U.S. SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[X] Quarterly Report Under Section 13 or 15 (d) of the
Securities Exchange Act of 1934 for the Quarterly
Period Ended June 30, 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 August 14, 2000 there were outstanding 12,476,805 shares
of the Company's common stock, par value $.01 per share.
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 June 30, 2000
and December 31, 1999 1
Unaudited Condensed Consolidated Statements of Operations for the
three months and six months ended June 30, 2000 and June 30,1999 2
Unaudited Condensed Consolidated Statements of Comprehensive Income
for the three months and six months ended June 30, 2000 and June 30,
1999 3
Unaudited Condensed Consolidated Statements of Cash Flows for the
three months and six months ended June 30, 2000 and June 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
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 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)
NGA Natural Gas Act
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
<TABLE>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
<CAPTION>
<S> <C> <C>
June 30, 2000 December 31, 1999
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1,685 $ 2,345
Accounts receivable, net of allowance of 75,936 55,189
$1,220 and $1,484, respectively
Other current assets 8,814 4,905
Total Current Assets 86,435 62,439
PROPERTY, PLANT AND EQUIPMENT, NET 405,168 392,969
OTHER ASSETS 23,648 22,964
Total Assets $ 515,251 $ 478,372
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES 74,133 63,978
LONG-TERM DEBT 257,623 240,000
OTHER LIABILITIES 2,155 2,147
DEFERRED INCOME TAXES 13,044 11,034
COMMITMENTS AND CONTINGENCIES (Note 3) - -
MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES 532 536
SHAREHOLDERS' EQUITY:
Common stock, par value $.01 per share;
authorized 31,250,000 shares;
issued 12,721,980 127 127
Paid-in capital 165,878 165,964
Retained earnings (accumulated deficit) 5,546 (2,915)
Accumulated other comprehensive income 73 71
Treasury stock (at cost), 242,175 and
161,156 (3,860) (2,570)
Total Shareholders' Equity 167,764 160,677
Total Liabilities and Shareholders'
Equity $ 515,251 $ 478,372
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
<TABLE>
<CAPTION>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except share data)
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
OPERATING REVENUES:
Energy marketing revenue $ 138,480 $ 74,387 $ 267,514 $ 149,442
Transportation fees 15,030 5,692 29,707 10,334
Natural gas processing revenue 9,068 3,213 16,689 5,107
Other 385 165 807 638
Total operating revenues 162,963 83,457 314,717 165,521
OPERATING EXPENSES:
Energy marketing expenses 132,004 66,842 251,660 135,054
Natural gas processing costs 5,622 2,880 10,964 4,901
Other operating expenses 7,173 5,583 14,348 8,634
Depreciation,depletion and 3,712 1,534 7,191 2,943
amortization
General and administrative 4,399 2,052 8,358 3,950
Total operating expenses 152,910 78,891 292,521 155,482
OPERATING INCOME 10,053 4,566 22,196 10,039
NON-OPERATING ITEMS:
Interest expense (4,727) (1,373) (9,622) (2,876)
Minority interest in consolidated (8) 17 (26) (23)
subsidiaries
Other income (expense), net 26 (97) 86 (92)
INCOME BEFORE INCOME TAXES 5,344 3,113 12,634 7,048
PROVISION FOR INCOME TAXES:
Current (71) (366) (403) (829)
Deferred (1,269) (171) (2,010) (388)
NET INCOME $ 4,004 $ 2,576 $ 10,221 $ 5,831
EARNINGS PER COMMON SHARE:
BASIC $ 0.32 $ 0.31 $ 0.82 $ 0.77
DILUTED $ 0.32 $ 0.31 $ 0.80 $ 0.75
WEIGHTED AVERAGE NUMBER OF
COMMON SHARES OUTSTANDING:
BASIC 12,487,887 8,224,972 12,517,382 7,581,609
DILUTED 12,711,478 8,428,998 12,730,326 7,792,269
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
<TABLE>
<CAPTION>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
Net income $ 4,004 $ 2,576 $ 10,221 $ 5,831
Foreign currency translation 10 (146) 2 (146)
adjustment
Comprehensive income $ 4,014 2,430 10,223 5,685
</TABLE>
The accompanying notes are an integral part of these condensed
consolidated financial statements.
<TABLE>
<CAPTION>
MIDCOAST ENERGY RESOURCES, INC., AND SUBSIDIARIES
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 4,004 $ 2,576 $ 10,221 $ 5,831
Adjustments to arrive at net cash
provided by (used in) operating
activities:
Depreciation,depletion and 3,712 1,534 7,191 2,943
amortization
Deferred income taxes 1,269 171 2,010 388
Minority interest in consolidated 38 (17) 56 23
subsidiaries
Other 10 (15) 51 (36)
Changes in working capital accounts:
Increase in accounts receivable (17,486) (7,308) (19,665) (17,311)
Increase in other current assets (4,708) (25) (4,145) (26)
Increase in accounts payable and
accrued liabilities 8,138 14,675 10,186 19,335
Net cash provided by (used in)
operating activities (5,023) 11,591 5,905 11,147
CASH FLOWS FROM INVESTING ACTIVITIES:
Acquisitions (7,237) (1,799) (13,020) (30,390)
Capital expenditures (3,162) (6,799) (6,419) (11,748)
Net advances to equity investee (56) - (161) -
Other (1,002) 744 (1,002) 188
Net cash used in investing activities (11,457) (7,854) (20,602) (41,950)
CASH FLOWS FROM FINANCING ACTIVITIES:
Bank debt borrowings 33,776 30,319 73,276 120,370
Bank debt repayments (17,175) (84,298) (55,724) (135,785)
Net proceeds from equity offerings - 54,693 - 54,693
Treasury stock purchases (211) (416) (1,290) (2,406)
Dividends on common stock (886) (479) (1,760) (921)
Other (88) (61) (465) 168
Net cash provided by (used in)
financing activities 15,416 (242) 14,037 36,119
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS (1,063) 3,495 (660) 5,316
CASH AND CASH EQUIVALENTS,beginning of 2,749 2,021 2,345 200
period
CASH AND CASH EQUIVALENTS,end of period $ 1,685 $ 5,516 $ 1,685 $ 5,516
SUPPLEMENTAL DISCLOSURES:
Cash Paid for Interest $ 3,450 $ 1,611 $ 8,398 $ 4,249
Cash Paid for Income Taxes $ - $ 60 $ 1,600 $ 60
</TABLE>
The accompanying notes are an integral part of these 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 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.
SHELCO ACQUISITION
In May 2000, DPI, a subsidiary of the Company, acquired
Shelco Transport, Inc. for approximately $1.5 million. Shelco, a
natural gas liquids transportation company located in Baton
Rouge, Louisiana and Sorrento, Louisiana, owns and operates 10
trucks, 11 high pressure trailers and a truck terminal and
maintenance facility. The acquisition was funded through the
Company's existing credit facility, the issuance of the Company's
common stock and the assumption of debt.
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 June 30, 2000, the Company has
made payments of $500,000 and has accrued an additional $62,500
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 June 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 June 30, 2000,
KPC is continuing to charge its customers the initial
FERC-approved rates. 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.
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.
<TABLE>
<CAPTION>
4. EARNINGS PER SHARE:
Basic and diluted earnings per share amounts are presented
below for the three months and six months ended June 30 (in
thousands, except per share amounts):
<S> <C> <C> <C> <C> <C> <C>
For the Three Months Ended
2000 1999
Average Average
Net Shares Earnings Shares Earnings
Income Outstanding Per Share Net Income Outstanding Per Share
Basic $ 4,004 $ 12,488 $ .32 $ 2,576 $ 8,225 $ .31
Effect of dilutive
securities:
Stock options - 160 - - 148 -
Warrants - 63 - - 56 -
Diluted $ 4,004 $ 12,711 $ .32 $ 2,576 $ 8,429 $ .31
For the Six Months Ended
2000 1999
Average Average
Net Shares Earnings Shares Earnings
Income Outstanding Per Share Net Income Outstanding Per Share
Basic $ 10,221 $ 12,517 $ .82 $ 5,831 $ 7,582 $ .77
Effect of dilutive
securities:
Stock options - 154 (.02) - 151 (.02)
Warrants - 59 - - 59 -
Diluted $ 10,221 $ 12,730 $ .80 $ 5,831 $ 7,792 $ .75
</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 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, interest or allocated corporate overhead.
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 and six
months ended June 30, 2000 and 1999:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C>
As of or for the Three Months Ended June 30, 2000
Gathering
Transmission End-User and
Pipelines Pipelines Processing Other Total
(In thousands)
Revenues:
Domestic $ 51,240 $ 40,294 $ 69,503 $ 385 $161,422
Foreign - - 1,541 - 1,541
Total Revenues 51,240 40,294 71,044 385 162,963
Gross Margin 9,984 1,616 6,179 385 18,164
Depreciation and Amortization (1,937) (226) (1,258) (291) (3,712)
General and Administrative - - - (4,399) (4,399)
Interest Expense - - - (4,727) (4,727)
Other, net - - - 18 18
Income before income taxes 8,047 1,390 4,921 (9,014) 5,344
Assets:
Domestic 340,411 40,158 97,570 10,350 488,489
Foreign - - 26,762 - 26,762
Total Assets 340,411 40,158 124,332 10,350 515,251
Capital Expenditures 196 1,319 1,332 315 3,162
(excluding acquisitions)
As of or for the Three Months Ended June 30, 1999
Gathering
Transmission End-User and
Pipelines Pipelines Processing Other Total
(In thousands)
Revenues:
Domestic $ 22,739 $ 29,772 $ 30,383 $ 165 $ 83,059
Foreign - - 398 - 398
Total Revenues 22,739 29,772 30,781 165 83,457
Gross Margin 2,452 2,090 3,445 165 8,152
Depreciation and Amortization (364) (221) (842) (107) (1,534)
General and Administrative - - - (2,052) (2,052)
Interest Expense - - - (1,373) (1,373)
Other, net - - - (80) (80)
Income before income taxes 2,088 1,869 (3,447) 3,113
Assets:
Domestic 144,864 10,992 75,852 9,653 241,361
Foreign - - 14,103 - 14,103
Total Assets 144,864 10,992 89,955 9,653 255,464
Capital Expenditures 4,055 1,423 1,017 304 6,799
(excluding acquisitions)
As of or for the Six Months Ended June 30, 2000
Gathering
Transmission End-User and
Pipelines Pipelines Processing Other Total
(In thousands)
Revenues:
Domestic $104,413 $ 73,807 $132,714 $ 807 $311,741
Foreign - - 2,976 - 2,976
Total Revenues 104,413 73,807 135,690 807 314,717
Gross Margin 21,261 4,027 11,650 807 37,745
Depreciation and Amortization (3,785) (521) (2,410) (475) (7,191)
General and Administrative - - - (8,358) (8,358)
Interest Expense - - - (9,622) (9,622)
Other, net - - - 60 60
Income before income taxes 17,476 3,506 9,240 (17,588) 12,634
Capital Expenditures 495 2,857 2,319 748 6,419
(excluding acquisitions)
As of or for the Six Months Ended June 30, 1999
Gathering
Transmission End-User and
Pipelines Pipelines Processing Other Total
(In thousands)
Revenues:
Domestic $ 58,763 $ 58,319 $ 47,135 $ 638 $164,855
Foreign - - 666 - 666
Total Revenues 58,763 58,319 47,801 638 165,521
Gross Margin 7,367 3,815 5,112 638 16,932
Depreciation and Amortization (736) (426) (1,579) (202) (2,943)
General and Administrative - - - (3,950) (3,950)
Interest Expense - - - (2,876) (2,876)
Other, net - - - (115) (115)
Income before income taxes 6,631 3,389 3,533 (6,505) 7,048
Capital Expenditures 4,844 3,852 2,569 483 11,748
(excluding acquisitions)
</TABLE>
6. NEW ACCOUNTING PRONOUNCEMENTS 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,
"Accounting for Derivative Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133" and SFAS
No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities - an Amendment of FASB Statement No. 133" and is
effective for fiscal years beginning after June 15, 2000.
The Company is currently evaluating the effects of this pronouncement.
In December 1999, the Securities and Exchange Commission
issued Staff Accounting Bulletin (SAB) No. 101 to provide
guidance for revenue recognition issues and disclosure
requirements. 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 is currently evaluating the
effects of this pronouncement.
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 six months of 2000.
Reserve at December 31, 1999 $ 1,701,009
Expenditures (1,540,009)
New Accruals -
Reserve at June 30, 2000 $ 161,000
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 June 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 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 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 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. 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 June 30, 2000, the Company had
total revenues of $163.0 million, a 95% increase from $83.5
million during the same period in 1999. Operating income
improved 120% and net income improved 55% to $10.1 million and
$4.0 million from $4.6 million and $2.6 million, respectively, in
1999. Diluted earnings per common share were $0.32 as compared
to $0.31 per share in the second quarter of 1999. Results were
positively impacted by a number of recent acquisitions including
KPC, Provost, Manyberries and Shelco, expansions along the MIDLA
system, and an improvement in margins for natural gas processing.
These results came despite a 51% increase in the weighted average
number of diluted common shares outstanding, as a result of stock
offerings in May and December 1999 and an increase to 7.7% in the
weighted average interest rate for the quarter as compared to
6.3% in the second quarter last year. The Company also had a
significant increase in its effective income tax rate.
Variations for each segment are discussed in the segment results
below.
For the six months ended June 30, 2000, the Company had
total revenues of $314.7 million, a 90% increase from $165.5
million during the same period in 1999. Operating income
improved 121% and net income improved 75% to $22.2 million and
$10.2 million from $10.0 million and $5.8 million, respectively,
in 1999. Diluted earnings per common share were $0.80 as
compared to $0.75 per share for the six months ended June 30,
1999. Results were positively impacted by a number of recent
acquisitions including DPI, KPC, Provost, Manyberries and Shelco,
expansions along the MIDLA system, and an improvement in margins
for natural gas processing. These results came despite a 63%
increase in the weighted average number of diluted common shares
outstanding, as a result of stock offerings in May and December
1999 and an increase to 7.8% in the weighted average interest
rate for the six months ended June 30, 2000 as compared to 6.5%
for the six months ended June 30, 1999. The Company also had a
significant increase in its effective income tax rate.
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 six-month periods ended June 30, 2000 and June
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,
interest or allocated corporate overhead.
<TABLE>
<CAPTION>
TRANSMISSION PIPELINES
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
(In thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $ 42,241 $ 21,458 $ 85,690 $ 55,565
Transportation Fees 8,999 1,281 18,723 3,198
TOTAL OPERATING REVENUES 51,240 22,739 104,413 58,763
OPERATING EXPENSES:
Marketing Costs 39,616 18,908 79,294 48,932
Operating Expenses 1,640 1,379 3,858 2,464
TOTAL OPERATING EXPENSES 41,256 20,287 83,152 51,396
GROSS MARGIN $ 9,984 $ 2,452 $ 21,261 $ 7,367
VOLUME (in MMBtu)
Marketing 11,131 9,471 26,851 25,784
Transportation 27,726 13,423 56,413 28,091
TOTAL VOLUME 38,857 22,894 83,264 53,875
GROSS MARGIN per MMBtu $ .26 $ .11 $ .26 $ .14
</TABLE>
Three Months Ended June 30, 2000 compared to Three Months Ended
June 30, 1999
Gross margin for the three months ended June 30, 2000
increased 307% or $7.5 million over the same period in 1999 due
primarily to increases in transportation fees ($7.7 million)
and marketing margins ($0.1 million) offset by increases in
operating expenses ($0.3 million). The $7.7 million increase in
transportation fees was a result of the KPC acquisition which
occurred in November 1999.
Six Months Ended June 30, 2000 compared to Six Months Ended June
30, 1999
Gross margin for the six months ended June 30, 2000
increased 189% or $13.9 million over the same period in 1999 due
primarily to increases in transportation fees ($15.5 million)
offset by decreases in marketing margins ($0.2 million) and
increased operating expenses ($1.4 million). The $15.5 million
increase in transportation fees was a result of the KPC
acquisition which occurred in November 1999.
<TABLE>
<CAPTION>
END-USER PIPELINES
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
(In thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $ 39,410 $ 28,745 $ 72,149 $ 56,553
Transportation Fees 884 1,027 1,658 1,766
TOTAL OPERATING REVENUES 40,294 29,772 73,807 58,319
OPERATING EXPENSES:
Marketing Costs 38,502 27,644 69,493 54,366
Operating Expenses 176 38 287 138
TOTAL OPERATING EXPENSES 38,678 27,682 69,780 54,504
GROSS MARGIN $ 1,616 $ 2,090 $ 4,027 $ 3,815
VOLUME (in MMBtu)
Marketing 12,055 13,312 25,502 27,218
Transportation 6,008 5,947 11,733 11,959
TOTAL VOLUME 18,063 19,259 37,235 39,177
GROSS MARGIN per MMBtu $ .09 $ .11 $ .11 $ .10
</TABLE>
Three Months Ended June 30, 2000 compared to Three Months Ended
June 30, 1999
Gross margin for the three months ended June 30, 2000
decreased 23% or $0.5 million over the same period in 1999 due
primarily to decreases in transportation fees ($0.2 million)
and marketing margins ($0.2 million) and an increase in operating
expenses ($0.1 million). The $0.2 million decrease in
transportation fees was due to lower margin, higher throughput
interruptible transportation and higher natural gas prices which
resulted in decreased natural gas demand from a primarily coal
fired power generation customer. The marketing margin decreased
$0.2 million due to lower throughput volumes as a result of
higher natural gas prices. The $0.1 million increase in
operating expenses was due primarily to the Southern Industrial
acquisition in June 1999.
Six Months Ended June 30, 2000 compared to Six Months Ended June
30, 1999
Gross margin for the six months ended June 30, 2000
increased 6% or $0.2 million over the same period in 1999 due
primarily to increases in marketing margins ($0.5 million) offset
by decreases in transportation fees ($0.1 million) and
increases in operating expenses ($0.2 million). The marketing
margin increased $0.5 million due to increases in higher margin
throughput volumes. The $0.1 million decrease in transportation
fees was due to lower margin, higher throughput interruptible
transportation and higher natural gas prices which resulted in
decreased natural gas demand from a primarily coal fired power
generation customer. The $0.2 million increase in operating
expenses was due primarily to the Southern Industrial acquisition
in June 1999.
<TABLE>
<CAPTION>
GATHERING PIPELINES AND NATURAL GAS PROCESSING
<S> <C> <C> <C> <C>
For the Three Months Ended For the Six Months Ended
June 30, 2000 June 30, 1999 June 30, 2000 June 30, 1999
(In thousands, except amounts per MMBtu)
OPERATING REVENUES:
Marketing Revenue $ 56,829 $ 24,184 $109,675 $ 37,324
Transportation Fees 5,147 3,384 9,326 5,370
Processing Revenues 9,068 3,213 16,689 5,107
TOTAL OPERATING REVENUES 71,044 30,781 135,690 47,801
OPERATING EXPENSES:
Marketing Costs 53,886 20,290 102,873 31,756
Operating Expenses 5,357 4,166 10,203 6,032
Processing Costs 5,622 2,880 10,964 4,901
TOTAL OPERATING EXPENSES 64,865 27,336 124,040 42,689
GROSS MARGIN $ 6,179 $ 3,445 $ 11,650 $ 5,112
VOLUME (in MMBtu)
Marketing 12,938 9,320 24,955 14,445
Transportation 30,884 23,232 60,655 42,789
Processing 4,159 2,080 7,557 4,041
TOTAL VOLUME 47,981 34,632 93,167 61,275
GROSS MARGIN per MMBtu $ .13 $ .10 $ .13 $ .08
</TABLE>
Three Months Ended June 30, 2000 compared to Three Months Ended
June 30, 1999
Gross margin for the three months ended June 30, 2000
increased 79% or $2.7 million over the same period in 1999 due
primarily to increased processing margins and the earnings impact
of acquisitions in the marketing, gathering and transportation
areas. Processing margins increased $3.1 million or 934% over
the same quarter in 1999 due to increased processed volumes
provided by the Gloria and Provost acquisitions, increased
processed volumes on the Anadarko System, and increased volumes
on other existing systems. In addition, the Company's NGL
hedging activity locked in spreads on approximately 70% of its
physical NGL production that were $.073/MMBtu higher than the
second quarter of 1999. The increase in the spread between the
MMBtu equivalent price of natural gas liquids and natural gas
also contributed to increased margins on the remaining 30% of NGL
production. Increased gathering volumes provided $1.8 million of
the increase in gross margin primarily due to the acquisition of
additional offshore gathering systems, the Manyberries crude oil
gathering system and Shelco, which was merged into DPI.
Six Months Ended June 30, 2000 compared to Six Months Ended June
30, 1999
Gross margin for the six months ended June 30, 2000
increased 128% or $6.5 million over the same period in 1999.
This increase was due primarily to increased processing spreads
and the impact of acquisitions in transportation and processing.
Processing spreads on our unhedged NGL production increased
approximately $.94/MMBtu from the same period in 1999. The
Company's NGL hedging activity also locked in 2000 spreads that
were an average of $.28/MMBtu higher than processing spread
levels for the first six months of 1999. Marketing margins,
transportation fees and processing margins increased by $10.7
million primarily due to increased volumes from the acquisitions
of DPI and the Calmar facility in March 1999, several offshore
gathering systems in third quarter 1999, and Provost, Shelco and
Manyberries in 2000. This was offset by an increase in operating
expenses of $4.2 million from these acquisitions.
OTHER INCOME, COSTS AND EXPENSES
Other revenues for the three and six months ended June 30,
2000 increased to $0.4 million and $0.8 million from $0.2 million
and $0.6 million for the same periods in 1999. This increase was
primarily attributable to an increase in income earned on mobile
processing plant facilities constructed for our customers.
Depreciation, depletion and amortization for the three and
six months ended June 30, 2000 increased to $3.7 million and $7.2
million, respectively from $1.5 million and $2.9 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, and Calmar acquisitions.
General and administrative expenses for the three and six
months ended June 30, 2000 increased to $4.4 million and $8.4
million, respectively from $2.1 million and $4.0 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. In addition, as the Company
continues to integrate recent acquisitions and move functions
from the field offices to the corporate office, it is anticipated
that corporate general and administrative expense will continue
to increase while operating expenses will decrease. General and
administrative expenses, as a percentage of gross margin,
decreased to 22% for the six months ended June 30, 2000 from 23%
for the same period in 1999.
Interest expense for the three and six months ended June 30,
2000 increased to $4.7 million and $9.6 million from $1.4 million
and $2.9 million 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 $261.0 million and $254.0 million in debt for the
three and six months ended June 30, 2000 as compared to $96.3
million and $97.0 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 six months ended June 30, 2000 increased to 7.7%
and 7.8%, respectively from 6.3% and 6.5% for the same periods in
1999.
INCOME TAXES
The Company's income tax provision for the three and six
months ended June 30, 2000 increased to $1.3 million and $2.4
million, respectively, from $0.5 million and $1.2 million in
1999. The Company's effective tax rate for the three and six
months ended June 30, 2000 was 25.1% and 19.1%, respectively,
compared to 17.2% and 17.3% in 1999. The effective tax rate for
the remainder of 2000 is expected to be closer to the federal
statutory rate of 34%.
As of June 30, 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 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 June 30, 2000,
KPC is continuing to charge its customers the initial
FERC-approved rates. 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. 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 $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 60% at
June 30, 2000 from 33% at June 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 2.0% on LIBOR based borrowings
and between 0.0% and 0.5% on base rate borrowings as the
Company's total debt to total capitalization ratio ranges from
under 40% to over 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 June 30, 2000, the
Company had approximately $42.3 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
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 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.
Natural 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.
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 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 June 30, 2000 and
1999, the fair value of this interest rate swap through the
initial termination date was a net asset of approximately
$224,080 and a net liability of approximately $200,000,
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 June 30, 2000
and 1999, the fair value of this interest rate swap through the
initial termination date was a net asset of approximately
$1,421,671 and $1,500,000, respectively.
The effect of these swap agreements was to lower interest
expense by $656,842 and $139,000 in the six months ended June 30,
2000 and 1999, respectively.
PART II. OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company held its Annual Meeting of Shareholders on May
16, 2000. Shareholders of record at the close of business on
March 31, 2000 were entitled to vote. The shareholders voted on
nominations to elect six Directors to the Board of Directors and
approve an amendment to the 1996 Incentive Stock Plan to increase
the number of shares authorized for issuance under the plan by
468,750 shares of common stock to an aggregate of 1,000,000
shares. For additional information concerning the Annual Meeting
of Shareholders please see the Company's proxy statement dated
April 14, 2000.
The Shareholders elected each of the six directors nominated for
the board of directors as follows:
Directors Votes For Votes Against Abstaining Broker No-Votes
Dan C. Tutcher 10,777,807 - 107,491 -
I.J. Berthelot, II 10,777,785 - 107,593 -
Richard N. Richards 10,777,785 - 107,593 -
Ted Collins, Jr. 10,777,785 - 107,593 -
Curtis J. Dufour III 10,777,785 - 107,593 -
Bruce M. Withers 10,777,301 - 107,996 -
The shareholders approved the proposal to amend to the 1996
Incentive Stock Plan as follows:
Votes For Votes Against Abstaining Broker No-Votes
1996 Incentive
Stock Plan 7,296,573 3,572,097 16,526 -
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: August 14, 2000
