<PAGE>
================================================================================
U.S. SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] Quarterly Report Under Section 13 or 15 (d) of the Securities Exchange Act
of 1934 for the Quarterly Period Ended September 30, 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 November 14, 2000 there were outstanding 12,491,684 shares of the
Company's common stock, par value $.01 per share.
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<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
TABLE OF CONTENTS
Caption Page
------- ----
Glossary........................................................... iii
Part I. Financial Information
Item 1. Condensed Consolidated Financial Statements
Unaudited Condensed Consolidated Balance Sheets as of
September 30, 2000 and December 31, 1999..................... 1
Unaudited Condensed Consolidated Statements of Operations for
the three months and nine months ended September 30, 2000 and
September 30, 1999........................................... 2
Unaudited Condensed Consolidated Statements of Comprehensive
Income for the three months and nine months ended
September 30, 2000 and September 30, 1999.................... 3
Unaudited Condensed Consolidated Statements of Cash Flows for
the three months and nine months ended September 30, 2000 and
September 30, 1999........................................... 4
Notes to Unaudited Condensed Consolidated Financial
Statements................................................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................. 11
Item 3. Quantitative and Qualitative Disclosures about Market
Risk............................................................ 19
Part II. Other Information........................................ 20
Signature.......................................................... 21
ii
<PAGE>
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
FERC.................. Federal Energy Regulatory Commission
KPC Acquisition....... The November 1999 acquisition of Kansas Pipeline
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 Acquisition..... The October 1997 acquisition of the MLGC and MLGT
Systems
MIT Acquisition....... The May 1997 acquisition of the MIT and TRIGAS 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
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
iii
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
<TABLE>
<CAPTION>
September 30, December 31,
2000 1999
------------- ------------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents.............................................................. $ 3,487 $ 2,345
Accounts receivable, net of allowance of $1,180 and $1,484, respectively............... 82,463 55,189
Other current assets................................................................... 6,336 4,905
------------------- ----------------
Total Current Assets................................................................ 92,286 62,439
------------------- ----------------
PROPERTY, PLANT AND EQUIPMENT, NET....................................................... 404,899 392,969
OTHER ASSETS............................................................................. 24,169 22,964
------------------- ----------------
Total Assets........................................................................ $521,354 $478,372
=================== ================
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES...................................................................... $ 84,157 $ 63,978
LONG-TERM DEBT........................................................................... 249,397 240,000
OTHER LIABILITIES........................................................................ 2,079 2,147
DEFERRED INCOME TAXES.................................................................... 14,694 11,034
COMMITMENTS AND CONTINGENCIES (Note 3)................................................... - -
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES........................................... 557 536
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per share; authorized 31,250,000 shares;
issued 12,732,359 and 12,721,980 shares, respectively............................ 127 127
Paid-in capital........................................................................ 165,871 165,964
Retained earnings (accumulated deficit)................................................ 8,426 (2,915)
Accumulated other comprehensive income (loss).......................................... (39) 71)
Treasury stock (at cost), 245,175 and 161,156 shares, respectively..................... (3,915) (2,570)
------------------- ----------------
Total Shareholders' Equity.......................................................... 170,470 160,677
------------------- ----------------
Total Liabilities and Shareholders' Equity.......................................... $ 521,354 $ 478,372
=================== ================
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
1
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
---------------------------------- --------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
2000 1999 2000 1999
-------------- --------------- -------------- -------------
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Energy marketing revenue................................ $ 172,121 $ 90,852 $ 439,636 $ 240,294
Transportation fees..................................... 14,871 5,206 44,578 15,540
Natural gas processing revenue.......................... 10,037 5,269 26,726 10,376
Other................................................... 647 517 1,453 1,155
----------- ----------- ----------- -----------
Total operating revenues..................................... 197,676 101,844 512,393 267,365
----------- ----------- ----------- -----------
OPERATING EXPENSES:
Energy marketing expenses............................... 163,713 84,663 415,372 219,717
Natural gas processing costs............................ 6,821 3,451 17,785 8,352
Other operating expenses................................ 7,825 6,003 22,174 14,637
Depreciation, depletion and amortization................ 4,174 1,850 11,364 4,793
General and administrative.............................. 4,446 1,986 12,804 5,936
----------- ----------- ----------- -----------
Total operating expenses..................................... 186,979 97,953 479,499 253,435
----------- ----------- ----------- -----------
OPERATING INCOME............................................. 10,697 3,891 32,894 13,930
NON-OPERATING ITEMS:
Interest expense........................................ (5,328) (775) (14,951) (3,651)
Minority interest in consolidated subsidiaries.......... (25) (5) (51) (28)
Other income (expense), net............................. 132 (23) 217 (115)
----------- ----------- ----------- ------------
INCOME BEFORE INCOME TAXES................................... 5,476 3,088 18,109 10,136
PROVISION FOR INCOME TAXES:
Current................................................. (69) (497) (472) (1,326)
Deferred................................................ (1,649) 167 (3,659) (221)
----------- ------------ ----------- ------------
NET INCOME................................................... $ 3,758 $ 2,758 $ 13,978 $ 8,589
=========== ============ =========== ============
EARNINGS PER COMMON SHARE:
BASIC...................................................... $ 0.30 $ 0.26 $ 1.12 $ 1.00
=========== ============ =========== ============
DILUTED.................................................... $ 0.30 $ 0.26 $ 1.10 $ 0.98
=========== ============ =========== ============
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
BASIC...................................................... 12,477,698 10,559,172 12,504,058 8,585,037
=========== ============ =========== ============
DILUTED.................................................... 12,725,235 10,795,517 12,728,533 8,804,258
=========== ============ =========== ============
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
2
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
--------------------------------- ---------------------------------
SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30, SEPTEMBER 30,
2000 1999 2000 1999
------------- ------------ ------------ -------------
<S> <C> <C> <C> <C>
Net income........................................ $3,758 $2,758 $13,978 $8,589
Foreign currency translation adjustment........... (112) 78 (110) (68)
------------- ------------ ------------ ------------
Comprehensive income.............................. $3,646 $2,836 $13,868 $8,521
============= ============ ============ ============
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
3
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
<TABLE>
<CAPTION>
For the Three Months Ended For the Nine Months Ended
---------------------------- ----------------------------
September 30, September 30, September 30, September 30,
2000 1999 2000 1999
---------- ------------- ------------ -------------
<S> <C> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income................................................... $ 3,758 $ 2,758 $ 13,978 $ 8,589
Adjustments to reconcile net income to net cash
from operating activities:
Depreciation, depletion and amortization................. 4,174 1,850 11,364 4,793
Deferred income taxes.................................... 1,649 (167) 3,659 221
Minority interest in consolidated subsidiaries........... 25 5 51 28
Gain on sale of plant assets............................. (101) - (101) -
Other.................................................... (317) 72 (236) 36
Changes in working capital accounts, net of effects of
acquisitions:
(Increase) decrease in accounts receivable........... (4,130) 2,164 (23,795) (15,147)
(Increase) decrease in other current assets.......... 857 (212) (3,288) (238)
Increase (decrease) in accounts payable and accrued
liabilities.......................................... 9,757 (12,455) 19,942 6,880
-------- -------- -------- ---------
Net cash provided by (used in) operating activities............ 15,672 (5,985) 21,574 5,162
-------- -------- -------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions................................................. (300) (3,998) (13,320) (34,388)
Capital expenditures......................................... (3,786) (3,040) (10,205) (14,788)
Proceeds from sale of plant assets........................... 111 - 111 -
Net advances to equity investee.............................. 188 - 27 -
Other........................................................ (617) (385) (1,619) (197)
-------- -------- -------- ---------
Net cash used in investing activities.......................... (4,404) (7,423) (25,006) (49,373)
-------- -------- -------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings......................................... 18,200 10,243 91,476 130,613
Bank debt repayments......................................... (26,426) (26) (82,150) (135,811)
Net proceeds from equity offering............................ - - - 54,583
Treasury stock purchases..................................... (55) - (1,345) (2,406)
Dividends on common stock.................................... (879) (747) (2,639) (1,668)
Other........................................................ (306) (110) (768) 168
-------- -------- -------- ---------
Net cash provided by (used in) financing activities............ (9,466) 9,360 4,574 45,479
-------- -------- -------- ---------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........... 1,802 (4,048) 1,142 1,268
-------- -------- -------- ---------
CASH AND CASH EQUIVALENTS, beginning of period................. 1,685 5,516 2,345 200
-------- -------- -------- ---------
CASH AND CASH EQUIVALENTS, end of period....................... $ 3,487 $ 1,468 $ 3,487 $ 1,468
======== ======== ======== =========
SUPPLEMENTAL DISCLOSURES:
Cash paid for interest.................................... $ 7,257 $ 1,077 $ 15,655 $ 5,326
======== ======== ======== =========
Cash paid for income taxes................................ $ - $ 250 $ 1,600 $ 310
======== ======== ======== =========
</TABLE>
The accompanying notes are an integral part of these condensed consolidated
financial statements.
4
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
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. The
condensed consolidated balance sheet at December 31, 1999 is derived from the
audited financial statements. 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 condensed consolidated financial statements for the periods presented in
1999 so that the presentation of the information is consistent with reporting
for the condensed 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. ACQUISITIONS:
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 gas gathering and processing system in the area. The
system is connected to 21 oil tank batteries and primarily gathers the
associated sour gas production from approximately 900 wells in the Provost area.
The acquisition was funded through the Company's existing credit facility.
MANYBERRIES ACQUISITION
In April 2000, the Company acquired the Manyberries Pipeline System from
Triumph Energy Corporation for approximately $5.7 million (U.S.). The
Manyberries acquisition consists of 80 miles of 6" and 10 miles of 4" crude oil
pipeline that originates at the Manyberries Oil Field and terminates at an
interconnection with the Milk River Pipeline system in southeast 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 6,500 Bbls/day. 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.
5
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
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 September 30, 2000, the
Company has made payments of $500,000 and has accrued an additional $125,000
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 additional consideration of up to $2.5 million. This
contingency expires on March 11, 2002. As of September 30, 2000, none of the
identified projects have been constructed and therefore no contingent payments
have been accrued.
RATES AND REGULATORY MATTERS
Each of our transmission 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. However, through
September 30, 2000, KPC is continuing to charge its customers the initial FERC-
approved rates. Additionally, the two customers have been paying only a portion
of the Company's invoices pursuant to their protest of the current rates. The
resultant unpaid balance from both customers at September 30, 2000 was
approximately $432,000. 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 to the extent which KPC may recover all or any part
of the proposed rate increase that it has not charged to its customers prior to
approval. The hearing related to the proposed increase commenced on September
26, 2000 and concluded on October 20, 2000. A final Commission decision is not
expected until at least the fourth quarter of 2001.
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 consolidated financial
position, results of operations, or cash flows.
6
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
4. EARNINGS PER SHARE:
Basic and diluted earnings per share amounts are presented below for the
three months and nine months ended September 30 (in thousands, except per share
amounts):
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
--------------------------------------------------------------------------------------
2000 1999
--------------------------------------------------------------------------------------
Average Average
Shares Earnings Per Shares Earnings Per
Net Income Outstanding Share Net Income Outstanding Share
---------- ----------- ------------ ---------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Basic............................. $3,758 12,478 $.30 $2,758 10,559 $.26
Effect of dilutive securities:
Stock options.................... - 184 - - 165 -
Warrants......................... - 63 - - 72 -
------ ------ ---- ------ ------ ----
Diluted........................... $3,758 12,725 $.30 $2,758 10,796 $.26
====== ====== ==== ====== ====== ====
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
--------------------------------------------------------------------------------------
2000 1999
--------------------------------------------------------------------------------------
Average Average
Shares Earnings Per Shares Earnings Per
Net Income Outstanding Share Net Income Outstanding Share
---------- ----------- ------------ ---------- ----------- ------------
<S> <C> <C> <C> <C> <C> <C>
Basic............................. $13,978 12,504 $1.12 $8,589 8,585 $1.00
Effect of dilutive securities:
Stock options.................... - 165 (.02) - 156 (.02)
Warrants......................... - 60 - - 63 -
------ ------ ----- ------ ------ -----
Diluted........................... $13,978 12,729 $1.10 $8,589 8,804 $ .98
====== ====== ===== ====== ====== =====
</TABLE>
5. SEGMENT DATA:
The Company conducts its business of gathering, transporting, processing
and marketing natural gas and other petroleum products through its 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 natural 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 natural 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 processing and
gathering systems typically consist of a network of pipelines which 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. In addition, the Company provides natural gas marketing services to its
customers within each of the three segments. The Company's marketing activities
include providing natural gas supply and sales services to some of its end-user
customers by purchasing the natural gas supply from other marketers or pipeline
affiliates and reselling the natural gas to the end-user. The Company also
purchases natural gas directly from well operators on many of the Company's
gathering systems and resells the natural gas to other marketers or pipeline
affiliates. Many of the contracts pertaining to the Company's natural gas
marketing activities are month-to-month spot market transactions with numerous
gas suppliers or producers in the industry. The Company also offers other
natural gas services to some of its customers including management of capacity
release and gas balancing.
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, depletion and amortization,
interest or allocated corporate overhead. The "Other" column includes results of
processing plant construction projects, which includes planning, fabrication,
installation and facility operations and management as
7
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
well as general corporate items. 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 and nine months ended September 30, 2000 and 1999:
<TABLE>
<CAPTION>
AS OF OR FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
-----------------------------------------------------------------------------
Transmission End-User Gathering and
Pipelines Pipelines Processing Other Total
-----------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
(In thousands)
Revenues:
Domestic...................................... $ 64,312 $43,634 $ 87,822 $ 647 $196,415
Foreign....................................... - - 1,261 - 1,261
-------- ------- -------- ------- --------
Total Revenues.................................. 64,312 43,634 89,083 647 197,676
Gross Margin.................................... 12,552 2,620 3,498 647 19,317
Depreciation, Depletion and Amortization........ (2,018) (277) (1,601) (278) (4,174)
General and Administrative...................... - - - (4,446) (4,446)
Interest Expense................................ - - - (5,328) (5,328)
Other, net...................................... - - - 107 107
-------- ------- -------- ------- --------
Income before Income Taxes...................... 10,534 2,343 1,897 (9,298) 5,476
======== ======= ======== ======= ========
Assets:
Domestic...................................... 292,532 71,203 121,970 9,717 495,422
Foreign....................................... - - 25,932 - 25,932
-------- ------- -------- ------- --------
Total Assets................................. 292,532 71,203 147,902 9,717 521,354
======== ======= ======== ======= ========
Capital Expenditures (excluding acquisitions) 280 2,049 794 663 3,786
======== ======= ======== ======= ========
AS OF OR FOR THE THREE MONTHS ENDED SEPTEMBER 30, 1999
------------------------------------------------------------------------------
Transmission End-User Gathering and
Pipelines Pipelines Processing Other Total
------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
(In thousands)
Revenues:
Domestic...................................... $25,530 $32,889 $ 42,372 $ 517 $101,308
Foreign....................................... - - 536 - 536
-------- ------- -------- ------- --------
Total Revenues.................................. 25,530 32,889 42,908 517 101,844
Gross Margin.................................... 3,562 2,219 1,429 517 7,727
Depreciation, Depletion and Amortization........ (352) (251) (1,126) (121) (1,850)
General and Administrative...................... - - - (1,986) (1,986)
Interest Expense................................ - - - (775) (775)
Other, net...................................... - - - (28) (28)
-------- ------- -------- ------- --------
Income before Income Taxes...................... 3,210 1,968 303 (2,393) 3,088
======== ======= ======== ======= ========
Assets:
Domestic...................................... 73,239 67,704 90,677 8,901 240,521
Foreign....................................... - - 14,563 - 14,563
-------- ------- -------- ------- --------
Total Assets.................................. 73,239 67,704 105,240 8,901 255,084
======== ======= ======== ======= ========
Capital Expenditures (excluding acquisitions)... 1,123 579 682 656 3,040
======== ======= ======== ======= ========
</TABLE>
8
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
<TABLE>
<CAPTION>
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
----------------------------------------------------------------------
Transmission End-User Gathering and
Pipelines Pipelines Processing Other Total
----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
(In thousands)
Revenues:
Domestic...................................... $168,725 $117,441 $220,537 $ 1,453 $508,156
Foreign....................................... - - 4,237 - 4,237
-------- -------- -------- -------- --------
Total Revenues.................................. 168,725 117,441 224,774 1,453 512,393
Gross Margin.................................... 33,813 6,647 15,149 1,453 57,062
Depreciation, Depletion and Amortization........ (5,803) (798) (4,011) (752) (11,364)
General and Administrative...................... - - - (12,804) (12,804)
Interest Expense................................ - - - (14,951) (14,951)
Other, net...................................... - - - 166 166
-------- -------- -------- -------- --------
Income before Income Taxes...................... 28,010 5,849 11,138 (26,888) 18,109
======== ======== ======== ======== ========
Capital Expenditures (excluding acquisitions)... 775 4,906 3,113 1,411 10,205
======== ======== ======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
-------------------------------------------------------------------
Transmission End-User Gathering and Other Total
Pipelines Pipelines Processing
-------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
(In thousands)
Revenues:
Domestic...................................... $83,518 $90,999 $90,491 $ 1,155 $266,163
Foreign....................................... - - 1,202 - 1,202
------- ------- ------- ------- --------
Total Revenues.................................. 83,518 90,999 91,693 1,155 267,365
Gross Margin.................................... 10,154 5,825 7,525 1,155 24,659
Depreciation, Depletion and Amortization........ (1,088) (677) (2,705) (323) (4,793)
General and Administrative...................... - - - (5,936) (5,936)
Interest Expense................................ - - - (3,651) (3,651)
Other, net...................................... - - - (143) (143)
------- ------- ------- ------- --------
Income before Income Taxes...................... 9,066 5,148 4,820 (8,898) 10,136
======= ======= ======= ======= ========
Capital Expenditures (excluding acquisitions)... 5,967 4,431 3,251 1,139 14,788
======= ======= ======= ======= ========
</TABLE>
6. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED:
The FASB issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" in June 1998. 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. If certain
conditions are met, a derivative may be specifically designated as (a) a hedge
of the exposure to changes in the fair value of a recognized asset or liability
or an unrecognized firm commitment, (b) a hedge of the exposure to variable
cash flows of a forecasted transaction, or (c) a hedge of the foreign currency
exposure of a net investment in a foreign operation, an unrecognized firm
commitment, an available-for-sale security, or a foreign-currency denominated
forecasted transaction. The accounting for the changes in the fair value of a
derivative depends on the intended use of the derivative and the resulting
designation. 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,
"Accounting for Derivative Instruments and Hedging Activities - Deferral of the
Effective Date of FASB Statement No. 133", in June 1999 and SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities",
in June 2000 and is effective for fiscal years
9
<PAGE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued
beginning after June 15, 2000. The Company does not believe adoption of this
pronouncement will materially effect the Company's consolidated financial
position, results of operations or cash flows.
In December 1999, the Securities and Exchange Commission (SEC) issued Staff
Accounting Bulletin (SAB) No. 101, "Revenue Recognition in Financial
Statements", to provide guidance for revenue recognition issues and disclosure
requirements. Subsequently, the SEC issued SAB No. 101A, "Amendment: Revenue
Recognition in Financial Statements", SAB No. 101B, "Second Amendment: Revenue
Recognition in Financial Statements", which ultimately delayed implementation to
the fourth quarter of fiscal years beginning after December 15, 1999. SAB No.
101 covers a wide range of revenue recognition topics and summarizes the staff's
interpretations on the application of generally accepted accounting principles
to revenue recognition. The Company does not believe this standard will have a
material impact on the Company's consolidated financial position, results of
operations or cash flows.
7. 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. The following table shows the status of, and changes to, the
restructuring reserve for the first nine months of 2000.
Reserve at December 31, 1999.................... $ 1,701,009)
Expenditures................................ (1,568,009)
-----------
Reserve at September 30, 2000................... $ 133,000
===========
10
<PAGE>
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 September 2000, the Company acquired or constructed 76 systems for an
aggregate cost of approximately $384 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 volumes 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 natural 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, the relationship of NGL prices to
natural gas prices, declines in natural gas throughput, or increases in
shrinkage or fuel costs. In the case of keep-whole contracts, margins can be
adversely affected by increases in natural gas prices. The Company uses over the
counter swaps to hedge its physical exposure to processing spread risk.
Processing spreads are the difference between the price the company receives for
the sale of natural gas liquids and the price it pays for the natural gas
equivalent on a heating value basis (MMBtu's). The Company has locked in a fixed
processing spread on approximately 70% of its NGL production through December
2000.
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 fluctuates 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
11
<PAGE>
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. 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.
For the three months ended September 30, 2000, the Company had total
revenues of $197.7 million, a 94% increase, primarily driven by increases in
commodity prices and acquisitions, from $101.8 million during the same period in
1999. Operating income improved 175% and net income improved 36% to $10.7
million and $3.8 million from $3.9 million and $2.8 million, respectively, in
1999. Diluted earnings per common share were $0.30 as compared to $0.26 per
share in the third quarter of 1999. The Company's results for the past quarter
were positively impacted by the addition of acquisition and expansion projects
completed over the past year, strong throughput volume growth, particularly in
the transmission and gathering/processing segments, along with improved
processing margins due to higher commodity prices. These gains were partially
offset by an increase in the Company's interest expense as a result of higher
outstanding debt levels and an increase in its weighted average interest rate
from 6.3% in the third quarter last year to 7.8% this year. Recently, the
Company has taken steps to partially insulate itself from further interest rate
increases by entering into a cancelable interest rate swap. Based on the
Company's existing borrowing rate spreads, this swap effectively converts $100
million of floating rate debt to a fixed rate of 7.45% for a period of three
years or until the counterparty cancels the swap at their option. Also impacting
results during the past quarter was an increase in the Company's effective
income tax rate to 31.4%, as compared to 10.7% last year due to the utilization
of NOL carryforwards in prior periods and an 18% increase in the weighted
average number of diluted common shares outstanding for the quarter resulting
from the December 1999 public stock offering.
For the nine months ended September 30, 2000, the Company had total
revenues of $512.4 million, a 92% increase, primarily driven by increases in
commodity prices and acquisitions, from $267.4 million during the same period in
1999. Operating income improved 136% and net income improved 63% to $32.9
million and $14.0 million from $13.9 million and $8.6 million, respectively, in
1999. Diluted earnings per common share were $1.10 as compared to $0.98 per
share for the nine months ended September 30, 1999. Variations for each segment
are discussed in the segment results below.
SEGMENT RESULTS
The Company has segregated its business activities into three segments:
Transmission Pipelines, End-User Pipelines, and Gathering Pipelines and Natural
Gas Processing. The following tables present certain data for each of the
segments for the three-month and nine-month periods ended September 30, 2000 and
September 30, 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, depletion and amortization, interest or allocated
corporate overhead.
12
<PAGE>
TRANSMISSION PIPELINES
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
----------------------------- -------------------------------
September 30, September 30, September 30, September 30,
2000 1999 2000 1999
-------------- ------------- ------------- --------------
(In thousands, except amounts per MMBtu)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Energy Marketing Revenue............................ $55,369 $24,234 $141,059 $79,024
Transportation Fees................................. 8,943 1,296 27,666 4,494
------- ------- -------- -------
TOTAL OPERATING REVENUES....................... 64,312 25,530 168,725 83,518
------- ------- -------- -------
OPERATING EXPENSES:
Energy Marketing Costs.............................. 50,018 20,832 129,311 69,764
Operating Expenses.................................. 1,742 1,136 5,601 3,600
------- ------- -------- -------
TOTAL OPERATING EXPENSES....................... 51,760 21,968 134,912 73,364
------- ------- -------- -------
GROSS MARGIN................................... $12,552 3,562 $ 33,813 $10,154
======= ======= ======== =======
VOLUME (in MMBtu)
Marketing........................................... 13,857 10,156 40,708 35,940
Transportation...................................... 28,036 12,782 84,449 40,873
------- ------- -------- -------
TOTAL VOLUME................................... 41,893 22,938 125,157 76,813
======= ======= ======== =======
GROSS MARGIN per MMBtu......................... $.30 $.16 $.27 $.13
======= ======= ======== =======
</TABLE>
THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1999
Gross margin for the three months ended September 30, 2000 increased 252%
or $9.0 million over the same period in 1999 due to increases in transportation
fees ($7.6 million) and marketing margins ($2.0 million) offset by increased
operating expenses ($0.6 million). The $7.6 million increase in transportation
fees was a result of the KPC acquisition in November 1999 and increased
throughput volumes on the MIT system. The $2.0 million increase in marketing
margins was a result of increased margins on the MIDLA system associated with
new customers coming on-line in the third quarter 2000, increased throughput
volumes on the Magnolia system and the MarGasCo acquisition in November 1999.
The $0.6 million increase in operating expenses was a result of the KPC
acquisition.
NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1999
Gross margin for the nine months ended September 30, 2000 increased 233% or
$23.7 million over the same period in 1999 due to increases in transportation
fees ($23.2 million) and marketing margins ($2.5 million) offset by increased
operating expenses ($2.0 million). The $23.2 million increase in transportation
fees was a result of the KPC acquisition in November 1999 and increased
throughput volumes on the MIT system. The $2.5 million increase in marketing
margins was a result of increased margins on the MIDLA system associated with
new customers coming on-line in the third quarter 2000, increased throughput
volumes on the Magnolia system and the MarGasCo acquisition in November 1999.
The $2.0 million increase in operating expenses was a result of the KPC
acquisition.
13
<PAGE>
END-USER PIPELINES
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
------------------------------- --------------------------------
September 30, September 30, September 30, September 30,
2000 1999 2000 1999
------------- ------------- ------------- -------------
(In thousands, except amounts per MMBtu)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Energy Marketing Revenue............................ $42,624 $32,071 $114,773 $88,415
Transportation Fees................................. 1,010 818 2,668 2,584
------- ------- -------- -------
TOTAL OPERATING REVENUES....................... 43,634 32,889 117,441 90,999
------- ------- -------- -------
OPERATING EXPENSES:
Energy Marketing Costs.............................. 40,834 30,558 110,327 84,924
Operating Expenses.................................. 180 112 467 250
------- ------- -------- -------
TOTAL OPERATING EXPENSES....................... 41,014 30,670 110,794 85,174
------- ------- -------- -------
GROSS MARGIN................................... $ 2,620 $ 2,219 $ 6,647 $ 5,825
======= ======= ======== =======
VOLUME (in MMBtu)
Marketing........................................... 11,723 12,927 37,225 36,285
Transportation...................................... 6,216 5,304 17,949 15,443
------- ------- -------- -------
TOTAL VOLUME................................... 17,939 18,231 55,174 51,728
======= ======= ======== =======
GROSS MARGIN per MMBtu......................... $.15 $.12 $.12 $.11
======= ======= ======== =======
</TABLE>
THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1999
Gross margin for the three months ended September 30, 2000 increased 18% or
$0.4 million over the same period in 1999 due to increases in transportation
fees ($0.2 million) and marketing margins ($0.3 million) offset by increased
operating expenses ($0.1 million). The $0.2 million increase in transportation
fees was due to increased industrial demand and the full quarter operations of
the Jummonville system. The $0.3 million increase in marketing margins was due
to the full quarter operations of the Chevron system and increases in volumes
on higher margin systems. The $0.1 million increase in operating expenses was
due primarily to the Southern Industrial acquisition.
NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1999
Gross margin for the nine months ended September 30, 2000 increased 14% or
$0.8 million over the same period in 1999 due to increases in transportation
fees ($0.1 million) and marketing margins ($0.9 million) offset by increased
operating expenses ($0.2 million). The $0.1 million increase in transportation
fees was due to increased industrial demand and year-to-date operations of the
Jummonville system. The $0.9 million marketing margin increase was due to the
Chevron system and increases in volumes on higher margin systems. The $0.2
million increase in operating expenses was due primarily to the Southern
Industrial acquisition.
14
<PAGE>
GATHERING PIPELINES AND NATURAL GAS PROCESSING
<TABLE>
<CAPTION>
FOR THE THREE MONTHS ENDED FOR THE NINE MONTHS ENDED
-------------------------------- --------------------------------
September 30, September 30, September 30, September 30,
2000 1999 2000 1999
------------ ------------ ------------ ------------
(In thousands, except amounts per MMBtu)
<S> <C> <C> <C> <C>
OPERATING REVENUES:
Energy Marketing Revenue............................ $74,128 $34,547 $183,804 $72,855
Transportation Fees................................. 4,918 3,092 14,244 8,462
Processing Revenues................................. 10,037 5,269 26,726 10,376
------- ------- -------- -------
TOTAL OPERATING REVENUES....................... 89,083 42,908 224,774 91,693
------- ------- -------- -------
OPERATING EXPENSES:
Energy Marketing Costs.............................. 72,861 33,273 175,734 65,029
Operating Expenses.................................. 5,903 4,755 16,107 10,787
Processing Costs.................................... 6,821 3,451 17,784 8,352
------- ------- -------- -------
TOTAL OPERATING EXPENSES....................... 85,585 41,479 209,625 84,168
------- ------- -------- -------
GROSS MARGIN................................... $ 3,498 $ 1,429 $ 15,149 $ 7,525
======= ======= ======== =======
VOLUME (in MMBtu)
Marketing........................................... 15,366 9,400 40,321 23,845
Transportation...................................... 35,320 23,609 95,975 66,398
Processing.......................................... 4,195 3,063 11,752 7,104
------- ------- -------- -------
TOTAL VOLUME................................... 54,881 36,072 148,048 97,347
======= ======= ======== =======
GROSS MARGIN per MMBtu......................... $ .06 $ .04 $ .10 $ .08
======= ======= ======== =======
</TABLE>
THREE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 1999
Gross margin for the three months ended September 30, 2000 increased 145%
or $2.1 million over the same period in 1999 due to increased processing margins
($1.4 million) and the earnings impact of acquisitions in the gathering and
transportation areas ($1.8 million) offset by increases in operating expenses
($1.1 million). The $1.4 million increase in processing margins was due to
increased volumes provided by the Gloria and Provost acquisitions and increased
margins per MMBtu due to average increased NGL prices of $0.16 per gallon on
percentage of proceeds contracts. The $1.8 million increase in transportation
fees was due to increased throughput volumes provided by the Shelco, Manyberries
and Seacrest acquisitions. The $1.1 million increase in operating expenses was
due to the Shelco, Manyberries, Seacrest, Gloria and Colorado County
acquisitions.
NINE MONTHS ENDED SEPTEMBER 30, 2000 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
1999
Gross margin for the nine months ended September 30, 2000 increased 101% or
$7.6 million over the same period in 1999. This increase was due primarily to
the benefits of acquisitions in transportation and processing and increased NGL
prices and processing spreads. Marketing margins, transportation fees and
processing margins before operating expense increased by $12.9 million primarily
due to increased volumes from the acquisitions of DPI and the Calmar facility in
March 1999, several offshore gathering systems in mid third quarter 1999, and
Provost, Shelco and Manyberries in 2000. In addition, processing spreads on our
unhedged NGL production increased approximately $0.64 per MMBtu from the same
period in 1999. The Company's NGL hedging activity also locked in 2000 spreads
that were an average of $0.10 per MMBtu higher than processing spread levels for
the first nine months of 1999. This was offset by an increase in operating
expense of $5.3 million from the acquisitions discussed above.
15
<PAGE>
OTHER INCOME, COSTS AND EXPENSES
Other revenues for the three and nine months ended September 30, 2000
increased to $0.6 million and $1.4 million, respectively, from $0.5 million and
$1.2 million for the same periods in 1999. This increase was primarily
attributable to an increase in income earned on processing plant construction
projects, which includes planning, fabrication, installation and facility
operations and management.
Depreciation, depletion and amortization for the three and nine months ended
September 30, 2000 increased to $4.2 million and $11.4 million, respectively,
from $1.9 million and $4.8 million for the same periods in 1999. This increase
was primarily due to increased depreciation and amortization on assets acquired
in the KPC, DPI/Flare, Calmar, Manyberries, and Provost acquisitions.
General and administrative expenses for the three and nine months ended
September 30, 2000 increased to $4.4 million and $12.8 million, respectively
from $2.0 million and $5.9 million for the same periods 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. General and administrative
expenses, as a percentage of gross margin, decreased to 22% for the nine months
ended September 30, 2000 from 24% for the same period in 1999.
Interest expense for the three and nine months ended September 30, 2000
increased to $5.3 million and $15.0 million from $1.0 million and $3.7 million,
respectfully, for the same periods 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 $258.5 million and
$256.0 million in debt for the three and nine months ended September 30, 2000 as
compared to $66.7 million and $86.9 million in debt for the same periods 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 and nine months ended September 30,
2000 increased to 7.8% respectively, from 6.3% for the same periods in 1999.
INCOME TAXES
The Company's income tax provision for the three and nine months ended
September 30, 2000 increased to $1.7 million and $4.1 million, respectively,
from $0.3 million and $1.5 million in 1999. The Company's effective tax rate
for the three and nine months ended September 30, 2000 increased to 31.4% and
22.8%, respectively, from 10.7% and 15.3% in 1999 due to the utilization of NOL
carryforwards in prior periods. The effective tax rate for the remainder of
2000 is expected to be closer to the federal statutory rate of 34%.
As of September 30, 2000, the Company has NOL carryforwards of approximately
$12.4 million, expiring in various amounts from 2004 through 2018. The ability
of the Company to utilize the carryforwards is dependent upon the Company
generating sufficient taxable income and will be affected by limitations
(currently estimated at $6.0 million) on the use of such carryforwards for 2000
due to a change in shareholder control under section 382 of the Internal Revenue
Code created by the acquisitions of Republic and DPI.
RATES AND REGULATORY MATTERS
Each of our transmission 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. However, through
September 30, 2000, KPC is continuing to charge its customers the initial FERC-
approved rates. Additionally, the two customers have been paying only a portion
of the Company's invoices pursuant to their protest of the current rates. The
resultant unpaid balance from both customers at September 30, 2000 was
approximately $432,000. 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 to the extent which KPC may recover all or any part
of the proposed rate increase that it has not charged to its customers prior to
approval. The hearing related to the
16
<PAGE>
proposed increase commenced on September 26, 2000 and concluded on October 20,
2000. A final Commission decision is not expected until at least the fourth
quarter of 2001.
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 consolidated financial
position, results of operations, or cash flows.
CAPITAL RESOURCES AND LIQUIDITY
Since 1996, the Company has acquired approximately $384 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 increased to 59% at September 30, 2000 from
33% at September 30, 1999.
In November 1999, March 2000 and again in June 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 $300 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 $300 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 (base rate borrowings) 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 the previous
fiscal quarter. The Company is charged a margin between 1.0% and 1.75% on LIBOR
based borrowings and between 0.0% and 0.25% on base rate borrowings as the
Company's total debt to total capitalization ratio ranges at or below 40% up to
65%, respectively. The Company is currently being charged margins of 1.5% on
LIBOR borrowings and no margin on base rate borrowings.
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. At September 30, 2000, the Company had approximately
$50.6 million of available capacity under its credit agreement.
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
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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.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Note 6, which is incorporated herein by reference.
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.
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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 and swap contracts to manage and hedge price risk
related to these market exposures. The futures contracts have pricing terms
indexed to the New York Mercantile Exchange.
The company also uses over-the-counter swaps to hedge its physical exposure
to processing spread risk. Processing spreads are the difference between the
price the company receives for the sale of natural gas liquids and the price it
pays for the natural gas equivalent on a heating value basis (MMBtu's). The
company has locked in a fixed processing spread on approximately 70% of its NGL
production through December 2000.
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 three separate swap agreements with a combined notional amount of $165
million dollars. The interest rate swap agreements entered into by the Company
effectively convert $165 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
September 30, 2000 and 1999, the fair value of this interest rate swap through
the initial termination date was a net asset of approximately $95,539 and a net
liability of approximately $199,642, 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
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reimburse the Company when the three-month LIBOR rate is reset above 4.475%. At
September 30, 2000 and 1999, the fair value of this interest rate swap through
the initial termination date was a net asset of approximately $1,046,963 and
$1,363,317, respectively.
The effect of these swap agreements was to lower interest expense by $961,511
and $182,501 in the nine months ended September 30, 2000 and 1999, respectively.
A third interest rate swap agreement was entered into with Scotiabank in
October 2000. The swap agreement effectively established a fixed interest rate
setting of 5.95% for a three-year period beginning October 2000 on a notional
amount of $100 million. The agreement is cancelable at Scotiabank's option at
the end of any three-month period during the three-year term with 2 days notice.
The variable three-month LIBOR rate is reset quarterly based on the prevailing
market rate and the company is obligated to reimburse Scotiabank when the three-
month LIBOR rate is reset below 5.95%. Conversely, Scotiabank is obligated to
reimburse the Company when the three-month LIBOR rate is reset above 5.95%.
PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits:
None
b. Reports on Form 8-K:
None
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SIGNATURE
In accordance with the requirements of the Exchange Act, the Registrant caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized.
MIDCOAST ENERGY RESOURCES, INC.
(Registrant)
BY: /s/ Richard A. Robert
-----------------------------
Richard A. Robert
Principal Financial Officer
Treasurer
Principal Accounting Officer
Date: November 14, 2000
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