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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 June 30, 1999 Commission file number 1-5663
Or
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
CLECO UTILITY GROUP, INC.
(FORMERLY KNOWN AS CLECO CORPORATION)
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
LOUISIANA 72-0244480
(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 August 2, 1999, there were 22,531,870 shares outstanding of the
Registrant's Common Stock, par value $2.00 per share.
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
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PART I. FINANCIAL INFORMATION
<S> <C>
Item 1. Financial Statements.......................................................................... 1
Report of Independent Accountants........................................................... 2
Consolidated Statements of Income........................................................... 3
Consolidated Balance Sheets................................................................. 5
Consolidated Statements of Cash Flows....................................................... 7
Notes to Consolidated Financial Statements.................................................. 8
Item 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations
Disclosure Regarding Forward-Looking Statements............................................. 14
Results of Operations....................................................................... 14
Financial Condition......................................................................... 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................................... 23
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders........................................... 25
Item 5. Other Information............................................................................. 26
Item 6. Exhibits and Reports on Form 8-K.............................................................. 27
SIGNATURE ................................................................................................ 28
</TABLE>
<PAGE> 3
PART I
FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The consolidated financial statements Cleco Corporation (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 the Company's business, the results of operations for the six months ended
June 30, 1999 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 Annual Report on Form 10-K for the year ended December 31, 1998
(1998 Form 10-K).
The consolidated financial statements included herein have been subjected to a
limited review by PricewaterhouseCoopers LLP, independent accountants for the
Company, whose report is included herein.
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REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholders
of Cleco Corporation
We have reviewed the consolidated balance sheets of Cleco Corporation as of June
30, 1999, and the related consolidated statements of income for the three-month
and six-month periods ended June 30, 1999 and 1998 and the consolidated
statements of cash flows for the six-month periods ended June 30, 1999 and 1998.
The financial statements are the responsibility of the Company's management.
We conducted our review in accordance with standards established by the American
Institute of Certified Public Accountants. A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit conducted in accordance
with generally accepted auditing standards, the objective of which is the
expression of an opinion regarding the financial statements taken as a whole.
Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should
be made to the consolidated financial statements referred to above for them to
be in conformity with generally accepted accounting principles.
We have previously audited, in accordance with generally accepted auditing
standards, the consolidated balance sheet as of December 31, 1998, and the
related consolidated statements of income, cash flows and changes in common
shareholders' equity for the year then ended (not presented herein); and in our
report dated January 27, 1999, we expressed an unqualified opinion on those
financial statements. In our opinion, the information set forth in the
accompanying balance sheet as of December 31, 1998, is fairly stated in all
material respects in relation to the balance sheet from which it has been
derived.
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
July 23, 1999
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CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE THREE MONTHS ENDED JUNE 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
1999 1998
------------- -------------
<S> <C> <C>
OPERATING REVENUES $ 222,474 $ 128,298
------------- -------------
OPERATING EXPENSES
Fuel used for electric generation 28,317 34,402
Power purchased 112,294 20,620
Other operation 23,233 16,845
Maintenance 7,743 7,615
Depreciation 12,575 11,854
Taxes other than income taxes 8,793 8,639
Federal and state income taxes 7,992 7,377
------------- -------------
200,947 107,352
------------- -------------
OPERATING INCOME 21,527 20,946
Allowance for other funds used during construction (71) 301
Other income and expenses, net (317) 625
------------- -------------
INCOME BEFORE INTEREST CHARGES 21,139 21,872
Interest charges, including amortization of debt expense, premium and
discount 6,888 7,071
Allowance for borrowed funds used during construction 11 (221)
------------- -------------
NET INCOME 14,240 15,022
Preferred dividend requirements, net 524 531
------------- -------------
NET INCOME APPLICABLE TO COMMON STOCK $ 13,716 $ 14,491
============= =============
WEIGHTED AVERAGE COMMON SHARES
Basic 22,531,141 22,481,365
Diluted 23,871,052 23,866,067
EARNINGS PER SHARE
Basic $ 0.61 $ 0.64
Diluted $ 0.59 $ 0.63
CASH DIVIDENDS PAID PER SHARE $ 0.415 $ 0.405
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL
STATEMENTS.
3
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CLECO CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
FOR THE SIX MONTHS ENDED JUNE 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
1999 1998
------------- -------------
<S> <C> <C>
OPERATING REVENUES $ 344,193 $ 225,507
------------- -------------
OPERATING EXPENSES
Fuel used for electric generation 53,882 62,099
Power purchased 145,692 32,764
Other operation 39,059 31,379
Maintenance 13,863 12,799
Depreciation 24,965 23,894
Taxes other than income taxes 17,733 17,389
Federal and state income taxes 12,011 10,408
------------- -------------
307,205 190,732
------------- -------------
OPERATING INCOME 36,988 34,775
Allowance for other funds used during construction 116 582
Other income and expenses, net (631) 478
------------- -------------
INCOME BEFORE INTEREST CHARGES 36,473 35,835
Interest charges, including amortization of debt expense, premium and
discount 13,877 14,248
Allowance for borrowed funds used during construction (184) (429)
------------- -------------
NET INCOME 22,780 22,016
Preferred dividend requirements, net 1,047 1,057
------------- -------------
NET INCOME APPLICABLE TO COMMON STOCK $ 21,733 $ 20,959
============= =============
WEIGHTED AVERAGE COMMON SHARES
Basic 22,518,237 22,475,719
Diluted 23,874,293 23,865,949
EARNINGS PER SHARE
Basic $ 0.97 $ 0.93
Diluted $ 0.95 $ 0.91
CASH DIVIDENDS PAID PER SHARE $ 0.82 $ 0.80
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL
STATEMENTS.
4
<PAGE> 7
CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands)
JUNE 30, 1999 DECEMBER 31, 1998
------------- -----------------
<S> <C> <C>
ASSETS
Utility and other property, plant and equipment
Property, plant and equipment $ 1,572,482 $ 1,565,028
Accumulated depreciation (565,077) (551,705)
------------ ------------
1,007,405 1,013,323
Construction work-in-progress 125,869 76,475
------------ ------------
Total utility and other plant, net 1,133,274 1,089,798
------------ ------------
Investments and other assets 3,931 3,500
------------ ------------
Current assets
Cash and cash equivalents 24,521 19,457
Accounts receivable, net 112,933 50,584
Unbilled revenues 21,597 9,712
Fuel inventory, at average cost 17,151 9,725
Materials and supplies, inventory, at average cost 16,316 12,674
Other current assets 4,633 1,738
------------ ------------
Total current assets 197,151 103,890
------------ ------------
Prepayments 8,533 8,293
Regulatory assets - deferred taxes 144,647 95,199
Other deferred charges 34,545 30,975
Accumulated deferred federal and state income taxes 116,145 97,345
------------ ------------
TOTAL ASSETS $ 1,638,226 $ 1,429,000
============ ============
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL
STATEMENTS.
(Continued on next page)
5
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CLECO CORPORATION
CONSOLIDATED BALANCE SHEETS (CONTINUED)
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands, except share amounts)
JUNE 30, 1999 DECEMBER 31, 1998
------------- -----------------
<S> <C> <C>
CAPITALIZATION AND LIABILITIES
Common shareholders' equity
Common stock, $2 par value, authorized 50,000,000
shares, issued 22,778,554 and 22,767,754 shares at
June 30, 1999 and December 31, 1998, respectively $ 45,557 $ 45,535
Premium on capital stock 113,834 113,871
Retained earnings 274,521 271,019
Treasury stock, at cost, 246,684 and 281,930 shares at
June 30, 1999 and December 31, 1998, respectively (5,060) (5,734)
------------ ------------
428,852 424,691
------------ ------------
Preferred stock, cumulative, $100 par value
Not subject to mandatory redemption 28,880 29,718
Deferred compensation related to preferred stock held
by ESOP (15,566) (16,923)
------------ ------------
13,314 12,795
Subject to mandatory redemption 0 5,680
------------ ------------
13,314 18,475
------------ ------------
Long-term debt, net 361,893 343,042
------------ ------------
Total capitalization 804,059 786,208
------------ ------------
Current liabilities
Short-term debt 119,993 68,416
Long-term debt due within one year 47,374 33,330
Accounts payable 89,385 61,786
Customer deposits 20,123 20,120
Taxes accrued 33,546 11,942
Interest accrued 8,078 7,340
Accumulated deferred fuel 1,666 4,613
Other current liabilities 4,448 3,868
------------ ------------
Total current liabilities 324,613 211,415
------------ ------------
Deferred credits
Accumulated deferred federal and state income taxes 341,216 286,619
Accumulated deferred investment tax credits 26,889 27,784
Regulatory liabilities - deferred taxes 97,632 81,074
Other deferred credits 43,817 35,900
------------ ------------
Total deferred credits 509,554 431,377
------------ ------------
TOTAL CAPITALIZATION AND LIABILITIES $ 1,638,226 $ 1,429,000
============ ============
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL
STATEMENTS.
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CLECO CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
FOR THE SIX MONTHS ENDED JUNE 30
(UNAUDITED)
<TABLE>
<CAPTION>
(In thousands)
1999 1998
---------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 22,780 $ 22,016
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and amortization 25,465 24,880
Allowance for funds used during construction (300) (1,011)
Amortization of investment tax credits (895) (895)
Deferred income taxes (370) 55
Deferred fuel costs (2,947) (3,196)
(Gain) Loss on disposition of utility plant, net (108) 2
Changes in assets and liabilities
Accounts receivable, net (61,942) (13,523)
Unbilled revenues (11,885) (603)
Fuel inventory, materials and supplies (11,068) 2,591
Accounts payable 27,599 (17,870)
Customer deposits 3 161
Other deferred accounts (2,882) (376)
Taxes accrued 21,604 19,322
Interest accrued 738 113
Other, net 10,738 4,980
---------- ----------
Net cash provided by operating activities 16,530 36,646
---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to utility plant (76,570) (28,720)
Allowance for funds used during construction 300 1,011
Sale of utility plant 165 186
Purchase of investments (200) (180)
---------- ----------
Net cash used in investing activities (76,305) (27,703)
---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuance of common stock 243 39
Issuance of long-term debt 50,000 0
Retirement of long-term debt (10,000) (15,000)
Increase in short-term debt, net 50,621 25,830
Redemption of preferred stock (6,518) (207)
Dividends paid on common and preferred stock, net (19,507) (19,037)
---------- ----------
Net cash provided by (used in) financing activities 64,839 (8,375)
---------- ----------
NET INCREASE IN CASH AND CASH EQUIVALENTS 5,064 568
CASH AND CASH EQUIVALENTS AT BEGINNING OF
PERIOD 19,457 18,015
---------- ----------
CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 24,521 $ 18,583
========== ==========
Supplementary cash flow information
Interest paid (net of amount capitalized) $ 12,798 $ 13,742
========== ==========
Income taxes paid $ 2,000 $ 1,000
========== ==========
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL
STATEMENTS.
7
<PAGE> 10
CLECO CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
NOTE A. RECLASSIFICATION
Certain prior-period amounts have been reclassified to conform with the
presentation shown in the current year's financial statements. These
reclassifications had no effect on net income applicable to common stock or
common shareholders' equity.
NOTE B. LEGAL PROCEEDING: FUEL SUPPLY - LIGNITE
The Company and Southwestern Electric Power Company (SWEPCO), each a
50% owner of Dolet Hills Power Station Unit 1 (Dolet Hills Unit 1), jointly own
lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982 the
Company and SWEPCO entered into a Lignite Mining Agreement (LMA) with the Dolet
Hills Mining Venture (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, the Company is receiving annually a minimum delivery of
1,187,500 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 1997 the Company and SWEPCO received deliveries which
approximated 28% of the annual lignite consumption at Dolet Hills Unit 1 from
the other lignite supplier.
On April 15, 1997, the Company and SWEPCO filed suit against DHMV and
its partners in the United States District Court for the Western District of
Louisiana (Federal Court Suit) seeking to enforce various obligations of DHMV to
the Company 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 the Company's
suit and filed a counterclaim asserting various contract-related claims against
the Company and SWEPCO. The Company and SWEPCO have denied the allegations in
the counterclaims on the grounds the counterclaims have no merit.
The counterclaims filed by DHMV in the Federal Court Suit resulted in
the Company and SWEPCO filing a separate lawsuit against the parent companies of
DHMV, namely, Jones Capital Corporation and Philipp Holzmann USA, Inc., on
August 13, 1997, in the First Judicial District Court for Caddo Parish,
Louisiana (State Court Suit). 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 January 8, 1999, the Company and SWEPCO filed an amended complaint
in the Federal Court Suit seeking, among other things, a termination of the LMA
after trial based on DHMV's breach of the contract. DHMV has answered the
amended complaint and denied all claims of
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breach. The parties have engaged in pre-trial motion practice and are in the
fact witness deposition phase of discovery at this time.
Federal Court has issued a revised scheduling order which has set the
Federal Court Suit for trial beginning January 31, 2000. A general discovery
cut-off date of November 15, 1999 has also been established.
The Company and SWEPCO will continue to aggressively prosecute the
claims against DHMV and defend against the counterclaims which DHMV has
asserted. The Company 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
cannot be predicted at this time, based on information currently available to
the Company, management does not believe that the counterclaims asserted by DHMV
in the Federal Court Suit will have a significant adverse effect on the
Company's financial position or results of operations.
NOTE C. ACCRUAL FOR ESTIMATED CUSTOMER CREDITS
The Company's reported second quarter earnings reflect a $4.9 million
accrual for estimated customer credits which may be required under terms of an
earnings review settlement reached with the Louisiana Public Service Commission
(LPSC) in 1996. Of the $4.9 million, $1.9 million relates to the 12-month-ended
September 30, 1998 cycle and the remaining $3 million relates to an increase in
the estimated refund for the 12-month-ended September 30, 1999 cycle. The
adjustment for the prior year's estimate of the refund for the 1998 cycle was
due to the LPSC's issuance on July 23, 1999 of a report proposing a larger
refund than the Company previously projected. See Note F. "Subsequent Events"
for more information. The final decision from the LPSC on the amount of the
refund is expected in September, 1999. The $4.9 million was recorded as a
reduction in revenue due to the nature of the of the customer credits.
The settlement reached with the LPSC in 1996, and a subsequent
amendment, set the company's rates until the year 2004, and also provided for
annual base rate tariff reductions of $3 million in 1997 and an additional $2
million in 1998. As part of the settlement, the Company is allowed to retain all
regulated earnings up to a 12.25% return on equity, and to share equally with
customers as credits on their bills all regulated earnings between 12.25% and
13% return on equity. All regulated earnings above a 13% return on equity are
credited to customers. The amount of credits due customers, if any, is
determined by the LPSC annually based on 12-month-ending results as of September
30 of each year. The settlement provides for such credits to be made on
customers' bills the following summer.
NOTE D. DISCLOSURES ABOUT SEGMENTS
The Company has determined that its reportable segment is based on the
Company's method of internal reporting, which disaggregates its business units
by regulatory jurisdiction. The Company's reportable segment is LPSC
Jurisdictional Utility. This segment contains the revenues, expense and assets
over which the LPSC may have material effect based upon state statutes. The
effects include rate-making powers, determination of depreciable lives,
determination of the cost of fuel permitted to be passed through the fuel cost
adjustment clauses,
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determination of prudent capital expenditures, transfers of assets, as well as
the issuance of securities and incurrance of long term debt.
The financial results of the Company's segment is 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. Material intersegment transactions occur on a regular
basis.
The table below presents information about the reported operating
results and net assets of the Company's reportable segments.
FOR THE THREE MONTHS ENDED JUNE 30, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
LPSC
JUSIDICTIONAL ALL
UTILITY OTHER TOTAL
---------- ---------- ----------
<S> <C> <C> <C>
Operating revenues from external customers $ 222,474 $ 1,985 $ 224,459
Operating intersegment revenues .......... -- $ 2,218 $ 2,218
Segment profit ........................... $ 21,888 $ 344 $ 22,232
Segment assets ........................... $1,630,603 $ 117,161 $1,747,764
</TABLE>
Reconciliation between segment amounts and
consolidated amounts
<TABLE>
<S> <C>
PROFIT
Total profit on reportable segments............$ 21,888
Other profit................................... 344
Unallocated items
Income taxes............................... (7,992)
Preferred dividend requirements, net....... (524)
----------
Net income to common.......................$ 13,716
==========
</TABLE>
For the Three Months Ended June 30, 1998
(In thousands)
<TABLE>
<CAPTION>
LPSC
Jurisdictional All
Utility Other Total
------------ ---------- ----------
<S> <C> <C> <C>
Operating revenues from external customers............. $ 128,298 $ 6,389 $ 134,687
Operating intersegment revenues........................ $ -- $ 1,148 $ 1,148
Segment profit......................................... $ 21,744 $ 655 $ 22,399
Segment assets......................................... $ 1,378,220 $ 35,604 $1,413,824
</TABLE>
Reconciliation between segment amounts and
consolidated amounts
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<TABLE>
<S> <C>
PROFIT
Total profit on reportable segments............................ $ 21,744
Other profit................................................... 655
Unallocated items
Income taxes............................................... (7,377)
Preferred dividend requirements, net....................... (531)
----------
Net income to common....................................... $ 14,491
==========
</TABLE>
FOR THE SIX MONTHS ENDED JUNE 30, 1999
(IN THOUSANDS)
<TABLE>
<CAPTION>
LPSC
JUSIDICTIONAL ALL
UTILITY OTHER TOTAL
---------- -------- --------
<S> <C> <C> <C>
Operating revenues from external customers...................... $ 344,193 $ 3,748 $347,941
Operating intersegment revenues ................................ -- $ 3,797 $ 3,797
Segment profit.................................................. $ 34,319 $ 472 $ 34,791
</TABLE>
Reconciliation between segment amounts and
consolidated amounts
<TABLE>
<S> <C>
PROFIT
Total profit on reportable segments....................... $ 34,319
Other profit.............................................. 472
Unallocated items
Income taxes.......................................... (12,011)
Preferred dividend requirements, net.................. (1,047)
----------
Net income to common.................................. $ 21,733
==========
</TABLE>
For the Six Months Ended June 30, 1998
(In thousands)
<TABLE>
<CAPTION>
LPSC
Jurisdictional All
Utility Other Total
-------- -------- --------
<S> <C> <C> <C>
Operating revenues from external customers... $225,507 $ 10,601 $236,108
Operating intersegment revenues ............. $ -- $ 1,561 $ 1,561
Segment profit .............................. $ 31,715 $ 709 $ 32,424
</TABLE>
Reconciliation between segment amounts and
consolidated amounts
<TABLE>
<S> <C>
PROFIT
Total profit on reportable segments........................... $ 31,715
Other profit.................................................. 709
Unallocated items
Income taxes.............................................. (10,408)
Preferred dividend requirements, net...................... (1,057)
----------
Net income to common...................................... $ 20,959
==========
</TABLE>
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NOTE E. ASSETS HELD FOR SALE
Oil and gas properties held by Cleco Energy LLC, an unregulated
subsidiary of the Company, have been identified as "Assets held for Sale" and
are accounted for in accordance with the provisions of Emerging Issues Task
Force (EITF) Consensus No. 87-11 "Allocation of Purchase Price to Assets to Be
Sold". Oil and Gas Properties held for sale are reflected net of working capital
and debt specifically identified with the purchase of the oil and gas
properties. These properties are periodically reviewed to determine if they have
been impaired. In accordance with EITF No. 87-11, a net loss of $258,768 has
been excluded from the Consolidated Statement of Income for the six months ended
June 30, 1999.
NOTE F. SUBSEQUENT EVENTS
At the October 23, 1998 meeting of the Company's Board of Directors,
the directors approved a proposal to reorganize the Company into a public
utility holding company structure. The proposed holding company structure would
create a parent company that would include several subsidiaries, one of which
would contain the Company's generation, transmission and distribution electric
utility operations necessary to serve its traditional retail and wholesale
customers. Another subsidiary, Cleco Midstream Resources LLC, would operate the
Company's competitive electric generation, oil and natural gas production,
energy and generating fuel procurement and natural gas pipeline businesses. A
third subsidiary, UtiliTech Solutions (formerly Cleco Services LLC), would sell
utility support services related to distribution and retail service to municipal
governments, rural electric cooperatives and investor-owned electric companies.
Under the terms of the proposal, the newly organized holding company
would become the owner of all of the Company's outstanding common and preferred
stock and existing common and preferred shareholders of the Company would
exchange their stock in the Company for stock in the holding company. Shares of
preferred stock in a series that did not approve the holding company proposal
would be redeemed. The proposal received LPSC approval on December 18, 1998, and
FERC approval on January 29, 1999. Approval was obtained from the Shareholders
at the Annual Meeting of Shareholders. See the Company's 1999 Notice of Annual
Meeting of Shareholders and Proxy Statement, dated April 9, 1999, incorporated
herein by reference.
The Holding Company structure became effective on July 1, 1999. Shares
of preferred stock, subject to mandatory redemption, 4.5% Series 1955, 4.65%
Series 1964, and 4.75% Series 1965 were redeemed at a cost of $5.8 million.
On June 29, 1999, the Company filed with the LPSC a monitoring report
for the September 30, 1998 cycle required by the settlement discussed in Note C,
"Accrual for Estimated Customer Credits." On July 23, 1999, the LPSC responded
to the monitoring report with a proposed adjustment to the monitoring report
setting the Company's customer credits at $7.8 million, which was above the $4.5
million the Company reserved in 1998 for the September 30, 1998 cycle. The
Company estimates that through the negotiation process, we may be able to
12
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reduce the amount of customer credits to $6.4 million for the September 30, 1998
cycle. Therefore, second quarter results reflect an accrual for customer credits
of $4.9 million, of which, $1.9 million relates to the September 30, 1998 cycle
and $3.0 million relates to the September 30, 1999 cycle.
Effective August 3, 1999, an unregulated subsidiary of the Company,
Cleco Midstream Resources LLC, purchased additional ownership interest in Cleco
Energy LLC from the other members, bringing the subsidiary's total ownership
interest from 44% to 93.63%. The total purchase price of the additional
ownership interest is approximately $2.9 million in a combination of cash,
assumption of debt and stock in Cleco Corporation.
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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 Management's Discussion and Analysis of Financial Condition and Results of
Operations in Item 7 of the Company's 1998 Form 10-K, the financial statements
and notes contained in Item 8 of the Company's 1998 Form 10-K 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. Such risks and uncertainties
include, without limitation, the effects of competition in the power industry,
legislative and regulatory changes affecting electric utilities, fluctuations in
the weather 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 June 30, 1999
Net income applicable to common stock totaled $13.7 million or $0.61
per average common share for the first quarter of 1999, as compared to $14.5
million or $0.64 per average common share for the corresponding period in 1998.
The following principal factors contributed to these results:
Operating revenues for the quarter increased $94.2 million or 73.4%
compared to the same period in 1998. This increase is primarily due to a $87.6
million increase in sales from energy marketing activities. Also contributing to
the increase in operating revenues was a $4.8 million increase in base revenues
from sales to regular customers, and a $1.2 million increase in fuel cost
recovery revenues. Partially offsetting these increases was a $4.9 million
accrual for estimated customer credits.
Sales from electric marketing activities increased $80.4 million over
the same period in 1998. The increase was due to several factors. The first
factor was that the electric marketing operation
14
<PAGE> 17
was not fully up and running until late in the second quarter of 1998. The
second factor is that in 1998 the operations only traded in the Into Entergy
market whereas in 1999, they also traded in the Cinergy market. Sales from the
gas marketing activities increased $7.2 million over the same period in 1998 due
to the fact that gas marketing was not taking place in 1998.
Base revenues increased 6.8% over the same period in 1998. This
increase is primarily the result of a $2.8 million increase in base revenues
from increased kilowatt-hour sales to residential customers and a $1.3 million
increase in sales to commercial customers. Kilowatt-hour sales to regular
customers for the first quarter of 1999 improved 7.2% over the second quarter of
1998. Sales to residential customers rose 7.9% and sales to commercial customers
improved 9.4% over the second quarter in 1998. The increase in kilowatt-hour
sales can be attributed to the above-normal additions of new commercial
customers and continued overall health of the economy in the Company's service
territory.
Fuel cost recovery revenues increased 2.6%, or $1.2 million, compared
to the same period in 1998. Fuel cost recovery revenues from sales to
residential and commercial customers increased $1.6 million in relation to the
same period in 1998 and was partially offset by a $0.4 million, or 38%, decrease
in fuel cost recovery revenues from sales to utilities for the same period. The
increase in fuel cost recovery revenues is related to higher natural gas prices
and an increase in kilowatt-hour sales in the second quarter of 1999, compared
to the second quarter of 1998. Changes in fuel cost have historically had no
effect on net income, as fuel costs are generally recovered through a fuel cost
adjustment clause that enables the Company 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) while the remaining portion,
regulated by the Federal Energy Regulatory Commission (FERC), is audited
periodically for several years at a time. Until approval is received, the
adjustments are subject to refund.
Moderating the base revenue increase was a $4.9 million accrual for
estimated customer credits which may be required under terms of an earnings
review settlement reached with the LPSC in 1996. Of the $4.9 million, $1.9
million was related to the 12-month-ending September 30, 1998 cycle. Three
million relates to the current cycle ending September 30, 1999. The amount of
credits due customers, if any, is determined by the LPSC annually based on
12-month ending results as of September 30 of each year. See "Management's
Discussion and Analysis of Results of Operations and Financial Condition -
Financial Condition - Retail Rates" in Item 7 of the 1998 Form 10-K for a
discussion of the LPSC settlement.
Operating expenses increased $93.6 million, or 87.1%, during the second
quarter of 1999 compared to the same period in 1998. The rise in operating
expenses is primarily the result of an increase in purchased energy expenses
related to energy marketing activities. Energy marketing expenses increased
$89.7 million compared to the same period in 1998 due to the fact that power
marketing operations were not fully operational until the late in the second
quarter of 1998 and gas marketing was not engaged until the second quarter of
1999.
The Company purchases power from other electric power generators when
the price of the energy purchased is less than the cost to the Company of
generating such energy from its own facilities, or when the Company's generating
units are unable to provide electricity to satisfy the
15
<PAGE> 18
Company's load. Thirty-four percent of the Company's energy requirements during
the second quarter of 1999 were met with purchased power, compared to 22% for
the corresponding period in 1998. The increase was caused by a scheduled major
maintenance at the Dolet Hills Power Station. The power station did not produce
electricity until the month of June 1999. Consequently, the Company purchased
power to meet load requirements.
For the Six Months Ended June 30, 1999
Net income applicable to common stock totaled $21.7 million or $0.97
per average common share for the first six months of 1999, as compared to $20.9
million or $0.93 per average common share for the corresponding period in 1998.
The following principal factors contributed to these results:
Operating revenues for the quarter increased $118.7 million or 52.6%
compared to the same period in 1998. This increase is primarily due to a $106.1
million increase in sales from energy marketing activities. Also contributing to
the increase in operating revenues was a $9.0 million increase in base revenues
from sales to regular customers, and a $2.3 million increase in fuel cost
recovery revenues. Partially offsetting these increases was a $4.9 million
accrual for estimated customer credits.
Sales from electric marketing activities increased $98.9 over the same
period in 1998. The increase was due to several factors. The first factor was
that the electric marketing operation was not fully up and running until late in
the second quarter of 1998. The second factor is that in 1998 the operations
only traded in the Into Entergy market whereas in 1999, they also traded in the
Cinergy market. Sales from the gas marketing activities increased $7.2 million
over the same period in 1998 due to the fact that gas marketing was not taking
place in 1998.
Base revenues increased 7.3% over the same period in 1998. This
increase is primarily the result of a $3.0 million increase in base revenues
from increased kilowatt-hour sales to residential customers and a $2.8 million
increase in sales to commercial customers. Kilowatt-hour sales to regular
customers for the first six months of 1999 improved 9.1% over the second quarter
of 1998. Sales to residential customers rose 4.9% and sales to commercial
customers improved 11.9% over the first six months in 1998. The increase in
kilowatt-hour sales can be attributed to the above-normal additions of new
commercial customers, continued overall health of the economy in the Company's
service territory.
Fuel cost recovery revenues increased 2.8%, or $2.3 million, compared
to the same period in 1998. Fuel cost recovery revenues from sales to commercial
customers increased $1.2 million in relation to the same period in 1998 and was
partially offset by a $0.7 million, or 2.3%, decrease in fuel cost recovery
revenues from sales to residential customers for the same period. The increase
in fuel cost recovery revenues is related to higher natural gas prices and an
increase in kilowatt-hour sales in the first six months of 1999, compared to the
same period of 1998. Changes in fuel cost have historically had no effect on net
income, as fuel costs are generally recovered through a fuel cost adjustment
clause that enables the Company 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
16
<PAGE> 19
total fuel cost adjustment) while the remaining portion, regulated by the
Federal Energy Regulatory Commission (FERC), is audited periodically for several
years at a time. Until approval is received, the adjustments are subject to
refund.
Moderating the base revenue increase was a $4.9 million accrual for
estimated customer credits which may be required under terms of an earnings
review settlement reached with the LPSC in 1996. Of the $4.9 million, $1.9
million related to the 12-month-ending September 30, 1998 cycle. Three million
relates to the current cycle ending September 30, 1999. The amount of credits
due customers, if any, is determined by the LPSC annually based on 12-month
ending results as of September 30 of each year. See "Management's Discussion and
Analysis of Results of Operations and Financial Condition - Financial Condition
- - Retail Rates" in Item 7 of the 1998 Form 10-K for a discussion of the LPSC
settlement.
Operating expenses increased $116.4 million, or 60.7%, during the first
six months of 1999 compared to the same period in 1998. The rise in operating
expenses is primarily the result of an increase in purchased energy expenses
related to energy marketing activities. Energy marketing expenses increased
$107.7 million compared to the same period in 1998 due to the fact that power
marketing operations were not fully operational until the late in the second
quarter of 1998 and gas marketing was not engaged until the second quarter of
1999.
The Company purchases power from other electric power generators when
the price of the energy purchased is less than the cost to the Company of
generating such energy from its own facilities, or when the Company's generating
units are unable to provide electricity to satisfy the Company's load.
Thirty-five percent of the Company's energy requirements during the first six
months of 1999 were met with purchased power, compared to 25% for the
corresponding period in 1998. The increase was caused by a scheduled major
maintenance at the Dolet Hills Power Station. The power station did not produce
electricity from March 1999 to June 1999. Consequently, the Company purchased
power to meet load requirements.
FINANCIAL CONDITION
Liquidity and Capital Resources
At June 30, 1999 and 1998, the Company had $119.5 million and $60.0
million, respectively, of short-term debt outstanding in the form of commercial
paper borrowing and bank loans. An existing $100 million revolving credit
facility is scheduled to terminate on June 15, 2000 and an $80 million credit
facility is scheduled to expire on August 27, 1999. These facilities provide
support for the issuance of commercial paper and working capital needs. A new
$200 million credit facility is expected to be finalized prior to the expiration
of the $80 million 364-day facility. This new facility will be structured so
that $120 million is for a term of 364 days and $80 million will be for a term
of three years. The facility will provide for the working capital needs of the
Company and its subsidiaries. Uncommitted lines of credit with banks totaling
$15 million are also available to support working capital needs.
At June 30, 1999, CLE Resources, Inc., an unregulated consolidated
subsidiary of the Company, had $12.8 million of cash and temporary cash
investments in securities with original
17
<PAGE> 20
maturities of 90 days or less. $10 million has been committed to provide credit
support for working capital and electricity or natural gas commodity positions
for Cleco Energy LLC. In addition, CLE Resources, Inc. has committed up to $25
million over a five-year period for acquisitions, strategic alliances, and
investments in capital projects to be made by Cleco Energy LLC, subject to the
satisfaction of certain conditions. Cleco Energy LLC has drawn down $2.5 million
of the $25 million.
The cost of the repowering project at the Coughlin Power Station (CPS)
is estimated to be $250 million. It is anticipated that the structure of
permanent financing for the project will be determined and finalized during
1999. Currently, the Company is using its commercial paper program to fund the
interim needs of the project. As of June 30, 1999, the Company has spent
approximately $89.6 million on the project.
On May 7, 1999, the Company issued $50 million in medium term notes.
The notes were issued with an interest rate of 6.52% and a maturity date of May
15, 2009. The proceeds of the notes were used to pay down $10 million of the
Company's outstanding medium term notes and otherwise to pay down its short-term
commercial paper.
Regulatory Matters - Retail
The LPSC continues its deliberations over the potential of
restructuring the retail electricity market in Louisiana. The LPSC has deferred
making a final public interest determination. It has, however, directed LPSC
Staff to develop a transition to competition plan to be presented on or before
January 1, 2001. Cleco has and will continue to actively participate in these
planning sessions. Louisiana has not adopted any specific legislation on retail
electric competition or restructuring, and no bills were introduced in the 1999
Legislative session.
Several restructuring bills have been introduced at the federal level.
In April, the Clinton administration introduced the "Comprehensive Electricity
Competition Act". This act would require nationwide implementation of retail
choice of electric generation suppliers by January 1, 2003. The other most
notable restructuring bill is HB 2050, introduced in June. It would require each
state to implement retail choice by January 1, 2002. Both bills would have
provisions for consumer protection, and various degrees of renewable generation
requirements.
Regulatory Matters - Wholesale Electric Competition
Wholesale power markets, as regulated by the FERC, involve sales of
power between power suppliers, marketers, and brokers for subsequent resale to
retail, or end-use customers. Competition in this market has increased since the
FERC mandated, through it Order No. 888 and subsequent interpretations thereof,
open access to transmission facilities that are necessary to complete these
sales. The Company, under FERC rules, has an open access transmission tariff
through which it offers wholesale transmission service to other parties that is
comparable to the service that it provides itself from its facilities. The
Company, as a member of the Southwest Power Pool, may also provide certain
specialized transmission services under an open access tariff administered by
the pool, and as approved by the FERC. In recent years, the Company has
purchased a part of its power requirements from the wholesale market when it is
economical to do so or when the Company's generating units are unable to provide
electricity to satisfy the
18
<PAGE> 21
Company's load. In this role, the Company has also been a purchaser of open
access transmission service from other parties, and expects to continue to do so
in the immediate future.
In early April, Entergy proposed to FERC the creation of the country's
first for-profit regional transmission organization (RTO), commonly called a
transco. Unique to Entergy's proposal is its request to transfer all its
transmission assets to a fully independent and incentive-driven transmission
company. This transco would control, operate and maintain all member
transmission assets as well as plan for the region's transmission needs. Entergy
is asking FERC for a declaratory order on its proposal by July 31, 1999. Entergy
officials have also expressed an interest in including other regional companies
participating in this "Transco."
Both of the proposed federal restructuring bills mentioned above would
expand FERC's authority. The "Comprehensive Electricity Competition Act"
reaffirms FERC Order No. 888, as amended. It also authorizes the agency to order
establishment of RTOs, and to order a transmitting utility to relinquish control
over operation of its transmission facility to such a entity. HB 2050 calls for
the establishment of an Electric Reliability Organization under FERC
jurisdiction to develop reliability standards while also empowering FERC to
establish RTOs and to take actions necessary to mitigate market power.
REPOWERING PROJECT
In July 1998, the Company's Board of Directors approved the
construction of a 750-megawatt repowering project (Project) to be implemented at
The Coughlin Power Station (CPS). The Project will use three new natural
gas-fueled combustion turbine generators and three related heat recovery system
generators to repower two existing units at CPS.
The Company has signed a non-binding letter of intent with a third
party gas supplier for a tolling arrangement. Under this arrangement, the third
party gas supplier would have the right to market all the electricity produced
by the plant and would be required to supply all the fuel needed to produce the
power it markets. The Project would collect a processing fee for converting the
gas to electricity. The final contract is still under negotiation and the final
outcome may be different than the non-binding letter of intent.
One of the Company's subsidiaries, Cleco Evangeline LLC, will own and
operate the Project. The total cost of the Project is expected to be $250
million and is scheduled to be completed and in service by June 1, 2000. As of
June 30, 1999, the Company has spent approximately $89.6 million on the Project,
which is currently being funded through the Company's commercial paper program.
Permanent financing for the Project has not yet been determined and is expected
to be finalized during 1999. The Company has received all necessary approvals
from the LPSC and FERC. In February 1999, the LPSC approved the transfer of the
existing CPS assets out of the LPSC regulated rate base of the Company into
Cleco Evangeline LLC. The actual transfer is expected to occur in the fourth
quarter of 1999, or in the first quarter of 2000. In return for the approval of
the asset transfer, the Company agreed to extend the terms of its 1996 rate
settlement with the LPSC for an additional three years, to the year 2004. The
agreement also requires the Company to hold harmless its ratepayers from
negative impacts resulting from the removal of the generating assets from the
rate base. In return, the Company is authorized to transfer the assets at their
net book value of approximately $10 million.
19
<PAGE> 22
YEAR 2000 READINESS DISCLOSURE
The year 2000 (Y2K) problem occurs because many systems, both hardware
and software, were designed to accept only two digits instead of four digits for
the year in a date field. Having two digits instead of four digits may cause the
system to read "00" as 1900 instead of 2000. This may cause calculations that
are date sensitive to arrive at an incorrect or impossible solution. This may
affect items such as delivery dates, interest calculations, pension benefit
calculations, and a variety of other date-dependent calculations.
The Company is aware of the issues surrounding Y2K and the problems
that may occur and has put into action a plan to address these issues. The
Company is aware that the Y2K problem may affect both internal information
technology (IT) and non-IT systems. IT systems consist of software programs such
as the operating system, spreadsheets, accounting and other programs. Non-IT
systems refer to embedded technology such as micro controllers found in
computers and other hardware systems. The Company has divided the IT and non-IT
systems into two categories: mission critical and non-mission critical. Mission
critical systems are those that would affect the health and safety of the public
by causing a disruption in supplying electricity. Non-mission critical systems
are those that would not cause a disruption in supplying electricity, but may
still have a material, negative impact on the liquidity and financial condition
of the Company. The following tables show the initiatives, the completion
percentage of the various stages and an estimated completion date for the
mission critical systems:
MISSION CRITICAL SYSTEMS
<TABLE>
<CAPTION>
ESTIMATED
PLANNING- DATE OF
INITIATIVES ASSESSMENT CORRECTION TESTING IMPLEMENT COMPLETION
----------- ---------- ---------- ------- --------- ----------
<S> <C> <C> <C> <C> <C>
Distribution 100% 100% 100% 100% N/A
Generation 100% 100% 98% 98% Sept. 1999
IT Services* 100% 99% 90% 89% Oct. 1999
Transmission 100% 100% 100% 100% N/A
</TABLE>
*IT Services includes business applications and telecommunications.
The description of the stages are:
Planning-Assessment: Develop a project plan, compile a complete list of affected
systems, and prepare a detailed technical plan.
Correction: Make the required changes identified in
Planning-Assessment.
Testing: Test all changes made in the Correction stage to insure
that systems will meet the compliance criteria and the
systems will be accepted by user management.
20
<PAGE> 23
Implementation: Integrate the changed systems into a production environment
and begin use. Monitor subsequent changes to other systems
to ensure overall system integrity.
Management considers the Company's non-mission critical systems to be Y2K
compliant.
Internal systems are not the only ones that may have a material effect
on the Company. Institutions external to the Company, such as vendors and
customers, may also impact the Company's operations if their systems are not Y2K
compliant. Vendors could impact the Company by their inability to deliver goods
and services required by the Company to operate. Customers could impact the
Company by their inability to operate, reducing the sale of power, or their
inability to pay the Company for the power consumed. The Company has addressed
this issue by identifying major vendors and customers and sending surveys to
discover their level of Y2K compliance. Major vendors are defined as those that
provide critical goods or services to the Company, or those that provide
critical components to the Company (such as fuel suppliers and financial
institutions). Major customers are identified as those customers that are at the
greatest risk of being impacted by the Y2K problem and are large consumers of
power (mainly industrial and commercial customers). All of the customers and
vendors we identified as major have responded to the survey. They responded that
they are aware of the importance of being Y2K compliant in a timely manner and
are working to minimize the potential impact on their business. The Company will
continue to monitor the Y2K readiness of its major vendors and customers and
will take steps in order to minimize the impact of foreseeable failures on the
part of its major vendors and customers.
The Company's cost to address its Y2K problem is currently estimated at
$1.5 million, with approximately $1.3 million expended so far. The remaining
$0.2 million is expected to be spent before September 1999. The expenses
associated with Y2K are being funded through cash flows from operations. Only a
nominal amount of the Y2K budget is being expended on hardware. Most of the
budget is being expended in software. The Company's overall IT operating budget
for the year ended December 31, 1999, is approximately $11 million, however, the
bulk of the Y2K expenses were budgeted and expended by the various departments
that were affected by Y2K issues.
At this point in time, management has not engaged any firm, nor does it
plan to engage any firm, to perform an independent verification and validation
of the Company's Y2K readiness. However, the Company's independent auditing firm
was engaged to review the readiness process being followed. Their review was
completed in February and a summary of their findings relative to the process
has been reviewed, but the firm will not issue an opinion on Y2K readiness.
The Company has been reporting to the LPSC on a quarterly basis
starting in 1998 and on a monthly basis starting in April 1999. Also, monthly
reports are sent to the SPP, which summarizes their member's reports and
forwards them to the North American Electric Reliability Council (NERC). The
U.S. Department of Energy receives its reporting from the NERC. The Company is
in full compliance with the NERC reporting requirements and is conforming with
the NERC contingency planning requirements for the electrical system. The
21
<PAGE> 24
Company participated in one NERC planned system test in April. The test brought
to light minor issues which were subsequently addressed. The Company will
participate in another NERC test scheduled in September.
The risks of not addressing the Y2K problem include the failure to bill
customers, collect payments, pay invoices, operate generation facilities,
operate substations, and order and receive critical materials. Each of these
risks, should they materialize, could have a material, negative impact on the
operations, liquidity and financial condition of the Company. It is the opinion
of management that the action plan outlined above will adequately address the
Y2K risks facing the Company and reduce them to manageable levels so that Y2K
issues will not materially impact the Company.
A worst case scenario would be the entire SPP grid collapsing due to
the lack of available power. Management believes the Company is capable of
disconnecting from the SPP grid and restarting its power generation stations.
However, other regional grids may also collapse, which in turn could cause a
disruption in the supply of fuel or critical parts. During a possible
disruption, the Company would have to rely on its inventory of fuel and critical
parts. The Company keeps approximately a 30-day supply of coal at the two
coal-fired plants, which are considered the Company's base load plants. If
deliveries of fuel were interrupted for more than 30 days or if certain critical
parts should fail, the Company's ability to generate power would be severely
curtailed.
The Company has contingency plans for mission critical systems against
normal operating hazards such as major storms or fires. These plans were
designed to minimize the impact to customers by providing alternatives and
solutions to possible adverse conditions. These plans are required by several
oversight agencies, such as the LPSC and the NERC. The existing contingency
plans were reviewed and evaluated by the Company's staff to find out if they
adequately addressed possible failures due to Y2K noncompliance. Plan amendments
have been proposed but not yet finalized. The amendments are expected to be
finalized before December 1999.
At present, the Company does not have a contingency plan in place to
specifically cover the non-mission critical Y2K issues. However, management is
continually monitoring the progress of each initiative. In the third quarter of
1999, management will evaluate the reasonableness of the projected completion
dates and at that time determine if a contingency plan is required. As of the
date of this filing, management reasonably expects the completion of the
initiatives in a timely manner; thus, a contingency plan is not believed to be
required.
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<PAGE> 25
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
FINANCIAL RISK MANAGEMENT
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 and the commodity
price of electricity traded on the Into Entergy and the Cinergy exchanges.
Generally, the Company's market risk sensitive instruments and positions are
characterized as "other than trading". 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 the commodity price of electricity. The market risk estimates
have materially changed from those disclosed in the Company's 1998 Form 10-K,
herein incorporated by reference. The changes are presented below.
Interest Rate
As of June 30, 1999, the carrying value of the Company's long-term,
fixed-rate debt was approximately $362 million. Each 0.05% change in the average
interest rates applicable to such debt would result in a change of approximately
$9 million in the fair values of these instruments. If these instruments are
held to maturity, no change in fair value will be realized.
As of June 30, 1999, the carrying value of the Company's short-term,
variable-rate debt was approximately $119.5. Each 0.5% change in the average
interest rates applicable to such debt would result in a change of approximately
$0.6 million in the Company's pre-tax earnings.
The Company is in the process of refinancing its $68.4 million in
long-term, variable-rate debt with long-term, fixed-rate debt. The refinancing
will also extend the life of the bonds from 19 years to 30 years. The
refinancing is expected to be completed in August 1999. As a part of this
refinancing, the Company entered into an interest rate lock which will fix the
effective rate of the bonds at 5.663%. At the earlier of the refinancing date or
September 30, 1999, the lock rate of 5.663% will be compared to the Bond Buyer
Municipal Bond Index (BBI). If the lock rate is lower than the BBI, the Company
will pay the counterparty the basis point difference between the lock rate and
the BBI times $90,665. If the lock rate is greater than the BBI, the
counterparty will pay the Company the basis point difference between the lock
rate and the BBI times $90,665. At June 30, 1999, the Company would have had to
pay the counterparty approximately $1 million.
Market Risks
As of July 1, 1999, the Company adopted a holding company structure
(See Notes to the Financial Statements, Note F, "Subsequent Events"). One of the
subsidiaries of the
23
<PAGE> 26
Company, Cleco Marketing and Trading LLC, will engage in marketing and trading
of power and natural gas. This subsidiary will have trades that will be
marked-to-market. The mark-to-market procedures may introduce more volatility in
earnings than traditionally has been seen by the Company. The Company does have
in place controls to help minimize the risks involved in marketing and trading.
The impact to the Company has not been determined at this time.
24
<PAGE> 27
PART II
OTHER INFORMATION
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
(a) The Annual Meeting of Shareholders of the Company was held on May 14,
1999, in Alexandria, Louisiana.
(b) Proxies for the election of directors were solicited pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended.
There was no solicitation in opposition to management's nominees, and
all nominees listed in the Proxy Statement were elected.
(c) The following is a tabulation of the votes cast upon each of the
proposals presented at the Annual Meeting of Shareholders of the
Company on May 14, 1999:
(1) The Holding Company Proposal:
For Against Abstain
--- ------- -------
18,469,574 323,337 234,859
(2) Election of Directors:
<TABLE>
<CAPTION>
Broker
Class II Directors For Withheld Non-Votes
------------------ --- -------- ---------
<S> <C> <C> <C>
Robert T. Ratcliff 18,848,409 181,410 0
Edward M. Simmons 18,745,227 284,592 0
William H. Walker, Jr. 18,863,899 165,920 0
</TABLE>
The term of office as a director of each of Messrs. Richard B. Crowell,
David M. Eppler, J. Patrick Garrett, F. Ben James, Jr., A. DeLoach
Martin, Jr. and Gregory Nesbitt, and Ms. Sherian G. Cadoria continued
after the meeting.
(3) Appointment of PricewaterhouseCoopers LLP as the Company's auditors
for 1999:
<TABLE>
<CAPTION>
Broker
For Against Abstain Non-Votes
--- ------- ------- ---------
<S> <C> <C> <C>
18,834,200 62,000 133,619 0
</TABLE>
25
<PAGE> 28
ITEM 5. OTHER INFORMATION
NEW ACCOUNTING STANDARD
Periodically, the Financial Accounting Standards Board (FASB) issues
Statements of Financial Accounting Standards (SFAS). These standards 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 June 1998, the FASB issued SFAS No. 133, "Accounting for Derivatives
Instruments and Hedging Activities", effective for fiscal years beginning after
June 15, 1999. This Statement establishes accounting and reporting for
derivative instruments, including certain derivative instruments embedded in
other contracts and for hedging activities. In June 1999, the FASB issued SFAS
No. 137, "Accounting for Derivatives Instruments and Hedging Activities -
Deferral of the Effective Date of FASB Statement No. 133." This statement delays
the effective date until all fiscal years beginning after June 15, 2000. The
effect of adopting this Statement has not been determined.
26
<PAGE> 29
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
11 Computation of Net Income Per Common Share for the
three and six months ended June 30, 1999 and June
30, 1998
12 Computation of Earnings to Fixed Charges and
Earnings to Combined Fixed Charges and Preferred
Stock Dividends for the twelve months ended June 30,
1999
15 Awareness letter, dated August 13, 1999, from
PricewaterhouseCoopers LLP regarding review of the
unaudited interim financial statements
27 Financial Data Schedule
(b) Reports on Form 8-K
During the three-month period ended June 30, 1999, the Company
filed no Current Reports on Form 8-K.
27
<PAGE> 30
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 UTILITY GROUP INC.
(Formerly known as Cleco Corporation)
(Registrant)
BY: /s/ Thomas J. Howlin
------------------------------------
Thomas J. Howlin
Senior Vice President of Finance
and Chief Financial Officer
(Principal Financial Officer)
Date: August 13, 1999
28
<PAGE> 31
EXHIBIT INDEX
<TABLE>
<CAPTION>
Exhibit
Number Description
------ -----------
<S> <C>
11 Computation of Net Income Per Common Share for the
three and six months ended June 30, 1999 and June
30, 1998
12 Computation of Earnings to Fixed Charges and
Earnings to Combined Fixed Charges and Preferred
Stock Dividends for the twelve months ended June 30,
1999
15 Awareness letter, dated August 13, 1999, from
PricewaterhouseCoopers LLP regarding review of the
unaudited interim financial statements
27 Financial Data Schedule
</TABLE>
<PAGE> 1
CLECO CORPORATION
COMPUTATION OF NET INCOME PER COMMON SHARE
FOR THE THREE MONTHS ENDED JUNE 30,
(Unaudited)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
1999 1998
------------ ------------
<S> <C> <C>
BASIC
- -----
Net income applicable to common stock $ 13,716 $ 14,491
============ ============
Weighted average number of shares of common stock outstanding
during the period 22,531,141 22,481,365
============ ============
Basic net income per common share $ 0.61 $ 0.64
============ ============
DILUTED
- -------
Net income applicable to common stock $ 13,716 $ 14,491
------------ ------------
Adjustments to net income related to Employee Stock Ownership
Plan (ESOP) under the "if-converted" method:
Add loss of deduction from net income for actual dividends paid
on convertible preferred stock, net of tax 348 359
Deduct additional cash contribution required which is equal to
dividends on preferred stock less dividends paid at the
common dividend rate, net of tax (7) (24)
Add tax benefit associated with dividends paid on allocated
common shares 99 87
------------ ------------
Adjusted income applicable to common stock $ 14,156 $ 14,913
============ ============
Weighted average number of shares of common stock outstanding
during the period 22,531,141 22,481,365
Number of equivalent common shares attributable to ESOP 1,339,911 1,378,250
Common stock under stock option grants - 0 - 6,452
------------ ------------
Average shares 23,871,052 23,866,067
============ ============
Diluted net income per common share $ 0.59 $ 0.63
============ ============
</TABLE>
<PAGE> 2
CLECO CORPORATION
COMPUTATION OF NET INCOME PER COMMON SHARE
FOR THE SIX MONTHS ENDED JUNE 30,
(Unaudited)
<TABLE>
<CAPTION>
(In thousands, except share and
per share amounts)
------------------------------
1999 1998
------------ ------------
<S> <C> <C>
BASIC
Net income applicable to common stock $ 21,733 $ 20,959
============ ============
Weighted average number of shares of common stock outstanding
during the period 22,518,237 22,475,719
============ ============
Basic net income per common share $ 0.97 $ 0.93
============ ============
DILUTED
Net income applicable to common stock $ 21,733 $ 20,959
------------ ------------
Adjustments to net income related to Employee Stock Ownership
Plan (ESOP) under the "if-converted" method:
Add loss of deduction from net income for actual dividends paid
on convertible preferred stock, net of tax 707 718
Deduct additional cash contribution required which is equal to
dividends on preferred stock less dividends paid at the
common dividend rate, net of tax (22) (47)
Add tax benefit associated with dividends paid on allocated
common shares 190 171
------------ ------------
Adjusted income applicable to common stock $ 20,608 $ 21,801
============ ============
Weighted average number of shares of common stock outstanding
during the period 22,518,237 22,475,719
Number of equivalent common shares attributable to ESOP 1,355,839 1,383,575
Common stock under stock option grants 217 6,655
------------ ------------
Average shares 23,874,293 23,865,949
============ ============
Diluted net income per common share $ 0.95 $ 0.91
============ ============
</TABLE>
<PAGE> 1
CLECO CORPORATION
COMPUTATION OF EARNINGS TO FIXED CHARGES
AND EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
FOR THE TWELVE MONTHS ENDED JUNE 30, 1999
(Unaudited)
<TABLE>
<CAPTION>
(In thousands,
except ratios)
<S> <C>
Earnings $ 54,564
Income taxes 28,270
--------
Earnings from continuing operations before income taxes $ 82,834
--------
Fixed charges:
Interest, long-term debt $ 23,917
Interest, other (including interest on short-term debt) 2,806
Amortization of debt expense, premium, net 1,170
Portion of rentals representative of an interest factor 466
--------
Total fixed charges $ 28,359
========
Earnings from continuing operations before income taxes and fixed charges $111,194
========
Ratio of earnings to fixed charges 3.92x
========
Fixed charges from above $ 28,359
Preferred stock dividends* 2,792
--------
Total fixed charges and preferred stock dividends $ 31,151
========
Ratio of earnings to combined fixed charges and preferred stock dividends 2.66x
========
</TABLE>
* Preferred stock dividends multiplied by the ratio of pretax income to net
income.
<PAGE> 1
August 13, 1999
Securities and Exchange Commission
Judiciary Plaza
450 Fifth Street, N.W.
Washington, D.C. 20549
Re: Cleco Corporation on Form S-8 (Registration Nos. 2-79671, 33-10169,
33-38362 and 33-44663, and Form S-3 (Nos. 33-24895, 33-62950 and
333-02895)
Commissioners:
We are aware that our report dated July 23, 1999 on our review of the interim
financial information of Cleco Corporation as of June 30, 1999 and for the
three-month and six-month periods ended June 30, 1999 and 1998 included in this
Form 10-Q is incorporated by reference in the above mentioned registration
statements. Pursuant to Rule 436(c) under the Securities Act of 1933, this
report should not be considered a part of the registration statements prepared
or certified by us within the meaning of Sections 7 and 11 of that Act.
Very truly yours,
/s/ PricewaterhouseCoopers LLP
New Orleans, Louisiana
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
COMPANY'S FINANCIAL STATEMENTS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO
SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,133,274
<OTHER-PROPERTY-AND-INVEST> 3,931
<TOTAL-CURRENT-ASSETS> 197,151
<TOTAL-DEFERRED-CHARGES> 295,337
<OTHER-ASSETS> 8,533
<TOTAL-ASSETS> 1,638,226
<COMMON> 45,557
<CAPITAL-SURPLUS-PAID-IN> 108,779
<RETAINED-EARNINGS> 274,521
<TOTAL-COMMON-STOCKHOLDERS-EQ> 428,852
0
13,314
<LONG-TERM-DEBT-NET> 121,893
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 240,000
<COMMERCIAL-PAPER-OBLIGATIONS> 119,993
<LONG-TERM-DEBT-CURRENT-PORT> 47,374
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 666,800
<TOT-CAPITALIZATION-AND-LIAB> 1,638,226
<GROSS-OPERATING-REVENUE> 344,193
<INCOME-TAX-EXPENSE> 17,733
<OTHER-OPERATING-EXPENSES> 289,472
<TOTAL-OPERATING-EXPENSES> 307,205
<OPERATING-INCOME-LOSS> 36,988
<OTHER-INCOME-NET> (515)
<INCOME-BEFORE-INTEREST-EXPEN> 36,473
<TOTAL-INTEREST-EXPENSE> 13,693
<NET-INCOME> 22,780
1,047
<EARNINGS-AVAILABLE-FOR-COMM> 21,733
<COMMON-STOCK-DIVIDENDS> 18,462
<TOTAL-INTEREST-ON-BONDS> 4,329
<CASH-FLOW-OPERATIONS> 16,530
<EPS-BASIC> 0.97
<EPS-DILUTED> 0.95
</TABLE>
