
Deferred (741) (217)
NET INCOME $6,217 $ 3,255
EARNINGS PER COMMON SHARE:
BASIC $ 0.50 $ 0.47
DILUTED $ 0.49 $ 0.46
WEIGHTED AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING:
BASIC 12,546,878 6,931,098
DILUTED 12,749,174 7,148,391
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE
INCOME
(In thousands)
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For the Three Months Ended,
March 31, 2000 March 31, 1999
<S> <C> <C>
Net income $ 6,217 $ 3,255
Foreign currency translation adjustment (8) -
Comprehensive income $ 6,209 $ 3,255
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENT OF SHAREHOLDERS'
EQUITY
(In thousands, except per share data)
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Retained Accumulated
Earnings Other Total
Common Stock Paid-in (Accumulated Comprehensive Treasury Stock Shareholders'
Shares Amount Capital Deficit) Income Shares Amount Equity
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Balance, December 31, 1999 12,722 $ 127 $165,964 $ (2,915) $ 71 (161) $ (2,570) $160,677
Net income - - - 6,217 - - - 6,217
Treasury stock purchased
(67 shares) - - - - - (67) (1,079) (1,079)
Foreign currency
translation adjustment - - - - (8) - - (8)
Common stock dividends,
$.07 per share - - - (874) - - - (874)
Other - - (28) - - - - (28)
Balance, March 31, 2000 12,722 $ 127 $165,936 $ 2,428 $ 63 (228) $(3,649) $164,905
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
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For the Three Months Ended
March 31, 2000 March 31, 1999
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CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 6,217 $ 3,255
Adjustments to arrive at net cash provided by (used) in
operating activities:
Depreciation, depletion and amortization 3,479 1,409
Deferred income taxes 741 217
Recognition of deferred income - (21)
Minority interest in consolidated subsidiaries 18 40
Other 41 -
Changes in working capital accounts:
Increase in accounts receivable (2,178) (10,003)
(Increase) Decrease in other current assets 563 (1)
Increase in accounts payable and accrued liabilities 2,047 4,660
Net cash provided by (used in) operating activities 10,928 (444)
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions (5,783) (28,591)
Capital expenditures (3,257) (4,949)
Net receipts from (advances to) equity investee (105) 229
Other - (556)
Net cash used in investing activities (9,145) (33,867)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings 39,500 90,051
Bank debt repayments (38,549) (51,487)
Treasury stock purchases (1,079) (1,990)
Dividends on common stock (874) (442)
Other (377) -
Net cash provided by (used in) financing activities (1,379) 36,132
NET INCREASE IN CASH AND CASH EQUIVALENTS 404 1,821
CASH AND CASH EQUIVALENTS, beginning of period 2,345 200
CASH AND CASH EQUIVALENTS, end of period $ 2,749 $ 2,021
SUPPLEMENTAL DISCLOSURES:
Cash Paid for Interest $ 4,948 $ 2,638
Cash Paid for Income Taxes $ 1,600 $ -
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
1. BASIS OF PRESENTATION:
The accompanying unaudited condensed consolidated 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 1999 so that the presentation of the
information is consistent with reporting for the Consolidated
Financial Statements in 2000. 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, 1999.
2. ACQUISITION:
PROVOST ACQUISITION
In March 2000, the Company acquired the Provost natural gas
plant and gathering system from NovaGas Canada LP, a division of
TransCanada, for approximately $5.1 million (U.S.). The Provost
acquisition includes 80 miles of natural gas gathering pipeline
and a 15 MMcf/day sour gas processing plant and sour gas
injection well. The system is located in east-central Alberta,
Canada and is the only sour natural gas gathering and processing
system in the area. The system is connected to 21 oil tank
batteries and primarily gathers the associated sour natural gas
production from approximately 900 wells in the Provost area. The
acquisition was funded through the Company's existing credit
facility.
3. 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 December 2002. 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 ACQUISITION 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 annually the
lesser of 50% of the gross revenues received under these
contracts or $250,000. Through March 31, 2000, the Company has
made one payment of $250,000 and has accrued an additional
$250,000 under the contingency.
DPI ACQUISITION CONTINGENCY
As part of the DPI acquisition, the Company agreed that, in
the event that the Company approves certain long-term DPI or
Flare projects and these projects are placed under contract and
in service, the Company would be obligated to pay the DPI
shareholders an additional consideration of up to $2.5 million.
This contingency expires on
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS,
Continued
March 11, 2002. As of March 31, 2000, none of the identified
projects have been constructed and therefore no contingent
payments have been accrued.
RATES AND REGULATORY MATTERS
Each of our pipeline systems has contracts covering a
portion of their firm transportation capacity with various terms
of maturity, and each operates in different markets and regions
with different competitive and regulatory pressures which can
impact their ability to renegotiate and renew existing contracts,
or enter into new long-term firm transportation commitments.
KPC filed a rate case pursuant to Section 4 of the NGA on
August 27, 1999 (FERC Docket No. RP99-485-000). KPC's proposed
rates reflect an annual revenue increase when compared to its
initial FERC-approved rates. The rates have been protested by
KPC's two principal customers and by the state public utility
commissions that regulate them. On September 30, 1999, the FERC
issued an order that set KPC's proposed rates for hearing and
accepted and suspended the rates to be effective March 1, 2000,
subject to possible refund. The Section 4 rate case proceeding
will determine whether the rates proposed by KPC for interstate
transportation of natural gas are just and reasonable, and the
extent to which KPC must refund all or any part of the proposed
rate increase that it charges to its customers prior to approval.
A procedural schedule in the case has been adopted by the
Presiding Administrative Law Judge. A hearing date is set for
September 26, 2000.
While we cannot predict with certainty the final
outcome or timing of the resolution of rates and regulatory
matters, the outcome of our current re-contracting and capacity
subscription efforts, or the outcome of ongoing industry trends
and initiatives, we believe the ultimate resolution of these
issues will not have a material adverse effect on our financial
position, results of operations, or cash flows.
4. EARNINGS PER SHARE:
Basic and diluted earnings per share amounts are presented
below for the three months ended March 31 (in thousands, except
per share amounts):
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2 0 0 0 1 9 9 9
Average Average
Net Shares Earnings Net Shares Earnings
Income Outstanding Per Share Income Outstanding Per Share
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Basic $ 6,217 12,547 $ .50 $ 3,255 6,931 $ .47
Effect of dilutive securities:
Stock options - 147 (.01) - 207 (.01)
Warrants - 55 - - 10 -
Diluted $ 6,217 12,749 $ .49 $ 3,255 7,148 $ .46
</TABLE>
5. SEGMENT DATA:
The Company conducts its business of gathering,
transporting, processing and marketing of natural gas and other
petroleum products through the transmission, end-user, and
processing and gathering segments. The Company's operations are
segregated into reportable segments based on the type of business
activity and type of customer served. The Company's transmission
pipelines primarily receive and deliver natural gas to and from
other pipelines, and secondarily, provide end-user or gathering
functions. Transportation fees are received by the Company for
transporting gas owned by other parties through the Company's
pipeline systems. The Company's end-user pipelines provide
natural gas and natural gas transportation services to industrial
customers, municipalities or electrical generating facilities
through interconnect gas pipelines constructed or acquired by the
Company. These pipelines provide a direct supply of natural gas
to new industrial facilities or to existing facilities as an
alternative to the local distribution company. The Company's
gathering systems typically consist of a network of pipelines
which
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS,
Continued
collect natural gas or crude oil from points near producing
wells, process the natural gas, and transport oil and natural gas
to larger pipelines for further transmission.
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. All of the Company's segments have
significant revenues from gas marketing activities.
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 Company's Annual Report on Form 10-K for the
year ended December 31, 1999. The following tables present
certain financial information relating to the Company's business
segments as of or for the three months ended March 31, 2000 and
1999:
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As of or for the Three Months Ended March 31, 2000
Transmission End-User Gathering and
Pipelines Pipelines Processing Other Total
(In thousands)
<S> <C> <C> <C> <C> <C>
Revenues:
Domestic $ 53,173 $ 33,513 $ 63,209 $ 422 $150,317
Foreign - - 1,435 - 1,435
Total Revenues 53,173 33,513 64,644 422 151,752
Gross Margin 11,277 2,411 5,471 422 19,581
Depreciation and Amortization (1,848) (295) (1,151) (185) (3,479)
General & Administrative - - - (3,958) (3,958)
Interest Expense - - - (4,895) (4,895)
Other, net - - - 42 42
Income before income taxes 9,429 2,116 4,320 (8,574) 7,291
Assets:
Domestic 338,645 30,123 89,231 9,909 467,908
Foreign - - 18,468 - 18,468
Total Assets 338,645 30,123 107,699 9,909 486,376
Capital Expenditures 299 1,538 987 433 3,257
</TABLE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS,
Continued
<TABLE>
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As of or for the Three Months Ended March 31, 1999
Transmission End-User Gathering and
Pipelines Pipelines Processing Other Total
(In thousands)
<S> <C> <C> <C> <C> <C>
Revenues:
Domestic $ 36,024 $ 28,547 $ 16,886 $ 339 $ 81,796
Foreign - - 268 - 268
Total Revenues 36,024 28,547 17,154 339 82,064
Gross Margin 4,915 1,725 1,831 339 8,810
Depreciation and Amortization (372) (205) (737) (95) (1,409)
General & Administrative - - - (1,928) (1,928)
Interest Expense - - - (1,503) (1,503)
Other, net - - - (35) (35)
Income before income taxes 4,543 1,520 1,094 (3,222) 3,935
Assets:
Domestic 130,934 8,684 74,274 9,487 223,379
Foreign - - 13,788 - 13,788
Total Assets 130,934 8,684 88,062 9,487 237,167
Capital Expenditures 789 2,429 1,552 179 4,949
</TABLE>
6. 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. 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 comprehensive income in shareholders' equity until the
hedged transactions occur and are recognized in earnings. The
ineffective portion of a hedging derivative's change in fair
value will be immediately recognized in earnings. The impact of
SFAS No. 133 on the Company's financial statements will depend on a
variety of factors, including future interpretative guidance from
the FASB, the extent of the Company's hedging activities, the
types of hedging instruments used and the effectiveness of such
instruments. The standard was amended by SFAS No. 137 in June
1999. The amendment defers the effective date of SFAS No. 133 to
fiscal years beginning after June 15, 2000. The Company is
currently evaluating the effects of this pronouncement.
7. SUBSEQUENT EVENT:
THE MANYBERRIES ACQUISITION
In April 2000, the Company completed the acquisition of the
Manyberries Pipeline System ("MBPL") in Canada from Triumph
Energy Corporation for cash consideration of approximately $5.7
million (U.S.), plus certain future contingent payments based on
the actual throughput volumes. MBPL consists of 90 miles of
crude oil pipeline that originates at the Manyberries Oil Field
and terminates at an interconnection with the Milk River Pipeline
system in southeastern Alberta, Canada. Truck terminals,
including the Legend terminal, and a significant amount of crude
oil storage also contribute to the operations. The system has a
design capacity of approximately 21,000 Bbls/day and transports
light sour crude oil from the Manyberries Oil Field, as well as
additional crude oil volumes from the Legend truck terminal. The
pipeline system is the only light gravity system in southern
Alberta, and current volumes are approximately 6500 Bbls/day. The
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS,
Continued
acquisition was funded through the Company's existing credit
facility.
8. UNUSUAL CHARGE:
During the fourth quarter of 1999, the Company
recorded a pre-tax unusual charge totaling $2.7 million ($2.2
million after tax) related to streamlining efforts announced in
November 1999. The charge primarily relates to the severance and
benefits of approximately 50 employees who were involuntarily
terminated. One of these employees was still employed with the
Company at March 31, 2000. The Company anticipates savings from
reduced employee cost and more streamlined operating and business
processes. The following table shows the status of, and changes
to, the restructuring reserve for the first three months of 2000.
<TABLE>
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<S> <C>
Reserve at December 31, 1999 $ 1,701,009
Expenditures (1,501,614)
New Accruals -
Reserve at March 31, 2000 $ 199,395
</TABLE>
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis should be read in
conjunction with the unaudited condensed consolidated financial
statements of the Company included elsewhere herein and with the
Company's Annual Report on Form 10-K for the year ended December
31, 1999.
GENERAL
Since its formation, the Company has grown significantly as
a result of the construction and acquisition of new pipeline
facilities. From January 1996 through March 2000, the Company
acquired or constructed 74 pipelines for an aggregate cost of
approximately $376 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 and newly constructed pipeline systems.
As the Company pursues its growth strategy in the future, its
financial position and results of operations may fluctuate
significantly from period to period.
The Company's results of operations are determined primarily
by the volumes of natural gas transported, purchased and sold
through its pipeline systems or processed at its processing
facilities. With the exception of the Company's natural gas
processing activities, whose margins fluctuate with commodity prices,
the Company's revenues are derived from fee-based sources.
In addition, most of the Company's operating costs do not
vary directly with volume on existing systems, thus,
increases or decreases in transportation volumes generally
have a direct effect on net income. The Company
derives its revenues from three primary sources: (i) the
marketing of natural gas and other petroleum products, (ii)
transportation fees from pipeline systems owned by the Company
and (iii) the processing of natural gas.
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, gas marketing activities
will generate higher revenues and correspondingly higher expenses
than revenues and expenses associated with transportation
activities, given the same volumes of natural gas. This
relationship exists because, unlike revenues derived from
transportation activities, gas marketing revenues and associated
expenses include the full commodity price of the natural gas
acquired. The operating income the Company recognizes from its
gas marketing efforts is the difference between the price at
which the natural gas was purchased and the price at which it was
resold to the Company's customers. The Company's strategy is to
focus its marketing activities on Company owned pipelines. The
Company's marketing activities have historically varied greatly
in response to market fluctuations.
Transportation fees are received by the Company for
transporting natural gas or crude oil owned by other parties
through the Company's pipeline systems, transport trucks and
railcars. Typically, the Company incurs very little incremental
operating or administrative overhead cost to transport natural
gas through its pipeline assets, 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's and residual natural gas revenues as a
fee for processing the producer's gas. The keep-whole contracts
require that the Company reimburse the producers for the Btu
energy equivalent of the NGL's 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. The Company's processing
margins can be adversely affected by declines in NGL prices,
declines in natural gas throughput, or increases in shrinkage or
fuel costs, and in the case of keep-whole contracts, margins can
be adversely affected by increases in natural gas prices.
The Company has had quarter-to-quarter fluctuations in its
financial results in the past due to the fact that the Company's
natural gas sales and pipeline throughputs can be affected by
changes in demand for natural gas primarily because of the
weather. In particular, demand on the Magnolia, MIT and MIDLA
systems fluctuate due to weather variations because of the large
municipal and other seasonal customers that are served by the
respective systems. As a result, the winter months have
historically 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.
RESULTS OF OPERATIONS
The Company has acquired or constructed numerous pipelines
since January 1996. The purchased assets were acquired from
numerous sellers, at different periods and all were accounted
for under the purchase method of accounting for business
combinations and accordingly, the results of operations
for such acquisitions are included in the Company's
financial statements only from the applicable date of the
acquisition. As a consequence, the historical results of
operations for the periods presented may not be comparable.
The Company adopted the provisions of SFAS No. 131,
Disclosures about Segments of an Enterprise and Related
Information, effective January 1, 1998. Accordingly, the Company
has segregated its business activities into three segments:
Transmission Pipelines, End-User Pipelines, and Gathering
Pipelines and Natural Gas Processing.
For the first quarter ended March 31, 2000, the Company had
total revenues of $151.8 million, an 85% increase from $82.1
million during the first quarter of 1999. Operating income
improved 122% and net income improved 91% to $12.1 million and
$6.2 million from $5.5 million and $3.3 million, respectively, in
1999. Basic earnings per share were $0.50 and diluted earnings
per share were $0.49 as compared to $0.47 and $0.46 per share in
the first quarter of 1999. Results were positively impacted by a
number of recent acquisitions including KPC, DPI and the SeaCrest
offshore systems, as well as expansions along the MIDLA system
and increased volumes and margins on the Magnolia system. These
results came despite a 78% increase in the weighted average
number of shares outstanding (diluted) as a result of stock
offerings in May and December 1999 and an increase to 7.9% in the
weighted average interest rate for the quarter as compared to
6.1% in the first quarter last year. Another historically mild
winter also negatively impacted volumes on several systems.
Variations for each segment are discussed in the segment results
below.
SEGMENT RESULTS
The following tables present certain data for each of the
three operating segments of the Company for the three-month
periods ended March 31, 2000 and March 31, 1999. 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 segment includes a transportation component and a
marketing component. The Company evaluates each of its segments
on a gross margin basis, which is defined as the revenues of the
segment less related direct costs and expenses of the segment and
does not include depreciation, interest or allocated corporate
overhead.
TRANSMISSION PIPELINES
<TABLE>
<CAPTION>
For the Three Months Ended March 31,
2000 1999
(In thousands, except amounts per MMBtu)
<S> <C> <C>
OPERATING REVENUES:
Marketing Revenue $ 43,449 $ 34,107
Transportation Fees 9,724 1,917
TOTAL OPERATING REVENUES 53,173 36,024
OPERATING EXPENSES:
Marketing Costs 39,678 30,024
Operating Expenses 2,218 1,085
TOTAL OPERATING EXPENSES 41,896 31,109
GROSS MARGIN $ 11,277 $ 4,915
VOLUME (in MMBtu)
Marketing 15,720 16,313
Transportation 28,687 14,668
TOTAL VOLUME 44,407 30,981
GROSS MARGIN per MMBtu $ .25 $ .16
</TABLE>
Quarter Ended March 31, 2000 compared to Quarter Ended March 31,
1999
Gross margin for the quarter ended March 31, 2000 increased
129% to $11.3 million over the same period in 1999 due primarily
to increases in transportation margins. Transportation margins
increased $6.4 million due to increased total throughput volumes
and higher average transportation fees. Marketing revenues and
expenses were higher in 2000 due to increases in the average
price of natural gas in 2000 over 1999. The gross margin per
MMBtu from marketing activities was $0.24 in 2000 and $0.25 in
1999. The 8% decrease in marketing margins was primarily due to
lower throughput volumes as a result of another historically mild
winter.
END-USER PIPELINES
<TABLE>
<CAPTION>
For the Three Months Ended March 31,
2000 1999
(In thousands, except amounts per MMBtu)
<S> <C> <C>
OPERATING REVENUES:
Marketing Revenue $ 32,739 $ 27,808
Transportation Fees 774 739
TOTAL OPERATING REVENUES 33,513 28,547
OPERATING EXPENSES:
Marketing Costs 30,991 26,722
Operating Expenses 111 100
TOTAL OPERATING EXPENSES 31,102 26,822
GROSS MARGIN $ 2,411 $ 1,725
VOLUME (in MMBtu)
Marketing 13,447 13,906
Transportation 5,725 6,012
TOTAL VOLUME 19,172 19,918
GROSS MARGIN per MMBtu $ .13 $ .09
</TABLE>
Quarter Ended March 31, 2000 compared to Quarter Ended March 31,
1999
Gross margin for the quarter ended March 31, 2000 increased
40% to $2.4 million over the same period in 1999 due primarily to
increases in marketing margins. Marketing margins increased $0.7
million due to a shift in our end-user customer base to customers
with higher margin contracts.
GATHERING PIPELINES AND NATURAL GAS PROCESSING
<TABLE>
<CAPTION>
For the Three Months Ended March 31,
2000 1999
(In thousands, except amounts per MMBtu)
<S> <C> <C>
OPERATING REVENUES:
Marketing Revenue $ 52,844 $ 13,285
Transportation Fees 4,179 1,976
Processing Revenues 7,621 1,893
TOTAL OPERATING REVENUES 64,644 17,154
OPERATING EXPENSES:
Marketing Costs 51,023 13,332
Operating Expenses 2,809 1,009
Processing Costs 5,341 982
TOTAL OPERATING EXPENSES 59,173 15,323
GROSS MARGIN $ 5,471 $ 1,831
VOLUME (in MMBtu)
Marketing 12,017 5,125
Transportation 29,771 19,557
Processing 3,398 1,961
TOTAL VOLUME 45,186 26,643
GROSS MARGIN per MMBtu $ .12 $ .07
</TABLE>
Quarter Ended March 31, 2000 compared to Quarter Ended March 31,
1999
Gross margin for the quarter ended March 31, 2000 increased
199% to $5.5 million over the same period in 1999 due primarily
to increases in marketing and processing margins. Marketing
margins increased $1.9 million due to increased volumes and the
marketing of higher priced liquids and other specialty gases
provided from the March 1999 DPI and December 1999 Gloria
acquisitions, as well as incremental margins on the Tinsley
system. Processing margins increased $1.4 million due to higher
average NGL prices and a 73% increase in throughput volumes due to
the Flare and Calmar acquisitions in 1999.
OTHER INCOME, COSTS AND EXPENSES
Other revenues for the three months ended March 31, 2000
increased to $0.4 million from $0.3 million for the same period
in 1999. The increase was primarily attributable to income
earned on processing plant construction projects.
Depreciation, depletion and amortization for the three
months ended March 31, 2000 increased to $3.5 million from $1.4
million for the same period in 1999. This increase was primarily
due to increased depreciation and amortization on assets acquired
in the KPC, DPI/Flare and Calmar acquisitions.
General and administrative expenses for the three months
ended March 31, 2000 increased to $4.0 million from $1.9 million
for the same period in 1999. The increase was due to increased
costs associated with the management of the assets acquired in
the KPC, DPI/Flare and Calmar acquisitions. The increase was
mitigated by reduced employee costs related to the streamlining
efforts announced in November 1999. General and administrative
expenses, as a percentage of gross margin, decreased to 20% for
the three months ended March 31, 2000 from 22% for the same
period in 1999.
Interest expense for the three months ended March 31, 2000
increased to $4.9 million from $1.5 million for the same period
in 1999. This increase was due to an increase in the debt level
as well as an increase in the weighted average interest rate.
The Company was servicing an average of $248 million in debt for
the three months ended March 31, 2000 as compared to $98 million
in debt for the same period in 1999. The increased debt level in
2000 was primarily associated with the debt used to finance the
Company's KPC acquisition in November 1999. The Company's
weighted average interest rate for the three months ended March
31, 2000 increased to 7.9% from 6.1% for the same period in 1999.
INCOME TAXES
The Company's income tax provision increased to $1.1 million
for the three months ended March 31, 2000 from $0.7 million for
the same period in 1999. The Company's effective tax rate was
14.7% and 17.3% for the three months ended March 31, 2000 and
1999, respectively. The effective tax rate in 2000 has been
reduced primarily due to the 1st quarter removal of the portion of
the valuation allowance related to net operating losses that are
more likely than not to be utilized in the future. The effective
tax rate for the remainder of 2000 is expected to be closer to
the federal statutory rate of 34%.
As of March 31, 2000, the Company has NOL carryforwards of
approximately $8.0 million, expiring in various amounts from 2003
through 2018. These loss carryforwards were generated by
companies acquired by Midcoast. 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 $6.7 million) on the
use of such carryforwards due to a change in shareholder control
under section 382 of the Internal Revenue Code triggered by the
Company's July 1997 Common Stock offering and the change of
ownership created by the acquisition of Republic and DPI.
RATES AND REGULATORY MATTERS
Each of our pipeline systems has contracts covering a
portion of their firm transportation capacity with various terms
of maturity, and each operates in different markets and regions
with different competitive and regulatory pressures which can
impact their ability to renegotiate and renew existing contracts,
or enter into new long-term firm transportation commitments.
KPC filed a rate case pursuant to Section 4 of the NGA on
August 27, 1999 (FERC Docket No. RP99-485-000). KPC's proposed
rates reflect an annual revenue increase when compared to its
initial FERC-approved rates. The rates have been protested by
KPC's two principal customers and by the state public utility
commissions that regulate them. On September 30, 1999, the FERC
issued an order that set KPC's proposed rates for hearing and
accepted and suspended the rates to be effective March 1, 2000,
subject to possible refund. The Section 4 rate case proceeding
will determine whether the rates proposed by KPC for interstate
transportation of natural gas are just and reasonable, and the
extent to which KPC must refund all or any part of the proposed
rate increase that it charges to its customers prior to approval.
A procedural schedule in the case has been adopted by the
Presiding Administrative Law Judge. A hearing date is set for
September 26, 2000.
While we cannot predict with certainty the final
outcome or timing of the resolution of rates and regulatory
matters, the outcome of our current re-contracting and capacity
subscription efforts, or the outcome of ongoing industry trends
and initiatives, we believe the ultimate resolution of these
issues will not have a material adverse effect on our financial
position, results of operations, or cash flows.
CAPITAL RESOURCES AND LIQUIDITY
Since 1996, the Company has acquired approximately $376
million of pipeline systems. Capital requirements have been
funded through equity infusions from common stock offerings,
borrowings from various commercial banks and cash flow from
operations.
The Company has raised net proceeds of approximately $128
million in four common stock offerings since being listed on the
American Stock Exchange in August 1996. These capital infusions
and the stability of our cash flow has allowed the Company the
financial flexibility to utilize lower cost conventional bank
debt financing to fund a large part of its growth. The Company's
long-term debt to total capitalization ratio decreased from 62%
at March 31, 1999 to 59% at March 31, 2000.
In November 1999 and again in March 2000, the Company
amended and restated its bank financing agreement under the
certain Amended and Restated Credit Agreement dated August 31,
1998. The amendments added additional banks to the syndicate,
increased our borrowing availability, modified our letter of
credit facility, extended the maturity five years to November
2004, modified financial covenants, established waiver and
amendment approvals and changed the method to determine the
interest rate to be charged.
The amendments to the credit agreement increased our
borrowing availability from $125 million to $335 million, with a
provision to increase up to $400 million. The amended credit
agreement provides borrowing availability as follows: (i) up to a
$50 million sublimit for the issuance of standby and commercial
letters of credit and (ii) the difference between the $335
million and the used sublimit available as a revolving credit
facility. At the option of the Company, borrowings under the
amended credit agreement accrue interest at LIBOR plus an
applicable margin or the higher of the Bank of America prime rate
or the Federal Funds rate plus an applicable margin.
The applicable margin percentage to be added to the interest
rate is based on the Company's debt to total capitalization ratio
at the end of each fiscal quarter. The Company is charged a
margin between 1.0% and 2.0% as the Company's total debt to total
capitalization ratio ranges from under 40% and over 65%,
respectively. The Company's borrowings are currently being
charged at the margin of 1.5%.
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. It 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 required
to comply with more stringent debt to capitalization and EBITDA
to interest ratios by June 30, 2000. At March 31, 2000, the
Company had approximately $94 million of available capacity under
its credit agreement.
During the quarter ended March 31, 2000, the Company
generated cash flow from operating activities of approximately
$10.9 million. At March 31, 2000, the Company had committed to
making approximately $3.2 million in construction related
expenditures. The Company believes that its credit agreement and
funds provided by operations will be sufficient to meet its
operating cash needs for the foreseeable future and its projected
capital expenditures, other than acquisitions.
If sufficient 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 in as aggressive a manner as currently planned.
ENVIRONMENTAL AND SAFETY MATTERS
Our activities in connection with the operation and
construction of pipelines and other facilities for transporting,
processing, treating, or storing natural gas and other products
are subject to environmental and safety regulation by numerous
federal, state, local and Canadian authorities. This regulation
can include ongoing oversight regulation as well as requirements
for construction or other permits and clearances that must be
granted in connection with new projects or expansions.
Regulatory requirements can increase the cost of planning,
designing, initial installation and operation of such facilities.
Sanctions for violation of these requirements include a variety
of civil and criminal enforcement measures, including assessment
of monetary penalties, assessment and remediation requirements
and injunctions as to future compliance. The following is a
discussion of certain environmental and safety concerns that
relate to us. It is not intended to constitute a complete
discussion of the various federal, state, local and Canadian
statutes, rules, regulations, or orders to which our operations
may be subject.
In most instances, these regulatory requirements relate to
the release of substances into the environment and include
measures to control water and air pollution. Moreover, we could
incur liability under the Comprehensive Environmental Response,
Compensation, and Liability Act of 1980, as amended, or state
counterparts, regardless of our fault, in connection with the
disposal or other releases of hazardous substances, including
those arising out of historical operations conducted by our
predecessors. Further, the recent trend in environmental
legislation and regulations is toward stricter standards, and
this trend will likely continue in the future.
Environmental laws and regulations may also require us to
acquire a permit before we may conduct certain activities.
Further, these laws and regulations may limit or prohibit
activities on certain lands lying within wilderness areas,
wetlands, areas providing habitat for certain species that have
been identified as "endangered" or "threatened" or other
protected areas. We are also subject to other federal, state and
local laws covering the handling, storage or discharge of
materials, and we are subject to laws that otherwise relate to
the protection of the environment, safety and health. As an
employer, we are required to maintain a workplace free of
recognized hazards likely to cause death or serious injury and to
comply with specific safety standards.
We will make expenditures in connection with environmental
matters as part of our normal operations and capital
expenditures. In addition, the possibility exists that stricter
laws, regulations or enforcement policies could significantly
increase our compliance costs and the cost of any remediation
that might become necessary. We are subject to an inherent risk
of incurring environmental costs and liabilities because of our
handling of oil, gas and petroleum products, historical industry
waste disposal practices and prior use of gas flow meters
containing mercury. There can be no assurance that we will not
incur material environmental costs and liabilities. Management
believes, based on our current knowledge, that we have obtained
and are in current compliance with all necessary and material
permits and that we are in substantial compliance with applicable
material environmental and safety regulations. Further, we
maintain insurance coverages that we believe are customary in the
industry; however, there can be no assurance that our
environmental impairment insurance will provide sufficient
coverage in the event an environmental claim is made against us.
We are not aware of any existing environmental or safety claims
that would have a material impact upon our financial position,
results of operations or cash flows.
DISCLOSURE REGARDING FORWARD LOOKING STATEMENTS
This Form 10-Q contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. All
statements other than statements of historical fact included in
and incorporated by reference into this Form 10-Q are forward-
looking statements. These 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 the Company's estimate
of the sufficiency of existing capital resources, whether funds
provided by operations will be insufficient to meet its
operational needs in the foreseeable future, and its ability to
use NOL carryforwards prior to their expiration. Although, we
believe that the expectations reflected in these forward looking
statements are reasonable, we can not give any assurance that
such expectations reflected in these forward looking statements
will prove to have been correct.
When used in this Form 10-Q, the words "expect",
"anticipate", "intend", "plan", "believe", "seek", "estimate",
and similar expressions are intended to identify forward-looking
statements, although not all forward-looking statements contain
these identifying words. Because these forward-looking
statements involve risks and uncertainties, actual results could
differ materially from those expressed or implied by these
forward-looking statements for a number of important reasons,
including those discussed under "Management's Discussion and
Analysis of Financial Condition and Results of Operations", and
elsewhere in this Form 10-Q.
You should read these statements carefully because they
discuss our expectations about our future performance, contain
projections of our future operating results or our future
financial condition, or state other "forward- looking"
information. Before you invest in our common stock, you should
be aware that the occurrence of any of the events described in
"Risk Factors" in the Prospectus Supplement, dated December 6,
1999 and elsewhere in this Form 10-Q could substantially harm our
business, results of operations and financial condition and that
upon the occurrence of any of these events, the trading price of
our common stock could decline, and you could lose all or part of
your investment.
We cannot guarantee any future results, levels of activity,
performance or achievements. Except as required by law, we
undertake no obligation to update any of the forward-looking
statements in this Form 10-Q after the date of this Form 10-Q.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The Company utilizes derivative financial instruments to
manage market risks associated with certain energy commodities
and interest rates. According to guidelines provided by the
Board, the Company enters into exchange-traded commodity futures,
options and swap contracts to reduce the exposure to market
fluctuations in price and transportation costs of energy
commodities and fluctuations in interest rates. The Company does
not engage in speculative trading. Approvals are required from
senior management prior to the execution of any financial
derivative.
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 the New York Mercantile Exchange.
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.
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
an applicable margin based on the Company's debt to total
capitalization ratio. In an effort to mitigate interest rate
fluctuation exposure, the Company entered into interest rate
swaps under two separate swap agreements with a combined notional
amount of $65 million dollars. 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 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 Bank of America in November 1998
and replaced with a new swap agreement. The new swap agreement
provides a fixed 5.09% interest rate to the Company with a new
two year termination date of December 2000 which may, however, be
extended through December 2003 at Bank of America'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
the Company is obligated to reimburse Bank of America when the
three-month LIBOR rate is reset below 5.09%. Conversely, Bank of
America is obligated to reimburse the Company when the three-
month LIBOR rate is reset above 5.09%. At March 31, 2000 and
1999, the fair value of this interest rate swap through the
initial termination date was a net asset of approximately
$266,000 and a net liability of approximately $20,000,
respectively.
The second interest rate swap agreement was entered into
with CIBC in October 1998. The swap agreement effectively
established a fixed 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 the Company is obligated to reimburse
CIBC when the three-month LIBOR rate is reset below 4.475%.
Conversely, CIBC is obligated to reimburse the Company when the
three-month LIBOR rate is reset above 4.475%. At March 31, 2000
and 1999, the fair value of this interest rate swap through the
initial termination date was a net asset of approximately
$1,592,000 and $1,300,000, respectively.
The effect of these swap agreements was to lower interest
expense by $238,000 and $49,000 in the three months ended March
31, 2000 and 1999, respectively.
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
None
b. Reports on Form 8-K:
None
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 15, 2000
<TABLE> <S> <C>
<CAPTION>
<S> <C>
<ARTICLE> 5
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-2000
<PERIOD-START> JAN-01-2000
<PERIOD-END> MAR-31-2000
<CASH> 2,749,000
<SECURITIES> 0
<RECEIVABLES> 58,766,000
<ALLOWANCES> 1,294,000
<INVENTORY> 1,110,000
<CURRENT-ASSETS> 64,326,000
<PP&E> 415,925,000
<DEPRECIATION> 17,111,000
<TOTAL-ASSETS> 486,376,000
<CURRENT-LIABILITIES> 65,976,000
<BONDS> 0
0
0
<COMMON> 127,000
<OTHER-SE> 164,778,000
<TOTAL-LIABILITY-AND-EQUITY> 486,376,000
<SALES> 151,752,000
<TOTAL-REVENUES> 151,752,000
<CGS> 126,830,000
<TOTAL-COSTS> 139,608,000
<OTHER-EXPENSES> (42,000)
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 4,895,000
<INCOME-PRETAX> 7,291,000
<INCOME-TAX> 1,074,000
<INCOME-CONTINUING> 6,217,000
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 6,217,000
<EPS-BASIC> 0.50
<EPS-DILUTED> 0.49
</TABLE>
