--------------------------------------------------------------------------------
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2000 Commission file number 1-15759
or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
CLECO CORPORATION
(Exact name of registrant as specified in its charter)
LOUISIANA 72-1445282
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2030 DONAHUE FERRY ROAD, PINEVILLE, LOUISIANA 71360-5226
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (318) 484-7400
Indicate by check mark whether the Registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities 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
--- ---
As of November 1, 2000, there were 22,495,320 shares outstanding of the
Registrant's Common Stock, par value $2.00 per share.
<PAGE>
TABLE OF CONTENTS
Page
----
GLOSSARY OF TERMS ......................................................... 1
PART I. FINANCIAL INFORMATION ........................................... 3
Item 1. Financial Statements
Consolidated Interim Statements of Income............... 4
Consolidated Interim Balance Sheets..................... 6
Consolidated Interim Statements of Cash Flows........... 8
Notes to Consolidated Interim Financial Statements...... 9
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations............. 19
Disclosure Regarding Forward-Looking Statements....... 19
Results of Operations.................................. 19
Financial Condition.................................... 26
Repowering Project..................................... 29
New Power Plant........................................ 29
Constraints on Purchased Power......................... 29
New Accounting Standard................................ 30
Item 3. Quantitative and Qualitative Disclosures About
Market Risk............................................... 32
PART II. OTHER INFORMATION
Item 5. Other Information............................................ 34
Item 6. Exhibits and Reports on Form 8-K............................. 35
SIGNATURE ................................................................ 36
<PAGE>
GLOSSARY OF TERMS
THE FOLLOWING ABBREVIATIONS OR ACRONYMS USED IN THIS FORM 10-Q ARE DEFINED
BELOW:
ABBREVIATION OR ACRONYM DEFINITION
1935 Act .......................... Public Utility Holding Company Act of
1935
1999 Form 10-K..................... The Company's Annual Report on Form 10-K
for the year ended December 31, 1999
Acadia Tolling Agreement........... Capacity Sale and Tolling Agreement
between APP and Aquila Energy
APB................................ Accounting Principals Board
APB No. 18......................... The Equity Method of Accounting for
Investments in Common Stock
APB No. 25......................... Accounting for Stock Issued to Employees
APP................................ Acadia Power Partners LLC
CMT................................ Cleco Marketing & Trading LLC
Company ........................... Cleco Corporation
CPS................................ Coughlin Power Station
DHMV..... Dolet Hills Mining Venture
EITF............................... Emerging Issues Task Force
EITF No 98-10...................... Accounting for Contracts Involved in
Energy Trading and Risk Management
Activities
Energy............................. Cleco Energy, LLC
ESOP............................... The Company's Employee Stock Ownership
Plan
Evangeline......................... Cleco Evangeline LLC
Evangeline Tolling Agreement....... Capacity Sale and Tolling Agreement
between Evangeline and Williams
FASB............................... Financial Accounting Standards Board
Federal Court Suit................. Lawsuit filed by Utility Group and SWEPCO
on April 15, 1997 against DHMV and its
partners in the United States District
Court for the Western District of
Louisiana
FERC............................... Federal Energy Regulatory Commission
Four Square Gas.................... Four Square Gas Company, Inc.
Four Square Production............. Four Square Production, L.L.C.
kWh................................ Kilowatt-hour
LDEQ............................... Louisiana Department of Environmental
Quality
LMA................................ Lignite Mining Agreement between Utility
Group, SWEPCO and DHMV
LPSC............................... Louisiana Public Service Commission
Midstream ......................... Cleco Midstream Resources LLC
MW................................. Megawatt
Rights Plan........................ Shareholder Rights Plan
RTO ............................... Regional Transmission Organization
SFAS............................... Statement of Financial Accounting
Standards
SFAS No.13 ........................ Accounting for Leases
SFAS No.29 ........................ Determining Contingent Rentals
SFAS No.58 ........................ Capitalization of Interest Cost in
Financial Statements That Include
Investments Accounted for by the
Equity Method
SFAS No.128 ....................... Earnings per Share
SFAS No.131 ....................... Disclosures about Segments of an
Enterprise and Related Information
SFAS No.133 ....................... Accounting for Derivative Instruments
and Hedging Activities
SFAS No.137 ....................... Accounting for Derivative Instruments and
Hedging Activities - Deferral of the
Effective Date of FASB Statement
No. 133
(Continued on next page)
1
<PAGE>
THE FOLLOWING ABBREVIATIONS OR ACRONYMS USED IN THIS FORM 10-Q ARE DEFINED
BELOW:
ABBREVIATION OR ACRONYM DEFINITION
State Court Suit................... Lawsuit filed by Utility Group and SWEPCO
on August 13, 1997 against the parent
companies of DHMV in the First Judicial
District Court for Caddo Parish,
Louisiana
SWEPCO............................. Southwestern Electric Power Company
UtiliTech.......................... Utility Construction & Technology
Solutions LLC
Utility Group...................... Cleco Utility Group Inc.
VAR................................ Value-at-risk
Williams........................... Williams Energy Marketing and
Trading Company
2
<PAGE>
PART I
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The consolidated interim financial statements for the Company included
herein are unaudited but reflect, in management's opinion, all adjustments,
consisting only of normal recurring adjustments, that are necessary for a fair
presentation of the Company's financial position and the results of its
operations for the interim periods presented. Because of the seasonal nature of
several of the Company's subsidiaries, the results of operations for the nine
months ended September 30, 2000 are not necessarily indicative of the results
that may be expected for the full fiscal year. The financial statements included
herein should be read in conjunction with the financial statements and notes
thereto included in the Company's 1999 Form 10-K.
Effective July 1, 1999, Utility Group reorganized into a holding
company structure. This reorganization resulted in the creation of the Company
as a new holding company. Pursuant to the reorganization, the Company became the
owner of all of Utility Group's outstanding common stock. Holders of Utility
Group's existing common stock and two series of preferred stock exchanged their
stock in Utility Group for stock in the Company. Shares of preferred stock in
three series that did not approve the reorganization were redeemed for $5.7
million. The reorganization had no impact on the Company's Consolidated
Financial Statements because the reorganization was accounted for similarly to a
pooling of interest.
3
<PAGE>
CLECO CORPORATION
CONSOLIDATED INTERIM STATEMENTS OF INCOME
FOR THE THREE MONTHS ENDED SEPTEMBER 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
2000 1999
---- ----
<S> <C> <C>
OPERATING REVENUES
Retail electrical operations $ 203,144 $ 157,939
Energy marketing and tolling operations 66,192 126,231
Other operations 4,340 1,465
----------- -----------
Gross operating revenue 273,676 285,635
Less: retail electric customer credits 8 200
----------- -----------
Total operating revenue 273,668 285,435
----------- -----------
OPERATING EXPENSES
Fuel used for electric generation 53,605 49,462
Power purchased for utility customers 54,381 17,770
Purchases for energy marketing operations 27,818 114,244
Other operation 40,567 24,015
Maintenance 11,390 9,672
Depreciation 15,811 12,785
Taxes other than income taxes 10,291 9,798
----------- -----------
Total operating expenses 213,863 237,746
----------- -----------
OPERATING INCOME 59,805 47,689
Allowance for other funds used during construction 3 431
Other income and expenses, net 1,992 (525)
----------- -----------
INCOME BEFORE INTEREST CHARGES 61,800 47,595
Interest charges, including amortization of 14,647 7,324
debt expenses, premium and discount
Allowance for borrowed funds used during construction 12 292
----------- -----------
NET INCOME BEFORE INCOME TAXES AND 47,141 39,979
PREFERRED DIVIDENDS
Federal and state income taxes 16,998 14,364
----------- -----------
NET INCOME BEFORE PREFERRED DIVIDENDS 30,143 25,615
Preferred dividend requirements, net 466 463
----------- -----------
NET INCOME APPLICABLE TO COMMON STOCK $ 29,677 $ 25,152
============ ===========
AVERAGE SHARES OF COMMON STOCK OUTSTANDING
Basic 22,488,037 22,505,311
Diluted 23,831,122 23,842,136
EARNINGS PER AVERAGE SHARE
Basic $ 1.32 $ 1.12
Diluted $ 1.26 $ 1.07
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.425 $ 0.415
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED INTERIM
FINANCIAL STATEMENTS.
4
<PAGE>
CLECO CORPORATION
CONSOLIDATED INTERIM STATEMENTS OF INCOME
FOR THE NINE MONTHS ENDED SEPTEMBER 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
2000 1999
---- ----
<S> <C> <C>
OPERATING REVENUES
Retail electrical operations $ 462,168 $ 389,278
Energy marketing and tolling operations 131,520 243,989
Other operations 12,080 1,465
----------- -----------
Gross operating revenue 605,768 634,732
Less: retail electric customer credits 1,233 5,100
----------- -----------
Total operating revenue 604,535 629,632
----------- -----------
OPERATING EXPENSES
Fuel used for electric generation 127,654 103,343
Power purchased for utility customers 94,425 52,966
Purchases for energy marketing operations 71,763 230,266
Other operation 97,062 57,546
Maintenance 27,112 23,535
Depreciation 40,762 37,747
Taxes other than income taxes 28,628 27,531
----------- -----------
Total operating expenses 487,406 532,934
----------- -----------
OPERATING INCOME 117,129 96,698
Allowance for other funds used during construction 657 547
Other income and expenses, net 3,229 (1,165)
----------- ------------
INCOME BEFORE INTEREST CHARGES 121,015 96,080
Interest charges, including amortization of
debt expenses, premium and discount 34,005 21,201
Allowance for borrowed funds used during construction (226) 108
------------ -----------
NET INCOME BEFORE INCOME TAXES,
PREFERRED DIVIDENDS AND EXTRAORDINARY ITEM 87,236 74,771
Federal and state income taxes 29,957 26,375
----------- -----------
NET INCOME BEFORE PREFERRED DIVIDENDS AND EXTRAORDINARY ITEM 57,279 48,396
Extraordinary item, net of income taxes 2,508 -
----------- -----------
NET INCOME BEFORE PREFERRED DIVIDENDS 59,787 48,396
Preferred dividend requirements, net 1,400 1,510
----------- -----------
NET INCOME APPLICABLE TO COMMON STOCK $ 58,387 $ 46,886
=========== ===========
AVERAGE SHARES OF COMMON STOCK OUTSTANDING
Basic 22,467,360 22,511,703
Diluted 23,801,939 23,861,981
EARNINGS PER AVERAGE SHARE
Basic
Income before extraordinary item $ 2.49 $ 2.08
Net income applicable to common stock $ 2.60 $ 2.08
Diluted
Income before extraordinary item $ 2.40 $ 2.02
Net income applicable to common stock $ 2.51 $ 2.02
CASH DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 1.265 $ 1.235
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED INTERIM
FINANCIAL STATEMENTS.
5
<PAGE>
CLECO CORPORATION
CONSOLIDATED INTERIM BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands)
At At
September 30, 2000 December 31, 1999
------------------ -----------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $ 26,110 $ 25,161
Accounts receivable, net 115,540 47,213
Unbilled revenues 29,970 20,816
Fuel inventory, at average cost 7,269 10,461
Materials and supplies inventory, at average cost 15,527 14,768
Assets for sale - 2,466
Accumulated deferred fuel 10,643 -
Other current assets 6,599 4,475
----------- ----------
Total current assets 211,658 125,360
----------- ----------
Equity investment in investee 51,779 -
----------- ----------
Property, plant and equipment
Property, plant and equipment 1,804,461 1,567,155
Accumulated depreciation (592,296) (555,675)
------------ ----------
Net property, plant and equipment 1,212,165 1,011,480
Construction work-in-progress 42,085 187,988
----------- ----------
Total property, plant and equipment, net 1,254,250 1,199,468
----------- -----------
Other assets 2,940 4,225
Prepayments 13,542 6,427
Restricted cash 65,588 77,251
Regulatory assets - deferred taxes 70,890 70,833
Other deferred charges 45,325 38,213
Accumulated deferred federal and state income taxes 50,714 55,705
----------- ----------
TOTAL ASSETS $ 1,766,686 $1,577,482
=========== ==========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED
INTERIM FINANCIAL STATEMENTS.
(Continued on next page)
6
<PAGE>
CLECO CORPORATION
CONSOLIDATED INTERIM BALANCE SHEETS (CONTINUED)
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share amounts)
At At
September 30, 2000 December 31, 1999
------------------ -----------------
<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ 75,193 $ 25,989
Long-term debt due within one year 29,722 27,374
Accounts payable 70,555 74,700
Retainage 8,755 7,733
Accrued Payroll 2,403 -
Customer deposits 20,503 20,326
Taxes accrued 33,492 4,786
Interest accrued 6,280 9,634
Accumulated deferred fuel - 2,638
Other current liabilities 7,523 5,263
----------- -----------
Total current liabilities 254,426 178,443
Deferred credits
Accumulated deferred federal and state income taxes 264,916 252,846
Accumulated deferred investment tax credits 24,688 25,994
Regulatory liabilities - deferred taxes 38,840 38,337
Other deferred credits 39,560 49,722
----------- -----------
Total deferred credits 368,004 366,899
Long-term debt, net 659,845 579,595
----------- -----------
Total liabilities 1,282,275 1,124,937
----------- -----------
Shareholders' equity
Preferred stock
Not subject to mandatory redemption 28,090 28,880
Deferred compensation related to preferred stock held by ESOP (13,123) (14,991)
----------- -----------
Total preferred stock not subject to mandatory redemption 14,967 13,889
Common shareholders' equity
Common stock, $2 par value, authorized 50,000,000 shares,
issued 22,531,870 shares at September 30, 2000
and December 31, 1999 45,064 45,064
Premium on capital stock 112,075 112,733
Long-term debt payable in Company's common stock 519 1,036
Retained earnings 312,927 282,825
Treasury stock, at cost, 37,166 and 90,094 shares at
September 30, 2000 and December 31, 1999, respectively (1,141) (3,002)
----------- -----------
Total common equity 469,444 438,656
----------- -----------
Total shareholders' equity 484,411 452,545
----------- -----------
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $1,766,686 $1,577,482
=========== ===========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED
INTERIM FINANCIAL STATEMENTS.
7
<PAGE>
CLECO CORPORATION
CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
FOR THE NINE MONTHS ENDED SEPTEMBER 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands)
2000 1999
---- ----
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income before preferred dividends $ 59,787 $ 48,396
Adjustments to reconcile net income to net
cash used in operating activities
Depreciation and amortization 41,699 38,213
Allowance for funds used during construction (883) (439)
Amortization of investment tax credits (1,306) (1,343)
Deferred income taxes 5,753 (1,616)
Deferred fuel costs (13,281) (5,391)
Extraordinary gain, net of income tax (2,508) -
Gain on disposition of plant, net - (108)
Changes in assets and liabilities
Accounts receivable, net (68,327) (81,405)
Unbilled revenues (9,154) (7,810)
Fuel inventory, materials and supplies 2,433 (8,298)
Accounts payable (720) 55,883
Customer deposits 177 (6)
Other deferred accounts (6,252) 3,338
Taxes accrued 27,238 31,377
Interest accrued (3,354) (5,170)
Other, net (72) 4,917
------------ ------------
Net cash provided by operating activities 31,230 70,538
------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to property, plant and equipment (91,641) (114,262)
Allowance for funds used during construction 883 439
Proceeds from sale of property, plant and equipment 303 208
Equity investment in investee (50,845) -
Purchase of Investments - (240)
------------ ------------
Net cash used in investing activities (141,300) (113,855)
------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock - 243
Reacquisition of common stock - (1,545)
Cash transferred from restricted account 11,663 -
Increase in short-term debt, net 48,749 61,146
Retirement of long-term obligations (29,780) (10,639)
Issuance of long-term debt 110,216 50,652
Redemption of preferred stock - (6,518)
Dividends paid on common and preferred stock, net (29,829) (29,303)
------------ ------------
Net cash provided by financing activities 111,019 64,036
------------ ------------
NET INCREASE IN CASH AND CASH EQUIVALENTS 949 20,719
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 25,161 19,457
------------ ------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $26,110 $40,176
============ ============
Supplementary cash flow information
Interest paid (net of amount capitalized) $ 36,276 $ 28,751
============ ==========
Income taxes paid $ 19,250 $ 10,422
============ ==========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED
INTERIM FINANCIAL STATEMENTS.
8
<PAGE>
CLECO CORPORATION
NOTES TO CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(UNAUDITED)
NOTE A. RECLASSIFICATION
Certain prior-period amounts have been reclassified to conform with the
presentation shown in the current year's consolidated financial statements of
the Company and its subsidiaries. These reclassifications had no effect on net
income applicable to common stock or common shareholders' equity.
NOTE B. SIGNIFICANT ACCOUNTING POLICIES
The Company considers the Evangeline Tolling Agreement to be an
operating lease as defined by SFAS No. 13 and SFAS No. 29 because of William's
ability to control the use of the plant for the next 20 years. The Evangeline
Tolling Agreement contains a monthly shaping factor which provides for a greater
portion of annual revenue to be received by the Company during the summer
months, which is designed to coincide with the physical usage of the plant. SFAS
No. 13 generally requires lessors to recognize revenue using a straight-line
approach unless another rational allocation of the revenue is more
representative of the pattern in which the leased property is employed. The
Company believes that the recognition of revenue pursuant to the monthly shaping
factor is a rational allocation method, which better reflects the expected usage
of the plant. Certain provisions of the Evangeline Tolling Agreement, such as
bonuses, are considered contingent rents as defined by SFAS No. 29. Contingent
rents are recorded as revenue in the period in which the contingency is met.
Revenue is subject to be reduced by certain penalty clauses contained in the
Evangeline Tolling Agreement. At September 30, 2000, Management has determined
that the penalties are remote and revenue was not reduced by penalties.
NOTE C. LEGAL PROCEEDING: FUEL SUPPLY - LIGNITE
Utility Group and SWEPCO, each a 50% owner of Dolet Hills Unit 1, jointly
own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982,
Utility Group and SWEPCO entered into the LMA with the DHMV, a partnership for
the mining and delivery of lignite from a portion of these reserves (Dolet Hills
Mine). The LMA expires in 2011. The price of lignite delivered pursuant to the
LMA is a base price per ton, subject to escalation based on certain inflation
indices, plus specified "pass-through" costs.
Currently, Utility Group is receiving annually a minimum delivery of
1,750,000 tons under the LMA. Since the late 1980s, additional spot lignite
deliveries have been obtained through competitive bidding from DHMV and another
lignite supplier. In 1999, Utility Group and SWEPCO received deliveries which
approximated 25% of the annual lignite consumption at the Dolet Hills Unit 1
from the other lignite supplier.
On April 15, 1997, Utility Group and SWEPCO filed the Federal Court Suit
against DHMV and its partners seeking to enforce various obligations of DHMV to
Utility Group and SWEPCO under the LMA, including provisions relating to the
quality of the delivered lignite, pricing, and mine reclamation practices. On
June 15, 1997, DHMV filed an answer denying the allegations in Utility Group's
suit and filed a counterclaim asserting various contract-related claims against
Utility Group and SWEPCO. Utility Group and SWEPCO have denied the allegations
in the counterclaims.
9
<PAGE>
As a result of the counterclaims filed by DHMV in the Federal Court Suit,
on August 13, 1997, Utility Group and SWEPCO filed the State Court Suit against
the parent companies of DHMV, namely Jones Capital Corporation and Philipp
Holzmann USA, Inc. The State Court Suit seeks to enforce a separate 1995
agreement by Jones Capital Corporation and Philipp Holzmann USA, Inc. related to
the LMA. Jones Capital Corporation and Philipp Holzmann USA, Inc. have asked the
state court to stay that proceeding until the Federal Court Suit is resolved.
On March 1, 2000, the court in the Federal Court Suit ruled that DHMV was
not in breach of certain financial covenants under the LMA and denied Utility
Group's and SWEPCO's claim to terminate the LMA on that basis. The ruling has no
material adverse effect on the operations of Utility Group and does not affect
the other claims scheduled for trial. Utility Group and SWEPCO have appealed the
federal court's ruling to the United States Court of Appeals for the Fifth
Circuit.
The civil, nonjury trial in the Federal Court Suit was to have commenced
on May 22, 2000. However, on April 20, 2000, all parties jointly requested that
the court postpone the trial date and grant a 120-day stay of all matters before
the trial court to give the parties an opportunity to attempt to reach an
amicable resolution of the litigation. A preliminary memorandum of understanding
to settle the litigation has been executed among Utility Group, SWEPCO, and
DHMV. The memorandum of understanding, however, is subject to several conditions
precedent that are not yet fulfilled, including prior authorization by the LPSC
of favorable rate recovery of the settlement by Utility Group and SWEPCO. The
federal court granted the motion, stayed the action at the trial court and
postponed the trial commencement date to October 23, 2000. At a status
conference held on July 12, 2000, the court extended the stay of the proceedings
and again postponed the trial date to January 16, 2001. Settlement negotiations
are on-going during the pendency of the stay.
Should settlement discussions be unsuccessful, Utility Group and SWEPCO
will continue aggressively to prosecute the claims against DHMV and defend
against the counterclaims that DHMV has asserted. Utility Group and SWEPCO
continue to pay DHMV for lignite delivered pursuant to the LMA. Normal
day-to-day operations continue at the Dolet Hills Mine and Dolet Hills Unit 1.
Although the ultimate outcome of this litigation or the settlement negotiations
cannot be predicted at this time, based on information currently available to
the Company, management does not believe that the outcome of the Federal Court
Suit or any settlement in the Federal Court Suit will have a material adverse
effect on the Company's financial position or results of operations.
NOTE D. EXTRAORDINARY GAIN
In March 2000, Four Square Gas, a wholly owned subsidiary of Energy,
which is 98% owned by Midstream, paid a third party $2.1 million for a note with
a face value of approximately $6.0 million issued by Four Square Production,
another wholly owned subsidiary of Energy. The note relates to the production
assets held by Four Square Production which were classified as assets available
for sale, described in "Note E. Assets Held for Sale," below. As part of the
transaction, the third-party debtholder sold the note, associated mortgage, deed
of trust
10
<PAGE>
and pledge agreement and assigned a 5% overriding royalty interest in the
production assets to Four Square Gas. Four Square Gas paid, in addition to the
$2.1 million, a total of 4.5% in overriding royalty interest in the production
assets. Four Square Gas borrowed the $2.1 million from the Company. The gain of
approximately $3.9 million was offset against the income tax related to the gain
of approximately $1.4 million to arrive at the extraordinary gain, net of income
tax, of approximately $2.5 million. For the nine months ended September 30,
2000, the extraordinary gain, net of income tax, had a basic and diluted
earnings per share impact of $0.11.
NOTE E. ASSETS HELD FOR SALE
Certain oil and gas properties held by Energy were previously
identified as "Assets Held for Sale" and were accounted for in accordance with
the provisions of EITF Consensus No. 87-11, "Allocation of Purchase Price to
Assets to Be Sold." As of September 30, 2000, the Company has discontinued
actively searching for a buyer for these assets, resulting in the
reclassification of the book value of the assets to property, plant and
equipment. Long-term debt of approximately $6.0 million relating to the
acquisition of the oil and gas properties was purchased by an affiliate as
described in "Note D. Extraordinary Gain," above.
NOTE F. DISCLOSURES ABOUT SEGMENTS
The Company has determined that its reportable segments are based on
the Company's method of internal reporting, which disaggregates its business
units by first-tier subsidiary. Reportable segments were determined by applying
SFAS No. 131. The Company's reportable segments are Utility Group and Midstream.
The Other segment consists of costs within the parent company, costs within a
shared services subsidiary, start-up costs associated with a retail services
subsidiary, activities of UtiliTech and revenue and expenses associated with an
investment subsidiary. These subsidiaries operate within Louisiana, Delaware and
several states bordering Louisiana. In previous reporting periods, UtiliTech was
a separate reportable segment. However, management has determined that UtiliTech
does not meet the quantitative thresholds of a reportable segment as defined by
SFAS No. 131. UtiliTech is included in the Other segment. All previous reporting
periods presented have been adjusted to reflect the change in reportable
segments.
Each reportable segment engages in business activities from which it
earns revenues and incurs expenses. Segment managers report at least monthly to
the Company's CEO (the chief decision maker) with discrete financial information
and present quarterly discrete financial information to the Company's Board of
Directors. Budgets were prepared by each reportable segment for 2000, which were
presented to, and approved by, the Company's Board of Directors. The reportable
segments exceeded the quantitative thresholds as defined in SFAS No. 131.
The financial results of the Company's segments are presented on an
accrual basis. Significant differences among the accounting policies of the
segments as compared to the Company's consolidated financial statements
principally involve the classification of revenue and expense between operating
and other. Management evaluates the performance of its segments and allocates
resources to them based on segment profit (loss) before income taxes and
preferred stock dividends. In the first six months of 1999, Midstream and the
Other segment reported profit(loss) as other income (expense) within Utility
Group. For purposes of this
11
<PAGE>
footnote, gross amounts of revenue and expenses are reported on the appropriate
line. The Unallocated Items, Reclassifications & Eliminations column
reclassifies the items of revenue and expense recorded under the equity method
to other income (expense). Material intersegment transactions occur on a regular
basis.
The tables below present information about the reported operating
results and net assets of the Company's reportable segments.
12
<PAGE>
SEGMENT INFORMATION
FOR THE QUARTER ENDING SEPTEMBER 30
(In Thousands)
<TABLE>
<CAPTION>
Unallocated
Items,
Reclassifications
Utility &
2000 Group Midstream Others Eliminations Consolidated
---- ----- --------- ------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues
Retail electric operations $ 203,144 - - - $ 203,144
Energy marketing operations 2,592 $ 63,600 - - 66,192
Other operations - (229) $ 4,569 - 4,340
Customer credits (8) - - - (8)
---------- --------- --------- ---------- ----------
Total operating revenue $ 205,728 $ 63,371 $ 4,569 - $ 273,668
========== ========= ========= =========== ==========
Intersegment revenue $ 605 $ 9,703 $ 27,479 $ (37,787) -
Segment profit (loss) (1) $ 31,023 $ 18,861 $ (2,743) - $ 47,141
Segment assets at 9/30/00 $1,309,825 $ 408,085 $ 384,809 (336,033) $1,766,686
Segment profit $ 47,141
(1) Reconciliation of segment profit to
consolidated profit Unallocated items
Income taxes 16,998
Preferred dividends 466
----------
$ 29,677
==========
1999
Revenues
Retail electric operations $ 157,939 - - - $ 157,939
Energy marketing operations 113,474 $ 13,904 - $ (1,147) 126,231
Other operations - - $ 1,465 - 1,465
Customer credits (200) - - - (200)
---------- --------- --------- --------- ----------
Total operating revenue $ 271,213 $ 13,904 $ 1,465 $ (1,147) $ 285,435
========== ========= ========= ========= ==========
Intersegment revenue $ 4,259 $ 4,365 $ 14,896 $ (23,365) -
Segment profit (loss) (1) $ 36,321 $ 3,508 $ 150 - $ 39,979
Segment assets at 12/31/1999 $1,525,570 $ 153,321 $356,810 $(346,821) $1,688,880
Segment profit $ 39,979
(1) Reconciliation of segment profit to
consolidated profit
Unallocated items
Income taxes 14,364
Preferred dividends 463
----------
$ 25,152
==========
</TABLE>
13
<PAGE>
SEGMENT INFORMATION
FOR THE NINE MONTHS ENDING SEPTEMBER 30
(In Thousands)
<TABLE>
<CAPTION>
Unallocated Items,
Reclassifications
Utility &
2000 Group Midstream Others Eliminations Consolidated
---- ----- --------- ------ ------------ ------------
<S> <C> <C> <C> <C> <C>
Revenues
Retail electric operations $ 462,168 - - - $ 462,168
Energy marketing operations 13,000 $ 118,520 - - 131,520
Other operations - 336 $ 11,744 - 12,080
Customer credits (1,233) - - - (1,233)
----------- --------- -------- ---------- -----------
Total operating revenue $ 473,936 $ 118,856 $ 11,744 - $ 604,535
========== ========= ======== ========== ==========
Intersegment revenue $ 7,781 $ 29,585 $ 76,980 $ (114,346) -
Segment profit (loss) before
Extraordinary item (1) $ 75,264 $ 18,649 $ (6,677) - $ 87,236
Segment profit (loss) (2) $ 75,264 $ 21,157 $ (6,677) - $ 89,744
Segment profit $ 89,744
(1) Reconciliation of segment profit
to consolidated profit
Unallocated items
Income taxes 29,957
Preferred dividends 1,400
----------
$ 58,387
==========
(2) Includes extraordinary gain, net of income tax
1999
Revenues
Retail electric operations $ 389,278 - - - $ 389,278
Energy marketing operations $ 230,418 $ 14,846 - $ (1,275) $ 243,989
Other operations - - $ 3,559 $ (2,094) $ 1,465
Customer credits $ (5,100) - - - $ (5,100)
----------- -------- -------- -------- -----------
Total operating revenue $ 614,596 $ 14,846 $ 3,559 $ (3,369) $ 629,632
========== ======== ======== ========= ==========
Intersegment revenue $ 4,259 $ 5,954 $ 16,302 $(26,515) -
Segment profit (loss) before
extraordinary item (1) $ 71,112 $ 2,567 $ 928 $ 164 $ 74,771
Segment profit (loss) $ 71,112 $ 2,567 $ 928 $ 164 $ 74,711
Segment profit $ 74,771
(1) Reconciliation of segment profit
to consolidated profit Unallocated items
Income taxes 26,375
Preferred dividends 1,510
-----------
$ 46,886
===========
</TABLE>
NOTE G. EVANGELINE PROJECT CONSTRUCTION
On July 8, 2000, Unit #7 of the Evangeline power plant was declared in
commercial operation. The other unit at the plant, Unit #6, was declared in
commercial operation during June 2000. Revenues and operating expenses
associated with Unit #7 prior to July 8 are reflected in construction work in
progress on the Company's consolidated interim balance sheet.
14
<PAGE>
Revenues and operating expenses relating to both units are reflected on the
Company's consolidated interim statement of income after they were declared in
commercial operation.
NOTE H. OPTIONS ON COMMON STOCK
In July 2000, the Company granted basic and premium non-qualified stock
options under its 2000 Long-Term Incentive Compensation Plan to directors and
key employees. Basic options have an exercise price approximately equal to the
fair market value of the stock at grant date. Premium options have three
exercise prices that are above the fair market value of the stock at grant date.
Both types of options granted in July 2000 vest one-third each year beginning on
the third anniversary of the grant date and expire after ten years. In
accordance with APB No. 25, the Company has not recognized any compensation
expense for the stock options granted.
NOTE I. EARNINGS PER SHARE
During 1999 and 2000, the Company granted basic and premium
non-qualified stock options under its incentive compensation plans. The 54,000
premium options granted in 2000 were considered antidilutive during the
three-month and nine-month periods ended September 30, 2000, as defined by SFAS
No. 128, and were excluded from the calculation of diluted earnings per share.
NOTE J. RESTRICTED CASH
Restricted cash represents cash to be used for specific purposes.
Approximately $15 million in restricted cash represents deposits into an escrow
account for credit support as required by a provision of the Evangeline Tolling
Agreement between Evangeline and Williams. The credit support is to be
maintained as security for the performance of certain obligations by Evangeline
in regard to the Evangeline Tolling Agreement. Upon the fulfillment of certain
conditions specified in the agreement, the credit support can be reduced to $13
million. The remaining $50.6 million of restricted cash consists of the
remaining proceeds from the sale of Evangeline senior secured bonds, a $38.6
million equity infusion from Midstream and cash received from Williams pursuant
to the Evangeline Tolling Agreement. The construction of the project is
substantially complete and the plant has begun commercial operation. However,
the $50.6 million of restricted cash remains restricted under the bond indenture
until certain of its provisions are met.
NOTE K. EQUITY INVESTMENT IN INVESTEE
Equity investment in investee represents Midstream's approximately $51.8
million investment in APP. APP is a joint venture 50% owned by Midstream and 50%
owned by Calpine Corporation. APP was formed in order to construct, own and
operate a 1,000 MW, natural gas-fired electric plant to be located near Eunice,
Louisiana. The Company reports its investment in APP on the equity method of
accounting as defined in APB No. 18.
Midstream's member's equity as reported in the unaudited interim balance
sheet of APP at September 30, 2000 was $50.8 million. The majority of the
difference of $1.0 million between
15
<PAGE>
the equity investment in investee and the member's equity was the interest
capitalized on funds used to contribute to APP as required by SFAS No. 58.
NOTE L. PROCEEDINGS BEFORE THE LPSC
Several Louisiana-based contractors providing utility line construction
services instituted a proceeding via petition with the LPSC on April 9, 1999
alleging subsidization by Utility Group to a non-regulated affiliate, Cleco
Services LLC, now operating as UtiliTech. The LPSC has assigned Docket No
U-24064 to the complaint. The complainants, LPSC staff and Utility Group have
conducted discovery, pre-filed testimony has been prepared and depositions
taken. On September 6, 2000, Utility Group and the complainants signed an
agreement to settle the dispute. The terms of the settlement did not result in a
material impact to the Company's results of operations or financial condition.
In connection with this proceeding, LPSC staff has engaged the services
of an outside consultant. The outside consultant has filed testimony on behalf
of the LPSC staff identifying several possible ratemaking adjustments to the
Company's previous and future Rate Stabilization Plan filings that could affect
Utility Group's customer credits. On October 3, 2000, Utility Group and the
staff of the LPSC signed an agreement resolving all outstanding issues, which
the LPSC approved on November 2, 2000. The settlement resulted in an increase
to Utility Group's customer credits of approximately $500,000, which will be
paid to Utility Group's customers in September 2001.
NOTE M. LDEQ LITIGATION
In August 2000, two lawsuits were filed in the 19th Judicial District
Court in Baton Rouge, Louisiana against LDEQ, seeking the modifications or
reversal of the air and water permits issued by LDEQ on APP's Acadia project.
The plaintiffs in both suits allege that LDEQ did not follow proper procedure in
granting the air and water permits. APP, the project entity of which the Company
has a 50% interest, has intervened in both matters to protect its interests.
The two lawsuits have been consolidated for hearing. The proceeding is
in its preliminary stages, and no hearing date has been set. Although management
is unable to predict the outcome of this proceeding, management believes that
ultimately LDEQ will be found to have acted properly in issuing the permits and
that the proceeding will not have a material adverse effect on the Company's
financial position or results of operations.
NOTE N. NEW ACCOUNTING STANDARD
Periodically the FASB issues Statements of Financial Accounting
Standards. These statements reflect accounting, reporting and disclosure
requirements the Company should follow in the accumulation of financial data and
in the presentation of financial statements. The FASB, a nongovernmental
organization, is the primary source of generally accepted accounting principles
within the United States.
16
<PAGE>
In 1998, the FASB issued SFAS No. 133, which established accounting and
reporting standards requiring that every derivative instrument (including
certain derivatives embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value. This statement
requires that changes in the derivative's fair value be recognized in current
earnings, unless effective accounting criteria are met, where changes in the
fair value of the derivative would be recorded in other comprehensive income in
the equity section of the balance sheet. In June 1999, the FASB issued SFAS No.
137, which deferred the effective start date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which
amended SFAS No. 133.
The Company will implement the requirements of these accounting
standards effective January 1, 2001. In early 2000, the Company organized a
cross-functional project team for the implementation of SFAS No. 133, as
amended. The team has completed an inventory of the majority of the Company's
financial instruments, commodity contracts and other commitments and has
assessed the Company's derivative-related transactions identified in this
inventory. This assessment led to the determination that Utility Group and
Midstream are both expected to be impacted by this standard.
Utility Group
Utility Group has entered into certain forward and option contracts for
the future purchase or sale of electricity and natural gas that meet the
derivative criteria of SFAS No. 133, as amended. Utility Group currently records
changes in the fair value (mark-to-market), due to changes in the underlying
commodity prices, for certain of these contracts in current earnings. These
changes are influenced by various market factors, including weather and the
availability of regional electric generation and transmission capacity. The team
expects that application of SFAS No. 133, as amended, will cause Utility Group
to reflect certain transactions in other comprensive income based on the
effectiveness of hedges. The team has not yet determined the amount of other
comprehensive income to be reflected on the statements of income and other
comprehensive income.
Midstream
CMT, a subsidiary of Midstream, engages in activities that are
considered "trading" as defined by EITF 98-10. All of CMT's positions are
currently being marked-to-market under the rules of EITF 98-10. As such,
implementation of SFAS No. 133, as amended, will not have an impact on the
current accounting procedures or results of CMT.
The implementation team is currently completing the assessment of the
impact of SFAS No. 133, as amended, on the operating results of Energy and
Evangeline, both of which are also subsidiaries of Midstream. Energy engages in
the wholesale marketing of natural gas and the production, gathering and
transmission of natural gas. Certain contracts between Energy and outside
parties involve forward purchases and sales that may be considered derivatives.
The proper accounting for these transactions under SFAS No. 133, as amended, is
currently under review, but is not expected to have a material effect on
reported results. Evangeline owns and operates a 750 MW wholesale electric
generating facility and "tolls" the output under the provisions of the
Evangeline Tolling Agreement. Provisions of the Evangeline Tolling Agreement
that
17
<PAGE>
contain derivative-type clauses are being assessed at this time. The effect of
accounting changes required by this standard for Evangeline will be reflected in
other comprehensive income.
NOTE P. SUBSEQUENT EVENT
On October 20, 2000, APP executed the Acadia Tolling Agreement with
Aquila Energy. Under the terms of the agreement, for 20 years Aquila will
provide the natural gas needed for 580 MW of the 1,000 MW capacity at the Acadia
facility and will have the right to own and market the electricity produced. APP
will collect a fee from Aquila for operating and maintaining the Acadia
facility.
18
<PAGE>
CLECO CORPORATION
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion and analysis should be read in combination
with the 1999 Form 10-K, the interim financial statements filed with the
Company's Forms 10-Q for the quarters ended March 31, 2000 and June 30, 2000 and
the interim financial statements and notes thereto contained elsewhere in this
Report.
DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS
This Report includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All statements other than
statements of historical fact included in this Report are forward-looking
statements. Although the Company believes that the expectations reflected in
such forward-looking statements are reasonable, such forward-looking statements
are based on numerous assumptions (some of which may prove to be incorrect) and
are subject to risks and uncertainties which could cause the actual results to
differ materially from the Company's expectations. In addition to any
assumptions and other factors referred to specifically in connection with these
forward-looking statements, the following list identifies some of the factors
that could cause the Company's actual results to differ materially from those
contemplated in any of the Company's forward-looking statements:
o the effects of competition in the power industry,
o legislative and regulatory changes affecting electric utilities,
o the weather and other natural phenomena,
o the operating performance of the facilities of Utility Group and Evangeline,
o and changes in general economic and business conditions, as well as other
factors discussed in this and the Company's other filings with the
Securities and Exchange Commission (Cautionary Statements).
All subsequent written and oral forward-looking statements attributable to the
Company or persons acting on its behalf are expressly qualified in their
entirety by the Cautionary Statements.
RESULTS OF OPERATIONS
FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2000
EARNINGS
Net income applicable to common stock totaled $29.7 million or $1.32
per basic average common share for the third quarter of 2000, as compared to
$25.2 million or $1.12 per basic average common share for the corresponding
period in 1999. Earnings increased due primarily to Evangeline Power Station's
first full quarter of operations. The increased earnings were
19
<PAGE>
partially offset by an increase in expansion of operations at UtiliTech and
lower earnings within Utility Group from decreased energy marketing operations
as compared to the same period in 1999.
CONSOLIDATED REVENUES
Operating revenues for the third quarter of 2000 decreased $11.8
million or 4.1% compared to the same period in 1999. This decrease was due
primarily to a $60.0 million decrease in energy marketing operations. Moderating
such decrease was a $45.2 million increase in retail electric operations, and an
increase in other operating revenues of $2.9 million. Changes in consolidated
revenues are further explained in the discussion of each segment of the Company
below.
UTILITY GROUP
<TABLE>
<CAPTION>
For the three months ended
September 30,
(In thousands)
Operating revenues: 2000 1999 Change
---- ---- ------
<S> <C> <C> <C>
Base $ 97,784 $ 92,173 6.1%
Fuel cost recovery 105,361 65,767 60.2%
Estimated customer credits (8) (200) (96.0)%
Energy marketing 2,592 113,473 (97.7)%
--------- ---------
Total operating revenues $ 205,729 $ 271,213 (24.1)%
========= =========
</TABLE>
Base revenues for the third quarter of 2000 increased $5.6 million
compared to the same period in 1999. The increase in base revenues was due
primarily to customer growth, warmer weather, and higher industrial customer
sales. KWh sales to residential customers increased 4.1% compared to the same
period in 1999. The increase in kWh sales to residential customers resulted from
an increase in cooling degree-days as compared to the same period in 1999. KWh
sales to industrial customers were 6.5% higher than the same period in 1999 due
to increased usage caused by increased production. Overall kWh sales to regular
customers during the third quarter of 2000 increased 3.4% over the third quarter
of 1999.
Fuel cost recovery revenues for the third quarter of 2000 increased
primarily from sales to residential customers, which increased $17.0 million,
and sales to industrial customers, which increased $8.8 million in relation to
the same period in 1999. The increase in fuel cost recovery revenues is related
to higher kWh sales and increased natural gas prices for the third quarter of
2000 compared to the same period in 1999. Changes in fuel costs have
historically had no effect on net income, as fuel costs are generally recovered
through fuel costs adjustment clauses that enable Utility Group to pass on to
customers substantially all changes in the cost of generating fuel and purchased
power. These adjustments are audited monthly and are regulated by the LPSC
(representing about 99% of the total fuel cost adjustment) and the FERC. Until
approval is received, the adjustments are subject to refund.
20
<PAGE>
An earnings review settlement was reached with the LPSC in 1996
pursuant to which accruals for estimated customer credits are sometimes
required. Based on an analysis of third quarter 2000 earnings, no such accrual
was found to be necessary for the third quarter whereas $0.2 million was accrued
in the third quarter of 1999. The amount of credit due customers, if any, is
determined by the LPSC annually based on 12-month ending results as of September
30 of each year. The calculation of the cycle ended September 30, 1999 was
increased by $0.5 million to be refunded to customers in September 2001 due to a
settlement of proceedings before the LPSC as discussed in Note L. to the notes
to the Consolidated Financial Statements, located elsewhere in this quarterly
report. Also see "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Financial Condition--Retail Rates of Utility Group"
in Item 7 of the 1999 Form 10-K for a discussion of the LPSC settlement.
Energy marketing revenues for the third quarter of 2000 decreased
$110.9 million as compared to the same period in 1999. The decrease is primarily
due to a reduced level of energy trading activity resulting from a refinement of
trading practice within Utility Group and from the transfer of specific CPS
generating assets to Evangeline. If Utility Group has excess electricity
capacity or excess natural gas at its power plants, CMT markets the excess on
Utility Group's behalf. CMT also develops a monthly gas procurement strategy for
Utility Group, giving priority to achieving a reliable supply of gas to fuel the
power plants, maintaining operational flexibility and cost of service in
developing the strategy.
Operating expenses decreased $66.1 million or 27% during the third
quarter of 2000 compared to the same period in 1999. The decrease in operating
expenses is primarily the result of a decrease in energy marketing expenses
partially offset by increased capacity charges and higher fuel costs. Energy
marketing expenses decreased $106.1 million compared to the same period in 1999
due to the same factors noted above for decreases in energy marketing revenues.
Offsetting the decrease in energy marketing expenses was an increase of $38.4
million in fuel and purchased power for retail utility operations due to the
increased kWh sales and increased energy prices primarily driven by increases in
natural gas prices as compared to the same period in 1999.
Utility Group purchases power from other electric power generators when
the price of the energy purchased is less than the cost to Utility Group of
generating such energy from its own facilities, or when Utility Group's
generating units are unable to provide electricity to satisfy its load.
Thirty-three percent of Utility Group's energy requirements during the third
quarter of 2000 were met with purchased power compared to 17% for the
corresponding period in 1999. The increase was caused by the replacement of the
CPS output with a power contract with Williams and to a lesser extent by outage
for maintenance at the Dolet Hills Power Station in 2000, both requiring Utility
Group to purchase more power in the third quarter of 2000 than it did in the
third quarter of 1999 to meet load requirements.
MIDSTREAM
Midstream revenues for the third quarter of 2000 were approximately
$63.4 million, an increase of $49.5 million over the third quarter of 1999. This
increase in revenues resulted primarily from a $49.7 million increase in energy
marketing and tolling revenue. Approximately $25.0 million of the increase in
energy marketing and tolling revenues is due to increased energy
21
<PAGE>
marketing and trading activity at CMT and Energy. CMT's increased marketing
activity is attributable to the fact that it's operations remained in an
incipient stage through the third quarter of 1999, as CMT did not start
operating until July 1, 1999. The remaining $25.8 million increase in energy
marketing and tolling revenues is due to Evangeline's first full quarter of
operations in the third quarter of 2000 and revenues earned pursuant to the
Evangeline Tolling Agreement.
Midstream operating expenses for the third quarter of 2000 were
approximately $42.1 million, an increase of $32.1 million over the third quarter
of 1999. The increase in expenses resulted primarily from a $18.0 million
increase in energy marketing expenses and an increase of $6.7 million in other
operations expense due to increased marketing activity in CMT and Energy in the
third quarter of 2000 as compared to the third quarter 1999. Operating expenses
relating to Evangline increased $6.2 million in the third quarter of 2000 as
compared to the third quarter of 1999 due to Evangline's first full quarter of
commercial operations in the third quarter of 2000. The increase in operating
expenses at Evangeline are due primarily to $2.0 million in depreciation
expense, $1.2 million in energy marketing expenses relating to replacement power
purchases under the Evangeline Tolling Agreement and an increase of $1.2 million
in other operations expense as compared to the third quarter of 1999.
COMPANIES IN THE OTHER SEGMENT
The other segment consists of the parent company, a shared services
subsidiary, a retail subsidiary, UtiliTech and an investment subsidiary.
Substantially all revenues for this segment are from UtiliTech.
Operating revenue for the companies in the other segment for the third
quarter of 2000 were approximately $4.6 million, a $3.1 million increase as
compared to the same period in 1999. The increase in revenue is due to the
expansion of UtiliTech to states other than Louisiana and to the increased
number of crews employed by UtiliTech.
Operating expenses for the companies in the other segment for the third
quarter of 2000 were approximately $6.8 million, an increase of approximately
$4.9 million as compared to the same period in 1999. The primary causes of the
increase in operating expenses are the costs of expanding operations of
UtiliTech and the costs of the shared services company which began operations on
January 1, 2000.
CONSOLIDATED INTEREST EXPENSE
Interest expense for the third quarter of 2000 increased $7.3 million
over the same period in 1999. The increase was due primarily to the interest
from the $218 million Evangeline senior secured bonds, interest from the $100
million Company senior unsecured notes and increased interest rates on
short-term debt. The Evangeline bonds were issued in November 1999. Interest on
interim financing relating to the construction of the Evangeline plant was
capitalized during the third quarter of 1999, whereas Evangeline was in
commercial operation during the third quarter of 2000. Interest during the third
quarter of 2000 is reflected on the income statement. The interest from the
notes was reported in the three months ended September 30, 2000 but not in the
same period of 1999.
22
<PAGE>
FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
EARNINGS
Net income before the extraordinary item discussed below totaled $55.9
million, or $2.49 per basic average common share, for the nine months ended
September 30, 2000, as compared to $46.9 million, or $2.08 per basic average
common share, for the corresponding period in 1999. Earnings before the
extraordinary item increased primarily due to an increase in earnings within
Utility Group from higher kWh sales as compared to the same period in 1999.
Earnings before extraordinary item also increased as a result of the first full
quarter of commercial operations for Evangeline power station. The increased
earnings from Utility Group and Evangeline were partially offset by an increase
in expenses relating to the expansion of operations at UtiliTech.
Net income applicable to common stock totaled $58.4 million, or $2.60
per basic average common share, for the nine months ended September 30, 2000, as
compared to $46.9 million or $2.08 per basic average common share for the
corresponding period in 1999. The increase in earnings resulted from an
extraordinary gain on extinguishment of debt and the first quarter of commercial
operations at Evangeline.
In March 2000, Four Square Gas, a wholly-owned subsidiary of Energy,
which is 98% owned by Midstream, paid a third party $2.1 million for a note with
a face value of approximately $6.0 million issued by Four Square Production,
another wholly owned subsidiary of Energy. The note relates to the production
assets held by Four Square Production that were classified as assets available
for sale. As a part of the transaction, the third-party debtholder sold the
note, associated mortgage, deed of trust and pledge agreement and assigned a 5%
overriding royalty interest in the production assets to Four Square Gas. Four
Square Gas paid, in addition to the $2.1 million, a total of 4.5% in overriding
royalty interest in the production assets. Four Square Gas borrowed the $2.1
million from the Company. The gain of approximately $3.9 million was offset
against the income tax related to the gain of approximately $1.4 million to
arrive at the extraordinary gain, net of income tax, of approximately $2.5
million. The extraordinary gain, net of income tax, had a basic and diluted
earnings per share impact of $0.11.
CONSOLIDATED REVENUES
Operating revenues for the nine months ended September 30, 2000
decreased $25.1 million or 4.0% compared to the same period in 1999. This
decrease was due primarily to a $112.5 million decrease in energy marketing
operations. The decrease in operating revenues was partially offset by a $72.9
million increase in retail electric operations, a $3.9 million decrease in
retail electric customer credits and an increase of $10.6 million in other
operations. Changes in consolidated revenues are further explained in the
discussion of each segment of the Company below.
23
<PAGE>
UTILITY GROUP
<TABLE>
<CAPTION>
For the nine months ended
September 30,
(In thousands)
Percent
Operating revenues: 2000 1999 Change
---- ---- ------
<S> <C> <C> <C>
Base $ 247,369 $ 237,360 4.2%
Fuel cost recovery 214,799 151,918 41.4%
Estimated customer credits (1,233) (5,100) (75.8)%
Energy marketing 13,000 230,418 (94.3)%
--------- ---------
Total Operating revenues $ 473,935 $ 614,596 (22.9)%
========= =========
</TABLE>
Total operating revenues for the nine months ended September 30, 2000
were 22.9% less the same period in 1999. The decrease in operating revenues was
due to a reduced level of trading activity, partially offset by higher base,
fuel and transmission revenues, along with increased customer ancillary charges
for disconnects and reconnects. Year-to-date base revenues were higher than the
same period in 1999 due to customer growth, warmer weather, and higher
industrial customer sales. KWh sales to residential customers increased 2.4%
compared to the same period in 1999, increasing base revenues for the nine
months ended September 30, 2000 by $2.4 million as compared to the same period
in 1999. KWh sales to industrial customers were 7.8% higher than the same period
in 1999 due to increased usage.
Fuel cost recovery revenues for the nine months ended September 30,
2000 increased primarily from sales to residential customers, which increased
$25.7 million, and sales to industrial customers, which increased $18.2 million
in relation to the same period in 1999. The increase in fuel cost recovery
revenues is related to higher kWh sales and increased natural gas prices for the
nine months ended September 30, 2000 compared to the same period in 1999.
Operating revenues for the nine months ended September 30, 2000 were
decreased by a $1.2 million accrual for estimated customer credits, which was a
$3.9 million decrease from the $5.1 million accrual recognized for the same
period in 1999. Accruals for estimated customer credits may be required under
terms of an earnings review settlement reached with the LPSC in 1996.
Energy marketing revenues for the nine months ended September 30, 2000
decreased $217.4 million as compared to the same period in 1999. We have seen a
reduction in energy marketing revenues in 2000 when compared with prior years
due to a reduced level of energy trading activities resulted from a refinement
of trading practices and from the transfer of certain CPS generating assets to
Evangeline.
Operating expenses decreased $146.9 million or 28.1% during the nine
months ended September 30, 2000 compared to the same period in 1999. The
decrease in operating expenses is primarily the result of a decrease in energy
marketing expenses, partially offset by increased capacity charges and higher
fuel costs. Energy marketing expenses decreased $213.7 million compared to the
same period in 1999 due to the same factors noted above for decreases in energy
24
<PAGE>
marketing revenues. Offsetting the decrease in energy marketing expenses was an
increase of $63.4 million in fuel and purchased power for retail utility
operations due to the increased kWh sales and increased energy prices.
Utility Group purchases power from other electric power generators when
the price of the energy purchased is less than the cost to Utility Group of
generating such energy from its own facilities, or when Utility Group's
generating units are unable to provide electricity to satisfy its load.
Thirty-five percent of Utility Group's energy requirements during the nine
months ended September 2000 were met with purchased power, compared to 30% for
the corresponding period in 1999. The increase was caused by increased kWh sales
in the first nine months of 2000 compared to the same period in 1999.
MIDSTREAM
Midstream revenues for the nine months ended September 30, 2000 were
approximately $118.8 million, an increase of $104.0 million over the same period
in 1999. This increase in revenues resulted primarily from a $103.9 million
increase in energy marketing and tolling revenues. Approximately $76.6 million
of the increase in energy marketing and tolling revenues is due to increased
energy marketing and trading activity at CMT and Energy. CMT's increased
marketing activity for the nine months ended September 30, 2000 as compared to
the same period in 1999 is attributable to the fact CMT did not start operating
until July 1, 1999. The remaining $27.3 million increase in energy marketing and
tolling revenues is due to Evangeline's first full quarter of operations in the
third quarter of 2000 and revenues earned pursuant to the Evangeline Tolling
Agreement.
Midstream operating expenses for the nine months ended September 30,
2000 were approximately $97.9 million, an increase of $83.8 million over the
same period in 1999. The increase in expenses resulted primarily from a $54.4
million increase in energy marketing expenses and an increase of $24.7 million
in other operations expense due to increased marketing activity in CMT and
Energy in the nine months ended September 30, 2000 as compared to the same
period in 1999. Operating expenses relating to Evangline increased $7.7 million
in the nine months ended September 30, 2000 as compared to the same period in
1999 due to Evangline's first full quarter of commercial operations in the third
quarter of 2000. The increase in operating expenses at Evangeline are due
primarily to $2.2 million in depreciation expense, $1.2 million in energy
marketing expenses relating to replacement power purchases under the Evangeline
Tolling Agreement and an increase of $2.4 million in other operations expense in
the nine months ended September 30, 2000 as compared to same period in 1999.
COMPANIES IN THE OTHER SEGMENT
Operating revenue for the companies in the other segment for the nine
months ended September 30, 2000 were approximately $11.7 million, a $8.2 million
increase as compared to the same period in 1999. The increase in revenue is due
to the expansion of UtiliTech to states other than Louisiana and to the
increased number of crews employed by UtiliTech.
Operating expenses for the companies in the other segment for the nine
months ended September 30, 2000 were approximately $17.3 million, an increase of
approximately $14.0
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<PAGE>
million as compared to the same period in 1999. The primary causes of the
increase in operating expenses are the costs of expanding operations of
UtiliTech and the costs of the shared services company that began operations on
January 1, 2000.
CONSOLIDATED INTEREST EXPENSE
Interest expense for the nine months ended September 30, 2000 increased
$12.5 million over the same period in 1999. The increase was due primarily to
the interest from the $218 million Evangeline senior secured bonds, interest
from the $100 million Company senior unsecured notes and increased interest
rates on short-term debt. The Evangeline bonds were issued in November 1999.
Interest on interim financing relating to the construction of the Evangeline
plant was capitalized during the third quarter of 1999, whereas Evangeline was
in commercial operation during the third quarter of 2000. Interest during the
third quarter of 2000 is reflected on the income statement. The interest from
the notes was reported in the three months ended September 30, 2000 but not in
the same period of 1999.
FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
At September 30, 2000 and December 31, 1999, there was $75.2 million and
$26.0 million, respectively, of short-term debt outstanding in the form of
commercial paper borrowings and bank loans. Guarantees issued by the Company to
third parties for certain types of transactions between those parties and the
Company's subsidiaries, other than Utility Group, will reduce the amount of the
$200 million in credit facilities available to the Company by an amount equal to
the stated or determinable amount of the primary obligation. In addition,
certain indebtedness incurred by the Company outside of the credit facilities
will reduce the amount of the credit facilities available to the Company. The
amount of such guarantees and other indebtedness totaled $33.4 million at
September 30, 2000. Uncommitted lines of credit with a bank totaling $5 million
are also available to meet short-term working capital needs.
At September 30, 2000, CLE Resources, Inc., an unregulated subsidiary of
the Company, held approximately $18.5 million of cash and temporary cash
investments in securities with original maturities of 90 days or less.
The $51.8 million reported as equity investment in investee represents
the amount of cash and other assets contributed to APP, which is in the process
of building the 1,000 MW Acadia power station. The contributions primarily have
been funded by the Company's $100 million five-year senior unsecured notes.
Management is currently seeking financing through the use of short-, medium-,
long-term debt or a combination of the three types of debt in order to replace
the funding from the Company's senior unsecured notes. Management expects to
finalize the financing in 2001.
REGULATORY MATTERS - RETAIL ELECTRIC COMPETITION
Forces driving increased competition in the electric utility industry
involve complex economic, technological, legislative and regulatory factors.
These factors have resulted in the
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<PAGE>
introduction of federal and state legislation and other regulatory initiatives
in various jurisdictions that are likely to produce even greater competition at
both the wholesale and retail levels in the future. The LPSC has been continuing
its investigation into whether retail choice is in the best interest of
Louisiana electric utility customers. During 1999, the LPSC directed its staff
to develop a transition to competition plan to be presented in January 2001.
Utility Group and a number of parties, including the other Louisiana electric
utilities, certain power marketing companies and various associations
representing industry and consumers, have been participating in electric
industry restructuring proceedings before the LPSC since 1997. Several
neighboring states have taken steps to initiate retail choice by 2002. At the
federal level, several bills, some with conflicting provisions, were introduced
this past year to promote a more competitive environment in the electric utility
industry. During the summer of 2000, the California electricity market, which
was the first U.S. electricity market to introduce full wholesale competition,
experienced shortages of capacity at peak periods. In response to the
dramatically higher prices experienced during the summer of 2000, as compared to
previous years, the price cap in the spot market was reduced significantly. A
number of groups in California have made proposals to re-regulate the provision
of wholesale power in the California market under traditional cost-of-service
regulation. While the situation in California has not led to a direct change in
plans in states other than California, it may influence future decisions and
plans in other states, including Louisiana. Management expects the debate
relating to customer choice of electricity providers and other related issues to
continue in legislative and regulatory bodies through the remainder of 2000 and
in 2001. At this time, the Company cannot predict whether any legislation or
regulation will be enacted or adopted during the remainder of 2000 or in 2001
and, if enacted, what form such legislation or regulation would take.
The regulatory requirement to serve customers and industry standards for
reliability of electric supply have resulted in the construction of facilities
sufficient, when combined with power purchased off-system, for Utility Group to
meet peak load conditions with a margin for reserve. With a potential
restructured regulatory environment and resulting customer choice of electricity
providers, costs associated with utility assets specifically dedicated to, or
used by, departing customers, such as Utility Group's generating plants and
power purchase contracts, would have to be paid by the departing customers
(stranded costs), absorbed by the remaining and new customers or written off by
Utility Group.
REGULATORY MATTERS - WHOLESALE ELECTRIC COMPETITION
The Energy Policy Act, enacted by Congress in 1992, significantly
changed U.S. energy policy, including regulations governing the electric utility
industry. The Energy Policy Act allows the FERC, on a case-by-case basis and
with certain restrictions, to order wholesale transmission access and to order
electric utilities to enlarge their transmission systems. The Energy Policy Act
prohibits FERC-ordered retail wheeling (I.E., opening up electric utility
transmission systems to allow customer choice of energy suppliers at the retail
level), including "sham" wholesale transactions. Further, under the Energy
Policy Act, a FERC transmission order requiring a transmitting utility to
provide wholesale transmission services must include provisions generally
permitting the utility to recover from the FERC applicant all of the costs
incurred in connection with the transmission services, including any enlargement
of the transmission system and any associated services.
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<PAGE>
In addition, the Energy Policy Act revised the 1935 Act to permit
utilities, including registered holding companies, and nonutilities to form
"exempt wholesale generators" without the principal restrictions of the 1935
Act. Under prior law, independent power producers were generally required to
adopt inefficient and complex ownership structures to avoid pervasive regulation
under the 1935 Act.
In 1996, the FERC issued Orders No. 888 and 889 requiring open access to
utilities' transmission systems. The open access provisions require
FERC-regulated electric utilities to offer third parties access to transmission
under comparable terms and conditions as the utilities' use of their own
systems. In addition, Order No. 888, as amended, provides for the full recovery
from a utility's departing customers of wholesale stranded costs, to the extent
such costs were prudently incurred to serve wholesale customers and would go
unrecovered if those customers used open access transmission service and moved
to another electricity supplier. Order No. 888, as amended, also allows
customers under existing wholesale sales contracts to seek FERC approval to
modify their contracts on a case-by-case basis. Because of the "grandfather"
provisions of Orders No. 888 and 889, most of our existing transmission
contracts are not affected by Orders No. 888 and 889. To date, the orders have
not had a material impact on our operations or financial condition.
In 1999, the FERC issued Order No. 2000, which further defines the
operation of utilities' transmission systems. Order No. 2000 establishes a
general framework for all transmission-owning entities in the nation to place
their transmission facilities under the control of appropriate Retail
Transmission Organizations (RTO). Although participation is voluntary, the FERC
has made it clear that any jurisdictional entity not participating in an RTO
will be subject to further regulatory steps. Current objectives state that all
electric utilities that own, operate or control interstate transmission
facilities should participate in an RTO that will be operational no later than
December 15, 2001. On October 16, 2000, Utility Group submitted a filing with
the FERC stating that it will likely join the Southwest Power Pool's (SPP) RTO
either as a member of the SPP Independent System Operator (ISO) or as part of
Entergy's Transco by December 15, 2001. The decision will be made once the
details of the transmission companies are finalized. The transfer of control of
Utility Group's transmission facilities to an RTO has the potential to
materially affect the Company's results of operations and financial condition.
Wholesale energy markets, including the market for wholesale electric
power, have been competitive and are becoming even more so as the number of
participants in these markets increases as a result of enactment of the Energy
Policy Act and the regulatory activities of the FERC.
FRANCHISES
Utility Group operates under nonexclusive franchise rights granted by
governmental units, such as municipalities and parishes (counties), and enforced
by state regulation. These franchises are for fixed terms, which vary from 10
years to 50 years. In the past, Utility Group has been substantially successful
in the timely renewal of franchises as each reaches the end of its term and
expires. Utility Group is currently negotiating with the City of Jeanerette for
franchise rights applicable to its approximately 3,000 customers. Utility
Group's franchise with the City of Opelousas, which has 10,873 customers, was
scheduled to expire August 2001. In November
28
<PAGE>
2000, Utility Group successfully negotiated a renewal of that franchise for a
term of ten years, beginning August 2001. Utility Group's franchises with the
cities of Washington and Franklinton, and their 1,891 and 2,484 customers
respectively, will be up for renewal in 2003. Utility Group was successful in an
October 7, 2000, referendum to renew its franchise agreement with the City of
New Iberia, where Utility Group currently serves 18,744 customers, for a term of
25 years.
No other franchises expire until 2008. A number of parishes have
attempted in recent years to impose franchise fees on retail revenues earned
within the unincorporated areas we serve. If the parishes are ultimately
successful, taxes other than income taxes could increase substantially in future
years.
REPOWERING PROJECT
On July 8, 2000, the Unit #7 of the Evangeline power plant was declared
in commercial operation. The other unit at the plant, Unit #6, was declared in
commercial operation during June 2000. Revenues and operating expenses
associated with Unit #7 prior to July 8 are reflected in construction work in
progress on the Company's consolidated interim balance sheet. Revenues and
operating expenses relating to both units are reflected on the Company's
consolidated interim statement of income after they were declared in commercial
operation.
NEW POWER PLANT
APP is in the process of constructing a new 1,000 MW, natural gas-fired
power plant near Eunice, Louisiana. Construction on the plant has begun, with a
projected completion date of mid-2002. Construction costs of the plant are
estimated to be approximately $500 million. As of September 30, 2000, APP has
spent approximately $100 million on constructing the plant. Permanent financing
has not been obtained, but several options are being investigated. APP is owned
50% by Midstream and 50% by Calpine Corporation. APP is being accounted for
using the equity method of accounting by the Company. As of September 30, 2000,
Midstream has contributed $50.8 million in cash and land to APP.
On October 20, 2000, APP executed the Acadia Tolling Agreement with
Aquila Energy. Under the terms of the agreement, for 20 years Aquila will
provide the natural gas needed for 580 MW of the 1,000 MW capacity at the Acadia
facility and will have the right to own and market the electricity produced. APP
will collect a fee from Aquila for operating and maintaining the Acadia
facility.
CONSTRAINTS ON PURCHASED POWER
In future years, Utility Group's generating facilities may not supply
enough electric power to meet its customers' growing demand (native load demand)
and it may need to purchase additional generating capacity and/or purchase power
to satisfy these needs. In March 2000, following a competitive bid process,
Utility Group entered into three contracts for firm electric capacity and energy
with Williams and Dynegy Power Marketing, Inc., for 605 MW of capacity in 2000,
increasing to 760 MW of capacity in 2004. These contracts were approved by the
LPSC in March 2000. Management expects the contracts, combined with Utility
Group's own
29
<PAGE>
generation resources or other power purchase agreements, to meet substantially
all of its native load demand through 2004. Because of its location on the
transmission grid, Utility Group relies on one main supplier of electric
transmission and is sometimes constrained as to the amount of purchased power it
can bring into its system. These three contracts were not affected by such
transmission constraints.
NEW ACCOUNTING STANDARD
Periodically the FASB issues Statements of Financial Accounting
Standards. These statements reflect accounting, reporting and disclosure
requirements the Company should follow in the accumulation of financial data and
in the presentation of financial statements. The FASB, a nongovernmental
organization, is the primary source of generally accepted accounting principles
within the United States.
In 1998, the FASB issued SFAS No. 133, which established accounting and
reporting standards requiring that every derivative instrument (including
certain derivatives embedded in other contracts) be recorded on the balance
sheet as either an asset or liability measured at its fair value. This statement
requires that changes in the derivative's fair value be recognized in current
earnings, unless effective accounting criteria are met, where changes in the
fair value of the derivative would be recorded in other comprehensive income in
the equity section of the balance sheet. In June 1999, the FASB issued SFAS No.
137, which deferred the effective start date of SFAS No. 133 to fiscal years
beginning after June 15, 2000. In June 2000, the FASB issued SFAS No. 138, which
amended SFAS No. 133.
The Company will implement the requirements of these accounting
standards effective January 1, 2001. In early 2000, the Company organized a
cross-functional project team for the implementation of SFAS No. 133, as
amended. The team has completed an inventory of the majority of the Company's
financial instruments, commodity contracts and other commitments and has
assessed the Company's derivative-related transactions identified in this
inventory. This assessment led to the determination that Utility Group and
Midstream are both expected to be impacted by this standard.
Utility Group
Utility Group has entered into certain forward and option contracts for
the future purchase or sale of electricity and natural gas that meet the
derivative criteria of SFAS No. 133, as amended. Utility Group currently records
changes in the fair value (mark-to-market), due to changes in the underlying
commodity prices, for certain of these contracts in current earnings. These
changes are influenced by various market factors, including weather and the
availability of regional electric generation and transmission capacity. The team
expects that application of SFAS No. 133, as amended, will cause Utility Group
to reflect certain transactions in other comprensive income based on the
effectiveness of hedges. The team has not yet determined the amount of other
comprehensive income to be reflected on the statements of income and other
comprehensive income.
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<PAGE>
Midstream
CMT, a subsidiary of Midstream, engages in activities that are
considered "trading" as defined by EITF 98-10. All of CMT's positions are
currently being marked-to-market under the rules of EITF 98-10. As such,
implementation of SFAS No. 133, as amended, will not have an impact on the
current accounting procedures or results of CMT.
The implementation team is currently completing the assessment of the
impact of SFAS No. 133, as amended, on the operating results of Energy and
Evangeline, both of which are also subsidiaries of Midstream. Energy engages in
the wholesale marketing of natural gas and the production, gathering and
transmission of natural gas. Certain contracts between Energy and outside
parties involve forward purchases and sales that may be considered derivatives.
The proper accounting for these transactions under SFAS No. 133, as amended, is
currently under review, but is not expected to have a material effect on
reported results. Evangeline owns and operates a 750 MW wholesale electric
generating facility and "tolls" the output under the provisions of the
Evangeline Tolling Agreement. Provisions of the Evangeline Tolling Agreement
that contain derivative-type clauses are being assessed at this time. The effect
of accounting changes required by this standard for Evangeline will be reflected
in other comprehensive income.
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<PAGE>
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The market risk inherent in the Company's market risk-sensitive
instruments and positions is the potential change arising from increases or
decreases in the short-, medium- and long-term interest rates, commodity prices
of electricity traded on the Into Entergy and the Into Cinergy exchanges, and
commodity prices of natural gas traded. Generally, Utility Group's market risk
sensitive instruments and positions are characterized as "other than trading";
however, Utility Group does have positions that are considered "trading" as
defined by EITF No. 98-10. All of CMT's positions are characterized as "trading"
under EITF No. 98-10. The Company's exposure to market risk, as discussed below,
represents an estimate of possible changes in the fair value or future earnings
that would occur, assuming possible future movements in the interest rates and
commodity prices of electricity and natural gas. The market risk estimates have
materially changed from those disclosed in Item 7A of the 1999 Form 10-K, which
Item is incorporated herein by reference. The material changes are presented
below.
INTEREST RATE RISKS
The Company has entered into various fixed- and variable-rate debt
obligations. The calculations of the changes in fair market value and interest
expense of the debt securities are made over a one-year period.
As of September 30, 2000, the carrying value of the Company's
short-term, variable-rate debt was approximately $75.2 million, which
approximates the fair market value. Each 1.0% change in the average interest
rates applicable to such debt would result in a change of approximately $0.8
million in the Company's pretax earnings.
The Company monitors its mix of fixed- and variable-rate debt
obligations in light of changing market conditions and from time to time may
alter that mix by, for example, refinancing balances outstanding under its
variable-rate commercial paper program with fixed-rate debt.
COMMODITY PRICE RISKS
CMT engages in marketing and trading of electricity and natural gas. CMT
has trades that are marked-to-market. The mark-to-market procedures may
introduce volatility to carrying values and to the Company's financial
statements. The Company has controls in place to help minimize the risks
involved in marketing and trading. Such controls include a risk management
committee comprised of senior management of the Company, the Company's risk
manager and the Company's internal audit personnel. The risk management
committee receives a daily risk report containing mark-to-market and VAR
analysis. The risk management committee has set parameters on the trading
activities, such as a ceiling on the daily VAR. The mark-to-market of trading
positions of CMT at September 30, 2000 was a loss of $2.0 million.
Utility Group had financial positions that were defined as "trading"
under EITF No. 98-10. Controls similar to the ones in place for CMT are in place
for Utility Group to minimize risk. At September 30, 2000, the mark-to-market
for those positions was a gain of $0.3 million.
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<PAGE>
Both CMT and Utility Group utilize a VAR model to assess the market risk
of their derivative financial instruments. VAR represents the potential loss for
an instrument from adverse changes in market factors for a specified period of
time and confidence level. The VAR was estimated using historical simulation
calculated daily assuming a holding period of one day and with a 95% confidence
level for natural gas positions and a 99.7% confidence level for electricity
positions. Total volatility is based on historical cash volatility, implied
market volatility, cash volatility and option pricing. Based on these
assumptions, the high, low and average VAR during the three months and nine
months ended September 30, 2000, as well as the VAR at September 30, 2000, is
summarized below:
<TABLE>
<CAPTION>
(In thousands)
At
For the Three Months Ended September 30, 2000 September 30, 2000
--------------------------------------------- ------------------
High Low Average
---- --- -------
<S> <C> <C> <C> <C>
CMT $ 4,140.31 $ 248.16 $ 1,221.53 $ 705.1
Utility Group $ 2,168.09 $ 57.15 $ 545.72 $ 107.2
Consolidated $ 4,780.29 $ 399.68 $ 1,767.26 $ 812.3
</TABLE>
<TABLE>
<CAPTION>
(In Thousands)
For the Nine Months Ended September 30, 2000
--------------------------------------------
High Low Average
---- --- -------
<S> <C> <C> <C>
CMT $ 4,140.31 $ 35.20 $ 956.60
Utility Group $ 2,168.09 $ 17.70 $ 324.90
Consolidated $ 4,730.93 $ 69.40 $ 1,286.40
</TABLE>
In 1999, the Company reported VAR using a 99.7% confidence level for both
natural gas and electricity. The change in reporting VAR using a confidence
level of 95% for natural gas is due to the greater maturity, greater liquidity
and depth of products in the natural gas market as compared to the immaturity
and volatility of the electricity markets. Reporting VAR using a confidence
level of 95% is also the industry standard for natural gas. The table below
summarizes the VAR at December 31, 1999 if VAR had been reported using a 95%
confidence level:
<TABLE>
<CAPTION>
(In Thousands)
At December 31, 1999
--------------------
<S> <C>
CMT $ 46.3
Utility Group $ 51.2
Consolidated $ 97.4
</TABLE>
33
<PAGE>
PART II
OTHER INFORMATION
ITEM 5. OTHER INFORMATION
On September 21, 2000, Utility Group filed applications with the FERC and
the LPSC requesting authorization to convert its form of business organization
from a corporation to a limited liability company. The purpose of Utility
Group's proposed conversion is to lessen its Louisiana state tax obligations.
Utility Group must obtain authorization from the FERC and the LPSC to engage in
the conversion because of their jurisdiction over Utility Group as a utility. On
November 2, 2000, the LPSC authorized Utility Group's conversion to a limited
liability company. Utility Group anticipates receiving the necessary
authorization from the FERC by the end of 2000 and will proceed with the
conversion if and when such authorization is given.
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<PAGE>
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
11(a) Computation of Net Income Per Common Share for the three
months ended September 30, 2000
11(b) Computation of Net Income Before Extraordinary Item Per Common
Share for the nine months ended September 30, 2000
11(c) Computation of Net Income Per Common Share for the nine months
ended September 30, 2000
12 Computation of Earnings to Fixed Charges and Earnings to
Combined Fixed Charges and Preferred Stock Dividends for the
twelve months ended September 30, 2000
27 Financial Data Schedule
(b) Reports on Form 8-K
On July 28, 2000, the Company filed a Current Report on Form
8-K reporting under Item 5 thereof the adoption of a
shareholder rights plan by the Company's board of directors.
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<PAGE>
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
CLECO CORPORATION
(Registrant)
By: /S/ R. Russell Davis
------------------------
R. Russell Davis
Vice President and
Corporate Controller
(Principal Accounting Officer)
Date: November 14, 2000
36
