-----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, AyLEa3+vK32vbdWFM/HglZZBwd6oiy++iQTdfvCieCvby3Id5hEcL6Jui2SqreY5 FRVstb8TDKsbBvW+HHFDTQ== 0000899243-01-000821.txt : 20010409 0000899243-01-000821.hdr.sgml : 20010409 ACCESSION NUMBER: 0000899243-01-000821 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20001231 FILED AS OF DATE: 20010402 FILER: COMPANY DATA: COMPANY CONFORMED NAME: CLECO POWER LLC 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-K405 SEC ACT: SEC FILE NUMBER: 001-05663 FILM NUMBER: 1591455 BUSINESS ADDRESS: STREET 1: 2030 DONAHUE FERRY ROAD CITY: PINEVILLE STATE: LA ZIP: 71360 BUSINESS PHONE: 3184847400 MAIL ADDRESS: STREET 1: 2030 DONAHUE FERRY ROAD CITY: PINEVILLE STATE: LA ZIP: 71360 FORMER COMPANY: FORMER CONFORMED NAME: CLECO UTILITY GROUP INC DATE OF NAME CHANGE: 19990708 FORMER COMPANY: FORMER CONFORMED NAME: CENTRAL LOUISIANA ELECTRIC CO INC DATE OF NAME CHANGE: 19920703 10-K405 1 0001.txt FORM 10-K FOR YEAR ENDED DECEMBER 31, 2000 - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------------- FORM 10-K [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Transition period from to Commission File No. 0-01272 Cleco Power LLC (Exact name of registrant as specified in its charter) 72-0244480 Louisiana (I.R.S. Employer Identification Number) (State or other jurisdiction of incorporation or organization) 71360-5226 (Zip Code) 2030 Donahue Ferry Road Pineville, Louisiana (Address of principal executive offices) Registrant's telephone number, including area code: (318) 484-7400 Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on Title of each class which registered ------------------- ------------------------ None None
Securities registered pursuant to Section 12(g) of the Act: Title of each class Limited Liability Company Common Equity Units 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 [_] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the Registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] The Registrant meets the conditions set forth in General Instructions I(1)(a) and (b) of Form 10-K and is therefore filing this form with the reduced disclosure format. DOCUMENTS INCORPORATED BY REFERENCE NONE - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- TABLE OF CONTENTS
Page ---- PART I.................................................................... Item 1. Business....................................................... 7 Item 2. Properties..................................................... 21 Item 3. Legal Proceedings.............................................. 22 Item 4. Submission of Matters to a Vote of Security Holders............ 23 PART II................................................................... Item 5. Market Price for Registrant's Common Equity and Related Stockholder Matters............................................. 24 Item 6. Selected Financial Data........................................ 24 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations........................................... 24 Item 8. Financial Statements and Supplementary Data.................... 37 PART III.................................................................. Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure............................................ 62 Item 10. Directors and Executive Officers............................... 62 Item 11. Executive Compensation......................................... 62 Item 12. Security Ownership of Certain Beneficial Owners and Management. 62 Item 13. Certain Relationships and Related Transactions................. 62 PART IV................................................................... Item 14. Exhibits, Financial Statement Schedules and Reports on Form 10-K............................................................ 63
2 Glossary of Terms References in this filing to "we," "us," "the Company" or other similar terms mean Cleco Power LLC, and references to "Cleco" mean Cleco Corporation, unless the context clearly indicates otherwise. Additional abbreviations or acronyms used in this filing are defined below:
Abbreviation or Acronym Definition - ----------------------- ---------- 1935 Act................ Public Utility Holding Company Act of 1935 AFUDC................... Allowance for Funds Used During Construction AQD..................... Air Quality Division of the LDEQ Dynegy.................. Dynegy Power Marketing Inc. CPS..................... Coughlin Power Station DHMV.................... Dolet Hills Mining Venture Dolet Hills............. Dolet Hills Power Station EITF No. 97-4........... Deregulation of the Pricing of Electricity--Issues Related to the Application of FASB Statements No. 71 and 101 EITF No. 98-10.......... Accounting for Contracts Involved in Energy Trading and Risk Management Activities EITF.................... Emerging Issues Task Force EMFs.................... Electric and magnetic fields EPA..................... Environmental Protection Agency ESOP.................... Employee Stock Ownership Plan Evangeline.............. Cleco Evangeline LLC FAC..................... Fuel adjustment clause FASB.................... Financial Accounting Standards Board Federal Court Suit...... Lawsuit filed by the Company and SWEPCO on April 15, 1997 against DHMV and its partners in the United States District Court for the Western District of Louisiana FERC.................... Federal Energy Regulatory Commission Intrastate.............. CLE Intrastate Pipeline Company, Inc. ISO..................... Independent System Operator kV...................... Kilovolt kW...................... Kilowatt kWh..................... Kilowatt-hour LDEQ.................... Louisiana Department of Environmental Quality LMA..................... Lignite Mining Agreement LPDES................... Louisiana Pollution Discharge Elimination System LPSC.................... Louisiana Public Service Commission Marketing & Trading..... Cleco Marketing & Trading LLC Midstream............... Cleco Midstream Resources LLC MMBtu................... Million British thermal units MW...................... Megawatt NOx..................... Nitrogen oxides NPDES................... National Pollutant Discharge Elimination System RTO..................... Regional Transmission Organization Rodemacher.............. Rodemacher Power Station SEC..................... Securities and Exchange Commission
3
Abbreviation or Acronym Definition - ----------------------- ---------- SFAS.................... Statement of Financial Accounting Standards SFAS No. 71............. Accounting for the Effects of Certain Types of Regulation SFAS No. 123............ Accounting for Stock-Based Compensation SFAS 133................ Accounting for Derivative Instruments and Hedging Activities SO\\2\\ ................ Sulfur dioxide SPP..................... Southwest Power Pool State Court Suit........ Lawsuit filed by the Company and SWEPCO on August 13, 1997 against the parent companies of DHMV in the First Judicial District Court for Caddo Parish, Louisiana Support Group........... Cleco Support Group LLC SWD..................... Solid Waste Division of the LDEQ SWEPCO.................. Southwestern Electric Power Company TMDL.................... Total Maximum Daily Loading The Act................. Clean Air Act Amendments of 1990 TRI..................... Toxics Release Inventory UtiliTech............... Utility Construction & Technology Solutions LLC VAR..................... Value-at-risk Williams Energy......... Williams Energy Marketing and Trading Company
4 Disclosure Regarding Forward-Looking Statements This Annual Report on Form 10-K (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, including, without limitation, the statements under "Business-- Operations--Power Purchases," "--Natural Gas Supply," "--Sales," "Regulatory Matters, Industry Developments and Franchises--Industry Developments," "Environmental Matters--Environmental Quality--Air Quality," "Legal Proceedings," "Management's Discussion and Analysis of Financial Condition and Results of Operations" "--Financial Condition--Cash Generation and Cash Requirements--Construction Overview," and Notes D, N and P of the Notes to the Financial Statements, contain forward-looking statements. Included elsewhere in this Report are forward-looking statements regarding sales growth, available power supply, our 1996 Louisiana Public Service Commission (LPSC) settlement, the effect of certain recent Federal Energy Regulatory Commission (FERC) regulations, future legislative and regulatory changes affecting electric utilities, the effects of the outcome of litigation and other legal proceedings, efforts to transfer generation facilities from us to Midstream, capital expenditures, sources of funds for capital expenditures, and other matters. Although we believe 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 those indicated in such forward-looking statements. Forward-looking statements have been and will be made in our written documents and oral presentations. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used in our documents or oral presentations, the words "anticipate," "estimate," "expect," "objective," "projection," "forecast," "goal" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause our actual results to differ materially from those contemplated in any forward- looking statements include, among others, the following: Factors affecting utility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages; unusual maintenance or repairs; unanticipated changes to fuel costs, gas supply costs, or availability constraints due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints; Increased competition in the electric environment, including effects of industry restructuring or deregulation, transmission system operation or administration, retail wheeling or cogeneration; 5 Regulatory factors such as unanticipated changes in rate-setting policies or procedures; recovery of investments made under traditional regulation; and the frequency and timing of rate increases; Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board (FASB), the Securities and Exchange Commission (SEC), the FERC, the LPSC or similar entities with regulatory or accounting oversight; Economic conditions, including inflation rates and monetary fluctuations; Changing market conditions and a variety of other factors associated with physical energy and financial trading activities, including, but not limited to, price, basis, credit, liquidity, volatility, capacity, transmission, interest rate and warranty risks; Availability or cost of capital resulting from changes in U.S. interest rates, and securities ratings or market perceptions of the electric utility industry and energy related industries; Employee work force factors, including changes in key executives; Legal and regulatory delays and other obstacles associated with mergers, acquisitions, capital projects, reorganizations or investments in joint ventures; Cost and other effects of legal and administrative proceedings, settlements, investigations, claims and other matters; and Changes in federal, state or local legislature requirements, such as changes in tax laws or rates, regulating policies, or environmental laws and regulations. We undertake no obligation to update or revise any forward-looking statements, whether as a result of changes in actual results, changes in assumptions or other factors affecting such statements. 6 PART I. ITEM 1. BUSINESS. General We are a Louisiana limited liability company and a wholly owned principal subsidiary of Cleco Corporation, a diversified energy service holding company. We are an electric utility that provides generation, transmission and distribution electric utility operations subject to the jurisdiction of the LPSC. We provide electric utility services to approximately 249,000 retail and wholesale customers in 63 communities and rural areas in a 14,000-square-mile region in the State of Louisiana. Cleco Corporation, subject to certain limited exceptions, is exempt from regulation as a public utility holding company pursuant to Section 3(a)(1) of the Public Utility Holding Company Act of 1935 (1935 Act) and Rule 2 thereunder. Cleco Corporation is subject to the reporting requirements of the Securities Exchange Act of 1934. Our principal executive offices are located at 2030 Donahue Ferry Road, Pineville, Louisiana 71360-5226, and our phone number at this address is (318) 484-7400. On December 31, 2000, Cleco Utility Group Inc., a wholly owned subsidiary of Cleco Corporation, converted its form of business organization from a corporation to a limited liability company by merging with and into us. This conversion was effected in order to lessen Cleco Utility Group's Louisiana state tax obligations. We held no significant assets or liabilities prior to the conversion. As a result of the conversion, we acquired all of Cleco Utility Group's assets and assumed all of its liabilities. We obtained the necessary regulatory approvals from the FERC and the LPSC prior to engaging in the conversion. Cleco Utility Group, formerly named Cleco Corporation, was incorporated under the laws of the State of Louisiana on January 2, 1935. Effective July 1, 1999, Cleco Utility Group was reorganized into a holding company structure. This reorganization resulted in the creation of a holding company, Cleco Corporation, which became the owner of all of Cleco Utility Group's outstanding stock. This stock was converted into common equity in us in the conversion of Cleco Utility Group. Operations Power Generation We operate and either own or have an ownership interest in three steam electric generating stations, the Teche Power Station, the Rodemacher Power Station (Rodemacher) and the Dolet Hills Power Station (Dolet Hills) and a gas turbine, the Franklin Gas Turbine. We are the sole owner of Teche Power Station and Rodemacher Unit 1. We own a 50% interest in Dolet Hills Unit 1 and a 30% interest in Rodemacher Unit 2. At December 31, 2000, our aggregate electric generating capacity was 1,366,900 kilowatts (kW). We are the sole owner of the Franklin Gas Turbine. 7 The following table sets forth certain information with respect to our generating facilities.
Capacity at Year of December 31, Type of fuel used Generating initial Generating Station 2000 (kW) for generation(1) Unit # operation - ------------------ ------------ ----------------- ---------- --------- Franklin Gas Turbine.... 7,000 gas 1 1973 Teche Power Station..... 23,000 gas 1 1953 48,000 gas 2 1956 367,000 gas/oil (standby) 3 1971 Rodemacher Power Station................ 440,000 gas/oil 1 1975 156,900(2) coal/gas 2 1982 Dolet Hills Power Station................ 325,000(3) lignite 1 1986 --------- Total Generating Power.. 1,366,900 =========
- -------- (1) When oil is used on a standby basis, capacity may be reduced. (2) Represents our 30% interest in the capacity of Rodemacher Unit 2, a 523,000-kW generating unit. (3) Represents our 50% interest in the capacity of Dolet Hills Unit 1, a 650,000-kW generating unit. In February 1999 the LPSC approved the transfer of the existing Coughin Power Station (CPS) assets out of our LPSC-regulated rate base into Cleco Evangeline LLC (Evangeline), and indirect wholly-owned subsidiary of Cleco Corporation. The actual transfer occurred in November 1999. In return for the approval of the asset transfer, we agreed to extend the terms of our 1996 rate settlement with the LPSC for an additional three years to 2004. See "-- Regulatory Matters Industry Developments and Franchises--Rates" for more information about our LPSC Settlement. The agreement also contains specific provisions designed to hold our ratepayers harmless from negative impacts that might result from the removal of the CPS generating assets from our rate base. In return, we were authorized to transfer the CPS generating and transmission assets to Evangeline at their net book value of approximately $9.8 million. This resulted in a reduction in our generating capability of 334,000 kW. We are exploring the possibility of transferring additional generation facilities to Cleco Midstream Resources LLC, a wholly owned subsidiary of Cleco Corporation. Management believes any potential transfer of LPSC jurisdiction generation facilities to Midstream would be accompanied by consumer safeguards for our retail customers. Management is unable to predict whether it will be able to transfer any additional generation to Midstream or what impact any such transfer would have on our financial condition or results of operations. Fuel Changes in fuel and purchased power expenses reflect fluctuations in generation fuel mix, fuel costs, availability of economic purchased power and deferral of expenses for recovery from customers through fuel adjustment clauses in subsequent months. We use various types of fuel for generation of electricity. The following table sets forth, for the periods indicated, the percentages of power generated from various fuels at our electric generating plants, the cost of fuel used per kilowatt hour (kWh) attributable to each such fuel and the weighted average fuel cost per kWh. 8
Lignite Coal Gas Fuel Oil Weighted ------------------ ------------------ ------------------ ------------------ average Cost Cost Cost Cost cost per per kWh Percent of per kWh Percent of per kWh Percent of per kWh Percent of kWh Period (cents) generation (cents) generation (cents) generation (cents) generation (cents) - ------ ------- ---------- ------- ---------- ------- ---------- ------- ---------- -------- 2000.................... 1.556 37.0 1.507 16.8 4.678 45.7 4.318 0.5 2.988 1999.................... 1.574 28.5 1.490 17.2 2.745 54.3 -- -- 2.196 1998.................... 1.585 32.0 1.488 16.7 2.538 51.3 -- -- 2.057 1997.................... 1.485 36.7 1.706 19.1 2.985 44.2 -- -- 2.190 1996.................... 1.545 38.1 1.667 21.3 3.006 39.8 2.609 0.8 2.161
Power Purchases If transmission capacity is available, we purchase electric energy from neighboring utilities and energy marketing companies when the price of the energy purchased is less than our cost of generating energy from our own facilities or when we need power to supplement our own electric generation. We have a long-term contract under which we purchase 20,000 megawatt (MW) of firm power from the Sabine River Authority. In addition, we have several power contracts with two energy marketing companies for 605 MW of capacity in 2000, increasing to 760 MW of capacity in 2004. In March 2000, following a competitive bid process, we entered into three contracts for firm electric capacity and energy with Williams Energy Marketing and Trading Company (Williams Energy) and Dynegy Power Marketing, Inc. (Dynegy), for 605 megawatts (MW) of capacity in 2000, increasing to 760 MW of capacity in 2004. These contracts were approved by the LPSC in March 2000 and expire in 2004. In 2000, the amount of power we purchased increased compared to 1999 as a result of the increased demand for electric energy and the reduction of our generation capacity resulting from the transfer of the existing assets of (CPS) from our LPSC-regulated rate base in 1999 into (Evangeline), which repowered the plant. The following table sets forth the amounts of power we purchased on the wholesale market, including pursuant to the power purchase agreements discussed above, for the periods indicated.
% of Total Million Energy Period kWh Requirements ------ ------- ------------ 2000................................................. 3,255 34 1999................................................. 2,359 27 1998................................................. 2,117 24 1997................................................. 1,924 24 1996................................................. 2,529 33
For information regarding our ability to pass through changes in costs of fuel to our customers, see "--Regulatory Matters, Industry Developments and Franchises--Rates" below. In future years, our generating facilities may not supply enough electric power to meet our customers' growing demand (native load demand) and we may need to purchase additional generating capacity and/or purchase power to satisfy these needs. 9 Management expects to meet substantially all of our native load demand through 2004 with our own generation capacity and the power purchase agreements discussed above. Because of our location on the transmission grid, we rely on one main supplier of electric transmission and are sometimes constrained as to the amount of purchased power we can bring into our system. The three power supply contracts with Williams and Dynegy discussed above are not expected to be affected by such transmission constraints. Natural Gas Supply During 2000, we purchased a total of 31,210 million British thermal units (MMBtu) of natural gas for the generation of electricity. The annual and average per-day quantities of gas we purchased from each supplier are shown in the table below.
Average Amount 2000 purchased Percent purchases per day of total Natural gas supplier (MMBtu) (MMBtu) gas used - -------------------- --------- --------- -------- Amoco Natural Gas.................................. 5,583 15.3 17.89 ONEOK.............................................. 3,825 10.5 12.26 Reliant Energy Services, Inc....................... 3,571 9.8 11.44 Louisiana Interstate Gas........................... 2,486 6.8 7.97 Exxon.............................................. 1,723 4.7 5.52 Others............................................. 14,022 38.4 44.92 ------ ---- ------ 31,210 85.5 100.00 ====== ==== ======
CLE Intrastate Pipeline Company, Inc. (Intrastate), a wholly owned subsidiary of one of our affiliates, owns a series of natural gas interconnections with Trunkline Gas Company, Columbia Gulf Transmission Co. and ANR Pipeline Company. The pipeline interconnections have allowed us to access various additional natural gas supply markets, which helps to maintain the competitiveness of our generating units. Natural gas was available without interruption throughout 2000, although, the price of natural gas increased significantly in 2000 as compared to 1999 due to increased demand and decreased production. We currently meet, and expect to continue to meet, our natural gas requirements with purchases on the spot market through daily, monthly and seasonal contracts with various natural gas suppliers. However, future supplies of natural gas remain vulnerable to disruptions due to weather events and transportation disruptions. The potential for disruptions to us has been decreased by the addition of the Intrastate pipeline interconnections. Nevertheless, large boiler fuel users of natural gas, including electric utilities, generally have low priority among natural gas users in the event pipeline suppliers are forced to curtail deliveries due to inadequate supplies. As a result, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply disruptions. Such events, though rare, may require us to shift our gas-fired generation to alternative fuel sources, such as fuel oil, to the extent we have the capability to burn those alternative fuels. Currently, we anticipate that our alternative fuel capability, combined with our solid-fuel generation resources, are adequate to meet our fuel needs during any temporary disruption of natural gas supplies. 10 Coal and Lignite Supply We use coal fuel for generation at Rodemacher Unit 2. The majority of the coal for Rodemacher Unit 2 is purchased from mines in Wyoming under a long- term contract with Jacobs Ranch Coal Company expiring in 2007. The contract has been modified under price reopener procedures initiated in early 1997. The pricing structure under the modified contract has been defined through mid- 2002. After purchasing a given annual quantity of base coal (approximately 500,000 tons in 2000), we have the right to purchase coal from third parties on the spot market through competitive bidding. Provisions for pricing and terms can again be renegotiated in early 2002 under a contract reopener provision which expires on June 30, 2002. If negotiations are not complete by the expiration date, the contract terminates unless the parties have expressly agreed in writing to extend the negotiating period. Management currently expects to complete negotiations before the expiration. We currently meet, and expect to continue to meet, our coal requirements with purchases on the spot market through daily, monthly and seasonal contracts with various coal suppliers. We use lignite fuel for generation at Dolet Hills Unit 1. Substantially all of the lignite used to fuel Dolet Hills Unit 1 is obtained under two long-term agreements. We and Southwestern Electric Power Company (SWEPCO), each a 50% owner of Dolet Hills Unit 1, have entered into agreements pursuant to which each acquired an undivided 50% interest in the other's leased and owned lignite reserves in northwestern Louisiana. We and SWEPCO also have entered into a long-term agreement expiring in 2011 with the Dolet Hills Mining Venture (DHMV) for the mining and delivery of such lignite reserves. These reserves are expected to provide a substantial portion of the fuel requirements for the projected operating life of Dolet Hills Unit 1. Our minimum annual purchase requirement under the agreement with DHMV is 1,750,000 tons. The price of lignite delivered pursuant to the agreement is a base price per ton, subject to escalation based on certain inflation indices, plus specified "pass-through" costs. Additional spot lignite may be obtained through competitive bidding. We are currently engaged in litigation involving our agreement with DHMV. For information regarding this litigation, see "Item 3. Legal Proceedings" below. Additionally, we and SWEPCO have entered into a long-term agreement expiring in 2011 with Red River Mining Co., a joint venture of the North American Coal Corporation and Phillips Coal Company, which provides for base contract purchases and spot purchases of lignite. Our minimum annual purchase requirement is 550,000 tons. The base lignite price under the agreement is a base price per MMBtu, subject to escalation, plus certain "pass-through" costs, while the spot lignite price is determined through competitive bidding. The continuous supply of coal and lignite from the mining sources described above may be subject to interruption due to adverse weather conditions or other factors that may disrupt mining operations or transportation. At December 31, 2000, our coal inventory at Rodemacher Unit 2 was approximately 120,974 tons (about a 58-day supply) and our lignite inventory at Dolet Hills Unit 1 was approximately 148,770 tons (about a 25-day supply). Oil Supply We store fuel oil as an alternative fuel source. Rodemacher has storage capacity for an approximate 75-day supply and our other generating stations have storage capacity totaling about a 20-day supply. However, in accordance with our current fuel oil inventory practices, at December 31, 2000, we had between 5 to 10 days' supply of fuel oil stored at our generating stations. During 2000, approximately 2.2 million gallons of fuel oil were burned. Fuel oil was burned during 2000 because the cost of using fuel oil to generate electricity was lower than the cost of using natural gas. 11 Sales We are a public utility engaged principally in the generation, transmission, distribution and sale of electricity within the State of Louisiana. For further information regarding our generating stations and transmission and distribution facilities, see "--Power Generation" above and "Item 2. Properties" below. Our 2000 system peak demand occurred in August and was 1,839,000 kW. Our sales and peak demand are affected and influenced by weather and are generally highest during the summer air-conditioning and winter heating seasons. For information concerning the financial effects of seasonal demand on our quarterly operating results, see Note O to the audited financial statements included in "Financial Statements and Supplemental Data" in Item 8 below. Capacity reserve margin is the net capacity resources (either owned capacity or purchased capacity) less native load demand divided by your net capacity resources. Our capacity reserve margin is established by the Southwest Power Pool (SPP) at 12%. A member of the SPP meets the capacity reserve margin goal by submitting the forecasted native load demand and the forecasted mix of net capacity resources to meet the forecasted native load demand. In 2000, we were deemed to have met the reserve requirements established by the SPP. If capacity reserve requirements are not met, the SPP can require higher capacity reserve requirements in subsequent years. Our capacity reserve margin for 2000 was 7.7%. We expect the peak demand on our system to grow at a compound annual rate of approximately 2% to 3% over the next five years. To meet our capacity reserve margin through 2004, we purchased 605 MW of firm capacity and transmission service that began on June 1, 2000, and increases to 760 MW in 2004 pursuant to several agreements. See "--Power Purchases" above for a description of these power purchase agreements. We believe we can meet our anticipated growth in customer demand by purchasing the required capacity on the wholesale market. Future capacity requirements may be satisfied by continuing to purchase power on the wholesale market. Marketing Operations We began marketing electricity into the Entergy market in mid-1998. In 1999, we expanded that activity into the Cinergy market. In 1999, we also began marketing natural gas. We have seen a reduction in energy marketing revenues in 2000 when compared with prior years due to a reduced level of energy trading activity resulting from a refinement of trading practices to target selective market opportunities and due to the transfer of specific CPS generating assets to Evangeline. If we have excess electricity capacity or excess natural gas at our power plants, Cleco Marketing & Trading LLC (Marketing & Trading), an affiliate of ours, markets the excess on our behalf. Marketing & Trading also develops a monthly gas procurement strategy for us, giving priority to achieving a reliable supply of gas to fuel our power plants, maintaining operational flexibility and cost of service in developing the strategy. Marketing & Trading charges us a fee for managing fuel cost, resource coordination and marketing excess electric power and natural gas. This fee is based on cost incurred for such services by Marketing & Trading. 12 Energy Marketing Operations
Year ended December 31, ------------------------ 2000 1999 1998 ------- -------- ------- (Thousands) Revenue.......................................... $18,078 $237,731 $32,695 Purchases........................................ 13,583 230,084 27,322 ------- -------- ------- Gross Margin..................................... $ 4,495 $ 7,647 $ 5,373 ======= ======== =======
Regulatory Matters, Industry Developments and Franchises Rates Our retail electric operations are subject to the jurisdiction of the LPSC with respect to rates, standards of service, accounting and other matters. We also are subject to the jurisdiction of the FERC with respect to certain aspects of our business, including rates for wholesale service, interconnections with other utilities and the transmission of power. Periodically, we have sought and received increases in base rates from both the LPSC and the FERC to cover increases in operating costs and costs associated with additions to generation, transmission and distribution facilities. Our electric rates include a fuel and purchased power cost adjustment clause that enables us to adjust rates for monthly fluctuations in the cost of fuel and short-term purchased power. Pretax income from certain off-system sales to other utilities is passed on to customers through a reduction in fuel cost adjustment billing factors. Fuel costs and fuel adjustment billing factors are approved by the LPSC and the FERC. These cost adjustments are based on costs from earlier periods that can result in over- or under-recovery for the period in which the adjustment is made. Any over- or under-recovery is corrected by an adjustment in later periods. At December 31, 2000, the net accumulated asset for under-recovery on sales subject to the LPSC's jurisdiction was approximately $3.6 million, which is reported as accumulated deferred fuel on the balance sheets included in this Report. The LPSC elected in 1993 to review the earnings of all electric, gas, water and telecommunications utilities that it regulates to determine whether the returns on equity of these companies were higher than returns that might be awarded in the economic environment at that time. In 1996, the LPSC approved a settlement of our earnings review, which lowered our electricity rates. The terms of the settlement were to be effective for a five-year period. In February 1999, the period was extended three years until 2004. For information regarding this settlement, see "Management's Discussion and Analysis of Financial Condition and Results of Operations --Financial Condition--Retail Rates" in Item 7 below. 13 We are exploring the possibility of transferring generation facilities to Midstream. Management believes any potential transfer of LPSC jurisdictional generation facilities to Midstream would be accompanied by consumer safeguards for our retail customers. Management is unable to predict whether it will be able to transfer any additional generation to Midstream or what impact any such transfer would have on our financial condition or results of operations. Franchises We operate under nonexclusive franchise rights granted by governmental units, such as municipalities and parishes (counties), and enforced by state regulation. These franchises are for fixed terms, which vary from 10 years to 50 years. In the past, we have been substantially successful in the timely renewal of franchises as each reaches the end of its term. In February 2001, we successfully negotiated a franchise with the City of Jeanerette for a 20- year franchise covering its approximately 3,000 customers. The City of Jeanerette franchise had expired in 1997, and we continued to serve the city while negotiating for a new franchise. Our franchise with the City of Opelousas, which has 10,873 customers, was scheduled to expire in August 2001. In November 2000, we successfully negotiated the renewal of that franchise for a term of 10 years, beginning August 2001. Our franchises with the cities of Washington and Franklinton, and their 1,891 and 2,484 customers respectively, will be up for renewal in 2003. We were successful in an October 7, 2000, referendum to renew our franchise agreement with the City of New Iberia, where we currently serve 18,744 customers, for a term of 25 years. No other franchises expire until 2008. A number of parishes have attempted in recent years to impose franchise fees on retail revenues earned within the unincorporated areas we serve. If the parishes are ultimately successful, taxes other than income taxes could increase substantially in future years. Industry Developments Technological improvements in recent years have somewhat lessened the historical barriers to entry in the electric utility industry and have set in motion statutory and regulatory changes aimed at increased competition in the industry. Federal and state legislation and new regulatory initiatives designed to restructure electricity markets will likely produce even greater competition at both wholesale and retail levels in the future. In 2000, the LPSC staff developed a transition to competition plan that was proposed to the LPSC. The staff's plan would allow large industrial customers to have the opportunity to choose a power provider starting in January 2003. The plan does not suggest a date for residential or commercial customers. On January 19, 2001, the LPSC staff presented their proposed competitive transition plan to the commissioners. All interested parties were given a 45 day period to comment on different aspects of the plan. We expect commission action on the plan in April 2001. The LPSC is investigating whether retail choice is in the best interest of Louisiana electric utility customers. 14 Several neighboring states have passed legislation providing for retail choice by 2002. At the federal level, several bills, some with conflicting provisions, have been introduced and were actively debated in the last few years to promote a more competitive environment in the electric utility industry, although none were passed. Conversely, the troubled electric supply situation experienced in California this past year has led many participants in the industry to reexamine and question certain aspects of the restructuring process. While a competitive environment continues to be espoused in many markets, several states have modified or abandoned their restructuring efforts or have asked for delays in implementing already passed rules or regulations. Management expects the debate relating to retail choice and other related issues to continue in legislative and regulatory bodies in 2001. At this time, we cannot predict whether any legislation or regulation will be enacted or adopted during 2001 and, if enacted, what form such legislation or regulation would take. Wholesale Electric Competition The Energy Policy Act, enacted by Congress in 1992, significantly changed U.S. energy policy, including regulations governing the electric utility industry. The Energy Policy Act allows the FERC, on a case-by-case basis and with certain restrictions, to order wholesale transmission access and to order electric utilities to enlarge their transmission systems. The Energy Policy Act prohibits FERC-ordered retail wheeling (i.e., opening up electric utility transmission systems to allow customer choice of energy suppliers at the retail level), including "sham" wholesale transactions. Further, under the Energy Policy Act, a FERC transmission order requiring a transmitting utility to provide wholesale transmission services must include provisions generally permitting the utility to recover from the FERC applicant all of the costs incurred in connection with the transmission services, including any enlargement of the transmission system and any associated services. In addition, the Energy Policy Act revised the 1935 Act to permit utilities, including registered holding companies, and nonutilities to form "exempt wholesale generators" without the principal restrictions of the 1935 Act. Under prior law, independent power producers were generally required to adopt inefficient and complex ownership structures to avoid pervasive regulation under the 1935 Act. In 1996, the FERC issued Orders No. 888 and 889 requiring open access to utilities' transmission systems. The open access provisions require FERC- regulated electric utilities to offer third parties access to transmission under comparable terms and conditions as the utilities' use of their own systems. In addition, Order No. 888, as amended, provides for the full recovery from a utility's departing customers of wholesale stranded costs, to the extent such costs were prudently incurred to serve wholesale customers and would go unrecovered if those customers used open access transmission service and moved to another electricity supplier. Order No. 888, as amended, also allows customers under existing wholesale sales contracts to seek FERC approval to modify their contracts on a case-by-case basis. Because of the "grandfather" provisions of Orders No. 888 and 889, most of our existing transmission contracts are not affected by Orders No. 888 and 889. To date, the orders have not had a material impact on our operations or financial condition. 15 In 1999, the FERC issued Order No. 2000, which further defines the operation of utilities' transmission systems. Order No. 2000 establishes a general framework for all transmission-owning entities in the nation to place their transmission facilities under the control of appropriate Regional Transmission Organizations (RTO). Although participation is voluntary, the FERC has made it clear that any jurisdictional entity not participating in an RTO will be subject to further regulatory directives. Current objectives state that all electric utilities that own, operate or control interstate transmission facilities should participate in an RTO that will be operational no later than December 15, 2001. On October 16, 2000, we submitted a filing with the FERC stating we will join the SPP RTO either as a member of the SPP Independent System Operator (ISO) or as part of Entergy's transmission company by December 15, 2001. Our decision will be made once the details of the transmission companies are finalized. The transfer of control of our transmission facilities to an RTO has the potential to materially affect our results of operations and financial condition. Wholesale energy markets, including the market for wholesale electric power, have been competitive and are becoming even more so as the number of participants in these markets increases as a result of enactment of the Energy Policy Act and the regulatory activities of the FERC. For a Discussion of regulatory accounting relating to our electric utility operations, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financial Condition--Regulatory Matters" in Item 7 below. Retail Electric Competition Currently, the LPSC does not provide exclusive service territories for electric utilities under its jurisdiction. Instead, retail service is obtained through the long-term, nonexclusive franchises described above under "-- Franchises." The LPSC uses a "300 foot rule" for determining the supplier for new customers. The application of this rule has led to competition with neighboring utilities for retail customers at the borders of our service areas. We also compete in our service area with suppliers of alternative forms of energy, some of which may be less costly than electricity for certain applications. We could experience some competition for electric sales to industrial customers in the form of cogeneration or from independent power producers. However, we believe that our rates and the quality and reliability of our service place us in a favorable competitive position in current retail markets, as we have ranked number one in reliability among electric utility companies in our state for the past two years, based upon annual filings in the LPSC Reliability Order. Legislative and Regulatory Changes and Matters Various federal and state legislative and regulatory bodies are considering a number of issues in addition to those discussed above that will shape the future of the electric utility industry. Such issues include, among others: . the deregulation of retail electricity sales; . the ability of electric utilities to recover stranded costs; 16 . the repeal or modification of the 1935 Act; . the unbundling of vertically integrated electric utility companies into separate business segments or companies (i.e., generation, transmission, distribution and retail energy service); . the role of electric utilities, independent power producers and competitive bidding in the construction and operation of new generating capacity; and . the pricing of transmission service on an electric utility's transmission system. We are unable, at this time, to predict the outcome of these issues or their effect on our financial position, results of operations or cash flows. For information on certain regulatory matters and regulatory accounting affecting us, see "Management's Discussion and Analysis of Financial Condition and Results of Operations--Financial Condition" in Item 7 below. Environmental Matters Environmental Quality We are subject to numerous laws and regulations administered by federal, state and local authorities to protect the environment. These statutory and regulatory provisions impose various substantive requirements, the violation of which may result in substantial fines and penalties. Environmental requirements continue to increase as a result of new legislation, administrative actions and judicial interpretations. Therefore, the precise future effects of existing and potential requirements are difficult to determine. During 2000, our capital expenditures related to environmental compliance totaled approximately $0.5 million, due to routine replacement of pollution control devices at various plants. Expenditures related to environmental compliance for 2001 are estimated to total approximately $0.6 million. Air Quality The State of Louisiana regulates emissions from each of our generating units through regulations issued by the Air Quality Division (AQD) of the Louisiana Department of Environmental Quality (LDEQ). In addition, the AQD implements certain programs initially established by the federal Environmental Protection Agency (EPA). The AQD establishes standards of performance or requires permits for certain generating units in Louisiana. All of our generating units are subject to these requirements. The federal Clean Air Act Amendments of 1990 (the Act) established a regulatory program to address the effects of acid rain and imposed restrictions on sulfur dioxide (SO\\2\\) emissions from certain generating units. The Act essentially requires that utilities, like us, must hold a regulatory "allowance" for each ton of SO\\2\\ emitted beginning in the year 2000. The EPA is required to allocate a set number of allowances to each affected unit based on its historic emission levels. As of December 31, 2000, we expect to have sufficient allowances for 2001. 17 The Act also requires the EPA to revise nitrogen oxides (NOx) emission limits for existing coal-fired boilers. In November 1996, the EPA finalized rules lowering the NOx emission rate for certain boilers, including Rodemacher Unit 2 and Dolet Hills Unit 1. Under this rule, Rodemacher Unit 2 and Dolet Hills Unit 1 would have had to meet this new emission rate by January 1, 2000. The rule also allows an option to "early elect," that is, achieve compliance with a less restrictive NOx limit beginning January 1, 1997. We exercised this option in December 1996. Early election protects us from any further reductions in the NOx permitted emission rate until 2008. Rodemacher Unit 2 and Dolet Hills Unit 1 were in compliance with the NOx early election limits in 1998, 1999 and 2000 and are expected to be in compliance in 2001 without undergoing significant capital improvements. Significant future reductions in NOx emission limits may require modification of burners or other capital improvements at either or both of these units. Water Quality We have received from the EPA all National Pollutant Discharge Elimination System (NPDES) permits required under the Clean Water Act for discharges from our four generating stations. NPDES permits have fixed dates of expiration and we have applied for renewal of these permits within the applicable time periods. The Office of Water Resources of the LDEQ requires facilities that discharge wastewater into Louisiana waters to obtain permits from the Louisiana Pollution Discharge Elimination System (LPDES). We have applied for and received LPDES permits for our four generating stations. For the upcoming session of the Louisiana Legislature, a proposed bill, Senate Bill 1 has been filed for consideration. The bill institutes a process by which all new industrial and agricultural users of groundwater must apply for and obtain permits to pump groundwater if their wells have a maximum flow rate of one million gallons or more. If the bill becomes law, management expects that it will not have a material adverse effect on our financial condition or results of operations. The federal Clean Water Act, which was passed in 1972, contains provisions requiring the EPA to evaluate all bodies of water within its jurisdiction to determine if they meet water quality standards and to establish a program to bring noncompliant bodies of water into compliance with the standards. Given the enormous number of bodies of water required to be evaluated and the complexity of standards set forth in the Clean Water Act, the EPA has not completed the requirements. In the last few years, environmental groups have sued the EPA over the failure to address these requirements of the Clean Water Act. In October 1999, the EPA received a federal court order to develop and implement Total Maximum Daily Loadings (TMDLs) for all impacted streams in Louisiana. The TMDLs will restrict the amount of specific covered pollutants that may be discharged under revised permits that will incorporate the limitations of TMDL. The EPA has released TMDLs for copper, oxygen demanding substances and nutrients, none of which have had a material impact on us. We are evaluating the potential impact of current and future TMDL limitations to its facilities. 18 Solid Waste Disposal The Solid Waste Division (SWD) of the LDEQ has adopted regulations and a permitting system for the management and disposal of solid waste generated by power stations. We have received all required permits from the SWD for the on- site disposal of solid waste generated at our four generating stations. Hazardous Waste Generation We produce certain wastes at our four generating stations and at other locations that are classified as hazardous. The Hazardous Waste Division of the LDEQ regulates these wastes and has issued identification numbers to the sites where such wastes are produced. We do not treat, store or dispose of these wastes on-site; therefore, no permits are required. All hazardous wastes we produce are disposed of at federally permitted hazardous waste disposal sites. Toxics Release Inventory The Toxics Release Inventory (TRI) is a part of the Emergency Planning and Community Right to Know Act and is administered by the EPA. The TRI is an annual reporting requirement for industrial facilities on about 650 substances they release into air, water and land. The TRI ranks companies based on how much of a particular substance they release on a state level and a parish (county) level. We were exempt from the reporting requirements of the TRI until the EPA added seven new industry groups, including electric utility facilities, to the TRI in May 1997. We submitted timely TRI reports on our 1998 activities and the TRI rankings were made publicly available by the EPA and LDEQ reported TRI data in May and June 2000, respectively. The rankings do not result in any federal or state penalties, and did not result in any significant adverse public perceptions of us. Management is aware of the potential adverse effects and continues to monitor the TRI process. Management is currently taking steps to protect against possible negative public perception of the Company as a result of the TRI, by increasing the recycling of fly ash from Dolet Hills. Electric and Magnetic Fields The possibility that exposure to electric and magnetic fields (EMF) emanating from electric power lines, household appliances and other electric devices may result in adverse health effects or damage to the environment has been a subject of recent public attention. We fund research on EMFs through various organizations. The scientific research conducted to date concerning the effects of EMFs has not led to any definitive results, but research is continuing. Lawsuits alleging that the presence or use of electric power transmission and distribution lines has an adverse effect on health and/or property values have arisen in several states against electric utilities and others. Customers No customer accounted for 10% or more of our electric operating revenues in 2000, 1999, or 1998. Additional information regarding our sales and revenues is set forth in "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Item 7. below. Employees At December 31, 2000, we had 992 full-time employees. Employee relations are good and we have not had any material work stoppage due to labor disagreements. 19 ITEM 2. PROPERTIES All of our electric generating stations and all other electric operating properties are located in the State of Louisiana. We consider all of our properties to be well maintained, in good operating condition and suitable for their intended purposes. Electric Generating Stations As of December 31, 2000, we either owned or had an ownership interest in three steam electric generating stations and a gas turbine with a combined electric generating capacity of 1,366,900 kW. For additional information regarding our generating facilities, see "Business Operations--Power Generation" in "Item 1" above. Electric Substations and Lines As of December 31, 2000, we owned 87 transmission substations and 313 distribution substations. As of December 31, 2000, our transmission system consisted of approximately 67 circuit miles of 500 kilovolt (kV) lines, 462 circuit miles of 230 kV lines, 661 circuit miles of 138 kV lines, and 17 circuit miles of 69 kV lines. Our distribution system consisted of approximately 2,256 circuit miles of 34.5 kV lines and 12,414 circuit miles of other lines. General Properties We own various properties, which include a seven-story headquarters office building, regional offices, a central warehouse, service centers, telecommunications equipment and other facilities owned for general purposes. Title Our electric generating plants and certain other principal properties are owned in fee. Electric transmission and distribution lines are located either on private rights-of-way or along streets or highways by public consent. Substantially all of our property, plant and equipment is subject to a lien securing our obligations under an Indenture of Mortgage, which does not impair the use of such properties in the operation of our business. 20 ITEM 3. LEGAL PROCEEDINGS Proceeding before the LPSC For information on the proceedings before the LPSC see Note M in the Notes to the Financial Statements. Fuel Supply--Lignite We and SWEPCO, each a 50% owner of Dolet Hills Unit 1, jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982, we and SWEPCO entered into a Lignite Mining Agreement (LMA) with 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, we are receiving annually a minimum delivery of 1,750,000 tons under the LMA. Since the late 1980s, additional spot lignite deliveries have been obtained through competitive bidding from DHMV and another lignite supplier. In 2000, we and SWEPCO received deliveries that approximated 25% of the annual lignite consumption at the Dolet Hills Unit 1 from the other lignite supplier. On April 15, 1997, we and SWEPCO filed suit against DHMV and its partners in the United States District Court for the Western District of Louisiana (the Federal Court Suit), seeking to enforce various obligations of DHMV to us 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 our suit and filed a counterclaim asserting various contract-related claims against us and SWEPCO. We and SWEPCO have denied the allegations in the counterclaims. As a result of the counterclaims filed by DHMV in the Federal Court Suit, on August 13, 1997, we and SWEPCO filed a separate lawsuit against the parent companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA, Inc. 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 March 1, 2000, the court in the Federal Court Suit ruled that DHMV was not in breach of certain financial covenants under the LMA and denied our and SWEPCO's claim to terminate the LMA on that basis. The ruling has no material adverse effect on our operations and does not affect the other claims scheduled for trial. We and SWEPCO have appealed the federal court's ruling to the United States Court of Appeals for the Fifth Circuit. The civil, nonjury trial in the Federal Court Suit was to have commenced on May 22, 2000. However, on April 20, 2000, all parties jointly requested that the court postpone the trial date and grant a 120-day stay of all matters before the trial court to give the parties an opportunity to attempt to reach an amicable resolution of the litigation. A preliminary memorandum of understanding to settle the litigation has been executed among us, SWEPCO, and DHMV. However, the memorandum of understanding is subject to several conditions precedent that are not yet fulfilled, including prior authorization by the LPSC of favorable rate recovery of the settlement by us and SWEPCO. The federal court granted the motion, stayed the action at the trial court and postponed the trial commencement date to October 23, 2000. At a status conference held on July 12, 2000, the court extended the stay of the proceedings and again postponed the trial date to January 16, 2001. Due to the need for additional time to attempt to refine the settlement, the parties requested, and on September 26, 2000, the court ordered that the stay be extended and the trial date be postponed indefinitely. The Fifth Circuit appeal of the federal court's March 1, 2000, ruling has also been stayed pending settlement. Settlement negotiations are ongoing during the pendency of the stay. 21 Should settlement discussions be unsuccessful, we and SWEPCO will continue aggressively to prosecute the claims against DHMV and defend against the counterclaims that DHMV has asserted. We and SWEPCO continue to pay DHMV for lignite delivered pursuant to the LMA. Normal day-to-day operations continue at the Dolet Hills Mine and Dolet Hills Unit 1. Although the ultimate outcome of this litigation or the settlement negotiations cannot be predicted at this time, based on information currently available to us, management does not believe that the outcome of the Federal Court Suit or any settlement in the Federal Court Suit will have a material adverse effect on our financial position or results of operations. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS. Information for this Item is omitted pursuant to General Instruction I to Form 10-K. PART II. ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS. There is no market for our common equity units. All of our outstanding common equity units are owned by our parent, Cleco Corporation. Distributions on our common equity units will be paid when and if declared by our board of managers. Our current credit agreement contains some restrictions on our ability to pay cash distributions on our common equity units. Any future distributions also may be restricted by any credit or loan agreements that we may enter into from time to time. Certain provisions contained in the debt instruments under certain circumstances restrict the amount of equity available for the payment to members by us. The most restrictive covenant requires that member's equity be not less than 30% of total capitalization, including short-term debt. At December 31, 2000, approximately $164.4 million of member's equity was not restricted. The following table shows the dividends per share paid to holders of common shares for the last two fiscal years.(1)
Date Declared Dividend Rate Date Paid ------------- ------------- --------- January 22, 1999 $0.405 February 15, 1999 April 23, 1999 $0.415 May 15, 1999 July 23, 1999 $1.817 August 15, 1999 October 29, 1999 $1.324 November 15, 1999 January 28, 2000 $0.450 February 15, 2000 April 28, 2000 $0.560 May 15, 2000 July 28, 2000 $0.750 August 15, 2000 October 27, 2000 $0.880 November 15, 2000
- -------- (1) We had common shares before December 31, 2000 before the merger with Cleco Power LLC. After the merger, we replaced common shares with member's equity. ITEM 6. SELECTED FINANCIAL DATA Information for this Item is omitted pursuant to General Instruction I to Form 10-K. 22 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS. The following discussion and analysis should be read in combination with our audited financial statements and the notes thereto contained in Financial Statements and Supplementary Data" in Item 8 of this report. We are an electric utility that contains LPSC jurisdictional generation, transmission and distribution electric utility operations. We provide electric utility services to approximately 249,000 retail and wholesale customers in 63 communities and rural areas in an approximately 14,000-square mile region in the State of Louisiana. Effective July 1, 1999, we were reorganized into a holding company structure. This reorganization resulted in the formation of Cleco Corporation as a new holding company, which became the owner of all our outstanding common stock. In connection with the reorganization, we transferred the shares of capital stock and member's equity of all our subsidiaries to Cleco Corporation. Accordingly, financial statements and data in this report that pertain to the periods prior to our holding company reorganization include amounts related to subsidiaries that are no longer our subsidiaries. Our conversion to a limited liability company, discussed in "Business--General" in Item 1 of this report, had no impact on the financial statements. Results of Operations
Year ended December 31, ---------------------------- 2000 1999 1998 -------- -------- -------- (Thousands) Operating Revenues Base............................................. $322,716 $306,225 $296,893 Fuel cost recovery............................... 296,812 202,565 190,387 Energy marketing................................. 18,078 237,731 32,695 Affiliate revenues............................... 9,256 7,816 -- Customer credits................................. (1,233) (2,776) (4,800) -------- -------- -------- Total Operating Revenues....................... 645,629 751,561 515,175 Operating Expenses Fuel............................................. 182,024 146,825 142,737 Purchased power.................................. 121,963 65,303 53,011 Energy marketing................................. 13,583 230,084 27,322 Other operations................................. 81,084 75,856 71,066 Maintenance...................................... 30,959 29,369 30,285 Depreciation..................................... 49,787 49,285 48,369 Taxes other than income.......................... 36,533 35,870 35,420 Income taxes..................................... 30,998 27,272 26,666 Affiliate costs.................................. 7,871 6,397 -- -------- -------- -------- Total Operating Expenses....................... 554,802 666,261 434,876 -------- -------- -------- Operating Income................................. 90,827 85,300 80,299 -------- -------- -------- Other income (expense), net...................... (2,248) (203) 862 Interest charges including amortization of debt expense, premium and discount and AFUDC......... 28,722 28,414 27,360 Preferred dividend requirements, net............. -- 1,047 2,137 -------- -------- -------- Net income applicable to member's equity and common stock.................................... $ 59,857 $ 55,636 $ 51,664 ======== ======== ========
Our retail rates are regulated by the LPSC and FERC for more information refer to "Management's Discussion and Analysis--Financial Condition--Retail Rates" below. Weather influences the demand for electricity, especially among residential customers. Much of this demand is measured in cooling degree days and heating degree days. A cooling degree day is an indication of the 23 likelihood of a consumer utilizing air conditioning while a heating degree day is an indication of the likelihood of a consumer utilizing heating. The following chart indicates the percentage variance from normal and from the prior year for combined cooling/heating degree days for 2000, 1999 and 1998. Combined Cooling/Heating Degree Days
2000 1999 1998 ---- ------ ---- Increase/(Decrease) From Normal........................ 5.1% (3.4)% 1.0% Increase/(Decrease) From Prior Year.................... 8.6% (4.3)% (3.0)%
Demand for electricity by commercial and industrial customers is primarily dependent upon the strength of the economy in the service territory and the nation and is less affected by weather. Sales to industrial customers also are affected by the worldwide demand for wood products since our two largest customers are producers of such products. The following chart compares the kWh sales by customer class, for 2000, 1999 and 1998.
For the year ended December 31, ------------------------------------------------ 2000 1999 1998 -------------- -------------- -------------- Million Million Million kWh Change kWh Change kWh Change ------- ------ ------- ------ ------- ------ Retail electric customers Residential.................... 3,357 4.6% 3,208 (0.7)% 3,230 13.8% Commercial..................... 1,675 4.9% 1,597 4.4% 1,529 9.8% Industrial..................... 2,926 7.6% 2,720 8.0% 2,518 2.1% Other Retail................... 589 2.6% 574 3.4% 555 4.1% Sales for resale............... 342 (8.3)% 373 (7.2)% 402 29.3% ----- ------ ----- Total sales to regular customers..................... 8,889 4.9% 8,472 2.9% 8,234 9.2% Short-term sales to other utilities..................... 77 (38.9)% 126 65.8% 76 (51.6)% Sales from marketing activities.................... 81 (98.6)% 5,815 467.3% 1,025 -- ----- ------ ----- Total electric sales......... 9,047 (37.2)% 14,413 54.4% 9,335 21.2% ===== ===== ====== ===== ===== =====
During the last five years, electric sales growth to retail electric customers averaged 4.5% and, based on current information, is expected to range from 2% to 3% per year during the next five years. The levels of future sales will depend upon factors such as weather conditions, customer conservation efforts, retail marketing and business development programs, and the overall economy of our service area. Some of the issues facing the electric utility industry that could affect sales include deregulation, retail wheeling, legislative and regulatory changes, retention of large industrial customers, franchises, changes in electric rates compared to customers' ability to pay and access to transmission systems. Sales from energy marketing activities are primarily affected by transmission constraints, demand versus supply, market prices and our marketing strategies. Changes in fuel and purchased power expenses reflect fluctuations in generation mix, fuel costs, availability of economy power and deferral of expenses for recovery from customers through fuel adjustment clauses in subsequent months. The following tables show the amount and changes in fuel and purchased power expenses for 2000, 1999 and 1998.
For the years ended December 31, ----------------------------------------------------- 2000 1999 1998 ---------------- ---------------- ---------------- Thousands Change Thousands Change Thousands Change --------- ------ --------- ------ --------- ------ Fuel used for electric generation................ $182,023 25.3% $145,229 1.7% $142,737 4.9% Power purchased............ 121,963 86.8% 65,303 23.2% 53,011 18.9% -------- -------- -------- Total fuel expenses...... $303,986 44.4% $212,128 8.4% $195,748 8.4% ======== ===== ======== ===== ======== ==== Gas purchased for marketing................. $ 11,136 (54.9)% $ 24,687 -- -- -- Power purchased for marketing................. $ 2,447 (98.8)% $205,397 651.8% $ 27,322 --
24 We are exploring the possibility of transferring generation facilities to Midstream. Management believes any potential transfer of LPSC jurisdictional generation facilities to Midstream would be accompanied by consumer safeguards for our retail customers. Management is unable to predict whether it will be able to transfer any additional generation to Midstream or what impact any such transfer would have on the Company's financial condition or results of operations. 2000 compared to 1999 Operating revenues were $105.9 million, or 14%, less than 1999. The decrease in operating revenues was due to a greatly reduced level of trading activity, partially offset by higher base, fuel and transmission revenues, along with increased customer ancillary charges for disconnects and reconnects. Base revenues in 2000 were higher than 1999 due to customer growth, warmer summer weather, the third coldest December on record in our service territory, and higher large customer sales. kWh sales to residential customers in 2000 increased 4.6% compared to 1999, increasing base revenues for 2000 by $5.7 million as compared to 1999. kWh sales to industrial customers in 2000 were 7.6% higher than 1999 due to increased usage. The remainder of the increase was due to increased transmission and miscellaneous revenue. Fuel cost recovery revenues collected in 2000, increased primarily from sales to residential customers, which increased $36.7 million, sales to industrial customers, which increased $28.6 million and sales to commercial customers, which increased $18.0 million in relation to 1999. The remaining $10.9 million increase was due to sales to others. The increase in fuel cost recovery revenues is due to increased natural gas prices for 2000, compared to 1999 which increased the cost to generate power from our own generation stations and increased the cost of purchasing power in the region. Changes in fuel costs have historically had no effect on net income, as fuel costs are generally recovered through fuel costs adjustment clauses that enable us to pass on to customers substantially all changes in the cost of generating fuel and purchased power. These adjustments are audited monthly and are regulated by the LPSC (representing about 99% of the total fuel cost adjustment) and the FERC. Until approval is received, the adjustments are subject to refund. Energy marketing revenues in 2000, decreased $219.7 million as compared to 1999. We have seen a reduction in energy marketing revenues in 2000 when compared with prior years due to a reduced level of energy trading activity. The reduced trading activity resulted from a refinement of trading practices and from the transfer of specific (CPS) generating assets to Evangeline. The increase in sales to commercial and industrial customers during 2000 compared to 1999 resulted primarily from increased economic growth in the region served by us and in the United States generally. The increased sales to residential customers during 2000 as compared to 1999 resulted primarily from warmer than normal spring and summer seasons in 2000 and colder than normal weather during the winter of 2000. Affiliate revenues for 2000, increased by $1.4 million, or 18.4%, compared to 1999. The increase in affiliate revenues is primarily the result of leasing office space to Cleco Support Group LLC (Support Group), a wholly owned subsidiary of Cleco Corporation beginning January 2000, as well as providing supplemental line construction and line maintenance crews and selected distribution and transmission engineering services for Utility Construction & Technology Solutions LLC (UtiliTech), a wholly owned subsidiary of Cleco Corporation and providing interconnection and generation imbalance services to Evangeline. Operating revenues for 2000, were decreased by a $1.2 million accrual for estimated customer credits, which was $1.6 million less than the $2.8 million accrual recognized for 1999. Accruals for estimated customer credits may be required under terms of an earnings review settlement reached with the LPSC in 1996. For more information regarding the earnings review settlement, see "-- Financial Condition--Retail Rates" below. We obtain coal and lignite under long-term contracts. Natural gas is purchased under short-term contracts. We have several contracts with two power marketing companies for 605 MW of capacity in 2000, increasing to 760 MW of capacity in 2004. 25 Operating expenses decreased $111.5 million, or 16.7%, in 2000, compared to 1999. The decrease in operating expenses is primarily the result of a decrease in energy marketing expenses, partially offset by increased capacity charges and higher fuel costs. Energy marketing expenses in 2000 decreased $216.5 million compared to 1999 largely due to the same factors noted above for decreases in energy marketing revenues. Total fuel expense increased $91.9 million in 2000 compared to 1999 due to increased prices in natural gas and increased demand from native load customers. Of the 1,359 MW of our generating capacity, 437 MW use natural gas as the source of fuel, 440 MW can use either natural gas or fuel oil, 157 MW can use either natural gas or coal and 325 MW use lignite. Purchased power increased $56.7 million in 2000 compared to 1999 largely due to the amount of generation in the region that uses natural gas as fuel, the overall increase in demand in the region and the reduction of generation capacity resulting from the transfer of the CPS assets to Evangeline. We also purchase power from other utilities to supplement our generation resources at times of relatively high demand, as well as when the purchase price is less than our cost of generation and when our generating units are unable to provide electricity to satisfy our load. Thirty-four percent of our energy requirements during 2000 were met with purchased power, compared to 27% in 1999. The increase was caused by the replacement of the CPS output with a power contract with Williams Energy and to a lesser extent by an outage for maintenance at Dolet Hills in 2000, both requiring us to purchase more power in 2000 than we did in 1999 to meet load requirements. The increase was also caused by increased kWh sales in 2000 compared to 1999. In future years, our generating facilities may not supply enough electric power to meet our growing native load demand. For more information on our generating facilities and our power contracts, see "--Operations--Power Generation" and "--Operations--Power Purchases" in Item 1 "Business" above. We and the joint owner of one of our electric generating units jointly filed suit in 1997 against a joint venture and its parties who mine lignite for the generating unit. For more information on this suit, see "Item 3. Legal Proceedings" above. Power and gas purchased for marketing in 2000 decreased $216.5 million compared to 1999 mainly due to a reduced level of energy trading activities resulting from a refinement of trading practice within our company and from the transfer of CPS assets to Evangeline. Affiliate costs for 2000, increased by $1.5 million, or 23%, compared to 1999. The increase in affiliate costs is primarily due to the lease of office space to Support Group beginning in January 2000, as well as providing supplemental line construction and maintenance crews for UtiliTech and interconnection services to Evangeline. Maintenance and depreciation expenses for 2000, remained relatively flat compared to 1999. 1999 Compared to 1998 Operating revenues for 1999, were 45.9% greater than 1998. The increase was primarily due to increased marketing activities. Electric marketing operation activities did not commence until late in the second quarter of 1998 and were still in start-up mode in the third quarter of 1998. Also contributing to the increase was a 4.2% increase in base revenues. The increased sales were attributable to above normal additions of commercial customers and continued overall health of the economy in our service territory. Approximately half of the $9.3 million increase in base revenues for 1999, as compared to 1998, was due to a 2.9% increase in sales to regular customers. The remainder of the increase was largely due to increased transmission and miscellaneous revenues. Fuel cost recovery revenues collected for 1999 increased $12.2 million, as increased demand for power necessitated the purchase of more power on the wholesale market at higher prices than in 1998. Energy marketing revenues increased $205.0 million in 1999 as compared to 1998 primarily due to growth and expansion in our electric marketing operation. Our electric marketing operation commenced late in the second quarter of 1998 and was not fully operational until 1999. The operation expanded from trading only on the Into Entergy market in 1998 to also trading on the Cinergy market in 1999. We also started marketing natural gas in 1999. 26 The increase in sales to commercial and industrial customers during 1999 as compared to 1998 resulted primarily from increased economic growth in the region served by us and in the United States generally. Affiliate revenues in 1999, were $7.8 million greater than 1998 due to the formation of a holding company on July 1, 1999. Prior to July 1999, all affiliates were subsidiaries and their operations were included with our operations and reflected in our income/(expenses), net. For more information on affiliate transactions after July 1, 1999, see Note K to the audited financial statements included in "Financial Statements and Supplemental Data" in Item 8 of this report. Revenues in 1999 were decreased by a $2.8 million accrual for estimated customer credits, $2 million less than the $4.8 million accrued in 1998. For more information, see Note J to the audited financial statements included in "Item 8. Financial Statements and Supplemental Data" of this report. Operating expenses increased $231.4 million in 1999 as compared to 1998. The increase in operating expenses was primarily the result of an increase in energy marketing expenses. Our electric marketing operations were not fully operational until 1999. Fuel and purchased power expense increased $16.4 million in 1999. This expense increased primarily due to increased demand from native load customers, which necessitated the purchase of more power on the wholesale market at higher prices than in 1998. During 1999, 27% of our energy requirements were met with purchased power, up from 24% in 1998. Power purchased for marketing increased primarily due to a full year of activity by our energy marketing operation in 1999. Natural gas marketing did not begin until 1999. Interest expense for 1999 increased $1.1 million as compared to 1998. The increase was due largely to higher interest rates on variable-rate, short-term debt during 1999, higher interest expense on pollution control bonds due to the refinancing of the bonds at a fixed rate, and the replacement of short- term debt with medium-term notes in order to pre-fund the refinancing of medium-term notes. Other operations expense, maintenance and depreciation expenses for 1999 remained relatively flat compared to 1998. Financial Condition Liquidity and Capital Resources Financing for construction requirements and operational needs is dependent upon the cost and availability of external funds through capital markets and from financial institutions. Access to funds is dependent upon factors such as general economic conditions, regulatory authorizations and policies and our credit rating. At December 31, 2000 and 1999, we had $41.3 million and $5.9 million, respectively, of short-term debt outstanding in the form of commercial paper and bank loans. Commercial paper increased by $35.4 million at December 31, 2000, compared to the same date in 1999, due to the maturity of $25 million in medium-term notes and the need to fund increased fuel costs until cash is received from customers. An existing $100 million revolving credit facility is scheduled to terminate on June 14, 2001. Upon termination this facility will be refinanced for the same amount. This facility provides support for the issuance of commercial paper and other working capital. 27 Cash Generation and Cash Requirements--Cash Flows During 2000, cash flows from operating activities generated $99.9 million as shown in the audited Statement of Cash Flows included in "Financial Statements and Supplemental Data" in Item 8 of this Report. Net cash provided by operating activities resulted primarily from net income, adjusted for noncash charges to income, and changes in working capital. Net cash used in investing activities related primarily to additions to property, plant and equipment and changes in utility and nonutility investments. Net cash used in financing activities resulted primarily from $59.4 million in dividends paid and the maturity of medium-term notes. Cash Generation and Cash Requirements--Construction Overview Our construction consists of assets that may be added to our rate base with the cost, if considered prudent by the LPSC, being passed on to our customers. Those assets earn a rate of return restricted by the LPSC and are subject to the rate agreement described under "--Retail Rates" below. Construction consists of additions to our distribution system, improvements to our transmission system and improvements at our generation stations. In recent years, our construction program has consisted primarily of enhancements to our transmission and distribution system and improvements at our generating stations. Construction expenditures, excluding AFUDC, totaled $47.9 million in 2000, $51.7 million in 1999 and $53.9 million in 1998. Our construction expenditures, excluding allowance for funds used during construction (AFUDC), for 2001 are estimated to be $57 million and for the five-year period ending 2005 are expected to total $249 million. About one- half of the planned construction in the five-year period will support line extensions and substation upgrades to accommodate new business and load growth. Some investment will be made to rehabilitate older transmission, distribution and generation assets. We will also continue to invest in technology to allow our utility assets to operate more efficiently. In 2000 and 1999, 100% of our construction requirements were funded internally, as compared to 99.8% in 1998. In 2001, 100% of construction requirements are expected to be funded internally. For the five-year period ending 2005, 96% of the construction requirements are expected to be funded internally. We are exploring the possibility of transferring additional generation facilities to Midstream. We are unable to predict whether we will be able to transfer any additional generation to Midstream or what impact any such transfer would have on our financial condition or results of operations. 28 Cash Generation and Cash Requirements--Other Cash Requirements Scheduled maturities of debt have totaled approximately $25.0 million for 2000 and will total approximately $125.0 million for the five-year period ending 2005. At December 31, 2000 we had a shelf registration providing for the issuance of $200 million aggregate principal amount of medium-term notes for which LPSC approval has been obtained. We plan to use the proceeds from the notes to paydown commercial paper balances and finance construction. Inflation Annual inflation rates, as measured by the U.S. Consumer Price Index, have averaged approximately 2.6% during the three years ended December 31, 2000. Management believes that inflation, at this level, does not materially affect our results of operations or financial position. However, under existing regulatory practices, only the historical cost of plant is recoverable from customers. As a result, our cash flows designed to provide recovery of historical plant costs may not be adequate to replace plant in future years. Retail Rates Retail rates regulated by the LPSC accounted for approximately 94% of our revenues in 2000 and 66% of our revenues in 1999. The increase in the proportion of revenues affected by the rate making authority of the LPSC is due to the decrease in energy marketing revenues, which prices are primarily set by the wholesale market. Fuel costs and monthly fuel adjustment billing factors are subject to audit by the LPSC. In the past, we have sought increases in base rates to reflect the cost of service related to plant facility additions and increases in operating costs. If we request an increase in our rates, and adequate rate relief is not granted on a timely basis, our ability to attract capital at reasonable costs to finance operations and capital improvements might be impaired. The LPSC elected in 1993 to review the earnings of all electric, gas, water and telecommunications utilities it regulates to determine whether the returns on equity of these companies were higher than returns that might be awarded in the economic environment at the time. In 1996 the LPSC approved a settlement of our earnings review, which provides our customers with lower electricity rates. A base rate decrease of $3 million annually became effective November 1, 1996, with a second decrease of an additional $2 million annually effective January 1, 1998. The terms of this settlement were to be effective for a five- year period. In February 1999, the period was extended three years until 2004 under an agreement with the LPSC to transfer the existing assets of CPS from our LPSC-regulated rate base into Evangeline, which repowered the CPS generating plant. During the eight-year period ending September 30, 2004, an LPSC-approved rate stabilization plan is in place. This plan allows us to retain all earnings equating to a regulatory return on equity up to and including 12.25% on our regulated utility operations. Any earnings which result in a return on equity over 12.25% and up to and including 13% will be shared equally between us and our customers. Any earnings above 13% will be fully refunded to customers. This effectively allows us the opportunity to realize a regulatory rate of return of up to 12.625%. As part of the rate stabilization plan, the LPSC will annually review our revenues and return on equity. If we are found to be achieving a regulatory return on equity above the minimum 12.25%, a refund will be made in the form of billing credits during the month of September following the evaluation period. Customers received a refund of $1.1 million in September 2000. Of that amount, approximately $0.6 million was reflective of the earnings level achieved in the previous earnings period while the remainder originated from a settlement agreement with the LPSC pertaining to the 1998 earnings period. The determination of any refund relative to the 2000 monitoring period is under review by LPSC staff. See Note J and Note M to the audited financial statements included in "Financial Statements and Supplemental Data" in Item 8 of this Report for information concerning amounts accrued by us based on the settlement agreement and information regarding a settlement with the LPSC. 29 In November 1997, the LPSC issued an order in a generic docket that promulgated new standards for the monthly Fuel Adjustment Clause (FAC) rate filings of electric utility companies under its jurisdiction. The order adopted new rules and procedures for the monthly FAC computation and changes in reporting of fuel and purchased power cost. Although the order narrowed the types of costs that can be included in the FAC, it offset this reduction with an increase in base rates. New rate schedules that incorporate the shifting of costs from FAC to base rates were calculated, subsequently approved by the LPSC and implemented on January 1, 2000. The changes resulted in an immaterial effect on our financial position and results of operations. Regulatory Matters We have recorded regulatory assets and liabilities, primarily for the effects of income taxes, as a result of past rate actions of regulators, pursuant to Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). The effects of potential deregulation of the industry or possible future changes in the method of rate regulation could require us to discontinue the application of SFAS No. 71, pursuant to SFAS No. 101, "Regulated Enterprises-- Accounting for the Discontinuation of Application of FASB Statement No. 71". At December 31, 2000, and December 31, 1999, we have recorded $61.5 million and $43.6 million, respectively, of regulatory assets, net of regulatory liabilities, because of the regulatory requirement to flow through the tax benefits of accelerated deductions to current customers and an implied regulatory compact that future customers would pay for additional taxes when we paid additional taxes. These differences occur over the lives of relatively long-lived assets, up to 30 years or more. Under the current regulatory and competitive environment, we believe that these regulatory assets are fully recoverable. However, if in the future, as a result of regulatory changes or increased competition, our ability to recover these regulatory assets would not be probable, then to the extent that these regulatory assets were determined not to be recoverable, we would be required to write off or write down these assets. SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of", establishes accounting standards for determining if long-lived assets are impaired, and when and how losses, if any, should be recognized. We believe that the net cash flows that will result from the operation of our assets are currently sufficient to cover the carrying value of the assets. 30 The Emerging Issues Task Force (EITF) assists the FASB in identifying emerging issues affecting financial reporting. In 1997, the EITF reached a consensus in Issue No. 97-4, "Deregulation of the Pricing of Electricity-- Issues Related to the Application of FASB Statements No. 71 and 101" (EITF No. 97-4). EITF No. 97-4 specified that SFAS No. 71 should be discontinued at a date no later than when the details of a transition plan toward the deregulation of electric rates for all or a portion of the entity subject to such plan are known. However, other factors could cause the discontinuation of SFAS No. 71 before that date. Additionally, EITF No. 97-4 establishes that regulatory assets to be recovered through cash flows derived from another portion of the entity which continues to apply SFAS No. 71 should not be written off, but rather should continue to be considered regulatory assets of the separable portion which will continue to apply SFAS No. 71. As of December 31, 2000, we continue applying SFAS No. 71, because none of the requirements of EITF No. 97-4 have been met. Recent Accounting Standards In 1998 the FASB issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133)." SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivatives embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. This statement requires that changes in the derivative's fair value be recognized in current earnings, unless effective accounting criteria tests are met, where changes in the fair value of the derivative would be recorded in other comprehensive income in the equity section of the balance sheet. In June 1999 the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000 the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which amended certain normal purchase and sales guidance within SFAS No. 133. In early 2000 Cleco Corporation organized a cross-functional project team for implementing SFAS No. 133, as amended. The team completed an inventory of our financial and commodity contracts and other commitments, and assessed our derivative-related transactions identified in this inventory. This assessment revealed that we were impacted by this standard. As of January 1, 2001, we had the following contractual obligations that met the definition of a derivative-related transaction: . Long-term power purchase agreements with two suppliers . Natural gas futures contracts . Natural gas option contracts. The long-term power purchase agreements give us the right to purchase up to a given amount of energy. Under one agreement, we can purchase up to 200 MW in years one through five and 100 MW in year six, while another agreement allows us to purchase up to 155 MW in year one, increasing to 225 MW in year two, 255 MW in year three, and 310 MW for the remainder of the four-and-a-half-year contract. The agreements set the purchase price for power on market index prices agreed to by both parties. Because the fair value of the power is based on these same market index prices, there is no SFAS No. 133 impact when the agreements are valued at market. 31 We have recorded in current income the changes in the fair value (marked- to-market) of open natural gas futures and options positions, prior to the implementation of SFAS No. 133. We will not change this accounting and will continue to record the changes in fair value of these derivative instruments by marking them to market and recording any change in value in income. At December 31, 2000, the mark-to-market estimated fair value of these open positions was a loss of $407,000. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The market risk inherent in our market risk sensitive instruments and positions is the potential change arising from increases or decreases in the short-, medium- and long-term interest rates, the commodity price of electricity traded on the Into Entergy and Cinergy exchanges and the commodity price of natural gas traded. Generally, our market risk sensitive instruments and positions, such as instruments used to provide fuel to our retail utility customers, are characterized as "other than trading" as defined by EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF No. 98-10). However, we do have some positions that are considered "trading," as defined by EITF No. 98-10, such as our positions in energy marketing operations. Our 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 prices of electricity and natural gas. Management's views on market risk are not necessarily indicative of actual results, nor do they represent the maximum possible gains or losses. The views do represent, within the parameters disclosed, what management estimates may happen. Interest We have entered into various fixed- and variable-rate debt obligations. Please read Note E to the audited financial statements included in "Financial Statements and Supplementary Data" in Item 8 of this Report for details regarding our debt obligations. Sensitivity to changes in interest rates for fixed-rate obligations is computed by calculating the current fair market value using a net present value model based upon a 1% change in the average interest rate applicable to such debt. Sensitivity to changes in interest rates for variable-rate obligations is computed by assuming a 1% change in the current interest rate applicable to such debt. As of December 31, 2000, the carrying value of our long-term, fixed-rate debt was approximately $361.2 million, with a fair market value of approximately $369.3 million. Fair value was determined using quoted market prices. Each 1% change in the average interest rates applicable to such debt would result in a change of approximately $20.6 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 December 31, 2000, the carrying value of our short-term, variable-rate debt, was approximately $41.4 million, which approximates the fair market value. Each 1% change in the average interest rates applicable to such debt would result in a change of approximately $414,000 in our pre-tax earnings. We monitor our mix of fixed- and variable- rate debt obligations which consists of commercial paper, in light of changing market conditions and from time to time may alter that mix by, for example, refinancing balances outstanding under our variable-rate commercial paper program with fixed-rate debt. 32 Market Risk We believe we have in place controls to help minimize the risks involved in marketing and trading. Controls over marketing and trading consist of a back office (accounting) and mid-office (risk management) independent of the marketing and trading operations oversight by a risk management committee comprised of Cleco Corporation officers and a daily risk report which shows value-at-risk (VAR) and current market conditions. Our board of managers appoints the members of the Risk Management Committee. VAR limits are set and monitored by the Risk Management Committee. For more information on our marketing and trading operations see "--Business--Marketing Operations" in Item 1 above. Most of our positions are considered "other than trading" under EITF No. 98-10. However, we do have financial positions that are defined as "trading" under EITF No. 98-10. At December 31, 2000, the mark-to-market value for those positions was a gain of $55,148. We utilize a VAR model to assess the market risk of our trading positions including the derivative financial instruments. VAR represents the potential loss in fair values for an instrument from adverse changes in market factors for a specified period of time and confidence level. The VAR is estimated using historical simulation calculated daily assuming a holding period of one day with a 95% confidence level for natural gas positions and a 99.7% confidence level for electricity purposes. Total volatility is based on historical cash volatility, implied market volatility, current cash volatility and option pricing. Based on these assumptions, the high, low and average VAR during the year ended December 31, 2000 as well as the VAR at December 31, 2000 is summarized below:
At December 31, High Low Average 2000 ---- --- ------- ------------ (Thousands) $2,168.1 $5.2 $275.2 $322.4
In 1999 we reported VAR using a 99.7% confidence level for both natural gas and electricity. The change in reporting VAR using a confidence level of 95% for natural gas is due to the greater maturity, greater liquidity and depth of products in the natural gas market as compared to the immaturity and volatility of the electricity markets. Reporting VAR using a confidence level of 95% is also the industry standard for natural gas. VAR would have been $512,000 at December 31, 1999 if a 95% confidence level had been used for 1999. 33 [PricewaterhouseCoopers letterhead] PricewaterhouseCoopers LLP 639 Loyola Avenue Suite 1800 New Orleans LA 70113 Telephone (504) 529 2700 Facsimile (504) 529 1439 Report of Independent Accountants To the Member and Board of Managers of Cleco Power LLC: In our opinion, the accompanying balance sheets and the related statements of income, cash flows and changes in common shareholder's equity and member's equity present fairly, in all material respects, the financial position of Cleco Power LLC. at December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for the opinion expressed above. /s/ PricewaterhouseCoopers LLP New Orleans, Louisiana January 30, 2001 34 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA CLECO POWER LLC BALANCE SHEETS
At December 31, ---------------------- 2000 1999 ---------- ---------- (Thousands) ASSETS ------ Utility plant and other property, plant and equipment Property, plant and equipment........................ $1,550,756 $1,539,435 Accumulated depreciation............................. (595,136) (552,556) ---------- ---------- Net property, plant and equipment.................... 955,620 986,879 Construction work-in-progress........................ 25,864 26,919 ---------- ---------- Total utility plant, net........................... 981,484 1,013,798 ---------- ---------- Current assets Cash and cash equivalents............................ 2,224 547 Accounts receivable, net Customer accounts receivable (less allowance for doubtful accounts of $757 in 2000 and $838 in 1999)................................. 41,637 26,720 Other accounts receivable.......................... 19,878 13,728 Affiliates......................................... 1,457 22,624 Notes receivable--affiliates......................... 2 2 Unbilled revenues.................................... 26,863 17,065 Fuel inventory, at average cost...................... 7,275 10,461 Material and supplies inventory, at average cost..... 14,513 14,189 Accumulated deferred fuel............................ 3,617 -- Other current assets................................. 6,758 5,560 ---------- ---------- Total current assets............................... 124,224 110,896 ---------- ---------- Prepayments.......................................... 7,974 6,428 Regulatory assets--deferred taxes.................... 100,267 70,834 Accumulated deferred federal and state income taxes.. 52,144 55,184 Other deferred charges............................... 37,539 33,839 ---------- ---------- TOTAL ASSETS....................................... $1,303,632 $1,290,979 ========== ==========
35 CAPITALIZATION AND LIABILITIES ------------------------------ Common shareholder's equity and member's equity Member's equity........................................ $ 172,376 $ -- Common stock, $2 par value, authorized 50,000,000 shares, issued zero and 22,531,870 shares at December 31, 2000 and 1999, respectively........... -- 45,064 Premium on capital stock............................... 127,477 Retained earnings...................................... 234,734 234,288 ---------- Total common shareholder's equity and member's equity.............................................. 407,110 406,829 Long-term debt, net...................................... 335,282 360,339 ---------- ---------- Total capitalization................................. 742,392 767,168 ---------- ---------- Current liabilities Short-term debt........................................ 41,397 5,989 Long-term debt due within one year..................... 25,000 25,000 Accounts payable....................................... 67,919 56,093 Accounts payable--Affiliate............................ 10,846 9,244 Customer deposits...................................... 20,447 20,326 Taxes accrued.......................................... 8,679 1,321 Taxes accrued--payable to parent....................... 8,161 24,428 Interest accrued....................................... 8,021 8,788 Accumulated deferred fuel.............................. -- 2,638 Other current liabilities.............................. 4,933 3,756 ---------- ---------- Total current liabilities............................ 195,403 157,583 ---------- ---------- Deferred credits Accumulated deferred federal and state income taxes.... 268,311 263,688 Accumulated deferred investment tax credits............ 24,252 25,994 Regulatory liabilities--deferred taxes................. 38,840 27,221 Other deferred credits................................. 34,434 49,325 ---------- ---------- Total deferred credits............................... 365,837 366,228 ---------- ---------- TOTAL CAPITALIZATION AND LIABILITIES................. $1,303,632 $1,290,979 ========== ==========
The accompanying notes are an integral part of the financial statements. 36 CLECO POWER LLC STATEMENTS OF INCOME
For the Year Ended December 31, ---------------------------- 2000 1999 1998 -------- -------- -------- (Thousands) Operating revenue Retail electric operations..................... $619,528 $508,790 $487,280 Energy marketing operations.................... 18,078 237,731 32,695 Affiliate revenues............................. 9,256 7,816 -- -------- -------- -------- Gross operating revenue........................ 646,862 754,337 519,975 Retail electric customer credits............... (1,233) (2,776) (4,800) -------- -------- -------- Total operating revenue...................... 645,629 751,561 515,175 -------- -------- -------- Operating expenses Fuel used for electric generation.............. 182,023 146,825 142,737 Power purchased for utility customer........... 121,963 65,303 53,011 Purchases for energy marketing operations...... 13,583 230,084 27,322 Other operations............................... 81,084 75,856 71,066 Maintenance.................................... 30,959 29,369 30,285 Depreciation................................... 49,787 49,285 48,369 Taxes other than income taxes.................. 36,533 35,870 35,420 Income taxes................................... 30,998 27,272 26,666 Affiliate costs................................ 7,871 6,397 -- -------- -------- -------- Total operating expenses..................... 554,802 666,261 434,876 -------- -------- -------- Operating income................................. 90,827 85,300 80,299 Interest income................................ 230 1,238 372 Allowance for other funds used during construction.................................. 507 654 812 Other income (expense), net.................... (2,525) (2,095) (322) -------- -------- -------- Income before interest charges................... 88,579 85,097 81,161 -------- -------- -------- Interest charges Interest on debt and other, net of amount capitalized................................... 28,356 27,223 27,016 Allowance for borrowed funds used during construction.................................. (580) (91) (904) Amortization of debt discount, premium and expense, net.................................. 946 1,282 1,248 -------- -------- -------- Total interest charges....................... 28,722 28,414 27,360 -------- -------- -------- Net income before preferred dividends............ 59,857 56,683 53,801 Preferred dividend requirements, net........... -- 1,047 2,137 Net income applicable to member's equity and common stock.................................... $ 59,857 $ 55,636 $ 51,664 ======== ======== ========
The accompanying notes are an integral part of the financial statements. 37 CLECO POWER LLC STATEMENTS OF CASH FLOWS
For the Year Ended December 31, ---------------------------- 2000 1999 1998 -------- -------- -------- (Thousands) OPERATING ACTIVITIES Net income..................................... $ 59,857 $ 56,683 $ 53,801 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and amortization................ 50,733 50,567 50,852 Allowance for funds used during construction. 1,087 745 (1,716) Amortization of investment tax credits....... (1,742) (1,790) (1,790) Deferred income taxes........................ 5,687 8,469 8,703 Deferred fuel costs.......................... (6,255) (1,975) 1,648 Gain on disposition of land sales, net....... -- (130) -- Changes in assets and liabilities Accounts receivable, net................... (20,792) 25,225 (2,231) Accounts receivable, affiliate............. 20,168 -- -- Unbilled revenues.......................... (9,798) (7,353) 1,378 Fuel, material and supplies inventories.... 2,862 (2,582) 662 Accounts payable........................... 12,209 5,224 4,421 Accounts payable, affiliate................ 2,601 -- -- Customer deposits.......................... 121 206 (52) Other deferred accounts.................... (2,215) -- -- Taxes accrued.............................. (8,910) 13,789 (269) Interest accrued........................... (767) 1,448 (341) Other, net................................. (4,882) 2,402 (1,682) -------- -------- -------- Net cash provided by operating activities.............................. 99,973 150,928 113,384 -------- -------- -------- INVESTING ACTIVITIES Additions to property, plant and equipment..... (47,925) (51,758) (94,030) Allowance for funds used during construction... (1,087) (745) 1,716 Sale of utility plant, including associated land.......................................... -- 9,231 408 Purchase of investments........................ -- (200) (480) -------- -------- -------- Net cash used in investing activities.... (49,012) (43,472) (92,386) -------- -------- -------- FINANCING ACTIVITIES Issuance of common stock....................... -- 243 100 Repurchase of common stock..................... -- (120) -- Redemption of preferred stock.................. -- (6,518) (522) Issuance of long-term debt..................... -- 50,000 -- Retirement of long-term debt................... (25,116) (10,639) (30,000) Increase (decrease) in short-term debt, net.... 35,408 (82,427) 49,197 Cash in subsidiaries moved to holding company.. -- (17,384) -- Distribution to member......................... (59,411) -- Dividends paid on common and preferred stock, net........................................... -- (59,521) (38,331) -------- -------- -------- Net cash used in financing activities.... (49,284) (126,366) (19,556) -------- -------- -------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS..................................... 1,677 (18,910) 1,442 CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR... 547 19,457 18,015 -------- -------- -------- CASH AND CASH EQUIVALENTS AT END OF YEAR......... $ 2,224 $ 547 $ 19,457 ======== ======== ======== Supplementary cash flow information Interest paid (net of amount capitalized)...... $ 29,996 $ 28,423 $ 28,118 ======== ======== ======== Income taxes paid.............................. $ 23,140 $ 7,724 $ 20,140 ======== ======== ========
The accompanying notes are an integral part of the financial statements. 38 CLECO POWER LLC STATEMENT OF CHANGES IN COMMON SHAREHOLDER'S EQUITY AND MEMBER'S EQUITY
For the Years Ended December 31, 1998, 1999 and 2000 ----------------------------------------------------------------- Common Premium Treasury Stock on Capital Retained Member's Stock Shares Amount Stock Earnings Equity Shares Cost ------------ -------- ---------- -------- -------- --------- ------- (Thousands, except share and per share amounts) Balance, January 1, 1998................... 22,762,754 45,525 113,763 255,549 299,842 6,086 ------------ -------- --------- -------- -------- --------- ------- Redemption of preferred stock.................. 10 Incentive stock options exercised.............. 5,000 10 74 Issuance of treasury stock.................. 24 (19,755) (401) Incentive shares forfeited.............. 1,987 54 Director's restricted stock award............ (144) (5) Dividend requirements, preferred stock, net... (2,137) Cash dividends paid, common stock, $1.61 per share.................. (36,194) Net income.............. 53,801 ------------ -------- --------- -------- -------- --------- ------- Balance, December 31, 1998................... 22,767,754 45,535 113,871 271,019 281,930 5,734 ------------ -------- --------- -------- -------- --------- ------- Redemption of preferred stock.................. 18 Repurchase of preferred stock.................. (62) Incentive stock options exercised.............. 10,800 22 217 Issuance of treasury stock.................. 5 (41,060) (831) Director's restricted stock award............ (86) (3) Treasury shares purchased.............. 5,900 120 Treasury shares cancelled.............. (246,684) (493) (1,316) (3,256) (246,684) (5,020) Dividend requirements, preferred stock, net... (1,047) Transfer of non cash items to the Company from Cleco Corporation. 1,639 Dividend of interest in subsidiaries and the Company to Cleco Corporation............ (30,637) Transfer of preferred ESOP shares to Cleco Corporation net of deferred compensation relating to ESOP....... 13,105 Cash dividends paid, common stock, $3.96 per share.................. (58,474) Net Income.............. 56,683 ------------ -------- --------- -------- -------- --------- ------- Balance December 31, 1999................... 22,531,870 $ 45,064 $ 127,477 $234,288 0 $ 0 ============ ======== ========= ======== ======== ========= ======= Merger of Cleco Utility Group Inc. With Cleco Power LLC.............. (22,531,870) $(45,064) $(127,477) $172,541 Adjustment to the transfer of non cash items to the Company from Cleco Corporation. (165) Distribution to member.. (59,411) Net income.............. 59,857 ------------ -------- --------- -------- -------- --------- ------- Balance, December 31, 2000................... -- $ -- $ -- $234,734 $172,376 0 0 ============ ======== ========= ======== ======== ========= =======
The accompanying notes are an integral part of the financial statements. 39 Note A--Holding Company Structure Effective July 1, 1999, Cleco Utility Group Inc. (Utility Group) reorganized into a holding company structure. This reorganization resulted in the creation of a new holding company, Cleco Corporation (Cleco), which holds investments in several subsidiaries. There was no impact to Cleco's Consolidated Financial Statements because the reorganization was accounted for similarly to a pooling of interests. Under the terms of the reorganization, Cleco became the owner of all of Utility Group's outstanding common stock, and holders of then-existing common stock and two series of preferred stock exchanged their stock in the Utility Group for common stock in Cleco. Shares of preferred stock in three series that did not approve the reorganization were redeemed for $5.7 million. As of July 1, 1999, the Company's common stock is no longer listed for trading on an exchange. Effective December 31, 2000, Utility Group converted its form of business organization from a corporation to a limited liability company by merging into Cleco Power LLC (the Company or Cleco Power), a Louisiana limited liability company and wholly owned subsidiary of Cleco, which became the successor issuer to Utility Group. The conversion was effected in order to lessen Utility Group's Louisiana State tax obligations. Immediately prior to the merger, Cleco Power LLC had only nominal assets or liabilities. Pursuant to the merger, the Company acquired all of the assets and assumed all of the liabilities and obligations of Utility Group in a transaction accounted for similar to a pooling of interest. Necessary approvals were obtained from the FERC and the LPSC prior to engaging in the conversion. Note B--Summary of Significant Accounting Policies General The Company provides electric generation, transmission, distribution and customer care services to a diversified base of residential, commercial and industrial customers in 23 parishes (counties) of Louisiana under the jurisdiction of the Louisiana Public Service Commission (LPSC). The Company also operates energy marketing operations which trade in the Cinergy and into Entergy power markets and market natural gas. The financial statements include the accounts of the Company and all subsidiaries, which the Company own directly, or indirectly, through a majority interest, through June 30, 1999. Intercompany balances were eliminated in consolidation. As of July 1, 1999, the Company's interest in its subsidiaries was transferred by dividend to Cleco; therefore, the Company's statements of income and statements of cash flows reflect the results of operations and cash flows for the Company and its subsidiaries on a consolidated basis through June 30, 1999. The transfer was accounted for at the net book value of net assets of its subsidiaries. Management Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. 40 Reclassification Certain reclassifications have been made to the 1998 and 1999 financial statements to conform to the presentation used in the 2000 financial statements. These reclassifications had no effect on net income applicable to member's equity and common stock, total common shareholders' or member's equity or cash flows. Regulation The Company maintains its accounts in accordance with the Uniform System of Accounts prescribed for electric utilities by the Federal Energy Regulatory Commission (FERC), as adopted by the Louisiana Public Service Commission (LPSC). The Company's retail rates for residential, commercial and industrial customers and other retail sales are regulated by the LPSC, and its rates for transmission services and wholesale power sales are regulated by the FERC. The Company follows Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). SFAS No. 71 allows utilities to capitalize or defer certain costs based on regulatory approval and management's ongoing assessment that it is probable these items will be recovered through the ratemaking process. During 2000 the LPSC staff developed a transition to competition plan that was presented to the LPSC. The staff's plan would allow large industrial customers to have the opportunity to choose a power provider starting in January 2003. The plan does not suggest a date for residential or commercial customers. The LPSC is currently receiving comments and is reviewing the plan. Any plan adopted by the LPSC may affect the regulatory assets and liabilities recorded in the Company under SFAS No. 71 if the criteria for the application of SFAS No. 71 cannot continue to be met. The Company has recorded regulatory assets and liabilities, primarily for the effects of income taxes, as a result of past rate actions of regulators pursuant to SFAS No. 71. The effects of potential deregulation of the industry or possible future changes in the method of rate regulation of the Company could require the Company to discontinue the application of SFAS No. 71 in the future, pursuant to SFAS No. 101, "Regulated Enterprises--Accounting for the Discontinuation of Application of FASB Statement No. 71". At December 31, 2000, the Company had recorded $61.5 million of regulatory assets, net of regulatory liabilities, because of the regulatory requirement to flow through the tax benefits of accelerated deductions to current customers and an implied regulatory compact that future customers would fund these amounts when the Company pays the additional taxes. These differences occur over the lives of relatively long-lived assets, up to 30 years or more. Under the current regulatory and competitive environment, the Company believes that these regulatory assets will be fully recoverable. However, if in the future, as a result of regulatory changes or increased competition, the Company's ability to recover these regulatory assets would not be probable, then to the extent that such regulatory assets were determined not to be recoverable, the Company would be required to write-off or write-down such assets. 41 Property, Plant and Equipment Property, Plant and Equipment primarily consist of LPSC regulated generation assets utilized for retail operations and electric transmission and distribution properties. Electric utility plant is stated at the original cost of construction, which includes certain materials, labor, payroll taxes and benefits, administrative and general costs, and the estimated cost of funds used during construction. The cost of repairs and minor replacements is charged as incurred to the appropriate operating expense and clearing accounts. The cost of improvements is capitalized. Upon retirement or disposition, the recorded cost of depreciable plant and the cost of removal, net of salvage value, are charged to accumulated depreciation. The table below discloses the amounts of plant acquisition adjustments reported in the Company's property, plant and equipment and the associated accumulated amortization reported in accumulated depreciation.
At December 31, -------------- 2000 1999 ------ ------ (Thousands) Plant acquisition adjustment.............................. $5,379 $5,379 Accumulated amortization.................................. (951) (698) ------ ------ Total plant acquisition adjustment...................... $4,428 $4,681 ====== ======
The provision for depreciation is computed using the straight-line method at rates that will amortize the unrecovered cost of depreciable property over its estimated useful life. Annual depreciation provisions expressed as a percentage of average depreciable property were 3.27% for 2000 and 3.28% for 1999. Cash Equivalents The Company considers highly liquid, marketable securities and other similar instruments with original maturity dates of three months or less at the time of purchase to be cash equivalents. Income Taxes Deferred income taxes are provided at the current enacted income tax rate on all temporary differences between tax and book basis of assets and liabilities. The Company recognizes regulatory assets and liabilities for the tax effect of temporary differences, which, to the extent past ratemaking practices are continued by regulators, will be realized over the accounting lives of the related properties. The Company joins in the filing of a consolidated U.S. Federal income tax return with its parent, Cleco Corporation. The income tax expense (benefit) is computed as if the Company was filing on a separate return basis, except for the effect of graduated income tax rate. Cleco Corporation's consolidated current and deferred taxes are allocated to the Company using the separate taxpayer method as defined in SFAS No. 109, "Accounting for Income Taxes". 42 Investment Tax Credits Investment tax credits, which were deferred for financial statement purposes, are amortized to income over the estimated service life of the properties that gave rise to the credits. Debt Expense, Premium And Discount Expense, premium and discount applicable to debt securities are deferred upon occurrence and are amortized to income ratably over the lives of the related issues. Debt expense and call premium related to refinanced Company debt are deferred and amortized over the remaining life of the original issue. Revenues And Fuel Costs Utility revenues. Revenues from sales of electricity are recognized based upon the amount of energy delivered. The cost of fuel and purchased power used for retail customers is currently recovered from customers through fuel adjustment clauses, based upon fuel costs incurred in prior months. These adjustments are subject to audit and final determination by regulators. Energy marketing and affiliate revenues. Revenues are recognized at the time products or services are provided to and accepted by customers. Allowance For Funds Used During Construction (AFUDC) The capitalization of AFUDC is a utility accounting practice prescribed by the FERC and the LPSC. AFUDC represents the estimated cost of financing construction work-in-progress. AFUDC does not represent a current source of cash, but under regulatory practices, a return on and recovery of AFUDC is permitted in setting rates charged for utility services. The composite AFUDC rate, including borrowed and other funds on a combined basis, for 2000 was 13.62% on a pretax basis (8.38% net of tax), for 1999 was 13.75% on a pretax basis (8.46% net of tax), and for 1998 was 13.49% on a pre-tax basis (8.30% net of tax). 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, the commodity price of electricity traded on the Into Entergy and the Cinergy exchanges and the commodity price of natural gas traded. Generally, the Company's market risk- sensitive instruments and positions are characterized as "other than trading". However, the Company does have positions that are considered "trading" as defined by Emerging Issues Task Force Consensus No. 98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98- 10), such as its positions in energy marketing operations. Positions that are considered "trading" under EITF 98-10 are marked-to-market at the end of reporting periods. The mark-to-market gains or losses are reflected in the income statement in the energy marketing revenue line item. The offsetting unrealized gain or loss is recorded on the balance sheet in other current assets or other current liabilities. Positions that are considered "other than trading" under EITF 98-10 are accounted for under the deferral method where income or loss on such positions are deferred until the underlying transactions have been realized. 43 Recent Accounting Standards In 1998 the Financial Accounting Standards Board (FASB) issued SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133). SFAS No. 133 established accounting and reporting standards requiring that every derivative instrument (including certain derivatives embedded in other contracts) be recorded on the balance sheet as either an asset or liability measured at its fair value. This statement requires that changes in the derivative's fair value be recognized in current earnings, unless specific hedge criteria are met, then changes in the fair value of the derivative would be recorded in other comprehensive income in the equity section of the balance sheet. In June 1999 the FASB issued SFAS No. 137, "Accounting for Derivative Instruments and Hedging Activities--Deferral of the Effective Date of FASB Statement No. 133," which deferred the effective date of SFAS No. 133 to fiscal years beginning after June 15, 2000. In June 2000 the FASB issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities," which amended certain normal purchase and sales guidance within SFAS No. 133. In early 2000 Cleco Corporation organized a cross-functional project team for implementing SFAS No. 133, as amended. The team completed an inventory of the Company's financial and commodity contracts and other commitments, and assessed the Company's derivative-related transactions identified in this inventory. This assessment determined that the Company was impacted by this standard. As of January 1, 2001, the Company had the following contractual obligations that met the definition of a derivative-related transaction: . Long-term power purchase agreements with two suppliers . Natural gas futures contracts . Natural gas option contracts. The long-term power purchase agreements give the Company the right to purchase up to a given amount of energy. Under one agreement, the Company can purchase up to 200 MW in years one through five and 100 MW in year six, while another agreement allows the Company to purchase up to 155 MW in year one, increasing to 225 MW in year two, 255 MW in year three, and 310 MW for the remainder of the four-and-a-half-year contract. The agreements set the purchase price for power on market index prices agreed to by both parties. Because the fair value of the power is based on these same market index prices, there is no SFAS No. 133 impact when the contracts are valued at market. 44 The Company has recorded in current income the changes in the fair value (marked-to-market) of open natural gas futures and options positions, prior to the implementation of SFAS No. 133. The Company will not change this accounting and will continue to record the changes in fair value of these derivative instruments by marking them to market and recording any change in value in income. At December 31, 2000, the mark-to-market of these open positions was a loss of $407,000. Note C--Jointly Owned Generating Units Two electric generating units operated by the Company are jointly owned with other utilities. The Company's proportionate share of operation and maintenance expenses associated with these two units is reflected in the financial statements.
At December 31, 2000 ------------------- Dolet Rodemacher Hills Unit #2 Unit #1 ---------- -------- (Dollar amounts in thousands) Percentage of ownership.............................. 30% 50% Utility plant in service............................. $85,536 $275,388 Accumulated depreciation............................. $47,200 $119,456 Unit capability (megawatts).......................... 523.0 650.0 Share of capability (megawatts)...................... 156.9 325.0
Note D--Fair Value of Financial Instruments The amounts reflected in the financial statements at December 31, 2000 and 1999, for cash and cash equivalents, accounts receivable, accounts payable and short-term debt approximate fair value because of their short-term nature. The fair value of the Company's long-term debt is estimated based upon the quoted market price for the same or similar issues or by a discounted present value analysis of future cash flows using current rates obtainable by the Company for debt with similar maturities. The estimated fair value of energy market positions is based upon observed market prices when available, and when such market prices are not available, management estimates market value at a discrete point in time based on market conditions and observed volatility. These estimates are subjective in nature and involve uncertainties, therefore, actual results may differ from these estimates. 45
At December 31, ------------------------------------- 2000 1999 ------------------ ------------------ Estimated Estimated Carrying Fair Carrying Fair Value Value Value Value -------- --------- -------- --------- (Thousands) Financial instruments not marked-to- market Long-term debt......................... $361,260 $369,386 $386,260 $380,133 Estimated Estimated Original Fair Carrying Fair Value Value Value Value -------- --------- -------- --------- Financial instruments marked-to-market Energy Market Positions Assets................................ $ 1,745 $ 1,342 $ 9,209 $ 8,089 Liabilities........................... $ 30,079 $ 30,537 $ 4,960 $ 4,266
The financial instruments not marked-to-market are reported on the Company's balance sheet at carrying value. The financial instruments marked- to-market represent off-balance-sheet risk because, to the extent the Company has an open position, it is exposed to the risk that fluctuating market prices may adversely impact its financial position or results of operations upon settlement. Original value represents the fair value of the positions at the time the transaction was originated. Note E--Debt A $100 million revolving credit facility expired on June 15, 2000 and a new $100 million, 364-day revolving credit facility was finalized concurrent with the expiration. The new facility supports the issuance of commercial paper and other general corporate purposes of the Company. This facility provides for uncollateralized borrowings at prevailing interest rates and is scheduled to expire on June 14, 2001. Interest rates are established by competitive bid. Commitment fees are based upon the Company's lowest secured debt rating and are currently 0.10%. At December 31, 2000, and December 31, 1999, there was approximately $41.4 million and $6.0 million, respectively, in commercial paper outstanding under the facility. 46 Total indebtedness as of December 31, 2000 and 1999 was as follows:
At December 31, ----------------- 2000 1999 -------- -------- (Thousands) Commercial paper, net........................................ $ 41,397 $ 5,989 ======== ======== First mortgage bonds Series X, 9 1/2%, due 2005.............. $ 60,000 $ 60,000 Pollution control revenue bonds, fixed rate of 5.875%, Due 2029, callable after September 1, 2009............................ 61,260 61,260 Medium-term notes 7.85%, due 2000............................................ -- 25,000 5.78%, due 2001............................................ 10,000 10,000 6.42%, due 2001............................................ 15,000 15,000 6.33%, due 2002............................................ 25,000 25,000 6.55%, due 2003............................................ 15,000 15,000 7.00%, due 2003............................................ 10,000 10,000 7.50%, due 2004, callable at 100%, 2002.................... 10,000 10,000 7.55%, due 2004, callable at 100%, 2002.................... 15,000 15,000 6.20%, due 2006............................................ 15,000 15,000 6.32%, due 2006............................................ 15,000 15,000 6.95%, due 2006............................................ 10,000 10,000 6.53%, due 2007............................................ 10,000 10,000 7.00%, due 2007............................................ 25,000 25,000 7.50%, due 2007............................................ 15,000 15,000 6.52%, due 2009............................................ 50,000 50,000 -------- -------- Total medium-term notes.................................. 240,000 265,000 -------- -------- Gross amount of long-term debt........................... $361,260 386,260 Less: Amount due within one year................................. 25,000 25,000 Unamortized premium and discount, net...................... 978 921 -------- -------- Total long-term debt, net................................ $335,282 $360,339 ======== ========
2001 2002 2003 2004 2005 Thereafter ------- ------- ------- ------- ------- ---------- (Thousands) Amounts payable under long- term debt agreements....... $25,000 $25,000 $25,000 $25,000 $25,000 $236,260 ======= ======= ======= ======= ======= ========
The weighted average interest rate on short-term debt at December 31, 2000, was 7.24% compared to 6.42% at December 31, 1999. The first mortgage bonds are collateralized by the LPSC jurisdictional property, plant and equipment within the Company. In the various parishes that contain such property, a lien is filed with the clerk of court. Before the Company can sell any of this property, it must get a release signed by the trustee. 47 Three issues of the Company's 1991 series pollution control bonds totaling $61.3 million were refinanced on September 2, 1999. Two new series were issued to replace the old bonds, which were retired using the legal defeasance method and removed from the balance sheet as permitted under SFAS No. 125, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities." The new bonds were issued at a fixed rate with a coupon of 5.875% and were discounted and sold at 98.956%, with a final maturity of September 1, 2029, subject to optional redemption by the Company after September 1, 2009. The bonds are insurance-backed, thereby fixing the cost of the credit support for the life of the bonds. In a related transaction, an interest rate lock agreement was entered into for the notional amount of the bonds, effectively locking the rate of the bonds at 5.663% for the 30-year period. The Company received approximately $1.8 million from the interest rate lock counterparty upon settlement, which will be amortized over the life of the bonds. Medium-term notes and the pollution control revenue bonds are not collateralized. Note F--Common Stock In association with incentive compensation plans in effect during the two- year period ended December 31, 1998, certain officers and key employees of the Company and its subsidiaries were awarded shares of restricted Company common stock. The cost of the restricted stock awards, as measured by the market value of the common stock at the time of the grant, is recorded as compensation expense during the periods in which the restrictions lapse. As of December 31, 2000, the number of shares of restricted stock previously granted for which restrictions had not lapsed was zero due to the reorganization. Changes in incentive shares for the three-year period ended December 31, 2000, were as follows:
Incentive Share ---------------------------------------- Option Price Unexercised Available for per Share Option Shares Future Grants ------------ ------------- ------------- Balance, January 1, 1998............ 15,800 708,039 Options exercised................... $16.780 (5,000) -- Options granted (directors)......... $31.875 12,503 12,503) Restricted stock granted............ -- (21,362) Restricted stock forfeited.......... -- 2,543 ------- -------- Balance, December 31, 1998.......... 23,303 676,717 Options exercised................... $16.780 (10,800) -- Options moved to holding company.... (12,503) (676,717) ------- -------- Balance, December 31, 1999.......... -- -- ======= ========
As a result of the holding company structure reorganization, all options on Company stock were exchanged for options on Cleco stock. All options outstanding on the Company common stock were cancelled. Had the compensation cost for the Company's stock-based compensation plans been determined consistent with SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123) the Company's net income and net income per common share would approximate the pro forma amounts below: 48
For the year ended December 31, 1998 --------------------- As Pro Reported Forma -------- ------- (Thousands except per share amounts) SFAS No. 123 expense............................... $ $ 525 Estimated reduction in income tax for SFAS No. 123 expense........................................... (173) Net income applicable to common stock.............. $51,664 $51,312 ======= ======= Net income per basic common share.................. $ 2.30 $ 2.28 ======= =======
The assumptions used to calculate the additional compensation expense are as follows:
For the year ended December 31, 1998 ------------------------------------ Expected term (in years)............ 5.00 Volatility.......................... 12.29% Expected dividend yield............. 5.05% Risk-free interest rate............. 5.79% Weighted average fair value (Black Scholes value)..................... $3.13
There were no options issued on the Company's stock in 2000 or 1999 accordingly no expense is shown. The effects of applying SFAS No. 123 in this pro forma disclosure are not necessarily indicative of future amounts. SFAS No. 123 does not apply to awards prior to 1995. Note G--Preferred Stock In connection with the establishment of the Employee Stock Ownership Plan (ESOP), Utility Group, the predecessor of the Company, sold 300,000 shares of 8.125% convertible preferred stock to the ESOP. As part of the holding company reorganization, each share of the Company's 8.125% convertible preferred stock was exchanged for one share of Cleco 8.125% convertible preferred stock. Each share of Cleco 8.125% preferred stock is convertible into 4.8 shares of Cleco common stock. The amount of total capitalization reflected in the consolidated financial statements has been reduced by an amount of deferred compensation expense related to the shares of convertible preferred stock which have not yet been allocated to ESOP participants. The amount shown in the consolidated financial statements for preferred dividend requirements in the first six months of 1999 and year ending 1998 has been reduced by $435,000 and $521,000, respectively, to reflect the benefit of the income tax deduction for dividend requirements on unallocated shares held by the ESOP. 49 Information about the components of preferred stock capitalization of Utility Group predecessor to the Company, is as follows:
Balance Balance Balance Jan. 1, Dec. 31, Dec. 31, 1998 Change 1998 Change 1999 ---------- ------- ---------- ----------- -------- (Thousands, except share amounts) CUMULATIVE PREFERRED STOCK, $100 par value NOT SUBJECT TO MANDATORY REDEMPTION 4.50%................. $ 1,029 $ 1,029 $ (1,029) -- Convertible, Series of 1991, Variable rate.... 29,073 (384) 28,689 (28,689) -- ---------- ------- ---------- ----------- $ 30,102 $ (384) $ 29,718 $ (29,718) -- ========== ======= ========== =========== SUBJECT TO MANDATORY REDEMPTION 4.50%, Series of 1955. 320 (40) 280 (280) -- 4.65%, Series of 1964. 2,940 (140) 2,800 (2,800) -- 4.75%, Series of 1965. 2,860 (260) 2,600 (2,600) -- ---------- ------- ---------- ----------- $ 6,120 $ (440) $ 5,680 $ (5,680) -- ========== ======= ========== =========== Deferred compensation related to convertible preferred stock held by the ESOP............... $ (18,766) $ 1,843 $ (16,923) $ (16,923) -- ========== ======= ========== =========== CUMULATIVE PREFERRED STOCK, $100 par value Number of shares Authorized............ 1,410,000 (4,000) 1,406,000 (1,406,000) -- Issued and outstanding.......... 362,218 (8,240) 353,978 (353,978) -- ========== ======= ========== =========== CUMULATIVE PREFERRED STOCK, $25 par value Number of shares authorized (None outstanding).... 3,000,000 3,000,000 (3,000,000) -- ========== ========== ===========
Note H--Pension Plan and Employee Benefits The Company is the plan sponsor of a defined benefit pension plan that covers substantially all employees of the Company and its affiliates. Benefits under the plan reflect an employee's years of service, age at retirement and highest total average compensation for any consecutive five calendar years during the last ten years of employment with the Company and its affiliates. The Company's policy is to fund contributions to the employee pension plan based upon actuarial computations utilizing the projected unit credit method, subject to the Internal Revenue Service's full funding limitation. The affiliate companies which adopt the pension plan accrue pension expense and record a pension liability using actuarially determined amounts with the benefit of pension assets presently in the plan. The Company records a pension benefit based on its actuarially determined expense, offset by the earning of the assets presently in the plan. If the plan required a contribution, each affiliate would be required to contribute to the plan its prorated share of pension liability and would begin to benefit from the earnings of its assets contributed to the plan. No contributions to the pension plan were required during the three-year period ended December 31, 2000. The Company is reimbursed by its affiliates for the service costs incurred by affiliate employees incurred while the employees are in the employ of the affiliates. 50 The following table represents amounts due to the Pension Plan from affiliates at December 31, 2000:
(Thousands) ----------- Cleco Support Group LLC....................................... $1,845 Cleco Marketing and Trading LLC............................... 246 Cleco Evangeline LLC.......................................... 95 Cleco Generation Services LLC................................. 1,945 Cleco Midstream Resources LLC................................. 60 UtiliTech Solutions........................................... 167 ------ Total....................................................... $4,358 ======
The Company's retirees and their dependents are eligible to receive health, dental and life insurance benefits (other benefits). The Company recognizes the expected cost of these benefits during the periods in which the benefits are earned. The employee pension plan, other benefits obligation plan assets and funded status as determined by the actuary at December 31, 2000 and 1999 are presented in the following table.
Pension Benefits Other Benefits ------------------ ------------------ 2000 1999 2000 1999 -------- -------- -------- -------- (Thousands) Change in benefit obligation Benefit obligation at beginning of year................................ $129,970 $132,721 $ 16,194 $ 16,602 Service cost......................... 3,825 4,353 848 661 Interest cost........................ 9,706 9,198 1,321 1,099 Plan participants contributions...... -- -- 454 338 Actuarial (gain)/loss................ (6,076) (8,728) 362 (1,624) Expenses paid........................ (1,212) (1,254) -- -- Benefits paid........................ (6,602) (6,320) (966) (882) -------- -------- -------- -------- Benefit obligation at end of year.... 129,611 129,970 18,213 16,194 -------- -------- -------- -------- Change in plan assets Fair value of plan assets at beginning of year................... 184,613 181,698 -- -- Actual return on plan assets......... 18,035 10,489 -- -- Expense paid......................... (6,602) (1,254) -- -- Benefits paid........................ (1,212) (6,320) -- -- -------- -------- -------- -------- Fair value of plan assets at end of year................................ 194,834 184,613 -- -- -------- -------- -------- -------- Funded status.......................... 65,223 54,643 (18,213) (16,194) Unrecognized net actuarial (gain).... (60,375) (53,369) (2,646) (3,058) Unrecognized transition obligation/(asset).................. (3,990) (5,308) 6,160 6,673 Prior service cost................... 11,806 12,775 -- -- -------- -------- -------- -------- Prepaid/(accrued) benefit cost....... $ 12,664 $ 8,741 $(14,699) $(12,579) ======== ======== ======== ========
Employee pension plan assets were invested in Cleco's common stock, other publicly traded domestic common stocks, U.S. government, federal agency and corporate obligations, an international equity fund, commercial real estate funds and pooled temporary investments. 51 The components of net periodic pension and other benefits cost (income) for 2000, 1999 and 1998 are as follows, along with assumptions used:
Pension Benefits Other Benefits ------------------------- ---------------------- 2000 1999 1998 2000 1999 1998 ------- ------- ------- ------ ------ ------ (Thousands) Components of periodic benefit costs Service cost............. $ 3,825 $ 4,353 $ 3,734 $ 848 $ 661 $ 671 Interest cost............ 9,706 9,198 8,326 1,321 1,099 1,062 Expected return on plan assets.................. (15,912) (14,267) (12,797) -- -- -- Amortization of transition Obligation (asset)...... (1,318) (1,317) (1,318) 513 513 513 Prior period service cost Amortization............ 969 969 969 -- -- -- Net (gain) loss.......... (1,194) -- (142) 5 -- (66) ------- ------- ------- ------ ------ ------ Net periodic benefit cost/(income)........... $(3,924) $(1,064) $(1,228) $2,687 $2,273 $2,180 ======= ======= ======= ====== ====== ====== Pension Benefits Other Benefits ------------------------- ---------------------- 2000 1999 1998 2000 1999 1998 ------- ------- ------- ------ ------ ------ Weighted-average assumptions as of December 31: Discount rate............ 8.00% 7.50% 6.75% 8.00% 7.50% 6.75% Expected return on plan assets.................. 9.50% 9.50% 9.50% N/A N/A N/A Rate of compensation increase................ 5.00% 5.00% 5.00% N/A N/A N/A
The assumed health care cost trend rate used to measure the expected cost of other benefits was 8.0% in 2000, 8.5% in 1999 and 9.5% in 1998, declining to 5.5% by 2009 and remaining at 5.5% thereafter. The initial health care cost trend rate was reduced from 10% in 1996 to 9.5% in 1998 and to 8.5% in 1999 and to 8.0% in 2000, which resulted in an unrecognized gain. Assumed health care cost trend rates have a significant effect on the amount reported for the health care plans. A one-percentage point change in assumed health care cost trend rates would have the following effects on other benefits:
1-percentage point ----------------- Increase Decrease -------- -------- (Thousands) Effect on total of service and interest cost components........................................... $147 $(149) Effect on post retirement benefit obligation.......... $953 $(988)
Substantially all employees are eligible to participate in a savings and investment plan (401(k) Plan). The Company makes matching contributions to 401(k) Plan participants by allocating shares of Cleco's convertible preferred stock held by the ESOP. Compensation expense related to the 401(k) Plan is based upon the value of shares of preferred stock allocated to ESOP participants and the amount of interest incurred by the ESOP, less dividends on unallocated shares held by the ESOP. At December 31, 2000 and 1999, the ESOP had allocated to employees 152,189 and 139,086 shares, respectively. 52 The table below contains information about the 401(k) Plan and the ESOP:
For the year ended December 31, -------------------- 2000 1999 1998 ------ ------ ------ (Thousands) 401(k) Plan expense.................................... $1,061 $1,108 $1,107 Dividend requirements to ESOP on convertible preferred stock................................................. $2,231 $2,283 $2,341 Interest incurred by ESOP on its indebtedness.......... $1,109 $1,296 $1,683 Company contributions to ESOP.......................... $1,391 $1,513 $1,075
Note I--Income Tax Expense Federal income tax expense is less than the amount computed by applying the statutory federal rate to book income before tax as follows:
For the year ended December 31, ---------------------------------------------- 2000 1999 1998 -------------- -------------- -------------- Amount % Amount % Amount % ------- ----- ------- ----- ------- ----- (Thousands, except for %) Book income before tax......... $90,855 100.0 $83,955 100.0 $80,467 100.0 Tax at statutory rate on book income before tax............. 31,799 35.0 29,384 35.0 28,163 35.0 Increase (decrease): Tax effect of AFUDC.......... (381) (0.4) (261) (0.3) (601) (0.8) Amortization of investment tax credits................. (1,742) (1.9) (1,790) (2.1) (1,790) (2.2) Tax effect of prior-year tax benefits not deferred....... 988 1.1 1,119 1.3 2,175 2.7 AFUDC gross up--FASB 109..... (1,731) (1.9) (1,548) (1.8) (1,009) (1.3) Other, net................... (1,256) (1.4) (2,550) (3.0) (2,443) (3.0) ------- ------- ------- Total federal income tax expense................... 27,677 30.5 24,354 29.0 24,495 30.4 Current state income tax expense....................... 3,321 3.7 2,918 3.5 2,171 2.7 ------- ------- ------- Total federal and state income tax expense........ $30,998 34.1 $27,272 32.5 $26,666 33.1 ======= ======= ======= =====
Information about current and deferred income tax expense is as follows:
2000 1999 1998 ------- ------- ------- (Thousands) Current federal income tax expense............... $23,732 $17,675 $17,582 Deferred federal income tax expense.............. 5,687 8,469 8,703 Amortization of accumulated deferred investment tax credits..................................... (1,742) (1,790) (1,790) ------- ------- ------- Total federal income tax expense............. 27,677 24,354 24,495 State income tax expense......................... 3,321 2,918 2,171 ------- ------- ------- Total federal and state income tax expense... $30,998 $27,272 $26,666 ======= ======= ======= Deferred federal income tax expense attributable to: Depreciation................................... $ 4,710 $ 8,428 $11,748 Storm damages.................................. (199) 912 492 Asset basis differences........................ (2,078) (2,717) (571) Employee benefits.............................. 3,443 222 (419) Fuel costs..................................... 2,062 660 (612) Reacquired debt................................ (210) (269) (249) Other.......................................... (2,041 1,233 (1,686) ------- ------- ------- Total deferred federal income tax expense.... $ 5,687 $ 8,469 $ 8,703 ======= ======= =======
53 The balance of accumulated deferred federal and state income tax assets and liabilities at December 31, 2000 and 1999, was comprised of the tax effect of the following:
2000 1999 ----------------- ----------------- Asset Liability Asset Liability ------- --------- ------- --------- (Thousands) Depreciation and property basis differences............................... $ 5,528 $157,987 $ 6,653 $152,971 Allowance for funds used during construction.............................. -- 28,756 -- 30,826 Investment tax credits..................... 16,259 -- 16,805 -- FASB 109 adjustments....................... 21,123 65,286 21,658 65,230 Post retirement benefits other than pension................................... 3,657 -- 4,723 -- Other...................................... 5,577 16,282 5,345 14,661 ------- -------- ------- -------- Accumulated deferred federal and state income taxes.............................. $52,144 268,311 $55,184 $263,688 ======= ======== ======= ========
Regulatory assets recorded for deferred taxes at December 31, 2000 and 1999, were $100.3 million and $70.8 million, respectively. Regulatory liabilities recorded for deferred taxes at December 31, 2000 and 1999, were $38.8 million and $27.2 million, respectively. Regulatory assets and liabilities will be realized over the accounting lives of the related properties to the extent past ratemaking practices are continued by regulators. Note J--Accrual of Estimated Customer Credits The Company's reported earnings in the year ended December 31, 2000, reflect a $1.2 million accrual for estimated customer credits that may be required under terms of an earnings review settlement reached with the LPSC in 1996. The 1996 LPSC settlement, 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 $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. Of the $1.2 million, $0.7 million relates to the 12-month-ended September 30, 2000, cycle, and the remaining $0.5 million relates to the estimated refund for the 12-month-ended September 30, 1999, cycle. The $1.2 million was recorded as a reduction in revenue due to the nature of the customer credits. The $0.5 million relating to the September 30, 1999, cycle is due to a settlement with the LPSC. The amount of the credit for the cycle ending September 30, 2000, if any, has not yet been determined by the LPSC, as more fully described in Note M. 54 Note K--Affiliate Transactions Effective July 1, 1999, the Company entered into service agreements with affiliates, which provide the Company access to professional services and goods. The service and goods are charged to the Company at the lower of fair market value or fully loaded costs in order to comply with Cleco's inter- affiliate policy. A summary of charges from each affiliate included in the Statement of Income follows:
Statement of Income ------------------- 2000 1999 --------- --------- (Thousands) Cleco Corporation Other operation.................................... $ -- $ 70 Other income (expense), net........................ -- 2 Cleco Marketing & Trading LLC Other operation.................................... 4,960 1,638 Other income (expense), net........................ 1 241 Cleco Evangeline LLC Fuel and power purchased........................... -- -- Other operations................................... 4 -- Maintenance........................................ 9 86 Cleco Midstream Resources LLC Other operations................................... 690 -- Other income and deductions........................ 1 -- Cleco Energy LLC Fuel and power purchased........................... 1,534 1,580 Cleco Generation Services LLC Other operations................................... 1,884 -- Maintenance........................................ 7,254 -- Other income and deductions........................ 4 -- Cleco ConnexUs LLC Other income and deductions........................ 29 -- Utility Construction & Technology Solutions LLC Other operations................................... -- 76 Maintenance........................................ 171 58 Taxes not including income......................... 1 -- Other income and deductions........................ 8 --
Prior to July 1, 1999, the affiliates were subsidiaries of the Company and their operations were included with those of the Company and reflected in other income/(expenses), net. 55 The Company also entered into agreements to provide goods and services to affiliated companies. The goods and services are charged by the Company at the higher of fully loaded cost or fair market value in order to comply with Cleco's interaffiliate policy. Following is a reconciliation of the Company's affiliate revenues:
2000 1999 ------ ------ (Thousands) Cleco Corporation.......................................... $ -- $ 19 Cleco Midstream Resources LLC.............................. 349 236 Utility Construction & Technology Solutions LLC............ 2,121 2,494 Cleco Support Group LLC.................................... 3,065 138 Cleco ConnexUs LLC......................................... 102 -- Cleco Evangeline LLC....................................... 1,570 3,841 Cleco Energy LLC........................................... -- 110 Cleco Marketing & Trading LLC.............................. 1,866 978 Cleco Generation Services LLC.............................. 183 -- ------ ------ Total.................................................... $9,256 $7,816 ====== ======
The Company has the following affiliate receivable and payable balances associated with the service agreements between the Company and its affiliates:
2000 1999 ------------------- ------------------- Accounts Accounts Accounts Accounts Receivable Payable Receivable Payable ---------- -------- ---------- -------- (Thousands) Cleco Corporation...................... $ 299 $ -- $ 7,525 $ -- Utility Construction & Technology Solutions LLC......................... 294 -- 1,676 -- Cleco Support Group LLC................ -- 5,172 -- -- Cleco Generation Services LLC.......... -- 2,884 -- -- Cleco Evangeline LLC................... -- 9 11,395 -- Cleco Midstream Resources LLC.......... 86 -- 1,405 -- Cleco Marketing & Trading LLC.......... -- 571 -- 7,892 Cleco Energy LLC....................... -- 1,887 -- 1,352 Others................................. 778 323 623 -- ------ ------- ------- ------ Total................................ $1,457 $10,846 $22,624 $9,244 ====== ======= ======= ======
During the period July 1, 1999 to December 31, 1999, the Company paid cash dividends to Cleco of approximately $39.8 million. For the year ended December 31, 2000, the Company paid cash dividends to Cleco of approximately $59.4 million. Note L--Disclosures about Segments The Company changed the structure of its internal organization, which caused a change in the determination of reportable segments from the reportable segments disclosed in 1999. The reorganization into a holding company structure effective July 1, 1999 entailed the movement of all subsidiaries of the Company to the new holding company, Cleco. The Company is a vertically integrated, regulated electric utility operating within Louisiana and is viewed as one unit by management. Discrete financial reports are prepared only at the company level. This approach is consistent with the accounting standards applicable to segment reporting. 56 Note M--Proceedings before the LPSC Several Louisiana-based contractors providing utility line construction services instituted a proceeding via petition with the LPSC on April 9, 1999, alleging subsidization by the Company of a non-regulated affiliate, Cleco Services LLC, now operating as Utility Construction & Technology Solutions LLC. The LPSC assigned Docket No. U-24064 to the complaint. The complainants, LPSC staff and the Company have conducted discovery, pre-filed testimony has been prepared and depositions taken. On September 6, 2000, the Company and the complainants signed an agreement to settle the dispute. The terms of the settlement did not result in a material impact to the Company's results of operations or financial condition. In connection with this proceeding, the LPSC staff engaged the services of an outside consultant. The outside consultant filed testimony on behalf of the LPSC staff identifying several possible ratemaking adjustments to the Company's previous and future Rate Stabilization Plan filings that could affect the Company's customer credits. On October 3, 2000, the Company and the staff of the LPSC signed an agreement resolving all outstanding issues, which the LPSC approved on November 2, 2000. The settlement resulted in an increase to the Company's customer credits of approximately $500,000, which will be paid to customers in September 2001. Note N--Commitments and Contingencies In recent years, the Company's construction program has consisted primarily of enhancements to its transmission and distribution systems and improvements at its generating stations. The Company's construction expenditures, excluding AFUDC, totaled $47.9 million in 2000, $51.7 million in 1999, and $53.9 million in 1998. The Company construction expenditures, excluding AFUDC, for 2001 are estimated to be $57 million and for the five-year period ending 2005 are expected to total $249 million. About one-half of the planned construction in the five-year period will support line extensions and substation upgrades to accommodate new business and load growth. Some investment will be made to rehabilitate older transmission, distribution and generation assets. The Company will also continue to invest in technology to allow it to operate more efficiently. In 2000 and 1999, 100% of the Company's construction requirements were funded internally, as compared to 99.8% in 1998. In 2001, 96% of construction requirements are expected to be funded internally. For the five-year period ending 2005, 96% of construction requirements are expected to be funded internally. The Company has entered into various long-term contracts for the procurement of coal and lignite to fuel certain of its generating stations. These contracts contain provisions for price changes, minimum purchase levels and other financial commitments. The Company purchases natural gas, as an additional fuel source for generation, under short-term contracts on the spot market. For the upcoming session of the Louisiana Legislature, a proposed bill, Senate Bill 1 has been filed for consideration. The bill institutes a process by which all new industrial and agricultural users of groundwater must apply for and obtain permits to pump groundwater if their wells have a maximum flow rate of one million gallons or more. If the bill becomes law, it will not have a material adverse effect on our financial condition or results of operations. The Company has accrued for liabilities to third parties, environmental claims, employee medical benefits, storm damages and deductibles under insurance policies that it maintains on major properties, primarily generating stations and transmission substations. Consistent with regulatory treatment, annual charges to operating expense to provide a reserve for future storm damages are based upon the average amount of noncapital, uninsured storm damages experienced by the Company during the previous five years. 57 Note O--Miscellaneous Financial Information (Unaudited) Quarterly information for the Company for 2000 and 1999 is shown in the following table.
2000 ----------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter -------- -------- -------- -------- (Thousands, except per share amounts) Operating revenues....................... $119,166 $146,793 $205,728 $163,913 Operating income......................... $ 25,917 $ 32,837 $ 38,680 $ 24,390 Net income applicable to common stock.... $ 12,688 $ 16,770 $ 19,832 $ 10,567 1999 ----------------------------------- 1st 2nd 3rd 4th Quarter Quarter Quarter Quarter -------- -------- -------- -------- (Thousands, except per share amounts) Operating revenues....................... $121,719 $222,474 $275,810 $131,558 Operating income......................... $ 19,481 $ 29,519 $ 30,631 $ 5,669 Net income applicable to common stock.... $ 8,017 $ 13,716 $ 23,537 $ 10,366 Dividends paid per common share.......... $ 0.405 $ 0.415 $ 1.817 $ 1.324 Market price per share High................................... $ 35.500 $ 33.563 $ N/A $ N/A Low.................................... $ 28.250 $ 28.438 $ N/A $ N/A
Note P--Legal Proceedings Proceeding before the LPSC For information on the proceedings before the LPSC see Note M in the Notes to the Financial Statements. Fuel Supply--Lignite The Company and SWEPCO, each a 50% owner of Dolet Hills Unit 1, jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana. In 1982, we and SWEPCO entered into a Lignite Mining Agreement (LMA) with 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 1,750,000 tons under the LMA. Since the late 1980s, additional spot lignite deliveries have been obtained through competitive bidding from DHMV and another lignite supplier. In 2000, the Company and SWEPCO received deliveries that approximated 21% of the annual lignite consumption at the 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 (the 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. 58 As a result of the counterclaims filed by DHMV in the Federal Court Suit, on August 13, 1997, the Company and SWEPCO filed a separate lawsuit against the parent companies of DHMV, namely Jones Capital Corporation and Philipp Holzmann USA, Inc. 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 March 1, 2000, the court in the Federal Court Suit ruled that DHMV was not in breach of certain financial covenants under the LMA and denied the Company's and SWEPCO's claim to terminate the LMA on that basis. The ruling has no material adverse effect on the Company's operations and does not affect the other claims scheduled for trial. The Company and SWEPCO have appealed the federal court's ruling to the United States Court of Appeals for the Fifth Circuit. The civil, nonjury trial in the Federal Court Suit was to have commenced on May 22, 2000. However, on April 20, 2000, all parties jointly requested that the court postpone the trial date and grant a 120-day stay of all matters before the trial court to give the parties an opportunity to attempt to reach an amicable resolution of the litigation. A preliminary memorandum of understanding to settle the litigation has been executed among the Company, SWEPCO, and DHMV. However, the memorandum of understanding is subject to several conditions precedent that are not yet fulfilled, including prior authorization by the LPSC of favorable rate recovery of the settlement by the Company and SWEPCO. The federal court granted the motion, stayed the action at the trial court and postponed the trial commencement date to October 23, 2000. At a status conference held on July 12, 2000, the court extended the stay of the proceedings and again postponed the trial date to January 16, 2001. Due to the need additional time to attempt to refine the settlement, the parties requested, and on September 26, 2000, the court ordered that the stay be extended and the trial date be postponed indefinitely. The Fifth Circuit appeal of the federal court's March 1, 2000, ruling has also been stayed pending settlement. Settlement negotiations are ongoing during the pendency of the stay. Should settlement discussions be unsuccessful, the Company and SWEPCO will continue aggressively to prosecute the claims against DHMV and defend against the counterclaims that 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 or the settlement negotiations cannot be predicted at this time, based on information currently available to the Company, management does not believe that the outcome of the Federal Court Suit or any settlement in the Federal Court Suit will have a material adverse effect on the Company's financial position or results of operations. 59 PART III. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS Information for this Item is omitted pursuant to General Instruction I to Form 10-K. ITEM 11. EXECUTIVE COMPENSATION Information for this Item is omitted pursuant to General Instruction I to Form 10-K. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information for this Item is omitted pursuant to General Instruction I to Form 10-K. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Information for this Item is omitted pursuant to General Instruction I to Form 10-K. 60 PART IV. ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 10-K 14(a)(1) The following consolidated financial statements of ours are included in Part II, Item 8:
Page ---- Independent Auditors Report......................................... 36 Balance Sheets at December 31, 2000 and 1999........................ 37 Statements of Income for the years ended December 31, 2000, 1999 and 1998 .............................................................. 39 Statement of Cash Flows for the years ended December 31, 2000, 1999 and 1998 .......................................................... 40 Statement of Changes in Common Shareholders Equity for the years ended December 31, 2000, 1999 and 1998............................. 41 Notes to the Financial Statements................................... 33 Independent Auditor's Report on Financial Schedules................. 71 14(a)(2) Financial Statement Schedules Financial Schedule II Valuation and Qualifying Accounts............. 72
Financial Statement Schedules other than those shown in the above index are omitted because they are either not required or are not applicable or the required information is shown in the Financial Statements and Notes thereto. 14(a)(3) The exhibits designated by an asterisk are filed herewith. The exhibits not so designated have been previously filed with the SEC and are incorporated herein by reference. The exhibits designated by two asterisks are management contracts and compensatory plans and arrangements required to be filed as exhibits to this Report. 61
SEC File or Registration Filing or Exhibit Exhibits Number Report Number -------------------------- ------------ --------------- -------- 2(a) Joint Agreement of Merger of Cleco Utility Group Inc. with and into Cleco Power UC, dated December 15, 2000 3(a) Articles of Organization and initial report of Cleco Power LLC, dated December 31, 2000 533-52540 S-3/A (1/26/01) 3(a) 3(b) Second Supplemental Indenture dated January 1, 2001 333-52540 S-3/A (1/26/01) 3(b) 4(a)(1) Indenture of Mortgage dated as of July 1, 1950, between the Company and First National Bank of New Orleans, as Trustee 1-5663 10-K (1997) 4(a)(1) 4(a)(2) First Supplemental Indenture dated as of October 1, 1951, to Exhibit 4(a)(1) 1-5663 10-K (1997) 4(a)(2) 4(a)(3) Second Supplemental Indenture dated as of June 1, 1952, to Exhibit 4(a)(1) 1-5663 10-K (1997) 4(a)(3) 4(a)(4) Third Supplemental Indenture dated as of January 1, 1954, to Exhibit 4(a)(1) 1-5663 10-K (1997) 4(a)(4) 4(a)(5) Fourth Supplemental Indenture dated as of November 1, 1954, to Exhibit 4(a)(1) 1-5663 10-K (1997) 4(a)(5) 4(a)(6) Tenth Supplemental Indenture dated as of September 1, 1965, to Exhibit 4(a)(1) 1-5663 10-K (1986) 4(a)(11) 4(a)(7) Eleventh Supplemental Indenture dated as of April 1, 1969, to Exhibit 4(a)(1) 1-5663 10-K (1998) 4(a)(8) 4(a)(8) Eighteenth Supplemental Indenture dated as of December 1, 1982, to Exhibit 4(a)(1) 1-5663 10-K (1993) 4(a)(8) 4(a)(9) Nineteenth Supplemental Indenture dated as of January 1, 1983, to Exhibit 4(a)(1) 1-5663 10-K (1993) 4(a)(9) 4(a)(10) Twenty-Sixth Supplemental Indenture dated as of March 15, 1990, to Exhibit 4(a)(1) 1-5663 8-K (3/90) 4(a)(27) 4(b) Indenture between the Company and Bankers Trust Company, as Trustee, dated as of October 1, 1988 33-24896 S-3 (10/11/88) 4(b) 4(b)(1) Agreement Appointing Successor Trustee dated as of April 1, 1996 by and among Central Louisiana Electric Company, Inc., Bankers Trust Company and The Bank of New York 333-02895 S-3 (4/26/96) 4(a)(2) 4(f) Agreement Under Regulation S-K Item 601(b)(4)(iii)(A) 333-71643-01 10-Q (9/99) 4(c) 4(g) $100,000,000 364-day credit agreement dated as of June 15, 2000, among the Company, certain Banks parties thereto, and The Bank of New York, Form 10 as administrative agent 0-1272 (11/15/2000) 4(g) 4(h) First Supplemental Indenture, dated as of December 1, 2000 between Cleco Utility Group Inc. and the Bank of New York 333-52540 S-3/A (1/26/01) 4(a)(2)
62
SEC File or Registration Exhibit Exhibits Number Filing or Report Number ------------------------- ------------ ---------------- --------- 4(i) Second Supplemental Indenture, dated as of January 1, 2001, between Cleco Power LLC and The Bank of New York 333-52540 S-3/A (1/26/01) 4(a)(3) 10(a) 1990 Long-Term Incentive 1990 Proxy Compensation Plan 1-5663 Statement (4/90) A 10(b) Participation Agreement, Annual Incentive Compensation Plan 1-5663 10-K (1999) 10(c) 10(c) Deferred Compensation Plan for Directors 1-5663 10-K (1992) 10(n) 10(d)(1) Supplemental Executive Retirement Plan 1-5663 10-K (1992) 10(o)(1) 10(e)(1) Term Loan Agreement dated as of April 2, 1991, among the 401(k) Savings and Investment Plan ESOP Trust, the Company, as Guarantor, the Banks listed therein and The Bank of New York, as Agent 1-5663 10-Q (3/91) 4(b) 10(e)(2) Assignment and Assumption Agreement, effective as of May 6, 1991, between The Bank of New York and the Canadian Imperial Bank of Commerce, relating to Exhibit 10(f)(1) 1-5663 10-Q (3/91) 4(c) 10(e)(3) Assignment and Assumption Agreement dated as of July 3, 1991, between The Bank of New York and Rapides Bank and Trust Company in Alexandria, relating to Exhibit 10(f)(1) 1-5663 10-K (1991) 10(y)(3) 10(e)(4) Assignment and Assumption Agreement dated as of July 6, 1992, between The Bank of New York, CIBC, Inc. and Rapides Bank and Trust Company in Alexandria, as Assignors, the 401(k) Savings and Investment Plan ESOP Trust, as Borrower, and the Company, as Guarantor, relating to Exhibit 10(f)(1) 1-5663 10-K (1992) 10(bb)(4)
63
SEC File or Registration Filing or Exhibit Exhibits Number Report Number ----------------------------- ------------ -------------- ------- 10(g) Reimbursement Agreement (The Industrial Development Board of the Parish of Rapides, Inc. (Louisiana) Adjustable Tender Pollution Control Revenue Refunding Bonds, Series 1991) dated as of October 15, 1997, among the Company, various financial institutions, and Westdeutsche Landesbank Girozentrale, New York Branch, as Agent 1-5663 10-K (1997) 10(I) 10(h) Selling Agency Agreement between the Company and Salomon Brothers Inc., Merrill Lynch & Co., Smith Barney Inc. and First Chicago Capital Markets, Inc. dated as of December 12, 1996 333-02895 S-3 (12/10/96) 1 10(i) 401(k) Savings and Investment Plan ESOP Trust Agreement dated as of August 1, 1997, between UMB Bank, N.A. and the Company 1-5663 10-K (1997) 10(m) 10(i)(1) First Amendment to 401(k) Savings and Investment Plan ESOP Trust Agreement dated as of October 1, 1997, between UMB Bank, N.A. and the Company 1-5663 10-K (1997) 0(m)(1) 12 Computation of Earnings to Fixed Charges 23 Consent of Independent Accountants 24 Powers of Attorney from each Manager of the Company whose signature is affixed to this Form 10-K for the year ended December 31, 2000 (b) Reports on Form 8-K During the three-month period ended December 31, 2000, the Company filed no current reports on Form 8-K
64 Report of Independent Accountants To the Board of Managers and Member of Cleco Power LLC: In our opinion, the financial statements listed in the index appearing under Item 14(a)(1) on page 67 present fairly, in all material respects, the financial position of Cleco Power LLC at December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 14 (a) (2) on page 67 presents fairly, in all material respects, the information set forth therein when read in conjunction with the related financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits. We conducted our audits of these statements in accordance with auditing standards generally accepted in the United States of America, which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. PricewaterhouseCoopers LLP New Orleans, Louisiana January 30, 2001 65 CLECO POWER LLC SCHEDULE II--VALUATION AND QUALIFYING ACCOUNTS Years ended December 31, 2000, 1999 and 1998 (Thousands)
Col. A Col. B Col. C Col. D Col. E - ------ ---------- ---------- --------------- ---------- Additions Uncollectible Balance at Charged to Accounts Write- Balance at Allowance for Uncollectible Beginning Costs and offs, End of Accounts of Period Expenses Less Recoveries Period (1) - --------------------------- ---------- ---------- --------------- ---------- Year Ended December 31, 2000. $838 $1,219 $1,300 $757 Year Ended December 31, 1999. $812 $ 751 $ 725 $838 Year Ended December 31, 1998. $684 $1,069 $ 942 $812
- -------- (1) Deducted in the balance sheet. 66 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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 Power Llc (Registrant) /s/ David M. Eppler _____________________________________ (David M. Eppler, President, Chief Executive Officer and Manager) Date: March 30, 2001 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
Signature Title Date --------- ----- ---- /s/ David M. Eppler President, Chief Executive April 2, 2001 ____________________________________ Officer and Manager (David M. Eppler) /s/ Thomas J. Howlin Senior Vice President-- April 2, 2001 ____________________________________ Financial Services and (Thomas J. Howlin) Chief Financial Officer (Principal Financial Officer) /s/ R. Russell Davis Vice President, Controller April 2, 2001 ____________________________________ (Principal Accounting (R. Russell Davis) Officer)
MANAGERS* Sherian G. Cadoria Richard B. Crowell J. Patrick Garrett F. Ben James, Jr. Elton R. King A. Deloach Martin, Jr. Robert T. Ratcliff Edward M. Simmons William H. Walker, Jr. /s/ David M. Eppler - ------------------------------- April 2, 2001 *By: David M. Eppler 67 EX-2.(A) 2 0002.txt JOINT MERGER AGREEMENT EXHIBIT 2(a) JOINT AGREEMENT OF MERGER OF CLECO UTILITY GROUP INC. WITH AND INTO CLECO POWER LLC This Joint Agreement of Merger (this "Joint Agreement") is dated December 15, 2000 between Cleco Utility Group Inc., a Louisiana corporation (the "Corporation"), and Cleco Power LLC, a Louisiana limited liability company (the "LLC"), and is entered into pursuant to the provisions of Sections 111 et seq. of the Louisiana Business Corporation Law ("LBCL") and Sections 1357 et seq. of the Louisiana Limited Liability Companies Law ("LLCL"). WHEREAS, the Board of Directors of the Corporation and the Managers of the LLC (collectively, the "Merging Companies") deem it advisable that the Corporation be merged with and into the LLC (the "Merger") pursuant to the LBCL and LLCL; and, WHEREAS, the sole shareholder of the Corporation has authorized the Merger pursuant to resolutions duly adopted at a meeting of the sole shareholder held on October 27, 2000; and WHEREAS, the sole member of the LLC has authorized the Merger pursuant to resolutions duly adopted at a meeting of the sole member on December 15, 2000; NOW THEREFORE, in consideration of the mutual benefits to be derived from this Joint Agreement and the Merger, the parties hereto agree as follows: 1. THE MERGER In accordance with the applicable provisions of the LBCL and LLCL, the Corporation shall be merged with and into the LLC; the separate existence of the Corporation shall cease; and the LLC shall survive the Merger. 2. EFFECTIVENESS OF THE MERGER 2.1 Effective Time and Effective Date of the Merger. The Merger shall become effective at 11:59 P.M. (Baton Rouge time) (the "Effective Time") on December 31, 2000 (the "Effective Date"). 2.2 Effect of the Merger. At the Effective Time, (i) the separate existence of the Corporation shall cease and the Corporation shall be merged with and into the LLC; (ii) the LLC shall continue to possess all of the rights, privileges and franchises possessed by it and shall, at the Effective Time, become vested with and possess all rights, privileges and franchises possessed by the Corporation; (iii) the LLC shall be responsible for all of the liabilities and obligations of the Corporation in the same manner as if the LLC had itself incurred such liabilities or obligations, and the Merger shall not affect or impair the rights of the creditors or of any persons dealing with the Merging Companies; (iv) the Merger will not of itself cause a change, alteration or amendment to the Articles of Organization or Operating Agreement of the LLC which shall be the entity surviving the Merger; and (v) the Merger shall, from and after the Effective Time, have all the effects provided by applicable Louisiana law. 2.3 Additional Actions. If, at any time after the Effective Time, the LLC shall consider or be advised that any further assignments or assurances in law of any other acts are necessary or desirable (a) to vest, perfect or confirm, of record or otherwise, in the LLC, title to or the possession of any property or right of the Corporation acquired or to be acquired by reason of, or as a result of, the Merger, or (b) otherwise to carry out the purposes of this Joint Agreement, the Corporation and its proper officers and directors shall be deemed to have granted to the LLC an irrevocable power of attorney to execute and deliver all such proper deeds, assignments and assurances in law and to do all acts necessary or proper to vest, perfect or confirm title to and possession of such property or rights in the LLC and otherwise to carry out the purposes of this Joint Agreement; and the members and the Managers of the LLC are fully authorized in the name of the Corporation to take any and all such action. 3. METHOD OF CARRYING MERGER INTO EFFECT This Joint Agreement shall be submitted to the shareholder of the Corporation and the member of the LLC for their respective approval. If such approval is given, then the fact of such approval shall be certified hereon by the Secretary of the Corporation and a Manager of the LLC. This Joint Agreement, so approved and certified, shall, as soon as is practicable, be signed and acknowledged by the President of the Corporation and a Manager of the LLC. As soon as may be practicable thereafter, this Joint Agreement, so certified, signed and acknowledged, shall be delivered to the Secretary of State of Louisiana for filing in the manner required by law and shall be effective at the Effective Time on the Effective Date; and thereafter, as soon as practicable, a copy of the Certificate of Merger issued by the Secretary of State of Louisiana, and certified by him to be a true copy, shall be filed for record in the Office of the Recorder of Mortgages in the parish in which the Corporation has its registered office and shall be filed for record in the office of the Recorder of Conveyances in each parish in which any of the Merging Companies own immovable property. 4. CANCELLATION OF SHARES On the Effective Date, by reason of the Merger and without any further action on the part of the Merging Companies or their respective shareholders or members, each issued and outstanding share of (i) common stock, par value $2.00 per share, (ii) preferred stock, par value $100 per share, and (iii) preferred stock, par value $25 per share, of the Corporation shall be canceled and the separate corporate existence of the Corporation shall cease. 2 5. MISCELLANEOUS 5.1 Headings. The descriptive headings of the sections of this Joint Agreement are inserted for convenience only and do not constitute a part hereof for any other purpose. 5.2 Modifications, Amendments and Waivers. At any time prior to the Effective Time (notwithstanding any shareholder or member approval that may have already been given), the parties hereto may, to the extent permitted by law, modify, amend or supplement any term or provision of this Joint Agreement. IN WITNESS WHEREOF, this Joint Agreement has been approved by the Board of Directors of the Corporation and the Managers of the LLC, effective as of the day and year first above written. FOR THE BOARD OF DIRECTORS OF CLECO UTILITY GROUP INC. /s/Sherian G. Cadoria ----------------------------------- Sherian G. Cadoria, Director /s/Richard B. Crowell ----------------------------------- Richard B. Crowell, Director /s/David M. Eppler ----------------------------------- David M. Eppler, Director /s/J. Patrick Garrett ----------------------------------- J. Patrick Garrett, Director /s/F. Ben James, Jr. ----------------------------------- F. Ben James, Jr., Director /s/Elton R. King ----------------------------------- Elton R. King, Director /s/A. DeLoach Martin, Jr. ----------------------------------- A. DeLoach Martin, Jr., Director 3 /s/Robert T. Ratcliff ----------------------------------- Robert T. Ratcliff, Director /s/Edward M. Simmons ----------------------------------- Edward M. Simmons, Director /s/William H. Walker, Jr. ----------------------------------- William H. Walker, Jr., Director FOR THE MANAGERS OF CLECO POWER LLC /s/Sherian G. Cadoria ----------------------------------- Sherian G. Cadoria, Manager /s/Richard B. Crowell ----------------------------------- Richard B. Crowell, Manager /s/David M. Eppler ----------------------------------- David M. Eppler, Manager /s/J. Patrick Garrett ----------------------------------- J. Patrick Garrett, Manager /s/F. Ben James, Jr. ----------------------------------- F. Ben James, Jr., Manager /s/Elton R. King ----------------------------------- Elton R. King, Manager /s/A. DeLoach Martin, Jr. ----------------------------------- A. DeLoach Martin, Jr., Manager /s/Robert T. Ratcliff ----------------------------------- Robert T. Ratcliff, Manager 4 /s/Edward M. Simmons ----------------------------------- Edward M. Simmons, Manager /s/William H. Walker, Jr. ----------------------------------- William H. Walker, Jr., Manager CERTIFICATE OF SECRETARY OF CLECO UTILITY GROUP INC. (A Louisiana Corporation) I hereby certify that I am the duly elected Secretary of Cleco Utility Group Inc., a Louisiana corporation, presently serving in such capacity, and that the foregoing Joint Agreement of Merger was, in the manner required by the Louisiana Business Corporation Law, duly approved, without alteration or amendment, by the sole shareholder of Cleco Utility Group Inc. pursuant to a written consent of the sole shareholder. Certificate dated December 15, 2000. /s/Michael P. Prudhomme ----------------------- Michael P. Prudhomme, Secretary CERTIFICATE OF EXECUTIVE MANAGER OF CLECO POWER LLC (A Louisiana limited liability company) I hereby certify that I am a duly elected Manager of Cleco Power LLC, a Louisiana limited liability company, presently serving in such capacity, and that the foregoing Joint Agreement of Merger was duly approved, without alteration or amendment, by the sole member of Cleco Power LLC pursuant to a written consent of the sole member. Certificate dated December 15, 2000. /s/David M. Eppler ------------------ David M. Eppler, Manager 5 EXECUTION BY THE PARTIES Considering the foregoing certification, this Joint Agreement of Merger is executed by the parties hereto, this 15th day of December, 2000. CLECO UTILITY GROUP INC. By: /s/David M. Eppler ------------------ David M. Eppler, President CLECO POWER LLC By: /s/David M. Eppler ------------------ David M. Eppler, Manager 6 ACKNOWLEDGMENT AS TO CLECO UTILITY GROUP INC. STATE OF LOUISIANA PARISH OF RAPIDES BEFORE ME, the undersigned authority, personally came and appeared David M. Eppler, who, being duly sworn, declared and acknowledged before me that he is the President of Cleco Utility Group Inc. and that in such capacity he was duly authorized to and did execute the foregoing Joint Agreement of Merger on behalf of said Corporation, for the purposes therein expressed, and as his and said Corporation's free act and deed. /s/David M. Eppler ------------------ David M. Eppler Appearer SWORN TO AND SUBSCRIBED BEFORE ME THIS 15th DAY OF DECEMBER, 2000. /s/ Beatrice P. Newcomb - ------------------------- Beatrice P. Newcomb NOTARY PUBLIC 7 ACKNOWLEDGMENT AS TO CLECO POWER LLC STATE OF LOUISIANA PARISH OF RAPIDES BEFORE ME, the undersigned authority, personally came and appeared David M. Eppler, who, being duly sworn, declared and acknowledged before me that he is a Manager of Cleco Power LLC and that in such capacity he was duly authorized to and did execute the foregoing Joint Agreement of Merger on behalf of said limited liability company, for the purposes therein expressed, and as his and said limited liability company's free act and deed. /s/David M. Eppler ------------------ David M. Eppler Appearer SWORN TO AND SUBSCRIBED BEFORE ME THIS 15th DAY OF DECEMBER, 2000. /s/Beatrice P. Newcomb - ---------------------- Beatrice P. Newcomb NOTARY PUBLIC 8 EX-12 3 0003.txt COMPUTATION OF EARNINGS EXHIBIT 12 CLECO POWER LLC COMPUTATION OF EARNINGS TO FIXED CHARGES AND EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS
2000 1999 1998 1997 1996 -------- -------- -------- -------- -------- Earnings from continuing operations.................. $ 59,857 $ 56,683 $ 53,801 $ 52,519 $ 52,135 Income taxes................. 30,998 27,272 26,666 27,729 26,154 -------- -------- -------- -------- -------- Earnings from continuing operations before income taxes....................... $ 90,855 $ 83,955 $ 80,467 $ 80,248 $ 78,289 -------- -------- -------- -------- -------- Fixed charges: Interest, long-term debt... $ 24,929 $ 25,377 $ 23,350 $ 23,676 $ 25,134 Interest, other............ 3,427 1,755 3,666 3,873 2,359 Amortization of debt expense and premium, net.. 946 1,282 1,248 1,206 1,107 Portion of rental expense representative of interest factor.................... 493 615 486 487 445 -------- -------- -------- -------- -------- Total fixed charges...... $ 29,795 $ 29,029 $ 28,750 $ 29,242 $ 29,045 -------- -------- -------- -------- -------- Earnings from continuing operations before income taxes and fixed charges..... $120,650 $112,984 $109,217 $109,490 $107,334 ======== ======== ======== ======== ======== Ratio of earnings to fixed charges 4.05x 3.89x 3.80x 3.74x 3.70x -------- -------- -------- -------- -------- Fixed charges from above..... $ 29,795 $ 29,029 $ 28,750 $ 29,242 $ 29,045 Preferred dividends.......... -- 1,315 2,814 2,884 2,909 -------- -------- -------- -------- -------- Total fixed charges and preferred stock dividends. $ 29,795 $ 30,344 $ 31,564 $ 32,126 $ 31,954 ======== ======== ======== ======== ======== Ratio of earnings to combined fixed charges and preferred stock dividends 4.05x 3.72x 3.46x 3.41x 3.36x ======== ======== ======== ======== ========
EX-23 4 0004.txt CONSENT OF INDEPENDENT ACCOUNTANTS EXHIBIT 23 CONSENT OF INDEPENDENT ACCOUNTANTS We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-52540) of Cleco Power LLC of our report dated January 30, 2001 relating to the financial statements and financial statement schedule, which appears in this Form 10-K. PricewaterhouseCoopers LLP New Orleans, Louisiana January 30, 2001 EX-24 5 0005.txt POWERS OF ATTORNEY EXHIBIT 24 CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ Sherian G. Cadoria ------------------------------------- Sherian G. Cadoria CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ J. Patrick Garrett ------------------------------------- J. Patrick Garrett CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ F. Ben James, Jr. ------------------------------------- F. Ben James, Jr. CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ William H. Walker, Jr. ------------------------------------- William H. Walker, Jr. CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ A. DeLoach Martin, Jr. ------------------------------------- A. DeLoach Martin, Jr. CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ Robert T. Ratcliff ------------------------------------- Robert T. Ratcliff CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ Edward M. Simmons ------------------------------------- Edward M. Simmons CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001. /s/ Richard B. Crowell ------------------------------------- Richard B. Crowell CLECO POWER LLC POWER OF ATTORNEY WHEREAS, Cleco Power LLC, a Louisiana limited liability company, (the "Company"), intends to file with the Securities and Exchange Commission (the "Commission") under the Securities Exchange Act of 1934, as amended (the "Act"), an Annual Report on Form 10-K (the "Form 10-K") for the Company's fiscal year ended December 31, 2000, with any and all amendments thereto as may be necessary or appropriate, together with any and all exhibits and other documents having relation to the Form 10-K; NOW, THEREFORE, the undersigned, in the capacity of a director or officer or both a director and officer of the Company, as the case may be, does hereby appoint David M. Eppler and Michael P. Prudhomme, and each of them severally, his true and lawful attorney(s)-in-fact and agent(s) with power to act without the other, with full power of substitution and resubstitution, to execute in his name, place and stead, in any and all capacities, the Form 10-K and any and all amendments thereto and any and all instruments necessary or incidental in connection therewith, to file the same with the Commission and to appear before the Commission in connection with any matter relating thereto. Each of said attorneys-in-fact and agents shall have full power and authority to do and perform in the name and on behalf of the undersigned, in any and all capacities, every act whatsoever necessary or desirable to be done in the premises, as fully and to all intents and purposes as the undersigned might or could do in person, the undersigned hereby ratifying, approving and confirming the acts that said attorneys-in-fact and agents and each of them, or their or his substitutes or substitute, may lawfully do or cause to be done by virtue hereof. IN WITNESS WHEREOF, the undersigned has executed this power of attorney as of the 29th day of March, 2001 /s/ Elton R. King ------------------------------------- Elton R. King -----END PRIVACY-ENHANCED MESSAGE-----