-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, RRIJsEVwLaGzeEkRGgjSgZrFD+Uo9sTCNdMem9xUjZT9Cb418JKC8tgMQ3xHoNnX mCydaEldaaSEiL9Pm78aJw== 0000950129-99-003659.txt : 19990816 0000950129-99-003659.hdr.sgml : 19990816 ACCESSION NUMBER: 0000950129-99-003659 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990813 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLECO UTILITY GROUP INC CENTRAL INDEX KEY: 0000018672 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC SERVICES [4911] IRS NUMBER: 720244480 STATE OF INCORPORATION: LA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-05663 FILM NUMBER: 99687483 BUSINESS ADDRESS: STREET 1: PO BOX 5000 CITY: PINEVILLE STATE: LA ZIP: 71361-5002 BUSINESS PHONE: 3184847400 MAIL ADDRESS: STREET 1: P O BOX 5000 CITY: PINEVILLE STATE: LA ZIP: 71361-5002 FORMER COMPANY: FORMER CONFORMED NAME: CENTRAL LOUISIANA ELECTRIC CO INC DATE OF NAME CHANGE: 19920703 10-Q 1 CLECO UTILITY GROUP, INC. - DATED JUNE 30, 1999 1 ================================================================================ 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. ================================================================================ 2 TABLE OF CONTENTS
Page ---- PART I. FINANCIAL INFORMATION 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
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. 1 4 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 2 5 CLECO CORPORATION CONSOLIDATED STATEMENTS OF INCOME FOR THE THREE MONTHS ENDED JUNE 30 (UNAUDITED)
(In thousands, except share and per share amounts) 1999 1998 ------------- ------------- 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
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL STATEMENTS. 3 6 CLECO CORPORATION CONSOLIDATED STATEMENTS OF INCOME FOR THE SIX MONTHS ENDED JUNE 30 (UNAUDITED)
(In thousands, except share and per share amounts) 1999 1998 ------------- ------------- 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
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL STATEMENTS. 4 7 CLECO CORPORATION CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(In thousands) JUNE 30, 1999 DECEMBER 31, 1998 ------------- ----------------- 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 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL STATEMENTS. (Continued on next page) 5 8 CLECO CORPORATION CONSOLIDATED BALANCE SHEETS (CONTINUED) (UNAUDITED)
(In thousands, except share amounts) JUNE 30, 1999 DECEMBER 31, 1998 ------------- ----------------- 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 ============ ============
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL STATEMENTS. 6 9 CLECO CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE SIX MONTHS ENDED JUNE 30 (UNAUDITED)
(In thousands) 1999 1998 ---------- ---------- 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 ========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THE CONSOLIDATED FINANCIAL STATEMENTS. 7 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 8 11 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, 9 12 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)
LPSC JUSIDICTIONAL ALL UTILITY OTHER TOTAL ---------- ---------- ---------- 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 $1,747,764
Reconciliation between segment amounts and consolidated amounts PROFIT Total profit on reportable segments............$ 21,888 Other profit................................... 344 Unallocated items Income taxes............................... (7,992) Preferred dividend requirements, net....... (524) ---------- Net income to common.......................$ 13,716 ==========
For the Three Months Ended June 30, 1998 (In thousands)
LPSC Jurisdictional All Utility Other Total ------------ ---------- ---------- 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
Reconciliation between segment amounts and consolidated amounts 10 13 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 ==========
FOR THE SIX MONTHS ENDED JUNE 30, 1999 (IN THOUSANDS)
LPSC JUSIDICTIONAL ALL UTILITY OTHER TOTAL ---------- -------- -------- 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
Reconciliation between segment amounts and consolidated amounts 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 ==========
For the Six Months Ended June 30, 1998 (In thousands)
LPSC Jurisdictional All Utility Other Total -------- -------- -------- 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
Reconciliation between segment amounts and consolidated amounts 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 ==========
11 14 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 15 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. 13 16 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 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 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 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 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 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 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
ESTIMATED PLANNING- DATE OF INITIATIVES ASSESSMENT CORRECTION TESTING IMPLEMENT COMPLETION ----------- ---------- ---------- ------- --------- ---------- 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
*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 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 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. 22 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 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 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:
Broker Class II Directors For Withheld Non-Votes ------------------ --- -------- --------- 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
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:
Broker For Against Abstain Non-Votes --- ------- ------- --------- 18,834,200 62,000 133,619 0
25 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 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 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 31 EXHIBIT INDEX
Exhibit Number Description ------ ----------- 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
EX-11 2 COMPUTATION OF NET INCOME PRE COMMON SHARE 1 CLECO CORPORATION COMPUTATION OF NET INCOME PER COMMON SHARE FOR THE THREE MONTHS ENDED JUNE 30, (Unaudited)
(In thousands, except share and per share amounts) 1999 1998 ------------ ------------ 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 ============ ============
2 CLECO CORPORATION COMPUTATION OF NET INCOME PER COMMON SHARE FOR THE SIX MONTHS ENDED JUNE 30, (Unaudited)
(In thousands, except share and per share amounts) ------------------------------ 1999 1998 ------------ ------------ 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 ============ ============
EX-12 3 COMPUTATION OF EARNINGS TO FIXED CHAREGES 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)
(In thousands, except ratios) 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 ========
* Preferred stock dividends multiplied by the ratio of pretax income to net income. EX-15 4 AWARENESS LETTER - DATED AUGUST 13, 1999 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 EX-27 5 FINANCIAL DATA SCHEDULE
UT 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. 1,000 6-MOS DEC-31-1999 JAN-01-1999 JUN-30-1999 PER-BOOK 1,133,274 3,931 197,151 295,337 8,533 1,638,226 45,557 108,779 274,521 428,852 0 13,314 121,893 0 240,000 119,993 47,374 0 0 0 666,800 1,638,226 344,193 17,733 289,472 307,205 36,988 (515) 36,473 13,693 22,780 1,047 21,733 18,462 4,329 16,530 0.97 0.95
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